2022 EC1-1 Copper Sheet Study
Introduction
The purpose of the 2022 EC1-1 Copper Sheet (“Copper Sheet”) study is to identify areas within the Western Interconnection that would benefit from transmission reinforcement in the 10-year study horizon, and to quantify how much additional transmission capacity may be needed to relieve congestion observed in the 2022 Common Case. The study is conducted by running the 2022 Common Case without any transmission constraints. This allowed energy to flow freely as it would on a ‘copper sheet’, thus producing a highly efficient economic dispatch since the model does not have transmission limits that could constrain the dispatch. Production cost savings observed in the Copper Sheet study do not justify the type of capacity reinforcement that would be needed to achieve some of the increased flows observed around the system.
Key Questions
Results from the Copper Sheet study are intended to address the following key questions.
- Where does energy want to flow when transmission constraints are relaxed using a ‘copper sheet’ analysis?
2. How much additional transmission capacity would be required to facilitate this flow of energy?
3. What proposed transmission projects would provide this amount of additional transfer capability?
- How does production cost and generation by state change when transmission constraints are relaxed?
Study Limitations
The Copper Sheet study was performed by removing all transmission line and path/interface[1] constraints within the 2022 Common Case. With all transmission constraints removed, PROMOD chose to not utilize the two existing DC transmission lines in the Western Interconnection. Ventyx/ABB, the software developer of PROMOD, confirmed that this result is common in a largely unconstrained study due to the extra constraints given for the DC ties in the model (e.g., ramp rates, dispatch penalties). If the AC branches are sufficient to serve the transmission system given the branch ratings, PROMOD IV will use just these branch types to serve load within the dispatch. This is in spite of a common recognition that DC lines often have operating properties that makes them more efficient than AC lines over long distances.
In this report, stakeholders will be reminded of the potential use of the unutilized DC lines that are in parallel with the AC system. The potential impact to the AC system at both ends of the DC lines is also absent from the model solution.
Study 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 – No change to 2022 Common Case loads
• Transmission System – All monitored[2] AC lines were set to “un-monitored” meaning that no AC lines would serve as a constraint in the simulation optimization. In addition to this, the following changes were made:
o Path/Interface limits increased to ± 99,999 MW
o Nomogram bounds reset to ± 99,999 MW
• The nomogram for the Intermountain Power Project (IPP) DC line relating path flow to generation output was retained due to the dedicated use of this line for transferring generation from western Utah to southern California.
o Hurdle rates remained unchanged as compared to the 2022 Common Case
• Generation – No change to 2022 Common Case generation
o The assumption in the 2022 Common Case that added 2,000 MW of new hydro generation in British Columbia is a key element of this case since transmission constraints often prevented this new generation from serving any load in the 2022 Common Case.
Study Results
The following study results are organized according to the key questions associated with this study case. Additional results of interest are also outlined.
Change in Energy Flow
With the transmission system ‘opened up’, there is an expectation that path flows will increase on the paths that were constrained in the 2022 Common Case. Any surplus generation that was not previously utilized due to transmission constraints should now be available to displace generation from more expensive resources.
Changes in energy transfers between the TEPPC subregions from the 2022 Common Case to the Copper Sheet study are provided in Figure 2, to illustrate how transmission flows changed around the Western Interconnection in response to the elimination of transmission constraints. A map of the TEPPC subregions is provided in Figure 1.
As expected, the plot in Figure 2 shows that several of the regional transfers increased in the Copper Sheet study as compared to the 2022 Common Case. Changes in regional transfers are reported in average megawatts, so a change of 100 average megawatts is equivalent to 876,000 MWh annually.
Energy transfers from northern California to southern California increased the most, likely as a result of surplus hydro generation now being able to flow unconstrained from Canada and the Northwest into California in order to displace some of the most expensive generation observed in the 2022 Common Case (typically California combined cycle generation).
