LONDON: California has more than enough power generating capacity to meet its current needs.
But that capacity is becoming less flexible, as the proportion of intermittent wind and solar generation rises, and older gas-fired power plants are forced to close or undertake expensive retrofits under new regulations on water conservation.
Intermittent generation must be backed up by gas-fired plants, which can be ramped up to meet demand when the wind drops or the sun goes down, and cut back quickly if wind and solar generation threaten to overwhelm consumption.
Unfortunately, older gas plants are under threat from regulations requiring them to use less water, as well as low electricity prices and capacity payments, which make it
uneconomic to spend money upgrading them to meet the new requirements if they are only going to be used for a few hundred hours per year.
In 2014, the state will have enough capacity to meet 144 percent of its top summer-time needs. That is far more than the 15-17 percent margin the California Public Utilities Commission (CPUC) requires suppliers to have against peak weather (the hottest temperatures in 1:10 years) and the simultaneous loss of the two largest generating plants or transmission lines on the network.
By 2022, the state will still have a capacity margin of 20 percent, according to documents released as part of a long-term planning summit hosted by CPUC and the California Independent System Operator (CAISO), which operates the grid, on February 26.
But California’s excess generating capacity may be misleading. Wind and solar output is not always and predictably available. And the grid’s flexibility to respond to sudden changes in supply and demand may be falling as a result of changes in the generation mix, raising the risk of blackouts in future.
California enacted new water regulations in 2010 requiring power plants to lower their cooling water intake to reduce the harmful impact on marine and river life. The rules require 19 power plants (including two nuclear stations) using water-hungry once-through cooling (OTC) systems to close or be retrofitted with expensive new technology by the end of 2017.
Owners of gas-fired plants complain it is not worth spending money to retrofit them because they cannot be certain of recovering the costs from selling high-priced peak electricity for just a few hours per year, or from the low level of capacity payments currently offered by local electricity suppliers for back-up power resources.
Current overcapacity is the legacy from heavy investment in renewable wind and solar to meet California’s Renewable Portfolio Standard (RPS), which requires the state to generate 33 percent of its energy from renewable sources by 2020.
The situation has been exacerbated because the utility commission has approved the construction of new gas-fired power plants to replace older ones that were supposed to have closed as a result of tougher environmental regulations.
Only a limited amount of that generation has actually retired, according to CPUC, leaving the state with a glut.
Overcapacity is weighing on both the price of electricity and the capacity payments, which generators receive for keeping plants available for use in future or in an emergency.
The renewable portfolio standard and ban on once-through cooling are “fundamentally shifting the topology of the grid,” reshaping California’s electricity system in unprecedented ways, CAISO explained in a briefing paper.
“Without taking deliberate steps to secure flexible capacity ... rapid growth of intermittent renewable resources and the once-through cooling mandate will crowd out existing flexible conventional dispatchable resources that will be needed to maintain a reliable grid,” CAISO warns.
In other words, gas-fired power plants (or others) should receive higher payments to keep then available in case they are needed at some point in future.
At the moment, CPUC requires local electricity suppliers to enter into contracts for sufficient generating capacity one year ahead under its resource adequacy (RA) program.
Suppliers and the CPUC also undertake a long-term procurement plan (LTPP) exercise every two years which looks at demand and capacity 10-20 years ahead. The LTPP is designed to support construction of new generating assets and ensure the
state is never again hit by a re-run of the power crisis in 2000-01.
But between the one-year RA and 10-year LTPP, there is a gap where no one is planning or paying to ensure sufficient capacity is available three to five years ahead.
CAISO and power producers want the public utility commission to authorize a “three to five year forward capacity market” as the “best solution to balance reliability, cost and resource availability.”
“CPUC’s RA and LTPP regulatory framework has the effect of creating two separate capacity markets: one for new generation that can result in contracts of 10 years or longer, and a different market focused on shorter term contracts of less than five years for existing generation,” the Commission admits.
“Once a generator is out of its initial long-term contract, it has little expectation of a future long-term contract.
Generators can only expect to compete in the near-term RA markets for existing generation.”
— John Kemp is a Reuters market analyst. The views expressed are his own.
The problem is that short-term RA markets do not provide long enough for gas-fired generators to recover the cost of expensive upgrades. And there is so much surplus capacity competing in the one-year ahead RA market that prices are very low.
But existing gas-fired generators cannot secure 10-year capacity deals under the LTPP either. So many may be forced to close rather than retrofit.
The current two-part market is creating significant price discrepancies. LTPP is paying $ 150-300 per kilowatt year for long-term capacity, while the RA is paying just $ 18-38 per kilowatt-year in the short term, according to consultants from Brattle Group.
“High-cost new generation may be developed even as lower-cost existing generation may be forced to retire,” Brattle said.
Instead of meeting requirements by retrofitting existing plants (which is expensive), the state may end up scrapping them and constructing entirely new ones (which will prove even more expensive but will get payments under the LTPP). It is hardly a
sensible solution.
A forward market would create a level playing field between existing generation, new generation, imports, and retrofits, as well as demand response and energy efficiency programs, to compete to provide capacity in the most cost-effective manner.
CAISO would probably run any capacity market. Gas-fired power plant owners also have a strong interest. CPUC, however, must decide whether the costs are worth the benefits.
The Commission appears unconvinced. Low rates under the RA mechanism and a 44 percent margin suggest capacity is hardly a pressing problem. The most that the Commission can say is that “current excess capacity may result in idling or retiring some resources that may be needed in a few years.”
“CAISO maintains that the current one-year ahead forward requirement does not provide it with adequate assurances that the resources needed to operate the system will be available in future years,” CPUC explains. “Generators maintain that (it) does not provide them with adequate financial signals that they are ‘needed’ in future.”
“However the current system has thus far been sufficient to ensure reliability and strikes a balance between rates, reliability and investment returns.”
California’s foray into a wind and solar powered future is going to result in some big swings in net demand for conventional gas-fired generation in future. Maintaining
adequate capacity and system flexibility will be vital. But not every gas-fired plant has a future. Some sensible rationalization is needed.
Forward capacity markets are an efficient way to ensure the lights stay on at lowest cost. But CPUC must be careful it does not end up expensively supporting a fleet of aging facilities that may never be needed.
— John Kemp is a Reuters market analyst. The views expressed are his own.
