By Erin Sherbert
By Howard Cole
By Erin Sherbert
By Erin Sherbert
By Leif Haven
By Erin Sherbert
By Chris Roberts
By Kate Conger
As California's energy crisis heads into what promises to be a brutal summer, the degree of dysfunction within the state's electricity market is already painfully apparent. On May 16 alone, for instance, all of the state's major daily newspapers heralded a record $5.7 billion rate hike, as well as the worse-than-expected forecast of 260 hours of rolling blackouts in the coming months.
How we got here, of course, has been the subject of rampant speculation. One of the most widely held theories -- the subject of both city and state lawsuits, as well as numerous news accounts that have grown increasingly less speculative in nature -- suggests that energy companies have played an active role in running up prices through "gaming" the market. In other words, generators allegedly shut down plants and/or withheld capacity to force the electrical grid to the brink of blackouts, significantly raising the prices for their electricity. But, because this type of behavior has been clearly documented in other newly deregulated electricity markets, this would hardly make California special.
Yet California's deregulation debacle has succeeded in elevating market meltdowns to a new plateau. Clearly, as other states weigh the pros and cons of deregulating their own electricity systems, California's stature as the cautionary tale is well beyond reproach. Years from now, when scholars are studying the Golden State in an effort to learn how not to deregulate an electricity market, they will surely note that the state's electric grid operator (in conjunction with federal regulators) made the following, connected mistakes:
- It let the state's regulated utilities respond to a mandate to sell their power plants by packaging them in geographically concentrated bunches, effectively granting the potential for local electrical monopolies all over the state;
- It attempted to regulate those local monopolies through contracts that actually encouraged generators to ask for outlandish prices; and
- It tried to remedy the original contractual faux pas with a new contract that -- when teamed with federal market rules -- continues to give some of the state's most crucial generators huge monetary incentives to manipulate market prices at the moment electricity is needed most.
Last spring, the entity that operates the state's electrical system, a nonprofit corporation known as the Independent System Operator, or ISO, actually caught a power generator -- dead to rights -- exploiting this contract loophole in what appeared to be a fairly blatant manner. The ISO referred the case to federal energy regulators, who responded in an unusual way.
The regulators allowed the generator to make a $3 million profit on its illegitimate market manipulations.
Although almost everyone with sufficient knowledge of the contract loophole acknowledges it should be closed, neither the ISO nor federal regulators have acted. Market analysts, consumer activists, and even power generators find the ISO's inability to plug the loophole puzzling, bizarre, or even damnable.
"It's screwy," says Mike Florio, a former member of the ISO's board.
Back in the mid-1990s, when state and federal officials were evaluating how, exactly, electricity deregulation was going to unfold in California, it quickly became apparent that the grid was vulnerable to price goug- ing in higher-growth areas where, generally speaking, there was less cushion between power supplies and power demand.
When electric utilities were regulated monopolies, it didn't matter that there were only a few major power plants in, say, the Bay Area. If one of those plants went down, Pacific Gas & Electric Co., which handled most of the generation for Northern California, could simply call on electricity from elsewhere in its grid. The lights would stay on, and power bills would be unaffected.
But this dynamic changed when the state's deregulation program required PG&E and Southern California Edison to sell most of their power plants. The requirement to sell was based on a fear of market power: If the two giant, investor-owned utilities kept all their power plants, they would hold a clear, statewide monopoly and would be able to drive prices higher at will under a market-based electrical system. As it turned out, of course, the new system -- embodied by a cartel of out-of-state energy companies that snatched up the utilities' power plants -- has all but swallowed Edison and PG&E whole.
But there's an element of irony in the utilities' current plight: The manner in which they sold off their plants set them up to be gouged. The utilities, fearing that many of their oldest, smallest, and least efficient plants wouldn't sell, decided to package their worst plants in geographically concentrated bundles containing some of their best. "If you wanted to buy a prince, you had to kiss a frog or two," recalls Gary Ackerman, president of the Western Power Trading Forum, which represents energy companies in California.
