The cost of transmission for new generation has become a more salient issue. The CAISO found that distributed generation (DG) had displaced $2.6 billion in transmission investment by 2018. The value of displacing transmission requirements can be determined from the utilities’ filings with FERC and the accounting for new power plant capacity. Using similar methodologies for calculating this cost in California and Kentucky, the incremental cost in both independent system operators (ISO) is $37 per megawatt-hour or 3.7 cents per kilowatt-hour in both areas. This added cost about doubles the cost of utility-scale renewables compared to distributed generation.
When solar rooftop displaces utility generation, particularly during peak load periods, it also displaces the associated transmission that interconnects the plant and transmits that power to the local grid. And because power plants compete with each other for space on the transmission grid, the reduction in bulk power generation opens up that grid to send power from other plants to other customers.
The incremental cost of new transmission is determined by the installation of new generation capacity as transmission delivers power to substations before it is then distributed to customers. This incremental cost represents the long-term value of displaced transmission. This amount should be used to calculate the net benefits for net energy metered (NEM) customers who avoid the need for additional transmission investment by providing local resources rather than remote bulk generation when setting rates for rooftop solar in the NEM tariff.
- In California, transmission investment additions were collected from the FERC Form 1 filings for 2017 to 2020 for PG&E, SCE and SDG&E. The Wholesale Base Total Revenue Requirements submitted to FERC were collected for the three utilities for the same period. The average fixed charge rate for the Wholesale Base Total Revenue Requirements was 12.1% over that year. That fixed charge rate is applied to the average of the transmission additions to determine the average incremental revenue requirements for new transmission for the period. The plant capacity installed in California for 2017 to 2020 is calculated from the California Energy Commission’s “Annual Generation – Plant Unit”. (This metric is conservative because (1) it includes the entire state while CAISO serves only 80% of the state’s load and the three utilities serve a subset of that, and (2) the list of “new” plants includes a number of repowered natural gas plants at sites with already existing transmission. A more refined analysis would find an even higher incremental transmission cost.)
Based on this analysis, the appropriate marginal transmission cost is $171.17 per kilowatt-year. Applying the average CAISO load factor of 52%, the marginal cost equals $37.54 per megawatt-hour.
- In Kentucky, Kentucky Power is owned by American Electric Power (AEP) which operates in the PJM ISO. PJM has a market in financial transmission rights (FTR) that values relieving the congestion on the grid in the short term. AEP files network service rates each year with PJM and FERC. The rate more than doubled over 2018 to 2021 at average annual increase of 26%.
Based on the addition of 22,907 megawatts of generation capacity in PJM over that period, the incremental cost of transmission was $196 per kilowatt-year or nearly four times the current AEP transmission rate. This equates to about $37 per megawatt-hour (or 3.7 cents per kilowatt-hour).
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Further confirmation that the marginal cost of transmission in California is much higher than a penny per kilowatt hour. PG&E’s retail transmission rate component went from 1.469 cents per kWh in 2013 to 4.787 cents in 2022. (SDG&E’s is even higher.) By definition, the marginal cost must be higher than 4.8 cents (and likely much higher) to increase that much.
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CASIO noted this recently too-
…..”CAISO’s 20-year transmission plan calls for $35 billion in spending while the grid operator’s high-voltage access charge has grown to $16.39/MWh from $3.83/MWh, Kito said.”….
FERC urged to set interregional transfer capacity requirements to boost reliability, lower costs | Utility Dive
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The costs and delays in transmission interconnection for renewables are inhibiting renewable energy development. Network upgrades, which are often overlooked in estimating transmission marginal costs, are 50% to 100% of renewable interconnection costs according to LBNL.
https://www.canarymedia.com/articles/policy-regulation/here-are-ways-to-connect-clean-energy-projects-to-the-grid-more-quickly
https://www.greentechmedia.com/articles/read/report-renewables-are-suffering-from-broken-u.s-transmission-policy
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I see the problem. You were referring to Table 9-2 in the 2021 ERRA, but the link you included in your previous comment was to the 2022 ERRA testimony. IMO, the ERRA testimony is irrelevant — that’s just the energy value of the utilities’ entire RPS portfolios plus an administratively determined REC adder. If you want to know what RPS contracts have actually cost by the year they were approved, you need to look at the Padilla report. As you can see in Figure 3, wind/solar PPAs haven’t cost 5 c/kWh since 2015. As I’m sure you know, the IOUs have signed virtually no contracts for large projects for the past several years because they are so oversupplied with RPS energy. In Table C-1 you can see that the handful of contracts they executed in 2020 were programmatic obligations. Since CCAs were the LSEs executing contracts for large-scale solar and wind, you need to look at Table C-2, which, as I noted above, shows that solar PV contracts executed in 2020 cost 2.7 c/kWh on average. The only solar contracts that cost more than 5 c/kWh were for projects less than 3 MW.
