Integrating Wind
Resources Into the
Transmission Grid
Gary D. Bachman
Wisconsin Public
Utility Institute
May 26, 2010
Introduction
 Statement of FERC Chairman Jon Wellinghoff on Efficient
Integration of Renewables into the Grid, January 21,
2010:
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“Approximately 9,000 MW of variable energy resources went into
commercial operation in the U.S. during 2009 and a similar
number in 2008. Currently, there are thousands of MW of VERs,
particularly wind, in the process of interconnection to the electric
grid. These new resources offer low operating costs and low
greenhouse gas emissions, which can benefit consumers … VERs
also have some operational characteristics which present
challenges to system operators. Therefore, it is important that
the Commission examine the most efficient ways to effectively
integrate these resources into the electric grid, while maintaining
reliability and operational stability.”
Wisconsin Public Utility Institute
Introduction
 Wind and Natural Gas are the leading sources of new
generation capacity in the United States, collectively
totaling roughly 80% of new installed capacity in 2009.
 New growth driven in large part by state renewable
portfolio standards, production tax credits, and in some
cases, favorable economics.
 Here in the Midwest, the Midwest Governors’ Association
has established a goal of 30 percent renewable energy
consumption by 2030.
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Wisconsin Public Utility Institute
Introduction
 The rapid development of wind generation
presents challenges for transmission system
operators …
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Wisconsin Public Utility Institute
What’s the Problem?
 Balancing Area operators (“BAs”) are responsible
for continuously balancing generating resources
with load and must maintain adequate
generating reserves that are quickly available to
accomplish this task.
 NERC measures a BA’s compliance with this
requirement through its Control Performance
Standard 2 (“CPS-2”), which measures the
balance over 10-minute periods of each month.
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Wisconsin Public Utility Institute
What’s the Problem?
 CPS-2 sets a limit on the maximum permitted
Area Control Error (“ACE”).
 ACE is the instantaneous difference between actual
and scheduled flow on tie lines between a balancing
area and surrounding balancing areas.
 In order to be in compliance with CPS-2, a BA
must pass this measurement in at least 90
percent of the 10-minute periods in each one
month period.
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Wisconsin Public Utility Institute
What’s the Problem?
 The output from dispatchable (fossil-based, nuclear,
hydro) generation is typically set at a certain level, and
can be maintained so long as the unit is performing
properly.
 Dispatchable generation typically does not vary much
from its scheduled output, barring an unforeseen
outage.
 A BA’s intrahour role has therefore traditionally focused
on managing the moment-to-moment deviations in loads
using online generating capacity that can respond
instantaneously in a process known as “regulation.”
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Wisconsin Public Utility Institute
What’s the Problem?
 Wind generation introduces a new source of
variability that the BA must manage to meet its
CPS-2 requirements.
 The output from a wind generator can increase
or decrease in response to changes in wind
speed and direction, and is also susceptible to a
phenomenon known as “high speed cutout”
which can occur during high wind conditions
when governors on the generators shut them
down as a protective mechanism.
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Wisconsin Public Utility Institute
What’s the Problem?
Wild Horse: 0 MW to 129 MW in 11 minutes
250
Wind Generation (MW)
Ridge: 0 MW
to 134 MWfrom
in 7 minutes
 InsertHopkins
Telemetry
Example
PSE
200
150
100
50
June 4 - 5, 2009
Wild Horse
Hopkins Ridge
HR Schedule: HE 2100 = 15, HE 2200 = 130, HE 2300 = 140, HE 2400 = 100, HE 01 = 5
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Wisconsin Public Utility Institute
3:00
2:30
2:00
1:30
1:00
0:30
0:00
23:30
23:00
22:30
22:00
21:30
21:00
20:30
20:00
0
What’s the Problem?
 Wind generators underperform relative to their
schedules when the wind blows less than expected.
 During times of low load levels, wind projects may
produce energy that is not needed, which requires other
generation to back down to preserve balance on the
system.
 Example of Extreme Wind Variability:

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On November 27, 2009, one wind facility in the Pacific
Northwest recorded an output of 0 MW halfway through the
0:300 scheduling hour, 175 MW halfway through the 0:400
hour, and 26 MW halfway through the 0:500 hour.
