California’s community choice aggegrators (CCAs) are on track to meet their state-mandated renewable portfolio standard obligations. PG&E, SCE and SDG&E have not signed significant new renewable power capacity since 2015, while CCAs have been building new projects. To achieve zero carbon electricity by 2050 will require aggressive plans to procure new renewables soon.
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Rather than focus on CCA procurement, the CPUC would better serve the state to use the provisions of AB 57 (e.g., PUC Section 454.5(b)(6)) and its other authorities, including those still in force from AB 1890 (1996). PG&E and SCE already collected $7 billion on an accelerated basis during the “competitive transition period” from 1998 to 2001 towards their legacy utility-owned generation resources such as Diablo Canyon, San Onofre and their hydropower generation. SDG&E completely paid off its generation portfolio in 1999 this way. Further, PG&E had already recovered its entire investment in Diablo Canyon by December 31, 1997 prior to the start of the opening of the restructured market. (I tracked the CTC accounts throughout the period, reporting to the CEC in 2001, and calculated the return on investment in Diablo Canyon for settlement discussions in 1996.) If the Commission wanted to repay the debts incurred during the 2000-01 energy crisis, the better solution, which it did in part with SCE, would have been to simply establish a “regulatory asset” with no connection to the generating facilities which had already been paid off. As it is, customers-–bundled and departed–are paying twice (and THREE times in the case of Diablo Canyon) for the same power plants.
The IOUs currently lack any real incentives to control their portfolio costs, as evidenced by their bundled portfolio plans for PG&E and SCE. Those plans say nothing about minimizing costs or managing risks except to avoid incurring shareholder penalties for missing the RPS mandates. In fact, PG&E has accrued a 3.3 cents per kilowatt-hour premium above the market value of its RPS portfolio to protect against a potential “price spike” between now and 2027. It is no wonder that customers have become unhappy with how the IOUs have managed their generation portfolios.
As I listen to the opening of the joint California Customer Choice En Banc held by the CPUC and CEC, I hear Commissioners and speakers claiming that community choice aggregators (CCAs) are taking advantage of the current market and shirking their responsibilities for developing a responsible, resilient resource portfolio.
The CPUC’s view has two problems. The first is an unreasonable expectation that CCAs can start immediately as a full-grown organization with a complete procurement organization, and more importantly, a rock solid credit history. The second is how the CPUC has ignored the fact that the CCAs have already surpassed the state’s RPS targets in most cases and that they have significant shares of long-term power purchase agreements (PPAs).
State law in fact penalizes excess procurement of RPS-eligible power by requiring that 65% of that specific portfolio be locked into long-term PPAs, regardless of the prudency of that policy. PG&E has already demonstrated that they have been unable to prudently manage its long-term portfolio, incurring a 3.3 cents per kilowatt-hour risk hedge premium on its RPS portfolio. (Admittedly, that provision could be interpreted to be 65% of the RPS target, e.g., 21.5% of a portfolio that has met the 33% RPS target, but that is not clear from the statute.)
Nick Chaset is the CEO of East Bay Community Energy which is a community choice aggregator (CCA) that serves Alameda County. He also was Commission President Michael Picker’s chief advisor until last year when he left for EBCE. He explains in this article how two proposed decisions that the CPUC is considering are fundamentally wrong and will shift cost onto CCA customers. (I testified on behalf of CalCCA in this proceeding. I’ll have more on this before the Commission’s scheduled vote October 11.)
Figure 1 – CPUC’s Proposed Resource Adequacy Value vs. True Market Values
Figure 2 – GHG Premium Value Missing from CPUC Proposed Decision
Figure 3 – Falling Utility Rates as Customers Depart Filed in Their ERRA Rate Applications
The electricity industry in California seems to face a new world about every 20 years.
California passed AB 57 in 2002 to make the power procurement process for electric utilities confidential (as well as subject only to upfront review rather than ongoing prudence standards). The result has been overly high prices locked in for decades. A new study on the relative gains to landowners who sell the development rights for oil and gas development in Texas shows that using auctions creates more competition among multiple bidders than bilateral negotiations. As a result, landowners get higher prices for their development rights through an auction. The corollary is that California’s electric utilities probably could lower their power purchase costs by moving to public auctions instead. Yet another reason to repeal AB 57.
Yolo County and the City of Davis became the latest community to approve a CCE (for community choice energy, an alternative moniker to the legalistic community choice aggregation). I sat on the advisory committee assessing options and the business case is strong for the viability of this option. This is the leading edge of a wave of CCEs across California. The combination of market conditions, falling renewable power costs, recognition of changes in the electricity market, and dissatisfaction with the incumbent utilities is pushing broad community coalitions to take the leap.
To date three communities have operating CCE’s, with MCE starting first in 2010. MCE is made up of not only Marin County, but also Napa County, and the City of Richmond and Benecia. It also is considering adding new members. It currently has 17 voting communities. Sonoma Clean Power followed in 2014, and is considering adding Lake and Mendocino counties. The City of Lancaster started in late 2015 in SCE’s service territory. Peninsula Clean Energy, composed of San Mateo County and its cities, kicked off service in 2016. In addition, San Francisco has approved a CCE but has had various political barriers to getting off the ground.
Here’s a couple websites that show maps and lists of what counties and cities are pursuing CCAs (the lists are slightly different).
Other communities in the midst of either approving or implementing new CCEs include:
Contra Costa County – considering joining Alameda or MCE, or going it alone
Humboldt County as Redwood Coast Energy Authority – considering joining SCP or going alone
South Bay Cities of Los Angeles County as South Bay Clean Power
Monterey, Santa Cruz and San Benito Counties and their cities as Monterey Bay Community Power
Riverside and San Bernardino Counties – issued RFP for joint study
City of San Diego – issued RFP for a study
Santa Clara County and 11 cities as Silicon Valley CCE Partners – starting late 2016
City of San Jose – exploring joining SVCCEP or going alone
Santa Barbara County, San Luis Obispo County and Ventura County – released study on feasibility and options
City of Walnut Creek – considering joining with Contra Costa or going alone
All of this activity has serious implications for IOU purchasing and contract management going forward, CPUC regulation and overall procurement transparency. The IOUs and CPUC have operated in black box to date claiming that confidentiality is necessary to prevent market manipulation. Yet with all of these CCEs likely operating as open books, everyone will have the market information that the IOUs claim is so vital to protect. This is likely to open up IOU PPAs to greater scrutinty–attention that neither the IOUs or the CPUC probably want.
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