By Erin Sherbert
By Howard Cole
By Erin Sherbert
By Erin Sherbert
By Leif Haven
By Erin Sherbert
By Chris Roberts
By Kate Conger
For instance, the Atlanta-based Mirant Co. spent $801 million buying plants in the Bay Area. It bought a massive plant in Pittsburg, a midsize plant in Contra Costa County, and something of a dog of a plant on Potrero Hill. It all added up to a transfer, from regulated utility PG&E to private, unregulated generator Mirant, of more than half of the Bay Area's generating capacity.
This pattern played out all over California: As a result of the state's flawed deregulation scheme, Duke Energy Corp. was able to purchase two huge plants south of San Jose as well as a tiny, wheezing facility in Oakland; AES Corp., Reliant Energy Inc., and a partnership between Dynegy Inc. and Minneapolis-based NRG Corp. purchased the capacity to generate thousands of megawatts in their own pockets of Southern California.
These geographically concentrated investments gave generators the potential for what economists call "local market power." That is, when generators and energy traders control a high percentage of the available electricity in a given area, under the state's new "market" system, they can essentially get whatever price they feel like charging.
Even more important, if these units were not running at times when high usage pushed the electrical grid to its brink, they could imperil the reliability of the grid in their areas. The plant owners could literally threaten to black out their entire operating areas if they weren't satisfied with the going rate for electricity.
Under the old, regulated system, concerns about local market power and grid reliability were far less relevant. In Northern California, for instance, PG&E controlled the entire grid and sold the power it generated directly to consumers. It had no incentive to shut its own plants down for the purpose of manipulating the prices on the "real time" market. And, because it controlled the entire regional grid, it could respond to outages forced by maintenance and other naturally occurring factors by simply wheeling in power from elsewhere in its expansive grid. The absence of middlemen and the presence of price caps associated with regulation made local market power and grid reliability nonissues.
But with deregulation, and the geographically concentrated way in which the utilities unloaded their plants, the local power wielded by various energy firms became, potentially, an enormous factor in electricity availability. The leverage that power generators could have over price was so painfully obvious that even the generators -- not known for embracing scenarios that could reduce their prices -- agreed it needed to be checked.
The result, endorsed by federal energy regulators, was a special type of contract intended to protect the grid's reliability from the likelihood that generators might shut down or scale back production at some of their plants in an attempt to manipulate prices. The theory behind this new contract was simple enough: The ISO would be allowed to tell energy companies when certain crucial electric plants had to run. In theory, then, when electricity supplies were low in any given area of the state, the ISO could order energy suppliers to run their plants, supplying electricity at a predetermined, relatively low rate. These "must-run" contracts, required as a condition for buying some power plants, gave the energy companies benefits, too. Essentially, the state agreed to pay the companies for the fixed costs of keeping the plants ready to run -- payments that generally totaled millions of dollars in a given year -- all but ensuring the energy firms a reasonable annual profit on those plants.
However well-reasoned the theory seems, the actual practice of the state's "Reliability Must-Run" (RMR) contracts managed to defy all logic. Even though they were approved by federal energy regulators and written by the grid operators themselves, the new contracts still all but ensured much of what they were intended to prevent. According to an ISO lawyer, they actually encouraged generators to jack up their prices and, if the generators couldn't find any takers, to not run at all.
"[The contract] dis-incented them from getting in the market actively," says ISO attorney Eric Saltmarsh, who worked on the reliability contracts. "They could just bid high, and if they were left out of the market because of it, they had sufficient insurance."
That was definitely, as Saltmarsh puts it, "a boo-boo in the contract."
That "boo-boo" was approved by the Federal Energy Regulatory Commission, a previously little-known Washington agency run by a panel of presidential appointees. FERC's mission is to "foster competitive markets wherever possible," and, as such, it had to approve every aspect of the new California market before each was approved by the grid operator. While the sum of those approvals speaks for itself, the commission has also been widely criticized for its alleged inaction during California's crisis, particularly its unwillingness to make prices conform to the "just and reasonable" standard in its own bylaws. All the commission's supposed failures during this crisis aside, it is clear that FERC did not distinguish itself when approving the "must-run" contracts, either.
Nevertheless, the grid operator's legal team managed to further mangle the federally approved basic contract, in at least one case, with modifications. One federal filing described the incentives in deals the grid operator brokered with Duke, which owns "must-run" facilities in Moss Landing and Morro Bay, as "perverse."