2022 PC4 High EE, High DSM, and High DG Study Report

PC4 High EE-DG-DR

(2022 PC4High EE/DR/DGSeptember 19, 2013)

Introduction

The purpose of the 2022 PC4 High EE/DR/DG (High EE/DR/DG) study is to examine the impact of aggressive EE, DR, and DG policies on transmission and capacity needs relative to the 2022 Common Case. Lawrence Berkley National Laboratory (LBNL) and Energy + Environmental Economics (E3), in consultation with the Demand-side Management (DSM) Work Group of the State and Provincial Steering Committee (SPSC), were responsible for developing the EE, DR, and DG assumptions that were used to create the High EE/DR/DG study.

Key Questions

Results from the High EE/DR/DG study are intended to address the following key questions.

1. How much do planning reserve margins increase due to the deployment of aggressive EE, DR, and DG programs and policies?

2. Does the need for new transmission identified in the 2022 Common Case change as a result of the additional EE, DR, and DG?

3. How do congestion patterns change with the increased EE, DR, and DG?

4. How do production costs change in response to the additional EE, DR, and DG?

Study Limitations

Due to time and modeling limitations, it was decided that LBNL and the DSM Work Group of the SPSC would investigate separately how costs associated with the increased deployment of EE, DR, and DG may be estimated. For the purposes of this TEPPC study, then, the benefits of these programs/policies are quantified only using the change in production cost relative to the 2022 Common Case. This should be noted when reviewing the production cost savings reported from this study as those savings are only achievable if one assumes that capital expenditures have been made in EE, DR, and DG to reduce the loads and supply energy at the levels assumed in the study.

Further, it should be noted that the ultimate goal of the production cost model (PCM) is to reach the least cost solution for each hour of the study, and it takes advantage of imports and exports as a means to find the most economical resources throughout the Western Interconnection. In a scenario with low loads and an oversupply of generation, such as this one, the study results should be reviewed with this understanding of the PCM in mind as the results may include some unexpected yet explainable system changes. In particular, transmission flows resulting from the reduction in loads and increase in DR and DG resources are a function of the assumption that no conventional generation relative to the 2022 Common Case was removed in this study. This resulted in a significant increase in planning reserve margins across the Western Interconnection as discussed later in the report. These high reserve margins would likely be a temporary phenomenon as new generation build would slow down in concert with slower demand growth which would have an impact on the transmission utilizations reported in this study.

Finally, a reliability assessment of the level of distributed resources modeled in this study was not completed. As such, additional studies would be needed to assess the need for flexible generation to reliably integrate the levels of distributed solar photovoltaic (PV) modeled in this study. The extent to which distributed resources may be able to meet specific local area reliability (and flexibility) needs was also not assessed.

Input Assumptions

All 2022 study cases are constructed from the 2022 Common Case. As such, a number of the assumptions used to construct the 2022 Common Case are carried through to each subsequent study case. The following assumptions are those specific to this study case, and may be in addition to or an alternative of those assumptions used in the 2022 Common Case.

Loads – Loads were decreased to reflect the assumption that “all cost-effective EE potential” is achieved throughout the West. Load adjustments, as calculated by LBNL and provided to TEPPC, were made to both the monthly peak demand and monthly energy profiles for each TEPPC load area as documented in Figure 1.[footnoteRef:1] As a result of these adjustments, the coincident peak demand for WECC was decreased by 15,347 MW (8.9 percent) from 173,161 MW in the 2022 Common Case to 157,814 MW in the High EE/DR/DG study. The total WECC annual energy was decreased by 92,746 GWh (9.3 percent). [1: Add link to LBNL’s technical report when made available.]

