Experts say that many of the new policies by the PUC and the state legislature seem to be putting the Golden State on track for more blackouts.
Although California's electricity crisis reached its worst point two years ago, utilities, consumers, and other market participants continue to fear a recurrence of the supply shortages and price spikes that added $40 billion to the cost of electricity over a horrific 13-month period.
Despite a host of emergency measures implemented in response to the crisis, no one believes that the underlying problems of energy infrastructure or faulty market designs have been completely corrected. Particularly, many Californians are concerned that regulators:
- Have failed to attract enough generation to meet demand (witness many cancelled merchant projects);
- Have not created conditions conducive for energy efficiency; and
- Have established draconian liability schemes in the procurement process;
For example, regulatory policies about customer choice have largely been punitive since the crisis, with an emphasis on making certain that few customers can escape some liability for the costs of power procurement, says California Manufacturers and Technology Association's (CMTA) Vice President of Government Relations Dorothy Rothrock. Southern California (SoCal) Edison was able to win a 2 cents/kWh "historic procurement charge" (HPC) as part of its financial rescue plan to cover losses from the summer of 2000. Then, in December 2002, the California Public Utilities Commission (CPUC) implemented a statewide "cost-responsibility surcharge" (CRS) of 2.7 cents/kWh to raise about $500 million per year from direct-access customers and pay for the power that state Department of Water Resources purchased. The surcharge is non-bypassable, meaning that customers must pay it no matter where they obtain their energy commodity.
With a new assessment of the costs of paying off the DWR bonds, that CRS figure may rise to as much as 4 cents/kWh this summer, Rothrock said, eroding the cost savings that companies are seeing from market-based power options. She called it a "time-delayed impact" of the power crisis.
How the CPUC deals with such liabilities will provide a signpost for future regulatory directions about the marketplace.
One recent issue on the CPUC's agenda offered an illustration of the various factions at play. There were three alternate versions of a policy for imposing a departing-load charge (a.k.a. exit fee) for customers who install on-site cogeneration equipment. Any existing bypass units as of Jan. 17, 2001, will be exempt from the charge, which has not yet been calculated. That will await a later ruling. What was on the table for consideration were the various components of the prospective fee, particularly the responsibility for covering a portion of the DWR bond charges going forward and Edison's HPC, plus several possible exemptions from the charge.
Under an administrative law judge's draft decision, departing load would have been responsible for both the DWR costs and the HPC, but exemptions were carved out for up to 125 MW of new bypass in PG&E and Edison territories and 34 MW in San Diego Gas & Electric's region.
An alternate decision from former CPUC President Loretta Lynch, with the backing of Commissioner Carl Wood, would have exempted departing load from the fees if the customer installs "ultra-clean" technology, i.e., solar photovoltaics and other equipment with a minimal emissions profile-thus cutting out most gas-fired units. Units under 1 MW in size that sign up for net-metering options, capable of selling energy back to the utilities, would also be exempt. The third proposal, offered by CPUC President Michael Peevey and the newest commissioner, Susan Kennedy, exempted both the low-emission units and up to 3,000 MW of departing load, as well as any net-metering customers. After delaying the vote until April, Peevey was able to convince Commissioner Geoffrey Brown, who has become the swing vote on many energy and telecommunications decisions, to back the most market-permissive version of the ruling at the April 3 meeting.
Besides working to bridge the differences among CPUC members, Peevey has taken the lead in developing a new state energy policy. The recently released "joint energy plan" from the CPUC, the Power Authority, and the California Energy Commission is the best example of how the state can restore stability to the market and improve the investment climate, Peevey said. Besides articulating what he called "ambitious goals for reducing per capita energy consumption, installing new transmission and generation infrastructure, and furthering renewable resource goals," Peevey said the intent is to coordinate the actions of state energy agencies-something that has been missing from California's policy efforts for more than a decade. "We've worked hard at it," he said. "The people at these agencies now have a similar perspective as to where we should go." After finalizing a public review process, the new joint plan could be adopted by early May, Peevey indicated.
Among the few bright spots in the California energy picture-the PG&E bankruptcy and Edison credit status notwithstanding-is that as of Jan. 1, 2003, the utilities have regained power-procurement responsibilities from DWR. The amount of energy they are buying daily remains limited because of a weakened economy and moderate demand. So far, the biggest challenge has been to smooth out the bumps in delivery schedules built into the DWR purchase commitments, which frequently obligate the utilities to take too much power when it is not needed or from locations that are subject to transmission constraints.
Still, grid operators at the California ISO report much improved relationships with the utility schedulers compared with their problematic dealings with the California Energy Resource Scheduling (CERS) unit of DWR. ISO staff members were especially pleased when Edison bought firm transmission rights for the majority of its DWR contract power so that dispatchers no longer have to scramble to squeeze energy flows over congested lines.
Another group of players glad to see the utilities back in the procurement business are generation developers, especially those few with renewable power to sell from their facilities. Calpine Corp., one of the few generators that Gov. Gray Davis had not castigated as a market marauder, recently signed long-term contracts with PG&E and Edison for the output of its geothermal power plants. The deals boost the utilities' green power purchases under the state's renewables portfolio standard (RPS) adopted last year.
