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 premiumabove 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.)
In its annual report on resource adequacy (RA) transactions, the CPUC reports the wrong result for the market price to be used for valuing capacity from the RA market data. The Commission’s decision issued in the PCIA rulemaking on establishing the CCA’s “exit fee” uses this value in error. In the CAISO energy and ancillary services markets, the market clearing price used to set the value of the energy portfolio is determined by the highest accepted bid in a single hour, and then averaged across all hours. In contrast, the average reported RA price in The 2017 Resource Adequacy Report incorrectly reports the average of all transactions. This would be equivalent to the CAISO reporting the average of all accepted bids, including those at zero or even negative, as the market clearing price.
The appropriate RA price metric is the highest RA transaction price for each month. This price represents the market equilibrium point at which a consumer is willing to pay the highest price given how low a price a supplier is willing to provide that quantity of the resource. (The other transactions are called “inframarginal” and such transactions are common in many markets.) In a full auction market, all transactions would clear at this single price, which is why the CAISO reports a single market clearing price for all transactions in a single hour. That should also be the case for the RA market price, except the time unit is a month.
Due to a lack of an auction for the moment, it is possible to manipulate the highest apparent price through a bilateral transaction. Instead, the Commission could choose a price near the highest point, but with sufficient market depth to mitigate potential manipulation. Using the 90th percentile transaction is one metric commonly used based on a quick survey of market price reports.
The California Public Utilities Commission (CPUC) held a two-day workshop on rate design principles for commercial and industrial customers. To the the extent possible, rates are designed in California to reflect the temporal changes in underlying costs–the “marginal costs” of power production and delivery.
Professor Severin Borenstein’s opening presentation doesn’t discuss a very important aspect of marginal costs that we have too long ignored in rate making. That’s the issue of “putty/clay” differences. This is an issue of temporal consistency in marginal cost calculation. The “putty” costs are those short term costs of operating the existing infrastructure. The “clay” costs are those of adding infrastructure which are longer term costs. Sometimes the operational costs can be substitutes for infrastructure. However we are now adding infrastructure (clay) in renewables have have negligible operating (putty) costs. The issue we now face is how to transition from focusing on putty to clay costs as the appropriate marginal cost signals.
Another issue raised by Doug Ledbetter of Opterra is that customers require certainty as well as expected returns to invest in energy-saving projects. We can have certainty for customers if the utilities vintage/grandfather rates and/or structures at the time they make the investment. Then rates / structures for other customers can vary and reflect the benefits that were created by those customers making investments.
Jamie Fine of EDF emphasized that rate design needs to focus on what is actionable by customers more so than on a best reflection of underlying costs. As an intervenor group representative, we are constantly having this discussion with utilities. Often when we make a suggestion about easing customer acceptance, they say “we didn’t think of that,” but then just move along with their original plan. The rise of DERs and CCAs are in part a response to that tone-deaf approach by the incumbent utilities.
The analogy to Netflix is fascinating. As GTM points out, Netflix started out competing with Blockbuster in video DVDs, but then spilled over into video streaming (BTW, a market that Enron famously thought it could corner in the last 1990s.) So Netflix is now competing with both cable and broadcast companies. One can see how renewables could jump out of just electric service to building space conditioning and water heating, and vehicle fueling. Tesla is already developing those options.
Bjorn Lomborg, a Danish political scientist who has pushed for focusing spending on other pressing world needs over reducing climate change risk, has criticized the extension of California’s cap and trade program in the LA Times. I found two serious flaws in Lomborg’s analysis that undermine his conclusions.
The study that Lomberg cites about the electricity market impacts has not been reproduced since such extensive “contract reshuffling” can’t occur in the Western Electricity Coordinating Council (WECC) region or in the CAISO market. That’s just a simplistic modeling exercise not tied to reality. The fact is that thousands of megawatts of coal plants are retiring across the WECC at least in part in response to the cap & trade and renewables portfolio standards (RPS) adopted by California.
And then Lomberg writes “A smarter approach to climate policy — and one befitting California’s role as one of the most innovative states in the country — would be to focus on making green energy cheaper. ” Has Lomberg noticed that new solar and wind installations are now cheaper than new fossil-fueled plants? Contracts are being signed for less than 5 cents per kilowatt-hour–PG&E’s average cost for existing generation is close to 9 cents.
It’s as though Lomberg hasn’t updated his understanding of the energy industry since 2009 when the Copenhagen climate accord was signed.