A 175 positive ramping event, followed by a 149 MW negative
ramping event, in two hours.
Wisconsin Public Utility Institute
What’s the Problem?
 Offsetting Load Variability?
 When wind generators in a balancing area experience
a ramping event in the same direction of load
movement, the variability of wind and load offset to
reduce the BA’s within hour fluctuations.
 Of course, when wind and load vary in the opposite
direction, there is an additive effect on net variability.
 Analysis of some western systems has shown that the
beneficial effects of offsetting load variability dissipate
as more wind is added because the first few large
wind projects absorb the available offsetting load
variability.
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Wisconsin Public Utility Institute
What’s the Problem?
 Wind Diversity?
 Different wind sheds may experience ramping events
at different times, such that a wind resource in one
geographical corner of a balancing area may ramp up
while another resource ramps downward. This
offsetting wind variability reduces the within-hour
burden on the BA.
 However, a concentration of wind farms around a
single geographic resource (i.e., single windshed) can
have an additive effect and increase the burden on
the BA.
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Wisconsin Public Utility Institute
What’s the Problem?
 BAs must have sufficient flexible capacity
available that can be ramped up or down to
balance wind ramping events in order to meet
CPS-2 standard and keep the system balanced.
 Current tariff provisions and market protocols
were largely developed prior to the recent
increase in wind development and were
designed with dispatchable – not variable –
generation in mind.
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Wisconsin Public Utility Institute
What’s the Problem?
 For example, it is generally not efficient or appropriate to
balance wind generation using the same regulation
products used to balance load variation because of the
magnitude and duration of wind ramping events.
 The most appropriate products are similar to the
Spinning Reserve Service and Supplemental Reserve
Service, which reserve products are defined as ancillary
services under the pro forma OATT. However, they are
only available during contingencies.
 Most wind ramping events do not qualify as
contingencies as defined in the pro forma OATT and
thus the ancillary service products are not available for
use by BAs for that purpose.
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Wisconsin Public Utility Institute
What’s the Problem?
 Moreover, FERC’s restrictions on the sale of ancillary
services at market-based rates have limited the
development of a market for products that are like
spinning and supplemental reserves but are not
contingency products.
 Absent a market for reserve products, BAs are often
forced to balance wind resources using facilities or
resources on their system that are not well suited to the
task and/or would otherwise be dedicated to optimizing
cost of service to native load.
 The pro forma OATT does not recover the costs of
providing the integration service or such resources.
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Wisconsin Public Utility Institute
What’s the Problem?
 Wind developers are concerned that BAs may try to shift
the costs of wind integration to wind developers in a way
that is inconsistent among BAs, unduly discriminatory, or
punitive.
 Wind developers fear that if the cost of integrating wind
generation becomes unduly high, the growth of the
industry will be stunted.
 Wind developers also fear discriminatory curtailment
practices by BAs that could limit the amount of wind
energy that reaches the market and limit RECs.
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Wisconsin Public Utility Institute
What’s the solution?
 FERC-approved tariff amendments allow BAs to
recover costs of following wind generation:
 Entergy Services, Inc., 120 FERC 61,042 (2007):
 Commission approved amendment to Entergy OATT that
allowed for separate recovery of the costs of holding
additional reserves for meeting generation imbalances.
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Wisconsin Public Utility Institute
What’s the solution?
 FERC-approved tariff amendments allow BAs to recover
costs of following wind generation:

Westar Energy, Inc., 130 FERC 61,215 (2010)
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Westar sought and obtained FERC approval to implement new OATT
Schedule 3A, Generator Regulation and Frequency Response Service
Westar observed wind generators’ in Kansas from Dec. 2005 to Nov.
2006 to determine the deviation from schedule over 10-minute
intervals.
Westar allowed load variations and other wind variations in the BA to
offset a generator’s deviations where applicable – the “portfolio-wide”
approach to measuring wind variability.
The data collected demonstrated that wind generators’ deviations from
deployment signal are more than three times greater than those of
dispatchable generators.
Westar claimed that as a result, wind generators placed a heavier
burden on its system than dispatchable generation.
Wisconsin Public Utility Institute
What’s the solution?
