The New Californians
By: Ben Tansey
Frustrated by a lack of control as their citizens were battered by electricity price hikes and blackouts during the western price crisis of 2000-2001, the leaders of many California cities looked at municipalization options. The state constitution specifically allows cities to establish and operate utilities for water, heat, power and other services.
But if there is already a private utility in place, full municipalization can be a substantial undertaking. A couple cities had expensive demonstrations of the power of incumbent IOUs before scaling back to a greenfield model, serving only new residential, commercial or industrial development in their towns. Some towns went directly to the greenfield approach while others backed off entirely.
The power crisis was not the driving force in the creation of all of the new California municipal utilities. In two cases, the sale of surplus Navy bases got things started; in another, the crisis only added impetus to an existing drive for local control.
Of the half dozen stories reported here, no two are alike. Each city had a unique adventure.
“Different utilities have taken different strategies,” said Leonard Viejo, president of Astrum Utility Services, which worked with many of the cities that ultimately established some level of new electric service. “There is not one approach.” Some built generation to serve their needs, others signed interconnection agreements. A few entered the long-term market while others have maintained short-term portfolios.
Most cities already had some type of utility service; at least one had none. Two of the new utilities are not even cities, but ports. Some entered the business specifically to create new revenue for their general fund or for economic development purposes, while others did it solely to ensure reliable electric service at competitive rates. A few took several years to get on line, while one was delivering power after just three months. In a few cases, growth projections were exceeded, while in others, greenfields have not sprung.
But the new utilities that were established remain going businesses, most pursuing relatively modest enterprises that are or will soon be contributing to their town’s general fund and offering their customers reliable service at competitive rates.
While all the new municipally owned utilities remain optimistic about their futures, they face challenges that are more acute for the newer public power utilities than for their larger and more established municipal brethren.
Because of this, the California Municipal Utilities Association this spring began organizing a new committee to focus on the needs of new municipal utilities. The committee will be chaired by George Hanson, manager of Moreno Valley Utility. More than a dozen existing and prospective new public power utilities have been invited to join.
“The committee is designed for new utilities, which have unique problems designing programs” to comply with California’s new renewable portfolio standard, its solar initiative, energy efficiency “and other requirements that may affect small, new utilities in a unique manner,” CMUA said.
Prospective members may not have the financial resources, business experience or regulatory knowledge of older, more established utilities and may have different business goals and priorities, CMUA said. In addition, “smaller, newly formed publicly owned utilities are subject to a barrage of targeted attacks from IOUs.” The forum will be a place to share ideas and strategies on operational, political and regulatory challenges, and to pool both physical and administrative resources.
Jonathon Daly, general manager of Corona’s new utility, said municipal utilities are outgunned by the IOUs on the regulatory and legislative fronts. He cites California’s targets for renewable resources. “We’re not against green or solar, but the deadlines are not as easy for smaller municipals to pull off.” Some of the IOUs are already well on their way to meeting the target of 20 percent green by 2010, he said. “Corona’s percent of green is zero.”
Last August, the state Legislature changed California’s $3.35 billion rate-funded solar initiative—previously binding only on IOUs—to require that municipal utilities establish solar energy programs worth $784 million by Jan. 1, 2008. And while IOUs are required to make renewables 20 percent of sales by 2010, public power utilities are required to implement a portfolio standard that “recognizes the intent of the Legislature to encourage renewable resources, while taking into consideration the impact on rates, reliability, the goal of environmental improvement, and the impact on financial resources.” They must also comply with newly adopted greenhouse gas emission rules, new renewable and energy efficiency reporting requirements, and evolving resource adequacy standards.
Three of these new municipally owned utilities are near each other—Rancho Cucamonga, Corona and Moreno Valley are all within about 25 miles of each other in a triangle centered 40 miles east of Los Angeles. Three others are also close—Hercules and Island Power are on opposite sides of the bridge over the mouth of the Sacramento-San Joaquin Delta as it enters the bay 20 miles northeast of San Francisco, while the Port of Stockton is 75 river miles due east on the San Joaquin River. San Marcos is in northern San Diego County.