Figure 1: High EE/DR/DG Peak and Energy Load Adjustments

Transmission System – No change to 2022 Common Case transmission

Generation – Changes to DG, renewable portfolio standard (RPS) resources, and DR assumptions are as follows:

· The DG resources modeled in this case are a combination of distributed PV and distributed combined heat and power (CHP) resources. Incremental DG already modeled in the 2022 Common Case was increased in order to reach the ‘interconnection potential’ of distributed PV and 33 percent of the ‘technical potential’ of distributed CHP resources as estimated by E3,[footnoteRef:2] and as shown below in Figure 2 and Figure 3. [2: The report detailing E3’s work to estimate the ‘interconnection potential’ of distributed PV and the ‘technical potential’ of distributed CHP resources can be found here: http://www.westgov.org/sptsc/workgroups/DRwg/highDR/12-19-12WECCDGmr.pdf ]

Figure 2: Incremental DG-PV in High EE/DR/DG Study

Figure 3: Incremental DG – CHP in PC4 High EE/DR/DG

Three categories of distributed PV were modeled, including: residential rooftop, commercial rooftop, and ground-mounted PV. National Renewable Energy Laboratory (NREL) hourly solar production profiles for fixed tilt (20 degree) PV was used for the residential rooftop distributed PV resources and NREL single-axis tracking profiles were used for the ground-mounted distributed PV. E3 developed the hourly solar production profiles for the commercial rooftop distributed PV resources using PV watts and provided them to TEPPC for use in this study.

The distributed CHP resources added to the High EE/DR/DG study were modeled as flat output resources with a heat rate of 6,000 Btu/kWh and an average capacity factor of 85 percent.

Half of the incremental DG (both PV and CHP) modeled in this case was assumed to be located behind-the-meter, while the other half was assumed to be wholesale resources. The capacities of the DG resources added to the High EE/DR/DG study were scaled up to account for avoided transmission and distribution system losses. A scaling factor of 6 percent was used for all areas except for California, where a scaling factor of 7 percent was used. The DG additions were identified by TEPPC load area and the resources added to the case were distributed proportionally (based on load) among the largest associated area load busses. A summary of the incremental DG resources modeled in the High EE/DR/DG case is found in Table 1.

Table 1: Incremental DG Modeled in the High EE/DR/DG Study Case[footnoteRef:3] [3: Resource capacities have been scaled up for avoided transmission and distribution system losses]

DG Resource

Incremental DG in 2022 Common Case

Incremental DG Added to High EE/DR/DG

Total Incremental DG Modeled

Distributed PV

6,668 MW

18,513 MW

25,181 MW

CHP

2,881 MW

7,012 MW

9,893 MW

RPS requirements were recalculated by state based on the lower loads resulting from the increased EE and increased behind-the-meter DG. Resources being used to meet the RPS requirements in the 2022 Common Case classified as planned or future were removed as necessary to meet the lower RPS requirements in this case and to make room for the distributed PV resources which could be used to meet RPS requirements. However, in some states, conventional renewable resources in excess of the RPS requirements remained because they were classified as either existing or under-construction. This resulted in an over-build of RPS resources in three states as detailed in Table 2.

Table 2: RPS Requirements versus RPS Energy in High EE/DR/DG Case

State

Adjusted RPS Requirement (GWh)

RPS Energy in Dataset (GWh)

% Over Requirement

Arizona

5,655

6,689

18%

Nevada

4,348

8,912

105%

Utah

4,754

4,888

3%

DR was increased relative to the 2022 Common Case based on estimates of demand response potential developed by LBNL and the Brattle Group by updating the analysis and model used for a 2009 Federal Energy Regulatory Commission study on national DR potential, as shown in Figure 4 and Figure 5.[footnoteRef:4] [4: A summary of the demand response resource modeling assumptions developed by LBNL for use in the High EE/DR/DG study case can be found here: http://www.westgov.org/sptsc/workgroups/DRwg/highDR/12-19-12WECCDRma.pdf ]

Figure 4: Interruptible DR Adjustments (PC1 Common Case to PC4 High EE/DR/DG)

Figure 5: Incremental Economic DR in PC4 High EE/DR/DG

Study Results

The following study results are organized according to the Key Questions associated with this study. Additional results of interest are also outlined.

Planning Reserve Margins

As part of the development of the 2022 Common Case the Planning Reserve Margins (PRM) for each of the TEPPC subregions was estimated and the associated sub-region’s generation was adjusted as necessary to at least attain the PRM developed by WECC’s Loads and Resources Subcommittee (LRS) for the 2011 Power Supply Assessment. A comparison of the estimated PRM in the High EE/DR/DG study versus the 2022 Common Case is provided in Figure 6 for summer conditions and in Figure 7 for winter conditions. The load reductions and other adjustments associated with the High EE/DR/DG assumptions have a direct impact on the RPS requirements and PRM results. The focus of this study was primarily on the transmission impacts under the assumed conditions.

