Source: Utility Dive
California’s 44 electricity providers are updating their formal plans to meet the state’s new 60% renewables by 2030 mandate and its 100% clean energy by 2045 goal.
Investor-owned utility (IOU) regulatory filings say they have adequate renewables to meet the 2030 requirement and will begin procuring again after that. Customer choice aggregator (CCA) filings say they will procure adequate renewables to meet the 2030 mandate, though they do not specify how or when. And electric service providers (ESPs) say they don’t do long-term procurements.
The sum of the new renewables procurements from California’s 44 load serving entities (LSEs) do not add up to what will be needed to meet the ambitious Senate Bill 100 mandate and goal. Yet their filings reflect confidence that the state will meet its demanding ambitions and the LSEs will meet their obligations. Regulators and policymakers are not so sure.
Thanks to the IOUs’ existing long-term renewables contracts, the state is on track to meet its 2030 goal, CPUC Energy Division Director Edward Randolph recently told Utility Dive. But it is “premature for the CPUC to speculate” on the CCAs meeting 2020 and 2030 targets.
A few CCA long-term renewables procurements, a tiny portion of the state’s demand, are essentially the only new ones from California LSEs in the last two years. This is a hesitant changing of the guard in procurement that raises big questions about achieving the state’s goals. The questions were not answered by responses to the California Public Utility Commission’s Sept. 19 order to LSEs to update their renewable portfolio standard (RPS) plans.
The news was good on the state’s then 50% by 2030 renewables portfolio standard (RPS) in the November 2017 annual report from the California Public Utilities Commission (CPUC). The IOUs said they would meet the 2030 RPS requirement of 50% by 2020, and CCAs and ESPs said they would meet or exceed 2020’s 33% RPS requirement.
But the report only covered procurements of the five longest-standing of the nine CCAs at that time. As California’s customer choice movement accelerates, the new groups join the list of those not on track to meet RPS obligations.
“Ten CCAs just launched this year,” California Customer Choice Association(CalCCA) Executive Director Beth Vaughan told Utility Dive. They are too new to enter into long-term contracts, but there are “almost 10,000 MWs of new renewable construction” planned by 2030, and “there is no indication the CCAs will not meet their RPS obligations,” she noted.
Other stakeholders say the big concern is the RPS requirement that LSEs have 65% of their power under long-term contracts by the end of 2021.
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“Their filings show they need 6,700 MWs of new renewables online by 2022,” Large Scale Solar Association Executive Director Shannon Eddy told Utility Dive. “That is an amazing amount of power, considering their limitations and capabilities.”
The newer CCAs “will need to really scale up to meet the 65% obligation,”American Wind Energy Association California Caucus Director Danielle Mills told Utility Dive. “But credit and buying power limitations could make that challenging. We want the commission to pay attention to that issue.”
Stakeholder concerns with ESPs are different. SB 327, passed in the most recent legislative session, expanded the 13% limit on ESPs’ share of California’s commercial-industrial load to 16%. Yet ESPs “do not provide long-term forecasts on their renewable procurement,” the CPUC reported.
ESP plans “do address the RPS long-term contracting requirement,” according to the RPS docket filing by the Alliance for Retail Energy Markets. Its member ESPs will “enter into additional long-term contracts to meet the RPS requirement,” it wrote.
But its members’ customer commitments “rarely exceed 36-months,” making longer-term contracts “unrealistic” and “uneconomical” for those providers, the filing acknowledged.
However, “a 16% market is not inconsequential, and ESPs have near zero MWs of renewables contracted for after 2020. That appetite can help meet California’s long-term goals,” Matthew Freedman, staff attorney for consumer advocacy group The Utility Reform Network (TURN), told Utility Dive.
These questions are important, but the CPUC’s order was for a routine RPS update that is unlikely to provide big answers, Vote Solar Grid IntegrationSenior Director Ed Smelof told Utility Dive. “The real question is how RPS compliance fits together with the statewide strategy.”
That strategy will be determined in the state’s integrated resource planning (IRP) proceedings. California’s three dominant IOUs, Southern California Edison (SCE), Pacific Gas and Electric (PG&E), and San Diego Gas and Electric (SDG&E), are also thinking about how the RPS and IRP proceedings fit together.
But they are more immediately interested in the CPUC’s October 11 rulingon the Power Charge Indifference Adjustment (PCIA),
IOUs, the PCIA and the clean net short
In the PCIA ruling, the commission chose a new method to calculate the charge added to the bills of customers who move to CCAs. It compensates IOUs for the cost of generation they procured to serve those departing customers.
The method favors IOUs because it increases the charge, making CCAs unable to fulfill their commitments of customer rates lower than those of the IOUs. The higher rates will “stifle” CCAs ability to compete, Vaughan said. It is a “devastating blow to the flourishing CCA movement” and “could deter further market entry by CCAs.”
The decision will increase bills of CCA customers in PG&E territory by 1.68% this year, those in SCE territory by 2.50%., and those in SDG&E territory by 5.24%, according to the CPUC. And rate increases for customers departing their IOUs to CCAs are offset by rate decreases for customers remaining with their IOUs.
