Document name
2013 Interconnection-wide Plan
Variable Generation Integration
Category
( ) Regional reliability standard
( ) Regional criteria
( ) Policy
( ) Guideline
( ) Report or other
( ) Charter
Document date
September 19, 2013
Adopted/approved by
The WECC Board of Directors
Date adopted/approved
September 19, 2013
Custodian (entity
responsible for
maintenance and
upkeep)
TEPPC
Stored/filed
Physical location:
Web URL:
Previous name/number
(if any)
Status
( ) in effect
( ) usable, minor formatting/editing required
( ) modification needed
( ) superseded by _____________________
( ) other _____________________________
( ) obsolete/archived)
(Page intentionally left blank)
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L • W W W . W E C C . B I Z
155 NORTH 400 WEST • SUITE 200 • SALT LAKE CITY • UTAH • 84103 -1114 • PH 801.582.0353
September 19, 2013
3
2013 Interconnection-Wide Plan
Analysis of Flexible Reserves for the
Integration of Variable Generation
By
WECC Staff
Western Electricity Coordinating Council
September 19, 2013
September 19, 2013
4
Introduction
The integration of variable generation (VG) resources into the Western Interconnection
has become an increasingly important topic for transmission system planning and
operations. In the 2011 WECC Regional Transmission Expansion Plan, all of the cases
analyzed had high levels of VG, which caused significant and unprecedented levels of
conventional generation ramping and cycling in the PCM. In response, TEPPC
recommended that future transmission planning studies include a comprehensive
review of VG integration issues related to transmission expansion planning. Following
the 2011 Plan, TEPPC committed to identifying and evaluating the challenges of
integrating the VG assumed in the Plan and identifying possible options to address
these challenges. In the 2013 Plan, TEPPC took steps toward this objective and laid
important groundwork for future VG integration analyses within the context of
transmission expansion planning.
Four challenges/options to the integration of VG emerged from the 2011 Plan. This
report discusses operating reserves for VG (hereinafter “flexibility reserves”). Cycling
costs are included in the 2013 Plan via the cycling cost calculator developed by the
National Renewable Energy Laboratory (NREL) and described in detail in the Data and
Assumptions report. Balancing Authority consolidation and configuration, and intra-hour
scheduling are outside of TEPPC’s scope and were addressed in the WECC Variable
Generation Subcommittee’s (VGS) “BA Cooperation Study”.1
The analysis described below represents an initial attempt at characterizing VG
integration issues by way of flexibility reserves. The analysis was conducted from a
transmission planning standpoint, and should be interpreted in that light. The issues
surrounding the integration of VG span the realms of operations, markets and planning.
The TEPPC analysis of flexibility reserve requirements is a piece of a much larger,
evolving discussion of VG integration.
Background
Balancing loads and resources takes place as a basic function of grid operations;
variability on the grid must be balanced to ensure reliability. There are two primary
sources of variability on the grid: consumer loads and VG resources, (i.e., wind and
solar Photovoltaic (PV)). Load variability has long played a part in reliable planning and
operation of the electric grid. To a great extent, the grid in the Western Interconnection
has been built to address load variability. There is vast experience in the Western
1
http://www.wecc.biz/committees/StandingCommittees/JGC/VGS/Shared%20Documents/BA%20Cooperation%20Study/Final%.
Page 4 of 13
September 19, 2013
5
Interconnection with analyzing, forecasting and accounting for load variability, which is
essential to planners and operators as load patterns continue to change – perhaps
dramatically in the future.
Variability associated with VG resources is a relatively new concern that has taken
shape in the last decade as a large amount of VG has come on line in a short period of
time. As with load, forecasting is valuable tool to address VG variability; however, VG
forecasting is in a developmental phase and the data underlying VG forecasts do not
have the historical depth that load data does. Ultimately, advances in forecasting
notwithstanding, variability remains and will persist into the future because we cannot
forecast perfectly.
Conditions with high VG penetration can create stress on system operations as the
variability is balanced. While balancing load variability and balancing VG variability are
fundamentally the same – load must be equal to generation – the characteristics of VG
and the political and regulatory environment surrounding it pose unique challenges in
balancing the variability. Ultimately, VG cannot be controlled in the way that traditional
resources can be controlled. This is not to say that VG cannot be dispatched under
certain circumstances, such as CSP with storage, and VG can be curtailed, but, VG
resources cannot be dispatched up and down to balance out the continuous movement
of load the way that traditional resources, such as gas-fired and hydro resources, can.
In addition, the political and regulatory environment may change the way that balancing
is approached. For example, in cases of a generation surplus, curtailment of resources
is among the possible solutions; however, tax incentives like production tax credits,
make curtailing some VG resources unpalatable. The result may be that traditional
resources must be backed down to balance the surplus, a solution that comes with its
own costs and potential reliability ramifications.