Moreno Valley Utilities
—The formation of Moreno Valley Utilities, a division of the city’s public works department, was “largely a product of the power crisis in California,” said electric utility Manager George Hanson. “With rates seemingly increasing well above the national average and no relief in sight, city leaders got interested.”
But economic development and a new source of general fund revenue were also important. At the time, the city’s per capita revenue ranked lowest among the 46 state cities its size. In 2003, it took a significant tax hit when a Target store served by Southern California Edison Co. relocated over the municipal boundary to take advantage of rates offered by Riverside’s municipal utility.
The utility itself was formed in June 2001, followed by a lengthy research period and an open process with many public hearings. It went on line in February 2004, adopting a greenfield approach under which new development was conditioned to take electricity service from the district. By June 2004, it was serving 200 meters.
There was “quite a battle” between the city and Southern California Edison. The IOU funded a group that Hanson said consisted mostly of SCE’s own employees and their families. The group introduced an initiative for the November 2004 ballot aimed at hobbling the new municipal utility by preventing transfers between it and the city’s general fund. The measure failed by less than 1 percent. A second measure supported by utility opponents would have repealed the city’s utility users’ tax. It failed with only 44 percent.
According to news reports, Southern California Edison spent $2.4 million on the losing campaigns.
In October 2003, Moreno Valley signed a 17-year contract with ENCO Utility Services to provide operation and maintenance of the distribution system. Its seven employees do all the metering, billing, collection and provide a call center, leaving the district’s three city-paid employees to focus on resource management and regulatory oversight. Under the contract, Enco gets half the distribution component revenue after deductions for the city’s rate stabilization fund and in lieu contributions, or roughly 10 percent to 15 percent of total gross revenue.
Hanson said the utility got started with an $800,000 allocation, some of which is still in reserve. The city paid for an interconnection but developers pay for the infrastructure and turn it over to the utility, which now has assets in excess of $15 million.
To enhance reliability and aesthetics, distribution is entirely underground. Until last May, when a car hit a city switch causing a one-hour outage for most of those affected, the only interruptions had been due to problems on non-city lines feeding the system.
Rates “are consistent with or roughly equivalent” to those of Southern California Edison for all customer classes, Hanson said. “We’re evaluating our costs and rate structure. In the future, we hope to be able to hold rates consistent or even reduce them” as growth allows.
Moreno has a shaped, three-year power supply agreement with Sempra Solutions that enables it to meet load growth. That’s good because there are already 4,100 residential meters and 200 commercial meters, and a wave of commercial development is “following the rooftops.” The residential growth rate is expected to finish the year at 12 percent; commercial growth is expected to hit an extraordinary 65 percent. Last summer’s peak was 15 MW but Hanson said it’s likely to reach 25 MW this year. Although the growth has been a difficult challenge, the utility has so far managed to get infrastructure in place and energized ahead of developers’ schedules.
In 2006, the utility billed 42,000 MWh compared to 17,800 MWh in 2005. During the fiscal year 2005-06, it generated $1.1 million for the city on revenue of $7 million. It expects to do about as well this year, even though revenues are coming in short of the $11.7 million budget. Because Moreno Valley is 50 square miles, it has nine, 12-kV interconnections, although it is preparing to build a 115-kV substation to replace some of these.
“We’re in a start-up stage, a growth stage,” Hanson said. Financially, “I would say it’s not ‘day-to-day,’ but it’s been rough. With the growth, our health will improve considerably.” He said he is “fairly confident” the growth will persist, albeit not at 65 percent. He is satisfied to this point. “I think it was a great decision for the city and that it will provide an important revenue stream, especially as the utility matures.”
Rancho Cucamonga Municipal Utility
—The idea to create the Rancho Cucamonga Municipal Utility came about during the price spikes of 2000-2001. “The City Council was looking for ways to protect citizens of the district from rolling blackouts,” said Mike TenEyck, administrative resource manager for Rancho Cucamonga Municipal Utility.