Figure 6: Planning Reserve Margin - Summer

Figure 7: Planning Reserve Margin - Winter

As anticipated, the PRM increased in each of the TEPPC subregions as a result of the decreased loads and despite the removal of some RPS resources (due to reduced RPS requirements as a result of lower loads).

The estimated PRM would be less if conventional resources were removed from the High EE/DR/DG study in response to the reductions in load reflected in the case, but the conventional generation portfolio assumed in the High EE/DR/DG study was intentionally left at essentially the same levels as in the 2022 Common Case. As previously stated, RPS resources were adjusted downward to reflect the new RPS requirements based on the lower loads modeled in the case. The conventional fleet was not altered because the primary purpose of the case was to isolate the effect of the changes made to the EE, DG, and DR assumptions. Moreover, all of the conventional generators in the 2022 Common Case were either existing, under-construction, or planned (as defined by LRS). As such, TEPPC could not justify removing any of these generators from the study assumptions.

Impact on Need for New Transmission

As described in the 2022 Common Case study report, TEPPC uses a utilization screening to identify highly utilized or potentially congested paths in the TEPPC study cases. One metric used to identify potentially congested paths is the U99 metric which provides a measure of how often (i.e., number of hours) the path flows exceed 99 percent of the path limits. Paths for which flow exceeds 99 percent of the path limit for at least 5 percent of the year are flagged as highly utilized or potentially congested. Those paths that were flagged by the U99 utilization screening in either the 2022 Common Case or the High EE/DR/DG study are identified in Figure 8.

Figure 8: WECC Paths Passing U99 Utilization Screening in 2022 Common Case or High EE/DR/DG

Eleven paths were flagged by the U99 utilization screening in the 2022 Common Case. Of those eleven paths, eight also passed the utilization screening in the High EE/DR/DG study. Montana-to-Northwest (Path 8), Alberta-British Columbia (Path 1), and Inyo-Control 115-kV Tie (Path 60), however, did not pass the utilization screening in both cases, and as such, to the extent the U99 metric indicates potential need for additional transmission capacity along a given path, the need for additional capacity along these three paths is no longer indicated in the High EE/DR/DG study. In contrast, five paths passed the U99 utilization screening in the High EE/DR/DG study and not the 2022 Common Case, indicating that these paths might benefit from additional transmission capacity under the deployment of aggressive EE, DR, and DG policies and given the high level of generation reserves modeled in this study. These paths include COI (Path 66), PDCI (Path 65), TOT 2B2 (Path 79), Idaho-Sierra (Path 16) and the combined interface of the COI and PDCI lines. Changes in path utilization between the 2022 Common Case and the High EE/DR/DG study are described in further detail below.

Most Heavily Utilized Paths

The utilization increased for several paths under the High EE/DR/DG study assumptions, largely due to the increased availability of low cost energy as compared to the 2022 Common Case. This result is consistent with results observed in previous TEPPC studies involving a high EE/DG scenario, but it is also counterintuitive that increasing the deployment of EE and DG would increase the utilization of the transmission system. As stated in the Study Limitations, the goal of the PCM is to reach the least cost solution for each hour of the study, and it takes advantage of imports and exports as a means to find the most economical resources throughout the Western Interconnection. When loads are reduced in areas served by the lowest-cost generation available in the interconnection, this energy can now be used to displace higher-cost resources elsewhere, which increases the utilization of the transmission system. Figure 9 is a plot of the most heavily utilized paths for the High EE/DR/DG study sorted by the U90 metric.

Figure 9: Most Heavily Utilized Paths

Based on the U90 metric Path 66 COI is the most heavily utilized path in the High EE/DR/DG study, and based on the U99 metric this path is congested for 30 percent of the year as is further illustrated in Figure 10. The increased flow along this path is likely the result of surplus hydro and coal generation in the Northwest and Canada due to decreased loads and increased DG resources in these areas. As observed in previous TEPPC studies, gas-fired resources in California are among the most expensive in the interconnection and when low-cost generation is freed up in other parts of the interconnection, to the extent it is cost effective, it makes its way via the transmission system to serve California loads.