Much to the surprise of many industry insiders, many of the out-of-state generators were all too willing to pucker up. The power plants, good, bad, and indifferent, sold for well more than what they were widely considered to be worth. But before the utilities could fully congratulate themselves for making a killing on those sales -- a killing they promptly invested in other markets through their parent corporations -- it dawned on them that the transactions may have been less of a coup than originally thought. The utilities and the state's grid operator realized that statewide monopoly power had, essentially, been swapped for local monopoly power.
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."
What the modifications did, essentially, was allow Duke to exploit a clause designed to keep prices down by using a middleman firm, which Duke just happened to own.
The grid operator alleged that, for six months after the contracts were introduced in 1998, Duke's generators sold the power from their "must-run" plants exclusively to Duke's marketing wing, Duke Energy Trading and Marketing, at prices described as "suspiciously low" by several sources privy to the process. Duke's marketing unit could then sell the electricity it purchased without having to return any of its profits to the grid operator, as the "must-run" contracts required Duke itself to do. As alleged, this worked out pretty well for Duke's parent corporation, which pocketed the huge spread between the price of "must-run" power and market rates, while insisting that all the transactions were made at arm's length.
The case was eventually settled confidentially.
It was quickly apparent that Band-Aids weren't going to be sufficient to patch the gushing "boo-boos" in the contracts of the state's most crucial generators. In the messy, nasty, and seemingly endless legal wrangling that followed, utilities, energy firms, the grid operator, and federal regulators fought over every detail. At stake: hundreds of millions of dollars and the reliability of the state's transmission grid.
It was, by all accounts, not pleasant.
"If you're ever talking to people at the ISO, and you want to change the subject," jokes Mike Florio, president of the Utility Reform Network and a former consumer representative on the ISO's board, "all you have to say is "This is going to be another RMR.'"
Even today, the settlement process over the RMR contract debacle that began back in 1998 drags on. The loosest end is a dispute between Mirant and the California grid operator over the payment structure of the new contracts. The two sides are more than $50 million apart, and a decision from a FERC judge is expected sometime in the near future.
Aside from a few similar, straggling disputes over payments, most at the ISO felt as though they'd fixed the most egregious flaws in the "must-run" contracts by April 1999, when a new contract structure was introduced. The new deals supposedly purged the "perverse incentives" from the pacts. When the ISO actually caught a generator and an energy marketer profiting off a sizable loophole in the new "must-run" contracts last spring, most would have expected that line of thinking to cease. It didn't.
As they have become remarkably adroit at doing, federal energy regulators sent consumer activists and market analysts into a state of full-blown hysteria last month. The trigger, this time, was an $8 million settlement with an energy trader that allegedly had made $11 million in about three weeks through a price manipulation scam that involved shuttering some of its "must-run" plants in Southern California.
"It's like making a bank robber give back 80 percent of what he stole," shrieks Doug Heller of the Santa Monica-based Foundation for Taxpayer and Consumer Rights. "He gets no jail time, no punishment whatsoever, and he even gets to keep some of the money he took."
If Heller's sentiments are widespread among those who have read the brief daily news accounts of the settlement, those closer to the situation fume for a slightly different reason. The case involved AES, which owns reliability plants, and the energy trader it buys gas from and sells power to, the Tulsa-based Williams Co. Allegedly, the pair used a FERC rule to exploit a glitch in the latest reliability contract revision. This allowed Williams to charge 10 times as much as it could otherwise have gotten by reporting its reliability plants to be out of order, and by subbing in a replacement unit. What drove those familiar with the "must-run" contracts craziest was that federal energy regulators -- at the grid operator's urging -- caught Williams with its plants down, and acknowledged the loophole.
And then didn't bother to plug it.
What AES and Williams allegedly did during the spring of 2000 is not subtle: The pair responded to the grid operator's dispatching (that is, ordering into operation) of one of their "must-run" plants -- which the grid operator pays millions to keep available -- by saying that the dispatched plant was out of service for repairs, thus making the grid buy electricity from other units, also owned by AES/Williams. Those replacement units were able to charge full market rate, rather than the preset, much lower rate that "must-run" plants can charge when they are dispatched. That the ISO tried to order the plants online means the reliability of the grid was imperiled by an electrical shortage at that time. That is to say, the ISO needed power, and quickly, or a significant portion of the Southern California electric system could fail, an event that could create blackouts.