The utility was formed on paper in August 2001 and a feasibility study was commissioned. At about the same time, two developers were planning a 147-acre shopping mall. By March 2003, Astrum Utility Services presented a plan to make the mall the primary focus for a greenfield utility. The city decided not to go after residential load.
Everyone supported the plan except Southern California Edison, which was not as active as it could have been in opposing it, TenEyck said. The city dared Southern California Edison to shoot holes in the feasibility study. “It went back and forth a couple times, [but] up to the last meeting their biggest argument was ‘You guys have no experience whereas we’ve been around 100 years.’” But the City Council had confidence in its staff and decided to go forward.
Rancho Cucamonga Municipal Utility has been very successful, TenEyck said. It was energized in June 2004 and began serving the mall and a few other nearby customers. It now has 400 commercial and industrial consumers, whose peak last summer came to 12 MW. Energy comes mostly from two wholesale contracts, one with Corral Energy and another with the city of Vernon.
Rates are set to “mirror” those of Southern California Edison. “As theirs move, ours move. That was the policy adopted by the City Council.” The utility generated $3.2 million in gross revenue during 2004-05.
Two years ago the utility experienced its only outage, which lasted two hours.
To date, $9.3 million has been spent to construct a substation, an interconnection with Southern California Edison, and five miles of distribution lines. “We have an area our substation can reach efficiently,” said TenEyck. “Any vacant commercial or industrial development within that area will be served by this utility.”
Rancho Cucamonga Municipal Utility has no designs on Southern California Edison’s existing customers, and while new development is conditioned to take utility service from the municipal utility, it is not a hard sell. Developers like being able to forego the 34 percent federal income tax component they would have to pay to hook up to the investor-owned utility.
Corona Municipal Electric Utility
—Skyrocketing energy costs and rolling blackouts drove city leaders in Corona to form a municipally owned utility in April 2001, said General Manager Jonathon Daly. The investor-owned utilities in California “were doing a miserable job providing stable, reliable electricity at a reasonable cost. It was thought the city could be better served by a publicly owned utility.” It wasn’t a stretch for a city already providing water and wastewater service and there was strong support from the business community.
The city started with an attempt to take over Southern California Edison’s service territory, an effort that was abandoned after it became too lengthy, costly and controversial. “SCE knows how to protect its investment and made it known it was not going to go down quietly,” Daly said. “We’d have loved to take them over but the cost turned out to be double the original estimate and as the power crisis waned in late 2001, the urgency for a complete takeover subsided.”
The city did not get into the electricity business to create a revenue stream for itself, but rather “with the noble intent to provide a low-cost utility service to our customers that is locally controlled,” Daly said.
The City Council went with a green field strategy and also became an energy service provider, enabling it to offer direct access under California’s deregulation bill. Start-up costs were minimal, as Corona did not need new infrastructure for direct access load. “We started buying energy and getting revenue right away.” Corona began with 500 accounts serving its own municipal loads and signed more than 500 direct access customers before the window to do so closed in the aftermath of the energy crisis. Its green field and direct access profile now includes 336 residential, 1,427 commercial and 19 industrial consumers whose usage peaks at 38.7 MW. The utility sold 185,208 MWh in fiscal 2006 and sales totaled $19 million.
Customers seem satisfied. The only direct access customer with a renewable contract who did not re-up did so because it was leaving the area. Assistant General Manager Kerry Eden said customers leaving the city have asked if they could continue to receive city service at their new location.
Corona’s rates “are highly competitive—either right at or below” Southern California Edison’s, depending on the rate structure, Daly said. Most power comes under short-term contracts from the wholesale market.
In March 2005, Corona completed the $52 million, 32-MW Clearwater Power Plant, a gas-fired combined-cycle combustion turbine. With it, “we are not at the mercy of brownouts” and the excess heat is used in the wastewater plant to solidify biowaste, dramatically reducing hauling costs. Depending on market conditions, the city uses Clearwater output for its own needs or those of others. “When you own your own steel, there’s a lot of ways to get it to work for you. It can get very creative.”