All of this creates operational uncertainty around VG resources. Uncertainty in grid
operations invokes reliability concerns. Added to this, from the planning perspective, is
the uncertainty associated with future levels of VG. Current state renewable portfolio
standards provide some indication of where the future of VG might be going, and these
policies form the basis of the 10-year analysis. But, these kinds of drivers are a product
of a fluid political, regulatory, and economic environment, which can change
substantially over the long-term and are impossible to predict. Planning uncertainty
surrounding the future of VG compounds the operational uncertainty and makes
planning a future grid more complex.
Reducing or mitigating the uncertainty associated with VG is necessary. While great
strides have been made in reducing the uncertainty of VG (e.g., forecasting tools),
where uncertainty cannot be reduced, measures must be taken to ensure that enough
capacity is available to keep the system operating reliably. One method is to hold
enough capacity in reserve to “cover” the variability. TEPPC refers to this held capacity
Page 5 of 13
September 19, 2013
6
as “flexibility reserves.” TEPPC’s analysis of “flexibility reserves” is the subject of this
document. From a planning perspective, levels of flexibility reserves can be used as an
indicator of the amount of variability on the grid in a given study scenario.
It is important to note that there are other options being discussed, in development, and
available to address variability. Options like demand response, BA consolidation, and
market mechanisms are just three examples. TEPPC does not contend that any option,
including the holding of flexibility reserves, is more viable, preferable, or appropriate
than any other, nor does it intend to suggest or recommend how variability should be
addressed in the future.
Methodology and Input Assumptions
The 10-Year Plan Follow-up Group (2011 Plan) recommended that the 2013 Plan
include a comparison of various methods of managing the integration of variable
resources. WECC uses an analysis of flexibility reserves to evaluate two methods
identified by the Group: 1) increasing the size of the balancing footprint; and 2)
scheduling the variability of resources to the receiving area.
To conduct the analysis of flexibility reserves, WECC first needed to improve the
quantification of flexibility reserve requirements for VG. WECC worked with NREL to
develop a flexibility reserve calculator that was used to determine the amount of
flexibility reserves needed to balance the inherent variability of wind and solar
generation. Flexibility reserves calculated by the tool are included in the 2013 studies.
WECC then worked with NREL to develop a comparative analysis of flexibility reserve
requirements across three future resource assumptions: 1) 2020 Base Case
assumptions; 2) 3,000 MW wind added in Wyoming; and 3) 3,000 MW solar added in
Arizona. For each of the resource assumptions, flexibility reserves were compared
across four scenarios: 1) reserves held in the local BA/load area; 2) held in the local
subregion of the Western Interconnection; 3) held in the Southern California Edison
(SCE) BA/load area; and 4) held in the CA_South subregion. Table 1 summarizes the
10 scenarios analyzed.
Table 1: Summary of Scenarios Analyzed
BA/Load Area Level
Base
Case
Wind
WY
Wind
CA
Subregional Level
2020 Base Case (2020 PC1)
Flex Reserves for all
Flex Reserves for all portion of the Western
BA/load areas
Interconnection
3,000 MW wind in WY (2022 PC20)
Flex reserves for all wind
Flex Reserves for all wind located in Basin
located in PACE_WY
portion of the Western Interconnection
3,000 MW wind dynamically transferred from WY to CA
Flex reserves for all wind
Flex Reserves for all wind in CA_South portion
located in SCE
of the Western Interconnection
Page 6 of 13
September 19, 2013
Solar
AZ
Solar
CA
7
3,000 MW solar in AZ (2022 PC21)
Flex reserves for all solar
Flex Reserves for all solar located in AZNMNV
located in APS
portion of the Western Interconnection
3,000 MW solar dynamically transferred from AZ to CA
Flex reserves for all solar in Flex Reserves for all solar in CA_South portion
SCE
of the Western Interconnection
The scenarios are based on the Western Wind and Solar Integration Study-2 “TEPPC”
scenario (TEPPC 2020 PC1) with synchronized 2006 data for load, wind and solar PV. 2
The 3,000 MW of additional wind in Wyoming were randomly selected from the High
Wind scenario. Similarly, the 3,000 MW of solar PV in Arizona were selected from the
High Solar scenario. For the California scenarios, it was assumed that the added wind
and solar were dynamically transferred into California, rather than selected from
resources in California.
The table in Figure 1shows the TEPPC BA/load areas included in each of the regions
analyzed. The map shows the TEPPC regions as well as the three BAs used in the
flexibility reserves work.