By keeping its "must-run" plants down, Williams was able to charge $750 per megawatt hour, instead of the $63 designated in its "must-run" contracts.
After about a week and a half, the "must-run" plant that had been taken off-line was running again. But on the same daythat reliability plant came back up, AES informed the grid operator that its other reliability plant in the area had gone down. Again, a substitute unit would be paid -- per federal regulations -- well more than 10 times what its dispatched reliability units would have garnered. A chart posted on the ISO Web site underlines the symmetrical nature of the reliability plant outages.
Williams and AES say that symmetry is merely a coincidence, but it's a coincidence that happened to make them $10.8 million extra in a little more than three weeks' time by playing roulette with the reliability of the state's transmission grid.
But some experts say that, had the grid operator used common sense, Williams would have never been in a position to profit this way. The mistake: tying the reliability pacts to specific plants, when the ISO could have just required generators, which bought most of their plants in close proximity to one another, to pledge a specific amount of electricity in the "must-run" contracts. By contracting for specific "must-run" plants -- most of which are decades old and prone to breakdowns -- and not amounts of power, the grid operator seems to have all but ensured itself headaches related to the availability of its most crucial units.
The Utility Reform Network's Florio, who is so thoroughly immersed in the day-to-day crisis that he only has time to speak to reporters on his car phone during his daily commutes from San Francisco to Sacramento, finds the foolishness behind the reliability agreements baffling. "I've been trying to figure that one out," he says, reached somewhere on Interstate 80. "If you're contracting for a service, it's beyond me why you'd tie it to a specific piece of machinery."
Even Gary Ackerman, who represents power generators' interests, concedes it's "very possible" that the roots of AES's and Williams' conduct stem from the reliability contracts and the incentives they give power generators to game the market, and gouge consumers.
Frank Wolak's office at Stanford University has all the trappings of a conspiracy theorist's abode. The door is covered in scribbled-on, yellowing newspaper clippings about various market abuses and instances of monopoly behavior; amidst those clippings is a transcript of two airline officials discussing price fixing. And from the inside, rising up through the closed door, there's an angry voice, railing into a phone about the latest actions of federal regulators.
But what separates Wolak from conspiracy buffs, aside from his neatly tucked-in, well-starched appearance and Stanford pedigree, is this: As the chairman of the grid operator's independent Market Surveillance Committee, he's on a very short list of people who are not directly employed by the grid operator, federal regulators, or the state government, but who also get to see all of the state's electrical market data. When Wolak looks at reliability contracts, he sees exactly what he told the grid operator -- years ago -- that it would see if the reliability contract loophole remained unplugged.
And that sets him off.
"If I were a lawyer, it's the first thing I would have thought of," says Wolak, getting just loud enough to draw a glance or two from others around the noisy campus cafeteria in which he's sucking down a midafternoon cup of coffee. "I mean, think about it: Instead of the ISO saying that "I'm buying 450 megawatts of RMR energy and I don't care where it comes from,' they decide to designate specific units. ... And then FERC, as co-conspirator, rules that, when the RMR units go out, the replacements have to be paid as bid."
Wolak says he's told ISO negotiators about the still-gaping contract loophole. "But it's not like academia, where you write something down, and then it's OK," he says. "You've got to say it 50,000 times, or it just fades into oblivion."
Lawyers for the ISO say that considerations about specific megawatt amounts -- as opposed to entering into contracts with specific generators -- were considered and, in fact, shaped the current contracts. "In a way, they are based on megawatts," says Eric Hildebrandt, an ISO lawyer. "We started with a megawatt calculation, and then we looked at specific plants that could give us what we needed."
And it was the ISO's decision to contract with those specific plants that created the loophole that let power providers shut down "must-run" plants, and charge the utilities (and ratepayers) more than 10 times as much for electricity as the providers' "must-run" plants could charge.
Clearly, federal regulators saw the loophole in the "must-run" contracts when they forged the $8 million settlement with Williams/AES. The settlement forbids Williams from substituting market-price power for that to be provided by "must-run" plants for one year. After 12 months, of course, the loophole figures to be as open as ever, even for Williams and AES.