 FERC-approved tariff amendments allow BAs to
recover costs of following wind generation:
 Westar Energy, Inc., 130 FERC 61,215 (2010)
(cont’d)
 Westar therefore proposed to charge under Schedule 3A
intermittent generators a higher generator regulation charge
than dispatchable units – a regulation requirement of 7.8
percent of nameplate capacity (Westar’s Schedule 3 charges
dispatchable units a regulation requirement of 1.35 percent
of nameplate capacity).
 The Commission’s approved Westar’s proposal, finding that it
“reasonably assesses intermittent generation a higher
regulation requirement consistent with cost causation
principles.” Id. at P 36.
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Wisconsin Public Utility Institute
What’s the solution?
 FERC Rejects Tariff Amendments That Shift
Burden of Providing Following Services to
Generators:
 NorthWestern Corporation, 129 FERC 61,116 (2009)
 Northwestern proposed an amendment that would have
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required intermittent renewable generators to supply or
otherwise provider their own generation following capability for
both capacity and energy.
The Commission held that Northwestern could not shift its
responsibility to provide generator imbalance service under
Schedule 9 of the pro forma OATT to intermittent generators.
Opinion advised Northwestern to file tariff revisions that would
allow it to recover costs of providing regulation services to
intermittent generators if those costs were not already being
recovered under the utility’s OATT.
Wisconsin Public Utility Institute
What’s the solution?
 Curtailment?
 Generally, transmission providers are allowed to
curtail generation on a pro rate basis to reduce
transmission congestion.
 But: some wind generation cannot reduce output without
shutting down completely, presenting an all or nothing decision
for BAs.
 Some transmission providers have developed different
curtailment practices for wind generation to
accommodate ramping events:
 BPA agreed in a settlement with its customers to sell flexible
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capacity to wind generators under its OATT at a discounted rate
of $1.29 to $1.58 per kW-month.
In exchange, BPA obtained the right to curtail wind generators
when 90% of its balancing reserves are deployed.
Wisconsin Public Utility Institute
What’s the solution?
 Voluntary Regional Efforts:
 Various regions have formed working groups to
develop solutions to wind integration.
 Example: Northwest Wind Integration Action Plan
(“NWIAP”).
 Identifies 16 action plan items that would help facilitate the
reliable and efficient interconnection of large amounts of wind in
the region.
 Example: Joint Initiative
 Voluntary effort by ColumbiaGrid, Northern Tier Transmission
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group, and WestConnect to develop products and services to
aid wind integration.
Have developed a standard intrahour scheduling product and
business practice.
Wisconsin Public Utility Institute
What’s the solution?
 Different regions have taken different
approaches depending on the quantity and
characteristics of wind resources interconnected
to the grid in those regions.
 Wind generators are concerned that this ad hoc
approach may lead to a lack of consistency
across regions, a lack of transparency, and
potentially discriminatory treatment of wind
resources.
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 On January 21, 2010, FERC issued a Notice of
Inquiry (“NOI”) seeking comments on whether
reforms of existing policies are needed to better
integrate wind generation into the transmission
grid.
 The NOI welcomed general comments, and also
sought comments on seven particular subject
areas.
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 1. Data and Reporting Requirements:
 Development of state-of-the art forecasting
techniques could take some of the uncertainty out of
a BA’s job when it comes to integrating wind
resources.
 BAs will have a better idea of the quantity of reserves
they need to have available if they can better predict
large scale ramping events.
 Wind generators will be able to schedule more
accurately – and hence avoid scheduling penalties for
over/under generation – if they can better predict
output.
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 1. Data and Reporting Requirements:
 Questions Raised:
 Sharing of data collected by a generator at the site of wind
turbines with BAs
 Centralized forecasting by BA?
 Cost recovery?
 Even with a “perfect” forecast – the variability must still be
smoothed.
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 2. Scheduling Practices and Incentives/Penalties:
 FERC primarily sought comments on two areas of
inquiry:
 Whether there should be a move to intrahour scheduling
 Whether the current exemption from third tier scheduling
penalties for wind generation should be continued and/or
creating proper incentives to schedule accurately.
 Intrahour Scheduling:
 A move to intrahour scheduling would wind generators to
schedule more accurately in response to changing weather
conditions, and allow BAs to more frequently and efficiently
adjust the amount of reserves they need to have available to
balance wind.