Figure 1: TEPPC BA/load areas included in regional analysis
Basin
Far East
Magic Valley
PACE ID
PACE UT
PACE WY
SPP
Treasure Valley
AZNMNV
APS
NEVP
PNM
SRP
TEP
WALC
CA_South
IID
LDWP
SCE
SDGE
Alberta
British Columbia
Northwest
Basin
CA_NORTH
CA_SOUTH
RMPP
AZNMNV
The regulation reserves were calculated using the following components:
Load: 1 percent of load
Wind: Coverage of 10-minutes un-forecasted events with 95 percent confidence
2
The Western Wind and Solar Integration Study website contains information on the study and links to
study documents; it is available at http://www.nrel.gov/electricity/transmission/western_wind.html.
Page 7 of 13
September 19, 2013
8
PV: Coverage of 10-minutes un-forecasted events with 95 percent confidence
Assuming independence between the three components, the total reserves were added
geometrically, so reserves equal:
(1% 𝑙𝑜𝑎𝑑)2 + (𝑊𝑖𝑛𝑑 𝑟𝑞𝑡)2 + (𝑃𝑉 𝑟𝑞𝑡)2
The load component was reported so the incremental effect of wind and PV could be
calculated.
Key Observations



Flexibility reserve requirements were smaller when integrating variable resources
at the regional level versus the BA/load area level; however, there are instances
where the reduction is not significant.
Scheduling the variability of added resources in the SCE load area and CA South
region reduced the incremental flexibility reserve requirement; however, the
reductions varied in magnitude and significance. Scheduling the variability of
Wyoming wind into California resulted in significant reductions, while only
nominal reductions resulted from moving the Arizona solar.
Load is a determinative factor in comparing the impacts of different methods of
managing variability.
Small vs. Large
In the follow-up discussion to the 2011 Plan, concern was raised that it may be more
difficult and/or more expensive to integrate large amounts of variable resources in the
relatively small BAs in the Western Interconnection, as opposed to larger areas – in the
case of this study, the TEPPC regions. The TEPPC analysis of flexibility reserve
requirements supports the widely-accepted concept that integrating VG over a larger
area requires fewer flexibility reserves. However, the results should not be taken to
support an overarching conclusion that in all cases there is a significant benefit to
balancing resources in a region, as opposed to a BA/load area. In this analysis, the
level of benefits depends largely on the differences between the BA/Load area and the
region, in other words, if the two cover virtually the same area and load, the benefit will
likely be much smaller than if the BA/Load area is vastly different from the region.
Another factor that affects the benefits of integrating over larger areas is the diversity of
the variable resources. As the diversity of resources within a footprint increases, the
aggregated variability within that footprint decreases. This analysis did not evaluate the
effect of changes in the diversity of variable resources, an improvement that can be
made in the next study cycle as part of a more robust integration analysis. This analysis
may identify changes to flexibility reserves that implicate this relationship, however,
more analysis is necessary to determine the extent to which the increased diversity
affects the results in the specific cases presented here.
Page 8 of 13
September 19, 2013
9
Figure 2 shows the annual average flexibility reserve requirements in 2020 for each of
the scenarios studied. To avoid a skewed average in the case of solar, the average was
calculated only for the times during which there was solar generation (i.e., daylight
hours). The whiskers in the figure represent the annual maximum and minimum
flexibility reserve requirements. The flexibility reserve requirements are smaller in each
region than in its corresponding BA/load area.
Figure 2: Average Annual Flexibility Reserve Requirements
Base Case
+ 3,000 MW
200
Reserve Requirements (MW)
180
160
140
120
100
80
60
40
20
0
PACE_WY
Basin
SCE
CA_So
Wind
APS
AZNMNV
SCE
CA_So
Solar
A comparison of the increase from the 2020 Base Case to the +3,000 MW case (Figure
3) shows that the number of incremental reserves is also greater in the BA/load area
than in the region, except in the case of PACE_WY and Basin. In that case, there is
actually a larger percent increase in flexibility reserve requirements in the Basin region
than in PACE_WY. This seems counterintuitive given the assumption that spreading
variability across a larger footprint decreases the overall variability and reduces the
flexibility reserve requirement. A possible explanation is that because the Basin footprint
is relatively diverse, and thus has a relatively small flexibility reserve requirement to
start with, the addition of the 3,000 MW of wind makes a larger impact than in the
smaller and more variable PACE_WY footprint. It is important to recognize that the
overall number of flexibility reserves in the Basin region is smaller than in PACE_WY.