Figure 2: Comparison of Regional Transfers (aMW)
The net annual flow for the most heavily utilized paths[3] (top 15) in the Copper Sheet study is compared to the flows along these paths in the 2022 Common Case in Figure 3. Absent the path limits, branch, and nomogram constraints, the net annual flows increased on several paths.
Figure 3: Comparison of Net Annual Flow
Changes in path utilization based on the TEPPC utilization metrics (U75, U90, and U99) and the 2022 Common Case limits for the most heavily utilized paths in the Copper Sheet study are shown in Figure 4. The utilization of several paths had increased by more than 30 percent as compared to the 2022 Common Case. Note that an increase in utilization of a small line (with a low MW rating) is not necessarily as significant as an increase in utilization of a large line (with a high MW rating). Furthermore, those paths that had a high increase in U99 are those paths that had a significant amount of flow exceed the path limit, which suggests that these paths could benefit the most by transmission expansion. Figure 5, based on the 2022 Common Case limits, shows the utilization of the paths from the Copper Sheet solution.
Figure 4: Change in Utilization[4]
Figure 5: EC1-1 Most Heavily Utilized Paths
The following path flow plots combine the hourly chronological flows with the reverse-sorted duration plots. The horizontal axis is hours – sequential for the chronological series and non-sequential for the duration series. The purple and red lines indicate the upper and lower limits that were applied to the path in the 2022 Common Case. Any hourly flow greater than the path limits represents additional transfer capacity that would be used if the transfer limit was increased. The numeric values referenced in the plot headings are the net annual flows on the paths for the Copper Sheet study.
The paths that had the largest increases in net annual flow were Path 3, Path 26 and Path 45.
Figure 6: Path 3 Flows for Copper Sheet study
Figure 6 shows that removing transmission constraints on Path 3 Northwest-British Columbia is only beneficial to flow in the north to south direction. As previously mentioned, this is because of a large 2,000 MW hydro resource assumed in the 2022 Common Case (in addition to the hydro resources already existing in BC). This highly economic energy flows on Path 3 to serve loads in the Northwest. Without transmission constraints, more of this energy can flow north to south.
Figure 7: Combined Path 65 and 66 Path Flows for Copper Sheet study
Paths 65 and 66 were combined in Figure 7, but PROMOD did not actually use path 65 (Pacific DC Intertie (PDCI)) due to the preference given to the use of AC lines over DC lines. It may be a valid assumption that one-third to one-half of the energy flowing on the California-Oregon Intertie (COI) would actually use the PDCI, and also bypass Paths 15 and 26. Because of the poor representation of DC line flow in this study, particularly PDCI, it is difficult to draw substantive conclusions related to Paths 15 and 26. Flows for Path 15 and Path 26 are presented in Figure 8 and Figure 9, respectively.
Figure 8: Path 15 Flows for Copper Sheet study (note that positive direction is South to North)
Figure 9: Path 26 Flows for Copper Sheet study
Path 45 flows greatly exceeded the north to south path limit in the Copper Sheet study, as shown in Figure 10. This is likely due to assumptions made about future resource development in Mexico (Comision de Federal Electricidad (CFE)).
Figure 10: Path 45 Flows for Copper Sheet study
Path 46 flow did not utilize the ability to have unlimited flow, as shown in Figure 11. Flow in the Copper Sheet case was only slightly more than what was observed in the 2022 Common Case, as apparent in the duration plots in Figure 12.
Figure 11: Path 46 Flows for Copper Sheet study
Figure 12: Duration Plot Comparison for Path 46
Equivalent Path Upgrades
The paths that experienced increased flows in the Copper Sheet study may be indicative of transfer paths that could be upgraded or expanded to allow for the flow of more economic generation, thus reducing the production cost of the Western Interconnection. Table 1 quantifies the extent that the paths were utilized in excess of their 2022 limits. The difference between the path limit and the maximum flow suggests how much additional capacity may be of benefit to the path and optimal economic generation dispatch.