Figure 10: Duration Plot Comparison for Path 66

Congestion Pattern Changes

As mentioned above, the reductions in load as a result of the increased EE increased the amount of economical generation available for export from the Northwest and Desert Southwest. The changes shown in Figure 11 reflect the increase in the percent of hours that the path utilizations were above the U75, U90, and U99 metrics in the High EE/DR/DG study as compared to the 2022 Common Case.

Figure 11: Change in Utilization of Most Heavily Utilized Paths

The results show large increases in utilization on the paths between the Northwest and California. For example, Figure 10 in the previous section showed a substantial increase in the flow on the Path 66. This is also reflected in the comparison of the combined Paths 65/66 shown in Figure 12.

Figure 12: Duration Plots for Combined Paths 65 and 66

Path 29 has a relatively low capacity as compared to other WECC paths but it experienced a large utilization change in response to the High EE/DR/DG study assumptions, as shown in Figure 13. This path connects central Utah and northern Nevada and historically has not had significant flows except when the Intermountain Power Project DC line (Path 27) is unavailable. The increased utilization of this path in the High EE/DR/DG study may be in response to the displacement of some gas-fired generation in the Reno area and may also be related to the increased usage of Path 27.

Figure 13: Duration Plot Comparison for Path 29

The utilization of a few paths did decrease as a result of the increased EE/DR/DG. Most notably, Path 26 between northern and southern California had a lower utilization (see Figure 14) in the High EE/DR/DG study as compared to the 2022 Common Case.

Figure 14: Duration Plot Comparison for Path 26

Reduced flow on Path 26 is likely due to the increase in imports into southern California from both the Northwest and the Southwest, which reduced the need for energy to be transferred from northern California into southern California. This result is further illustrated in Figure 15 that compares the change in region-to-region transfers of energy between the 2022 Common Case and the High EE/DR/DG study.

Figure 15: Change in Region-to-Region Transfers - 2022 Common Case to High EE/DR/DG

One argument for pursuing high levels of EE, DR, and DG, such as modeled in this study, is that, by reducing loads, these activities reduce RPS requirements, and thereby reduce the need to build transmission to access remote renewables. However, because of the preference toward use of in-state resources to meet RPS requirements reflected in the RPS resource portfolios built into the 2022 Common Case, it is difficult to gauge the impact aggressive deployment of EE, DR, and DG have on the need for long distance transmission in the TEPPC studies. Investigating the impact of high EE, DR, and DG on the need for long distance transmission is further complicated due to the high reserve margins observed in this study, which actually suggest a need for additional long distance transmission capacity to take advantage of surplus remote low-cost resources. Still, it can be noted that while most RPS resources removed from this study relative to the 2022 Common Case to account for lower RPS requirement due to decreased loads were in-state RPS resources, approximately 1,900 MW of the CA RPS resources removed were located outside of the state. Removing these resources from the model would have an impact on the utilization of the transmission system, but it would be difficult to quantify this impact using the existing study results and would require additional, more detailed studies.

Production Cost

The variable production cost in the High EE/DR/DG study decreased by 19.9 percent ($2.9 billion) compared to the 2022 Common Case. Most of the savings are attributable to the decrease in total generation due to the direct load reductions (-92,746 GWh), reflecting the deployment of aggressive EE programs and policies described earlier. Several areas were able to meet their load and reserve requirements using more economic resources, including imports from other areas.

The Northwest and Basin subregions experienced slightly increased production costs, as demonstrated in Figure 16. Correspondingly, these subregions experienced the smallest overall decrease in total generation as compared to all the other TEPPC subregions. This, together with the fact that a higher proportion of incremental CHP generation was added in these subregions which displaced some coal-fired, nuclear, and biomass resources, explains the slight increase in variable production cost relative to the 2022 Common Case.

Figure 16: Variable Production Cost

The annual generation changes by subregion and type are provided in Figure 17.

Figure 17: Energy Difference by Subregion

Other Observations

The area load requirements were decreased by the High EE/DR/DG study program assumptions listed in Table 3. The load reductions are a combination of direct load reductions due to the increased deployment of EE, DR programs and policies, and also the increased deployment of behind-the-meter distributed generation. Within the PCM the only programs that were implemented on the load side were the EE and the non-interruptible DR programs. The interruptible DR programs and behind-the-meter DG were implemented on the generation side where they effectively displaced other generation sources.