Development in greenfields is conditioned on city electric service, but there are challenges. “Development has tapered off…and the type of development is changing,” Daly said. A stable pattern of low-density development has given way to a significant amount of high-end retail office space and mixed-use construction. “It’s like someone turned a switch.
It’s a change we haven’t got our arms around yet.” But it is favorable because it takes less infrastructure and fewer meters in a more concentrated area.
Because of its size, Daly is concerned about the city’s ability to meet the renewable power mandates while maintaining its competitive edge. But smallness does create some advantages. “We have less overhead; we don’t have 75 vice presidents and can be more flexible. “Can I predict we’ll come through this below cost or right at market? I can’t for sure, but I am optimistic.”
Hercules Municipal Utility
—Faced with a widening gap between revenues and expenses, providing electrical service was but one utility service the city of Hercules began contemplating in January 1999, well before the California energy crisis.
City officials resist pointing to a single reason for the formation of Hercules Municipal Utility. “Independence, rate stabilization or reduction, improved service to Hercules residents, [a] potential and significant source of revenue, and the ability to augment the general fund are all valid reasons,” the city wrote in a 2005 retrospective.
“Fundamental to the establishment of HMU was the concept of independence,” the report says. “Perhaps the single most important reason [was]…the ability to use the profit from this utility to provide public services to our residents without adding more taxes.”
“There were a number of factors,” said Raj Pankhania, Hercules Municipal Utility assistant general manager. Beyond local control, “we wanted to capture the dollars that were leaving our city” and going to PG&E.
Then came the rolling blackouts. “That truly wasn’t the driving force, but it emphasized it,” he said. Also critical was the high rate of growth projected for the community of 23,000.
The city knew the process might be lengthy, potentially cost-prohibitive and that the biggest hurdle would be dealing with PG&E. “No IOU would want to have [its] toes stepped on,” Pankhania said.
PG&E did employ a series of “typical scare tactics” to discourage the city, Pankhania said. They alleged that Hercules Municipal Utility’s cost of service would be high; the taxpayers would subsidize the venture; quality of service would be in question. But the IOU was unable to sway the City Council. “A city must have staying power, determination and grit” to take on electric utility service, Pankhania said. “You have to have a long-term commitment because this is not a flash-in-the-pan kind of business.”
In January 2000, the city hired Astrum Utility Services to conduct a study and a series of workshops on the feasibility of both electric and telecommunication service (the latter was dropped). Formation of HMU suffered a few false starts, first appearing on the council’s May agenda and not passing until January 2001.
“It was a lengthy process,” Pankhania acknowledged. The city hired two additional consulting firms to “work the numbers backward and forward. We had several dozen workshops and City Council meetings trying to determine whether this was viable.” Actual service did not begin until October 2002, initially with diesel generators. In November, tariffs were adopted and Hercules reached agreements with PG&E and the California Independent System Operator. Anticipating the construction boom, utility planners settled on a greenfield approach. They figured it would take six to eight years to get a positive financial flow. The city issued a $7 million bond to get the utility through its first five years.
So far, it has.
More than three miles of distribution line was built, nearly all underground. Pankhania acknowledged undergrounding is more costly, but said, in terms of reliability, overhead lines cannot compare. Hercules’ three interconnections also enhance reliability.
Additionally, it has developed its system as a loop, compared to PG&E’s radial system. When there’s an outage, Pacific Gas & Electric has no second system to provide service.
The city will also begin work on a new substation by year’s end.
To begin with, there were only 50 customers. Nearly five years later, there are 825.
Hercules Municipal Utility has a two-MW baseload and a peak of three-MW. Two-thirds of the consumers are residential, the rest commercial and light industrial. A Home Depot, a biotech firm and the city’s own 750-kW wastewater treatment plant make up over half the base load.
Hercules Municipal Utility’s rates for all customer classes have been 2 to 5 percent below PG&E’s, Pankhania said. “The projection is they will remain so.” Unlike the established municipal utilities, Hercules does not condition new development on taking electric service from the city. “Developers have a choice,” Pankhania said. They can go with HMU or PGE, “but we have a streamlined process for developers. We don’t have the cumbersome, convoluted process that PG&E has and our turn-around time is much shorter.” So far, the city has not lost a single customer to PGE.