The PCIA ruling will affect whether customers return to the IOUs and necessitate new procurement, SCE VP for Energy Procurement and Management Colin Cushnie told Utility Dive. In the near term, the challenge will be identifying what the load will be for each LSE.
“Our current portfolio and commitments will meet the 2030 RPS requirement, based on indications of what load the CCAs in our territory plan to meet, Cushnie said. “If the PCIA changes enough to drive customers back to us, that may change.”
PG&E and SDG&E agree. The renewables sector see this uncertainty, and the resulting small amount of new procurement being done by the CCAs, as a missed opportunity.
Right now, wind’s federal tax credit, which is already phasing down and will be fully phased out by the early 2020s, “makes it the cheapest clean resource available,” American Wind Energy Association California Caucus Director Mills said. “We don’t want LSEs to think 10 years ahead and miss the opportunity right in front of us.”
Near-term procurement is also needed so the commission can begin planning the transmission that will be needed, she added. “That planning cannot begin without committed LSE procurements.”
SCE “will presumably procure for the post-2030 period,” but to use the tax credits, resources would need to be in operation before they are needed, Cushnie said. “The curtailment would cost customers too much.”
In its next IRP filing, SCE will address 2045 planning, he added. “That could be transmission upgrades and energy storage procurements, but SCE will not be proposing more procurement.”
To meet the 2045 zero carbon goals, the IOUs want to link CPUC work with work being done by the California Air Resources Board (CARB), by using a clean net short (CNS) requirement, Cushnie added.
The CNS concept “is a metric now being used by CARB to help guide what new clean resources should be developed on the system to carry load and meet policy objectives,” Cushnie said.
As described in the PG&E IRP filing, the CNS compares a resource’s generation profile with the procuring LSE’s load shape. It could discourage the over-reliance on resources like solar that lead to over-generation, Cushnie said.
The CNS concept can be adapted for the IRP and for other proceedings, TURN’s Freedman agreed. It is also “a far more accurate method” of addressing the “more complicated” question of greenhouse gas emissions in LSE resource portfolios.
CCAs, ESPs and a procurer
CalCCA had no comment on the CNS concept, but is satisfied the CPUC is effectively coordinating the IRP and RPS proceedings, Vaughan said. An October 29 public stakeholder event will further identify “how the proceedings fit together and what the inter-relationships are.”
CalCCA supported SB 100 and its member CCAs have filed RPS compliance plans that show they will meet their obligations, Vaughan said. The filings forecast 44% of retail sales will be RPS compliant in 2020, 32% will be under long-term contracts in 2021, and 61% will be RPS compliant by 2030.
That is rapid movement, she added. “Two years ago, there were only five CCAs. Now there are 19 and they need time to get up and running.”
At the end of 2017, the nine CCAs serving load “had 1,100 MW of new renewables in long term agreements,” Vaughan said. “At the end of October 2018, that will be over 2,200 MW in 56 contracts, almost all for ten years or longer.”
Marin Clean Energy, the oldest CCA, has the only CCA credit rating. It has 803 MW of new renewables in contracts of 12 years or longer, according to CalCCA’s “Beyond Supplier Diversity” report. Filings in the RPS docket show the other established CCAs similarly moving ahead. But many of the newer CCAs’ filings offer assurance of compliance but little to no specificity.
This lack of specifics is concerning when the CPUC projects the 2030 goal will require 11,000 MW of new renewables, Vote Solar’s Smelof said.
It is not evident CCAs need help with procurement, Vaughan insisted. “Under the law, CCAs have the right and obligation to self-procure,” she said. “Communities form CCAs to be in charge of their own procurement.”
Many stakeholders understand CCAs’ challenges, TURN’s Freedman said. “The question is what they will do to meet their 65% long-term contracts by 2022 RPS obligation.”
The PCIA proceeding’s next phase may offer ways CCAs can cost-effectively assume IOU renewables contracts, “and they may build new projects, which is SB 100’s real goal,” Freedman said. “But we may need outside-the-box strategies that identify and overcome barriers to procurement.”
TURN wants the commission to use a neglected provision in the RPS code that authorizes “a procurement entity” to contract for renewables to meet RPS obligations. If reviewed and approved by the Commission, the costs of the procurements could be recovered through rates, Freedman said. “And the commitments would be transferable if ESP or CCA customers move to other providers.”
If the CPUC develops the structure and the specifics, ESPs and CCAs without adequate credit or commitment capabilities could use the entity to secure long-term contracts, Freedman said.
Other options are unlikely to be workable. Neither the IOUs nor the CCAs would approve having IOUs procure on CCAs’ behalf, and a statewide central procurer is too politically controversial, he said. “Given the urgency of the RPS 65% obligation, the commission should make every effort to turn the code’s provision for a procurement entity into a reality before 2021.”
There is a greater urgency, Large Scale Solar Association’s Eddy added. “In the United Nation’s report on climate change, the scientists wrote that avoiding the severest changes will require ‘a staggering transformation the likes of which we have never seen,'” she said. “SB 100 is an important step, but we need to be thinking about what is next.”