New Generation Slow To Come
Despite the governor's 2001 crisis commitment to install 20,000 MW of generation over four years, only about 5,725 MW of new facilities actually operate. Although the CEC has approved licensing for another 7,635 MW, nearly 3,300 MW of that construction has been suspended. The CEC additionally reports that 20 projects totalling 5,000 MW of new capacity have withdrawn from its siting process since the power crisis began.
There is another 8,679 MW of capacity awaiting certification, but each month more of that prospective energy is cancelled or withdrawn.
"There's almost nothing in the pipeline," lamented Ronan. "You can't build without financing, and you can't get financing without contracts."
Not all of the generation losses have been because of market prices or lack of contracts. In some instances, local opposition based on traditional NIMBY concerns has stymied new development-regardless of how much the power might be needed to meet future demand in specific areas.
San Francisco offers a case in point. Mirant Americas Development Inc. has put environmental hearings on hold for its $500 million Potrero No. 7 modernization project in the city. The 540 MW project has received a preliminary recommendation for approval from CEC staff. It would provide sufficient capacity to avoid problematic transmission upgrades into the city, and cover the retirement of the aging Hunters Point station, while improving environmental impacts from the existing unit.
The CEC staff would approve the plant if it could come up with sufficient emissions offsets, and they have hinted that the entire siting process-now two years along-would go a lot smoother if Mirant would agree to use more expensive air-cooling technologies rather than rely on water cooling.
The suspension, however, came about because Mirant is trying to resolve air-quality problems with the Potrero No. 3 unit. To maintain this 207 MW baseload facility, Mirant will need to install selective catalytic reduction equipment on Unit No. 3 before new emissions limits take effect in 2005.
"Without this plant, the lights don't stay on in San Francisco," said Mirant's Potrero Project Director Mark Harrer.
Efficiency Efforts Take a Hit
One area of energy policy in which California has traditionally been a national leader-energy efficiency-continues to offer cost-savings opportunities for customers and new business prospects for entrepreneurs. The big problem, according to Elizabeth Lowe, vice president of efficiency provider Onsite Energy, is uncertainty.
"What's happening is that people are at a standstill, they're so shocked at the rates now," Lowe said. "Most are just trying to stay in business, and they cannot put up the capital for efficiency."
It has always been true that the best way to avoid rate increases and utility cost liabilities is to use less energy. Even though high-technology remains in the doldrums and manufacturing is hanging on by a thread, Lowe said there is no dearth of efficiency opportunities.
The best sector for business currently is California's massive agricultural and food-processing industry. For these customers, demand-controls are proving to be cost-effective investments, while improvements in cold-storage equipment can provide savings benefits. Some newer technologies are a bit more costly, she said, but given the combination of California's high rates and older physical plant, there are savings to be achieved. "Unless it's a brand-new facility, we've never gone into a place where we haven't been able to find efficiency opportunities with at least a 3-year payback," she said.
The traditional utility demand-side management (DSM) programs have largely been turned over to third-party providers, Lowe noted. The current trend in California commercial DSM emphasizes "standard performance contracts" over equipment rebates. That provides a quantifiable basis for allocating efficiency rewards to the utilities and customers based on actual savings from installations and measures-something the CPUC has insisted upon in recent years-but it doesn't solve the problem of initial capitalization.
Energy policy is not the only uncertainty plaguing California's business sector, said CMTA's Rothrock. "The economy is bad and it's not getting better any time soon," she said. With the total cost of industrial operations about one-third higher than the national average, energy expenses remain one of the major factors in determining the state's future economic prospects. But new costs loom.
As lawmakers and the Davis administration struggle to restore some balance to the state's budget, the axe is falling on programs, and every new taxing opportunity is being tried on for size. The schoolteacher layoffs and social service cutbacks are what get headlines in the newspapers, while efforts to impose fees and taxes on the business community receive less attention, Rothrock said.
The overall picture is troubling, she said, because CMTA members are "making decisions to move production out of state to the extent they can and they're letting existing investments phase out."
Exactly how much the California electricity crisis contributed to the overall economic malaise is a subject of debate for economists and policy analysts. For the electric utilities that continue to suffer from financial uncertainty, though, the crisis had a direct and persistent impact.
SoCal Edison is banking on paying off its past debts and regaining creditworthy status later this year, said John Fielder, Edison's senior vice president for regulatory affairs. But issues remain, including working through the state Supreme Court appeal of the bailout that is being pursued by ratepayer activists. Fielder added, "We need to get the state to take out of their lexicon the assignment of the DWR contracts" to the utilities.
CPUC decisions and the bond-issue documents have suggested that the contract obligations may be transferred to the utilities, Fielder explained. "What they don't understand is that if you assign these contracts to the utilities, the rating agencies will never give us a good rating. So we will always be paying more for our capital. We'll have to post a lot of collateral, and we'll have to have hundreds of millions of dollars in cash in a collateral account to back up the mark-to-market obligations for these contracts because they're so above market. All of these are additional costs that don't need to be incurred."
But as the state tries to shed costs and liabilities in order to restore its own fiscal health, it may just cause another "time-delayed" aftershock in the still-shaky electric marketplace.
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