But the agreement also states that Williams and AES did nothing wrong. "While not an admission of any wrongdoing, Williams has taken action to ensure that no employee will in the future make any statement to [AES] that could be interpreted as inappropriately attempting to influence facility operations."
Perhaps most astonishing of all, the settlement does not extend the substitution prohibition to other power providers -- meaning that any of the other California plant owners that have both reliability plants and nonreliability plants can continue to exploit the loophole that every knowledgeable observer knows exists.
As William Massey, the one FERC member not appointed by President Bush, wrote in a tersely worded concurrence to the Williams/AES settlement: "Exercises of market power through withholding cause severe economic distortions and harm that are difficult, if not impossible, to rectify after the fact. Thus remedies for market misconduct must be comparably severe enough to act as a deterrent. ... In this respect, this settlement is not as strong as I would have preferred."
Wolak, the Stanford professor, puts it in terms that any Econ 101 student could grasp: "What's the cost of doing this [market manipulation]? Zero. What's the benefit? A whole lot of money. To expect someone -- especially these generators -- to sit back and be civic-minded is ridiculous."
It would be relatively easy for power generators to feign debilitating conditions that require "must-run" plants not to run. Wolak likens unscheduled power plant outages to sick days, in which the complexity of the machinery involved allows generators to do the equivalent of faking a cough into a cell phone while calling from the beach.
Deregulated generators do tend to call in sick considerably more than their regulated counterparts. A 1999 study of the recently deregulated New England market -- which features prominent California players such as Mirant, Calpine, and the parent company of PG&E -- found power plant outages increased 47 percent within the new system's first year. And California market watchers say they've seen a similar, if later-blooming, trend unfold here. California Energy Commission data from April show a nearly 400 percent increase in the curtailment of energy generation from a year earlier.
Reliability contracts, which were supposed to protect the grid from this behavior, haven't succeeded in keeping plants running. In the case of AES/Williams -- and other energy providers, according to Wolak, who says he's seen "pretty good evidence" of "must-run" market manipulation in other parts of the state -- this "must not run" phenomenon can be traced to the loophole in the ISO's reliability contracts.
But extremely tight electric supply conditions have made it advantageous for reliability units to withhold capacity even when they can't exploit the loophole by substituting much-higher-priced power from another plant in the same geographic area.
In the most power-strapped areas of the state -- the Bay Area and the San Diego Basin -- every electricity generating plant is under a reliability contract. The flaw in their "must-run" contracts does not, therefore, give the generators an incentive to keep their plants down; there are no unregulated power plants to substitute into the grid, at a 1,000 percent markup.
But power generators still have a nearly unchecked ability to manipulate prices by withholding capacity from a tight market. Brian Theaker, an ISO lawyer involved in the reliability contract process, says a generator such as Mirant, which controls more than half of the Bay Area's capacity, is "definitely" in a position to garner higher prices for itself by cutting back the amount of electricity it generates. Mirant's "must-run" contracts make this possible by allowing it to choose between selling its energy at a predetermined contract price that essentially covers its costs, or to sell its power for a market price. These days, with prices skyrocketing, it's not much of a choice.
And because the grid is so close to collapse during this supply crisis, every megawatt that generators withhold from the market winds up having an impact on the prices for their remaining plants. Mirant's own outages, clearly, have impacted prices. Despite having all of its plants under reliability contracts, this spring the company, on average, shut down more than 1,040 megawatts of its capacity a day, roughly a third of its generation. That's more than enough energy to power 1 million homes.
In April, when the company collected a near-record $533 million check from the state for power, Mirant's electricity curtailments were actually about 10 megawatts per day higher than they had been earlier in the year. Even without the loophole, it seems, the reliability pacts are doing little to stifle generators' market power now, when that power is at its most potent.
"The presumption was that the overall, global market would be competitive," the ISO's Theaker says. "These contracts were designed for local concerns. So when you have a global, overall supply problem like this, [the "must-run" contract is] not an effective Band-Aid for that. It doesn't really work for that."