Table 3: Load Adjustment Programs

Load Program

Load Adjustment(GWh)

Energy Efficiency (EE)

-92,746

Combined Heat & Power (CHP) – Behind the Meter

-28,349

Demand Response (DR)

-397

Distributed Photovoltaic (PV) – Behind the Meter

-13,401

Total Adjustment from all programs

-134,893

The generation surplus in British Columbia (BC) is largely based on an assumption of several new generators being added to the BC Hydro (BCH) portfolio during the next 10 years. There was an understanding that the purpose of the generation build-out is to enable BCH to be self-sufficient by 2020. A net annual export of 24,261 GWh as depicted in Figure 18 greatly exceeds their goals and may not be realistic under the High EE/DR/DG study load assumptions. There is a very good chance that the generation build-out assumed in the 2022 Common Case would be scaled back or delayed in response to a reduction in load assumptions as modeled in the High EE/DR/DG study.

Figure 18: Transfers from Canada to NWUS

Study Summary

The High EE/DR/DG study assumptions reflecting the aggressive deployment of EE, DG, and DR programs and policies highlighted some of the benefits from these proactive programs. The most significant assumption change made for the High EE/DR/DG study was the reduction of area loads as a result of additional EE assumptions, as depicted in Figure 19 .

Figure 19: Change in Annual Energy from 2022 Common Case

The reduced loads, together with the increase in DR and both wholesale and behind-the-meter DG, produced some substantial changes to the PCM results as compared to the 2022 Common Case, including a $2.9 billion reduction in production cost and a reduction in CO2 emissions of 49 million metric tons. In many cases, however, the expectation for a decreased utilization of transmission was not realized as more economic generation became available for export, especially in British Columbia, Oregon and Washington. While this may be a counterintuitive result, it is expected in a low-load high-reserve margin PCM scenario where reducing loads essentially “frees up” economic generation to serve loads elsewhere, thereby increasing the utilization of the transmission system.

Total WECC variable production cost and CO2 emissions are reduced as a result of the aggressive deployment of energy efficiency (EE), demand response (DR), and distributed generation (DG) programs and policies, primarily in response to the impact these programs and policies have on reducing the Western Interconnection’s load requirements. These savings are disproportionately large as compared to the energy savings resulting from the reduced load requirements. Specifically, total variable production cost and CO2 emissions were reduced 20 percent and 14 percent, respectively, relative to the 2022 Common Case as compared to a 9 percent decrease in load requirements associated with the deployment of aggressive EE. It should be noted that no estimate of the capital expenditures needed to achieve the level of EE, DR, and DG assumed in this study were estimated.

The WECC paths that are the most impacted by the freeing up of low-cost resources continue to be those paths connecting the Northwest with California, including the COI and PDCI. This observation is in large part a function of the modeling decision to not remove any existing, under construction or planned conventional resources from the system as compared to the 2022 Common Case that resulted in high reserve margins across the Western Interconnection. Over a longer planning horizon, if the trend in the levels of EE, DR, and DG modeled in this case continued, it is likely that reserve margins would come down, which would in turn limit the degree of transmission utilization observed in this scenario.

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0500010000150002000025000Energy -aMWPeak -MW

Peak and Energy Load AdjustmentsPC4 vs. PC1

PC1 Energy (aMW)PC4 Energy (aMW)PC1 Peak (MW)PC4 Peak (MW)

-2,000 4,000 6,000 8,000 10,000 12,000 14,000 ABAZBCCACOIDMTNMNVORTXUTWAWY

Incremental Distributed PV in 2022 PC4 (MW)

Added DG Scaled Up for Avoided T&D Losses

Incremental PV in the Common CaseIncremental PV to be Added in the High DG Case

-500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 ABAZBCCACOIDMTNMNVORTXUTWAWY

Incremental Distributed CHP in 2022 PC4 (MW)

Added DG Scaled Up for Avoided T&D Losses

Incremental CHP in the Common CaseIncremental CHP to be Added in the High DG Case

-100 200 300 400 500 600 700

Interruptible DR Capacity (MW)

PC4 Capacity (MW)PC1 Capacity (MW)