Table 1: Extended Flows by Path
Path / Constrained Direction / EC1_1 Copper Sheet(+/-) / Common Case Limit (MW) / Max. Flow (MW) / Sum of Excess (GWh)
Interstate COI plus PDCI / + / 7,900 / 11,502 / 3,017
P01 Alberta-British Columbia / + / 700 / 4,466 / 3,905
P03 Northwest-British Columbia / - / 3,150 / 8,436 / 14,486
P08 Montana to Northwest / + / 2,200 / 2,867 / 2,128
P14 Idaho to Northwest / - / 2,250 / 3,959 / 881
P15 Midway-Los Banos / - / 3,265 / 9,217 / 5,567
P18 Montana-Idaho / + / 337 / 662 / 375
P22 Southwest of Four Corners / + / 2,325 / 3,190 / 1,798
P26 Northern-Southern California / + / 4,000 / 12,966 / 23,645
P29 Intermountain-Gonder 230 kV / + / 200 / 410 / 1,133
P31 TOT 2A / + / 690 / 1,615 / 2,520
P35 TOT 2C / + / 600 / 1,602 / 2,624
P36 TOT 3 / + / 1,680 / 2,508 / 459
P45 SDG&E-CFE / + / 408 / 1,939 / 4,310
P47 Southern New Mexico (NM1) / + / 1,048 / 1,996 / 2,885
P61 Lugo-Victorville 500 kV Line / + / 900 / 2,752 / 2,791
P66 COI / + / 4,800 / 11,502 / 14,843
P73 North of John Day / + / 8,400 / 10,930 / 1,936
P76 Alturas Project / + / 300 / 707 / 1,849
P78 TOT 2B1 / + / 600 / 1,244 / 1,012
One of the most apparent increases in transmission flow as a result of the relaxed transmission constraints is observed on the paths between British Columbia and southern California, suggesting that upgrades of those paths would be the most beneficial assuming the hydro generation expansions modeled in British Columbia in the 2022 Common Case are realized and would result in excess hydro generation being available for use in the Western Interconnection. The predominant flow on Path 15 actually reversed in the Copper Sheet study as the effect of additional economy energy from the Northwest exceeded the deliveries from the southern Pacific Gas & Electric (PG&E) resources, such as Diablo Canyon, to the PG&E load centers.
Changes in Generation and Production Cost
The overall change in generation by resource type in the Copper Sheet study as compared to the 2022 Common Case is shown in Figure 13. The savings in variable production cost observed as a result of removing the transmission constraints from the 2022 Common Case were $236 million. Most of the savings are a result of additional transmission capacity enabling displacement of more expensive generation by surplus hydro generation from British Columbia, and previously constrained coal-fired resources. Notably, these coal-fired resources are often located in areas that feature high penetrations of renewable resources that are ‘must-take’, such as wind and solar, and are dispatched before the coal in the generation stack.
Figure 13: Change in Annual Generation
The generation changes by state and province are provided in Figure 14, which shows more economic generation displacing combined cycle and combustion turbine generation in Arizona, California, Mexico (CFE), and Nevada. There is also an unexpected increase in Alberta combined cycle generation. This is likely due to assumptions made about the heat rates of the Alberta combined cycle fleet.
One of the key changes that does not show up in the chart is with regard to the 376,000 MWh (over 40 aMW) of hydro energy that was previously dumped (unable to serve load) in British Columbia in the 2022 Common Case due to transmission constraints between British Columbia and the northwest United States. In the Copper Sheet study, the transmission constraints were removed and most of this ‘stranded’ hydro energy was able to serve load in other areas. Figure 14 does not show an increase in British Columbia hydro generation because this resource is a ‘must-take’ resource in PROMOD, so the software saw no change in its generation. However, since this generation was no longer being dumped because of transmission constraints in the Copper Sheet study, decreases from generation in other states is visible, mainly combined cycle (CC).