Hercules Municipal Utility relies on a combination of long-term, short-term and spot market power. Its cost of power has been “relatively constant” but has been following the upward trend in gas prices.
Hercules is also looking at acquiring a wind resource. On paper, the city may be able to obtain wind at such a competitive price that it could lead to a retail rate decrease, Pankhania said.
Hercules’s financial performance “is on par, or even a little ahead” of projections, Pankhania said. “We are not in the black yet, but will be in the next couple years, so that is within our ballpark.” It depends on development. The city saw significant growth during the first three years, but this year construction slowed. Things are expected to pick up in the next couple years.
“Like in any venture, there are growing pains,” Pankhania said. In hindsight, he wishes the utility had waited longer to bring in-house the operational functions that consultants were handling, and the amount of time it took to get the utility off the ground caused it to lose some new development load. But, overall, the city did “the right thing.” The utility is not constraining its vision. Its 2005 report speculates that “perhaps someday our utility will be large enough to offer PG&E the opportunity to sell the balance of the city to our own municipal utility.”
—When the Navy offered to sell the gas and electric distribution system at its newly decommissioned Mare Island Naval Shipyard in 1996, bidders did not come pouring in. The only offer was from a joint venture between Enova and the California city of Pittsburg. Enova approached the city and financed the start-up costs, including the $50,000 purchase price for the aging equipment. That was later reduced to $1 when it was learned that there were environmental hazards such as asbestos-wrapped pipes.
The 4,350-acre Mare Island is within the boundary of the city of Vallejo at the north end of San Francisco Bay. Pittsburg is 20 miles east along the estuary that flows into the bay at Vallejo.
The Navy’s specs required the city to form a municipal utility, so on Sept. 23, 1996, the city and its redevelopment authority formed a joint power authority called the Pittsburg Power Co. Seven months later, Pittsburg Power created a public-private utility and named it Island Energy.
There were only four customers on the system when Island Power took over, but all parties were optimistic about the prospects for growth. Vallejo hired Lennar Property Corp. to redevelop the island. Enova operated the utility and split the proceeds with the city. Island Power operated the facilities under license from the Navy until September 2001, when the distribution facilities were sold.
Now, the utility is the only provider of electricity on the island, but Pacific Gas & Electric is welcome to put in its lines, said Island Energy General Manager Garrett Evans.
Under the Defense Conversion Act, the city got a full-requirements contract with Western Area Power Administration through 2024, which has better terms than the standard WAPA preference contract. It does not provide for load growth, but that has not yet been an issue.
“Unfortunately the island has not grown as quickly as thought. There’s been no major development in 10 years,” he said. “Island Power’s current baseload is five MW. “We were hoping to be more in the 10-MW to 15-MW range by now.” Until two years ago, the island had only industrial and commercial tenants. Still, Island Power has added more than 400 commercial customers and the distribution system is worth $16 million.
The utility is working with Lennar and Vallejo to create new incentives by building infrastructure and offering rate discounts.
Evans said Island Energy rates are 10 percent below those of PG&E for all customer groups. Reliability is good because the Navy had a lot of redundancy built in. But the equipment is 50 years old. “That’s why we look forward to development,” since every new subdivision means new equipment is built In 2002, the city agreed to pay Enova $425,000 to assume its share. The operations agreement was transferred to Mare Island Operation Co., which has about a dozen technical and management employees who report to PPC.
There was little, if any, opposition to Island Power, at least in Pittsburg, Evans said. “The Navy required us to have quarterly meetings with Vallejo and the largest tenants on the island, so issues are brought up there.”
During the first few years, Pittsburg Power helped Enron develop a 555-MW gas-fired combined-cycle combustion turbine in Pittsburg; when Enron sold it to Calpine, the city got a $25 million cut. The utility also helped secure a transmission right-of-way for an 880-MW combustion turbine plant Calpine built in Pittsburg. The city wanted to own the line, but at the last minute Calpine exercised an option to keep it in exchange for $16 million payment.