-500 1,000 1,500 2,000 2,500

Ecnomic DR Capacity (MW)

PC4 Capacity (MW)PC1 Capacity (MW)

0%10%20%30%40%50%60%70%80%90%100%

Planning Reserve Margin Comparison -Summer

PC1PC4Goal

0%20%40%60%80%100%

Planning Reserve Margin Comparison -Winter

PC1PC4Goal

0%5%10%15%20%25%30%35%40%45%50% U99

WECC Paths with U99 Greater Than 5% in the 2022 Common Case or High EE/DSM/DG

U99 2022 Common CaseU99 High EE/DSM/DG

0%10%20%30%40%50%60%70%80%90%

Most Heavily Utilized Paths -PC4 High EE-DG-DR

U75U90U99

-5000-4000-3000-2000-10000100020003000400050006000

Megawatts

P66 COI Path Duration Plots

20082010PC1_CCPC4_EE_DG_DR

N->S

-20%-10%0%10%20%30%40%50%60%P66 COIP03 Northwest-British ColumbiaInterstate WA-BC WestP29 Intermountain-Gonder 230 kVP45 SDG&E-CFEP27 Intermountain Power Project DC LineInterstate WA-BC EastP79 TOT 2B2P47 Southern New Mexico (NM1)P26 Northern-Southern CaliforniaP25 PacifiCorp/PG&E 115 kV InterconnectionInterstate COI plus PDCIP16 Idaho-SierraP65 Pacific DC Intertie (PDCI)Intrastate CA PDCI South

Change in Utilization -PC1 to PC4

U75U90U99

-8000-6000-4000-20000200040006000800010000

Megawatts

Interstate COI plus PDCI Path Duration Plots

20082010PC1_CCPC4_EE_DG_DR

N->S

-250-200-150-100-50050100150200250

Megawatts

P29 Intermountain-Gonder 230 kV Path Duration Plots

2010PC1_CCPC4_EE_DG_DR

E->W

-5000-4000-3000-2000-1000010002000300040005000

Megawatts

P26 Northern-Southern California Path Duration Plots

20062010PC1_CCPC4_EE_DG_DR

N->S

(1000)010002000300040005000

AZNMNV

To Ca_S

Basin To

AZNMNV

Basin To

Ca_N

Basin To

Ca_S

Ca_N To

Ca_S

Canada To

NWUS

NWUS To

Basin

NWUS To

Ca_N

NWUS To

Ca_S

RMPA To

AZNMNV

RMPA To

Basin

Average Megawatts

Transfers between Sub -Regions (aMW)

2022 Common CaseHigh EE/DSM/DG

0 1,000 2,000 3,000 4,000 5,000 6,000 CANADANorthwestBASINRMPPCaliforniaAZNMNV

Variable Production Cost Comparison (M$)

2022 PC1 Common Case2022 PC4 High EE-DG-DR

(100,000)(80,000)(60,000)(40,000)(20,000)0 20,000 40,000 60,000 CANADANorthwestBASINRMPPCaliforniaAZNMNVWECCGWh

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC4 High EE-DG-DR

Steam -CoalSteam -OtherNuclearCombined CycleCombustion TurbineCogenerationBiomass RPSGeothermalSolarWindTotal

-1000-5000500100015002000250030003500400011673334996658319971163132914951661182719932159232524912657282329893155332134873653381939854151431744834649481549815147531354795645581159776143630964756641680769737139730574717637780379698135830184678633

Canada To NWUS -PC4

MW

-21,694-4,232-1,951-6,797-6,9320-856-412-333-323-957-399-1,912-564-4,910-326-740-4,274-1,159-2,912-823-1,170-1,814-489-1,742-1,751-2,043-1,398-416-1,227-1,516-5,909-1,586-230-733-1,196-5,528-1,454-38

-6,000-5,000-4,000-3,000-2,000-1,0000

AESOAPSAVABCHBPACFECHPDDOPDEPEFAR EASTGCPDIIDLDWPMAGIC VNEVPNWMTPACE_IDPACE_UTPACE_WYPACWPG&E_BAYPG&E_VLYPGNPNMPSCPSESCESCLSDGESMUDSPPSRPTEPTIDCTPWRTREAS VWACMWALCWAUW

Change in Annual Energy by Area (GWh)

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