I’m working on transmission numbers, but it’s difficult to disaggregate total Tx spend by resource type.
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Sorry about the link problem.
The REC is determined by taking the value of the RPS PPAs signed by IOUs in the previous year and then the Platts energy forward price is subtracted to arrive at the “green” adder which is interpreted as equivalent to the REC. I haven’t seen in anything in the information I have to contradict this value in any significant way.
Unlike the Padilla Report, the ERRA RPS price must meet regulatory evidence requirements and these have been approved by the CPUC in at least three ERRA proceedings. Again, I don’t know how the CPUC is seeing CCA transaction data because it doesn’t have jurisdiction or access to those entities transactions. There might be anecdotal information, but the low-cost agreements are the ones trumpeted in the headlines. (Until I see the Padilla Report database on PPAs, I won’t concede on this point.)
Because transmission is a network, it’s not possible to disaggregate the costs by technology. You have to include all of the downstream investment that facilitates the conveyance of power from the first substation interconnection to the rest of the substations. There’s no possible way to do that except through an arbitrary allocation method. That’s why I calculated the incremental cost on an aggregate basis.
One further point on this: both energy and peak loads have been flat since 2006. In this situation, if the generation fleet had remained static since no additions have been required for load growth, the only remaining factor that can cause transmission investment is a change in the generation fleet. That means regardless of the supposed explanation for transmission costs, it all rolls back to changes in generation. Since 2010, almost all of that has come from grid-scale renewables.
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An additional point–the “green adder” that I’ve referenced is being used to calculate the marginal cost of renewables in both the PG&E and SCE GRCs now, not the values from the Padilla Report.
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“The 2020 RPS procurement cost figures in this report were compiled from all CPUC jurisdictional load serving entities (LSEs): Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E); 3 SMJUs; 23 CCAs; and 13 ESPs.” Padilla Report, p. 3.
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Well, there’s certainly a discrepancy in data at the CPUC… I’ve seen other evidence that indicates that it’s closer to the higher value.
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Richard, see also https://emp.lbl.gov/utility-scale-solar/
“Nationwide average levelized power purchase agreement (PPA) prices fell to $24/MWh in 2019, down 17% from 2018 and more than 80% since 2010. Thirty-nine projects (totaling 4.2 GWAC) in our PPA price sample include battery storage (totaling 2.3 GWAC and 9.5 GWh). In the “lower 48” states, a number of these recent PV+battery PPAs have been inked in the mid-$20/MWh range (levelized in 2019 dollars).”
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Again, the CPUC data differs as well other information that I’ve seen for California.
Regardless, we’re talking about only a 2 cents / kWh difference on what looks like a total incremental cost of 10 cents/kWh or more in contrast to the claim that it is only 5 cents.
In addition, we are not asking the grid scale generators to pay the non bypassable charges that the NEM 3.0 proposals are demanding of rooftop solar. That’s particularly ironic given that solar PPAs are causing 2 to 3 cents /kWh of those charges.
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Later this week our 15th True Up Bill from PG&E will be arriving in our mailbox. . It be interesting to see the details of our cost allocations as our costs for an average kWh have gone up 22% this year.
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Back in 2006 PG&E filled our substation from their recently sold small hydro facility on the American River These days our juice comes from the Camino substation and I am unsure if the EID small hydro output flows into our substation or not. In any case over the last 15 years PG&E has invested a lot of money to optimize voltage in my service area.
By chance do you how this value is derived- “Applying the average CAISO load factor of 52%”?
Congestion issues have been going up over the last few years. The location of a new RE project will likely run into different congestion patterns. Does using average load factors vs project specific ones change the outcome of the analysis?
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I calculated the CAISO load factor by dividing the load within the CAISO service area (80% of statewide load as reported by the CEC) by the recorded annual peak.
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Since developers are executing large-scale solar PPAs at about 2.5 c/kWh, does that mean distributed solar should be compensated no more than 6.2 c/kWh?
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First, transmission costs are only one of the avoided cost elements. And as I point out in my testimony, my estimate of the incremental transmission cost is conservative, so it is actually higher. Further, I calculated that incremental transmission cost based on the average load factor of the entire CAISO system. If we instead use the average capacity factor of a grid scale solar project the transmission cost for that technology essentially doubles to $75/MWH. (https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_b). Now we’re up to 10 c/kWh from just those two elements. And if we add 8% line losses we’re approaching 11 c/kWh.