“If they hadn’t taken that off ramp, we’d have owned the line, had an asset and a revenue stream,” Evans said.
After a development hiatus, Pittsburg got back in the game as the lead city for Babcock and Brown’s Trans Bay Cable, a $400 million, 55-mile high-voltage dc transmission line that will go under San Francisco Bay from Pittsburg to San Francisco. PPC will own and operate the line. Babcock and Brown will build and finance it.
Island Energy is also exploring the possibility of serving all of Pittsburg’s 63,000 citizens.
“It’s a huge step,” Evans said, because the heavily industrial city is already served by Pacific Gas & Electric.
Pittsburg Power is strong financially, with several million dollars in reserves and roughly $500,000 in revenue. It’s been able to contribute about $100,000 per year to the city’s general fund, although it pays more than that in taxes to the city of Vallejo. It hopes the new Trans Bay Cable will add about $1 million in new revenue.
Island Energy is working with Lennar on a solar program in connection with the sale of new homes. Evans feels the hydro power Island Energy gets from Western Area Power Administration will help the utility meet its renewable portfolio contribution. Nonetheless, “I’ve got more solar and wind items on my desk right now than anything else.”
Port of Stockton Electric
—Port of Stockton Electric may have set a speed record for municipal utility formation. The gap between the day the port sent a demand letter to PG&E and the day in June 2003 when electricity began flowing was little more than three months. Port attorney Howard Golub said the speed was the result of a lot of good planning and not getting bogged down by the various tactics PG&E uses to drag things out, up the costs and wear out new market entrants.
As part of its base closure process, the Navy in the mid-1990s decommissioned nearby Rough and Ready Island. Seeing an opportunity for economic development, the port sought to acquire the island’s works, including its gas and electric distribution system. It gained operational control but did not take title until June 2000. The port operated the distribution system, reselling power to the island’s commercial and industrial tenants. By 2003, Deputy Port Director Jeff Kaspar said it became clear it did not make sense to own and operate the equipment while all the proceeds were going to PG&E. He also felt the port was paying too much for power.
PG&E was charging the port a retail rate under a FERC tariff for the power it was reselling to its tenants, Golub said. It was clear PG&E knew what was going on; when the port took title to the island, PG&E tried to have the distribution system transferred to it in what he believes was an initial effort to “snuff out” prospective port electric service.
Golub wrote the IOU saying it should recognize the port as a wholesale customer and that the port should be treated as a municipal utility with a right to an interconnection agreement. “After some resistance from PG&E, which we overcame, they agreed we had a right to purchase the power of our choice.” Appropriate papers were filed at FERC, leading to the unique situation in which a FERC action cleared the way for the operation of a public power utility. A transfer agreement was negotiated along with an interconnection agreement and a three-year distribution service agreement that has since been extended.
Also in 2003, the port signed a contract with a scheduling coordinator.
Now, under a recently renegotiated five-year, full-service power deal with Sempra Energy, the 135 consumers on the island are paying 30 percent less than when they were PG&E customers, Kaspar said. Reliability is just as good as it was under PG&E, he said. Since the formation, PG&E has attempted to collect various exit fees. In one case, the parties settled and PG&E paid Stockton Electric $75,000 and agreed to waive exit fees for the port’s own facilities. In another, the port won a favorable decision from the California Public Utilities Commission that ensured the IOU would not assess exit fees against the port’s tenants.
The port sees economic development and job creation as its core mission. It did not undertake negotiations with PG&E with the objective of creating a municipal utility, Golub said. “They came to me with a practical, down-to-earth concern.” Golub laid out the legal strategy and warned the port it would face a powerful adversary in PG&E. But port officials were “neither aggressive nor intimidated. They simply rolled up their sleeves and said: ‘Let’s do it.’” The port is not inclined to give PG&E permission to serve customers on the island. “We have not and would not,” Kaspar said. The port has no current plans to expand its utility beyond the island, but the subject does come up, he said.
