Sioshansi F.P. Smart Grid: Integrating Renewable, Distributed & Efficient Energy
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The diminishing capacity of DLC after the year 2013 is an
odd characteristic of Figure 9.11 that deserves attention.
Figure 9.12 highlights the observed decrease in DLC MWs by
region. The FERC study is not only assuming that DLC
participation peaks by the year 2013, but also that formerly
subscribed DLC resources will be displaced by dynamic
pricing capacity.
Figure 9.11
FERC's AP scenario disaggregated by DR program type with 100% AMI
rollout and 60–75% of customers engaged with dynamic pricing rates.
Source: FERC [31]
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Figure 9.12
DLC potential from FERC's AP scenario disaggregated by region.
Source: FERC [31]
This assumption convolves two discrete categories of DR as
outlined in the topology of this report. Switching DLC
capacity to dynamic pricing transfers DR resources from the
dispatchable (maximum ELCC) branch to the
non-dispatchable (minimum ELCC) branch. Such a shift is
suboptimal from the perspective of the grid's reliability,
efficiency, and flexibility in VER integration.
Furthermore, to the extent that increased VER penetration
drives greater demand for ancillary services applicable to
DLC operation (regulation, spin, and non-spin), it will be
unlikely that dynamic pricing displaces DLC capacity in this
way. From this perspective, the assessment of DLC potential
in the FERC report can be regarded as a conservative
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estimate, especially in the context of continued growth in the
deployment of variable energy resources.
Wind Integration and Demand Response
Illustrating DR's ability to decrease wind integration costs
requires contrasting DR's evolution with the evolution of
ancillary service requirements that originate from wind
integration. Due to the FERC AP scenario treatment of DLC
relative to economic DR programs, as well as the overall
diminishing cumulative MWs of DLC, FERC's EBAU
scenario was chosen for this analysis.
The evolution of ancillary service requirements associated
with wind integration was established with the following
methodology. Smith et al. estimated the capacity required for
total operating reserves to increase from 5% to 7% in a 25%
RPS scenario for a four-utility combined balancing area with
a peak load of about 21 GW [35]. This corresponds to a 40%
increase in ancillary reserve requirements. Upper and lower
bounds of total operating reserves (contingency and normal
operations) in power systems range from 5% to 10%[28].
Combining these facts lead to an upper and lower bound on
the incremental increase in operating reserves from high wind
penetration scenarios of 2% and 4% of peak system capacity.
Data from Heffner's international survey of loads providing
ancillary services indicates that PJM obtained operating
reserves at 4.75% of peak capacity and that ERCOT obtained
operating reserves at 7.5% of peak capacity [28].
The dataset also indicated that 50% of PJM's operating
reserves derived from regulation and instantaneous spinning
reserves and that 75% of ERCOT's operating reserves derived
from regulation and spinning reserves. The majority of this
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capacity corresponds to spinning rather than regulation
reserves (typically ~0.7% of load) [2]. Smith et al. estimated
that the regulation requirement increases from 0.65% in the
base case to 0.75% with a 25% RPS [35].
Putting these disparate studies and percentages together yields
upper and lower bounds on regulation, spinning, and
non-spinning reserve requirements of 1% to 3% of peak
capacity. Upper and lower bounds on load following and
supplemental reserve requirements were established to be
0.5% to 2% of peak capacity. Peak capacity in 2019, not
including the growth in DR, was back calculated from FERCs
EBAU scenario. A relative understanding of DR's ability to
mitigate wind integration costs is achieved by combining the
cumulative incremental increase in DR from FERCS EBAU
scenario with the upper and lower bound cumulative increase
in reserve capacities (Figure 9.13). It must be emphasized that
this method of comparison provides insights into the orders of
magnitude involved but does not offer a finely tuned
projection of the future.
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Figure 9.13
Comparison of interruptible tariff and capacity DR potential with load
following and supplemental reserve requirements for wind integration at 25%
penetration.
The variations between regions in the incremental ancillary
services needed to accommodate large VER penetrations
reflect differences in balancing authority size, transmission
system topology, available transfer capacity, market design,
load shape, resource diversity and temporal correlation,
diurnal and seasonal wind profile, system scheduling
frequency, and a host of other variables. The largest, most
diverse system with the most flexible generation mix and
stiffest transmission system will have the lowest need for
incremental firming capacity and vice versa.
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Total incremental DLC potential from FERC's EBAU
scenario is of the same order as incremental ancillary firming
capacity required for significant wind penetrations (Figure
9.14). Inspection of the preceding figures reveals that load
following and supplemental reserve requirements are satisfied
by interruptible tariff and capacity-based DR but that
regulation, spin, and non-spin requirements are not always
met by DLC DR.
Figure 9.14
DLC compared to regulation, spin, and non-spin wind integration requirements.
The upper bound of regulation, spin, and non-spin
requirements exceeds the DLC EBAU MWs in all regions. It
is important to note that some of the interruptible tariff DR is
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actionable on spinning and non-spinning reserve timescales.
Although the topology described in this study draws a line
between interruptible tariff DR programs and DLC programs,
some interruptible tariff DR resources are capable of
providing instantaneous response. LBNL's 2009 empirical
review of existing DR resources revealed that 15% of IT DR
is capable of response from 1–30 minutes in SPP and 35% in
MISO. The EBAU FERC scenario assumes that each
mutually exclusive DR topology grows under aggressive
scenarios without transferring MWs from other DR types. In
reality, commercial and industrial loads that are currently
signed up for interruptible tariff DR could switch to DLC if it
was better suited to provide valuable fast-acting response. In
addition, given the limited scope of resources included in
FERC's EBAU DLC potential assessment, this represents a
lower bound of available DLC potential.
Conclusions
DR is a rapidly growing resource in the electricity sectors
portfolio that can help facilitate large penetrations of
renewables on the grid. Instantaneously dispatchable DLC
offers the greatest value on the regulation and spinning
reserves timescales. Existing capacity and tariff based DR
programs are well suited to provide load following and
contingency reserves during economic and
reliability-constrained wind ramps.
Even under relatively conservative assumptions, total
incremental DLC potential is of the same order as the
incremental ancillary firming capacity required for significant
wind penetrations. Moving forward, this resource potential
could be further augmented through building automation and
software innovations that enable industrial, commercial, and
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residential loads to be dispatched into DR markets without
requisite oversight by a sophisticated energy user.
This suggests DR has the potential to take a prominent place
in the portfolio of wind integration strategies. If these
resources have access to clear price signals and market
products that facilitate their transparent participation, DR
could provide an important source of distributed flexibility for
the grid as a whole. Dispatchable DR resources will be of
particular importance when it comes to integrating renewable
resources with variable output and meeting the increased
demand for ancillary services that VERs will drive.
Acronyms
AP Achievable Potential
AMI advanced metering infrastructure
BAU Business-As-Usual
C&I commercial and industrial
CAGR compound annual growth rate
DR demand response
DOE Department of Energy
DLC direct load control
ELCC effective-load carrying capacity
EWITS Eastern Wind Integration and Transmission Study
FERC Federal Energy Regulatory Commission
GHG greenhouse gas
IT interruptible tariffs
LOLE loss of load expectation
LTRA Long Term Reliability Assessment
MAP Maximum Achievable Potential
NERC North American Electric Reliability Corporation
NREL National Renewable Energy Laboratory
PNNL Pacific Northwest National Laboratory
RAP realistic achievable potential
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VER variable energy resource
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