Another is avoided distribution system costs, which isn’t addressed here. There are also reliability and resilience benefits from having generation available at the local circuit level. (That the IOUs haven’t reconfigured their systems to take advantage of this, and the AMI infrastructure that was supposed to deliver us so many yet unrealized benefits, isn’t the fault of the customers who invested in rooftop solar.)
Finally, that some PPAs are signed at 2.5 c/kWh, the average reported by the IOUs in the Energy Division’s survey are around 5.5 c/kWh. Using data rather than anecdotes, we’re now to 14 c/kWh before we get into other values supplied by DERs. That’s pretty close to the average retail rate just before the IOUs went on a crazy spending binge that has driven those rates up. Where was the CPUC when that was happening?
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Richard, in order to calculate the marginal cost of transmission due to large-scale solar, we need to examine the data on recent annual additions of solar capacity and the cost of incremental transmission built specifically to deliver the output from large-scale solar. Are there data available that differentiate the network upgrade costs by resource? I have a hard time believing the average incremental transmission cost of large-scale solar is 7.5 c/kWh.
Where are you getting a recent large-scale solar cost of 5.5c/kWh? If you look at Figure 3 in the 2021 Padilla Report, the average prices of wind and solar contracts signed in 2019 and 2020 were about 3 c/kWh or less. If you look at the Table C-2, the CCAs’ average solar PV price for contracts signed in 2020 was 2.7 c/kWh.
Click to access 2021-padilla-report_final.pdf
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First, Bill Powers made a recent presentation on the incremental cost for transmission projects specifically for renewables. The Sunrise Project cost $90/MWH by his calculation. That’s higher than what the amount calculated here. The other important fact is that almost all of the new transmission has been built to serve new renewables, which are mostly solar. The system interconnections to support added renewables can’t always be directly attributed to a single project, but is the collective responsibility of all of the projects.
Second, my calculation was conservative. I used the entire state capacity even though the CAISO is only 80% of the state load. That adjustment raises the average cost to $47/MWH. In addition, I included the capacity repowered at the coastal plants which was about 25% of the new capacity. Making that adjustment increases the average incremental cost to $62/MWH. If we adjust for the solar capacity factor, then the incremental transmission cost rises to over $120/MWH. This may be hard to believe because the utilities have never reported the true incremental costs. They have always reported just the overall average system costs by year. This is the first effort to make a true incremental cost calculation. If one looks at how fast the CAISO TAC rate has increased over the last decade, that the marginal cost is so high is much less of a surprise. I will further that the economics of central station power plants have historically been oversold as many of these costs are socialized to other functions or hidden by using average rather than marginal costs.
As for the average cost of RPS contracts as reported by the Energy Division, the most recent public reference value is $51.50/MWH as shown in Table 9-2 of PG&E’s November Update for its 2021 ERRA: https://pgera.azurewebsites.net/Regulation/ValidateDocAccess?docID=656742 (The 2022 ERRA value is confidential, but the REC adder doesn’t look like it has changed much.) (I have no idea what the PUC report shows a lower value. The CPUC shouldn’t have access to the average prices for CCA contracts.)
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For the incremental Tx cost, it still doesn’t sound to me like your limiting costs to those that are triggered by new solar. Tehachapi alone was $3 billion, and that was built to access wind resources. The CPUC’s “Utility Costs…” report shows that much of the Tx cost increase since 2016 has been due to higher O&M expenses and an increase in “self-approved” projects that do not increase capacity.
Table 9-2 in the ERRA does not show the information you’re describing. Maybe you meant to refer to a different table? At any rate, the more relevant information is the cost of recent solar contracts, which is found in the Padilla report, besides numerous other articles in the trade press about utilities across WECC signing solar PPA (or even solar + storage PPAs) for less then 3 c/kWh.
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As I said earlier, the incremental costs triggered by solar extend beyond just the specific project costs. The O&M capital costs are netted out through the depreciation adjustment. My calculation excludes expensed O&M and focuses solely on net capital investments. And as I said Bill Powers calculated an incremental cost of $90/MWH for Sunrise. If you have an alternative calculation, you’re more than welcome to prepare and present it.
Table 9-2 shows the “green” energy market price benchmark. That is calculated by the Energy Division based on the average cost of utilities’ new RPS contracts. That includes the cost of new solar contracts which are the dominant technology. This value has been stable over the last several years. There are headline deals that are less than this, and others that are higher which don’t make the press. It is the high cost PPAs that rooftop solar will displace, not the low cost ones, so the 3 cent/kWh deals will still be signed.
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