For now the port is focused on operations. The utility does not yet turn a profit, although it expects to soon. Kaspar said current baseload is 2 MW with peaks of 2.6 MW. The port expects to triple that by 2010, which will make it possible to get beyond the break-even point, he said. The terms of the new five-year interconnection deal the port and PG&E filed with FERC last year allow for the delivery of 2.4 average megawatts of annual peak demand and 9.68 million kWh for 2006, rising to 3.45 average megawatts and 15 million kWh in 2011.
City of San Marcos
—The voters of San Marcos approved a city charter in 1994 that authorized the city to create a municipal utility but it was not until the height of the energy crisis in 2000-01 that the City Council voted to establish a gas and electric service called Discovery Valley Utility. Battered by blackouts and enormous rate increases from San Diego Gas & Electric, city leaders wanted a way to prevent such fiascos in the future.
San Marcos had to start at ground zero because it had no experience with any kind of utility service, said the city’s Karl Schwarm. With assistance from consultants, other California municipal utilities, California Municipal Utilities Association and the American Public Power Association, San Marcos considered a range of options, including municipalization and becoming a “community choice aggregator” under California’s deregulation statute. Ultimately, San Marcos decided to leverage its high growth rate by adopting a greenfield strategy.
But none of the strategies made financial sense unless they included a power plant, Schwarm said. In May 2001 the city took a stake in the Southern California Public Power Association’s 310-MW gas-fired plant in Burbank and worked on a number of potential renewable projects. But by 2003 Discovery Valley Utility still was not serving customers, “principally due to continued obstacles put in its way by the IOUs, the [California] PUC, as well as the state Legislature,” the city said.
The more serious the city became, the more seriously San Diego Gas & Electric sought to thwart the effort. By 2004, the conflict grew into a battle between two competing ballot initiatives—each supported by its own citizens group—one promoted by the city, the other by the IOU.
City Council support for a municipally owned utility was not unanimous. “I was against it,” said Councilman Hal Martin. It was too large an undertaking for the city. The battle would take years and would eclipse other important issues. He was not convinced the finances made sense and saw no advantage in putting council members in the inevitable position of having to vote for rate hikes from time to time.
Only three of the five City Council members were on board. By spring 2004, when the city had already spent $1.4 million on the project, one had a change of heart. That member concluded “it wasn’t feasible and was too risky,” said Schwarm. The city “lost the political will to go forward.” It pulled its share from the Southern California Public Power Authority power project.
In May 2004, the city and San Diego Gas & Electric agreed to “cease hostilities and work together,” Schwarm said. The city abandoned its utility plans in exchange for SDG&E’s promise to spend between $200,000 and $500,000 on public purposes in the city each year. The parties also agreed on language for a third ballot initiative that would prevent the city from distributing electricity for 10 years without a public vote. The city withdrew its earlier proposition, leaving the new one and the one SDG&E had championed. That November, voters approved both, but the one supported by the city and SDG&E got the wider margin, so it took precedence.
Relations with SDG&E have been good since then, Schwarm said. The IOU sends the city an annual report showing the value of public purpose spending in San Marcos. In 2006, spending amounted to $1.3 million, far above the level agreed to in 2004. The benefits are achieved through the aggressive promotion by both parties of SDG&E’s existing low-income, energy conservation and renewable programs within the city.
“We work collaboratively with SDG&E. As I call it, we are the door kickers,” he said. The city promotes the programs at street fairs and through neighborhood programs.
The “golden opportunity” for local control has passed, but the city has not abandoned the possibility of becoming a community choice aggregator, Schwarm said. Its commitment to SDG&E under the 2004 agreement expires in 2014 and it will be up to the City Council to renew it. Meanwhile, the Discovery Valley Utility, while not in service, still exists on paper.
Schwarm sees some positives from the city’s experience. “It got the attention of SDG&E. Maybe they became a better corporate citizen. It’s good to challenge the system every so often.”
Ben Tansey (email@example.com) is an energy writer in Seattle.