Page 9 of 13
September 19, 2013
10
Figure 3: MW and Percent Change in Flex Reserve Requirements from Base Case to +3,000 MW
Case
60
50
MW
40
30
20
10
241%
262%
43%
31%
144%
52%
43%
36%
PACE_WY
Basin
SCE
CA_So
APS
AZNMNV
SCE
CA_So
0
Wind
Solar
The impact of the incremental flexibility reserves can be further understood by looking at
the additional flexibility reserves as a percentage of load, as seen in Figure 4. The
impact of the additional flexibility reserves is smaller in the regions. This is due in part to
the larger loads in the regions. In addition, the variability of resources tends to be less
severe as resource diversity works to smooth the variability. For example, the difference
between the PACE_WY and Basin base case reserve numbers indicates that even
before the variability is added, Basin requires fewer reserves. When the wind is added,
the impact on Basin from the additional reserves is lower in terms of how it compares to
load than in PACE_WY. This indicates that Basin is better able to absorb the variability
of the new resources than PACE_WY. While the same observation holds true in the
wind in California and solar cases, the relative impact in the California cases is much
smaller. In some circumstances, while the larger balancing footprint does reduce the
flexibility reserve requirement, the magnitude of the reduction as a portion of load is
negligible.
Page 10 of 13
September 19, 2013
11
Figure 4: Average Reserve Requirements as a Percent of Load
Base Case
+ 3,000 MW
Reserve Requirement as % of Load
10%
9%
8%
7%
6%
5%
4%
3%
2%
1%
0%
PACE_WY
Basin
SCE
CA_So
Wind
APS
AZNMNV
SCE
CA_So
Solar
The discussion of footprint size is particularly timely as work is currently underway to
develop a new TEPPC topology for the next study cycle. The TEPPC topology will be
changed from eight regions to approximately 24 BA pools. The topology change will
also result in changes to the flexibility reserve requirement assumptions in the next
planning cycle.
Shifting the Burden
Scheduling the variability of variable resources into the receiving BA is the second
method evaluated in this analysis. One way that this may be accomplished is through
dynamic transfers from one BA/load area or region to another. This analysis assumed
dynamic transfers as the generic method of “moving” the added resources from one
area to another; it did not include any analysis of the costs, benefits, limitations or
feasibility of dynamic transfers.
Figure 4 shows the extreme difference between balancing 3,000 MW of wind in the
PacifiCorp East - Wyoming (PACE_WY) BA Area versus the SCE load area. Not only
are fewer flexibility reserves needed in the SCE (Figure 3), but in the SCE the ratio of
incremental flexibility reserves to load is much smaller. This is more so the case when
the wind is scheduled into the CA South region. However, scheduling the variability into
the receiving region does not seem to have significant impact in all cases. For example,
the ratio of flexibility reserve to load for the +3,000 MW Solar case is 1.23 percent in the
AZNMNV region and 1.25 percent in the CA South region. The benefits of transferring
the burden of holding flexibility reserves appears to have less impact when scheduling
Page 11 of 13
September 19, 2013
12
the variability of the solar to California. Other factors, such as cost of flexibility reserves,
have not been considered in this analysis. It appears from this limited analysis that the
benefits of shifting the burden of holding the flexibility reserves to the receiving BA/load
area or region depends on the specific areas involved and on additional factors,
including load.
Load Matters
Whether the discussion is about small versus large balancing footprints or about shifting
the responsibility for holding flexibility reserves, load is a key consideration. For
example, the benefits of balancing 3,000 MW of solar in the CA South region versus the
SCE load area are not significant. The average load in the SCE is 13,082 MW, while in
CA South the average load is 19,606 MW. Compare this to PACE WY, which has an
average load of 1,563 MW, to the Basin region which has an average load of 5,534
MW. In the Wyoming case, the regional load is over three times as large as that of the
BA/load area. In the California case, the regional load is only about fifty percent larger.
Table 2 shows the load values for the BA/load areas and regions in this analysis.
BA/Load
Area
Region
Table 2: Annual Load for Regions and BA/Load Areas
Basin
Total
(MWh)
583,342,521
Average Minimum Maximum
(MW)
(MW)
(MW)
5,534
4,089
8,187
AZNMNV
1,634,879,235
15,510
9,998
29,554
CA_South
2,066,614,272
19,606
13,052
36,030
PACE_WY
164,783,869
1,563
1,144
1,868
APS
414,216,339
3,930
1,916
8,789
SCE
1,378,901,731
13,082
8,315
24,177
Figure 5 gives another example of the impact of load on flexibility reserves. Figure 5
compares the fluctuation in flexibility reserve requirements for solar in Arizona Public
Service Company (APS) and wind in PACE WY. APS average load is over three times
that of PACE WY. The magnitude of the APS daily average more closely follows the
2020 Base Case daily average, whereas the magnitude of the PACE WY daily average
is much more extreme as the PACE WY load is less able to absorb the variability.
Page 12 of 13
September 19, 2013
13
Figure 5: Comparison of Flexibility Reserve Requirements Daily Average and Max (MW)
Load also affects the benefits of scheduling variability into the load area. From Figure 5,
there appear to be significant benefits from scheduling the variability of Wyoming wind
into California; however, the benefits of scheduling the solar variability from Arizona into
California are not as significant and may be overcome by costs to carry out this method
of managing VG integration.
Page 13 of 13