 Tariff provisions and operational protocols would need to be
revised to accommodate intrahour scheduling.
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 2. Scheduling Practices and Incentives/Penalties:
 Scheduling Penalties:
 Currently, intermittent generators are exempt from 25%
scheduling penalty for third tier scheduling errors (>7.5%),
which requires wind generators to purchase imbalance
energy at 125% of the energy’s incremental cost.
 Instead, wind generators must only pay 110% of the
incremental cost of replacement energy for even the largest
of generation imbalances.
 FERC solicited comments on whether this 10% penalty is an
adequate incentive for wind generators to schedule
accurately, or whether it is not harsh enough (or too harsh).
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 3. Day-Ahead Market Participation
 Currently, participating in day-ahead markets (in
regions where they are available) is generally
considered too risky for wind generation because of
the uncertain output and risk of underperformance.
 Wind generators without a full contract offtaker
generally participate only in the real time energy
market.
 The Commission is considering ways of encouraging
participation by wind resources in day-ahead markets.
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 4. Balancing Area coordination and/or
consolidation:
 In some cases, wind integration costs can be reduced
by increasing the size of a balancing area to
encompass more (hopefully) offsetting load and wind
variations.
 If there is little wind or load diversity in the region,
consolidating balancing areas may not have
significant benefits.
 Some western utilities have discussed the formation
of a “wind only” balancing area across the
interconnection, though significant transmission
issues would need to be resolved.
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 4. Balancing Area coordination and/or
consolidation:
 BA coordination activities that can facilitate
integration by shifting BA responsibilities and
burdens:
 Dynamic transfers
 Dynamic schedules
 Pseudo-ties
 ACE Diversity Interchange (“ADI”) – developed in Pacific
Northwest; voluntary frequency sharing program that has
allowed some BAs to better meet their CPS-2 requirements.
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 5. Reserve Products and Ancillary Services:
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As discussed previously, spinning reserves and supplemental
reserves contingency products that could otherwise be used to
balance wind ramping events.
The lack of a market for suitable wind following reserve products
means that transmission providers often rely on more expensive
regulation reserves or, outside of RTO/ISO areas, are required to
balance wind ramping events using resources that were acquired
to serve to native load.
The Commission thus sought comments on whether the
definitions of these ancillary services should be revised to make
them applicable to wind ramping events; and otherwise how a
market for such products and services should be fostered.
Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 5. Reserve Products and Ancillary Services:
 Key Questions:
 Type of product – flexible, can be ramped up or down
(spinning?) on short notice
 Technology – Natural gas, peaking unit?
 Who should be responsible under the tariff for providing
wind following service?


BA?
Wind generator?

generators?
Portfolio-wide approach, taking into account offsetting load
and wind variations
 Cost allocation if BA provides service
 Based on historical scheduling imbalances of wind
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 6. Wind participation in capacity markets
 In areas with organized capacity markets,
Commission has inquired, among other topics,
whether:
 Uniform capacity rating for wind resources should be
developed
 Wind resources are prohibited from participating in forward
capacity markets
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 7. Real-time Adjustments
 Redispatch – there is some uncertainty concerning
redispatch practices when a wind ramping event
results in a reserve shortage, and who is to bear the
costs associated with the event.
 Inability of to reduce output – when a wind
generator cannot reduce output through blade
feathering or a governor in response to BA dispatch
instructions, should they be ordered to shut down
completely?
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Wisconsin Public Utility Institute
FERC’s Notice of Inquiry
 The Commission received over 100 sets of
comments on these topics.
 Trends:
 BAs and transmission providers generally favor:
 Flexibility to develop regional/BA-specific solutions.
 Shifting of responsibility to balance wind generation to wind
generators – curtailment in extreme ramping events.
 Full cost recovery
 Wind developers generally favor:
 Consistent application of policies through a FERC rulemaking.
 BAs retain responsibility for balancing system with reserves,
even during ramping events.
 Policies which place wind generators on equal footing with
dispatchable generation.
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Wisconsin Public Utility Institute
QUESTIONS?
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Wisconsin Public Utility Institute
For more information
Gary D. Bachman
202 298 1880
[email protected]
Wisconsin Public
Utility Institute
May 26, 2010