Excerpted from “Summer of Discontent,” Fortnightly’s August 2010 Frontlines column.

As America approaches summer’s Dog Days, the debate over smart meters is heating up. Utilities in at least four states are facing public backlash against smart-meter rollouts — and that’s not counting the class-action lawsuits previously filed against Oncor and Pacific Gas & Electric in Texas and Bakersfield, Calif., respectively.

NORTHERN CALIFORNIA: About 60 residents picketed offices of the California Public Utilities Commission (CPUC) in San Francisco on July 20, carrying protest signs and chanting such slogans as, “One, two, three, four, smart meters no more.” The demonstrators voiced concerns about privacy and personal choice issues, as well as the meters’ radio-frequency transmissions and their possible effect on human health. Several local governments in Northern California, including Berkeley, Marin County, Santa Cruz and San Francisco, petitioned PG&E to stop its smart-meter rollout pending further public hearings and studies.

The Marin Independent Journal published an editorial on July 20 that stated, “Forcing your customers to do something without first making sure they are comfortable with it is not the best way to run a business.”

MARYLAND: Executives at Baltimore Gas & Electric were stunned when the Maryland Public Service Commission (PSC) decided in June to deny the company’s DOE-funded smart-grid investment plan. The decision came in the midst of a heated gubernatorial campaign, in which Gov. Martin O’Malley (D) is campaigning on a theme of green jobs, while former Gov. Robert Ehrlich (R) accuses the O’Malley administration of killing jobs with anti-business regulations. Against this backdrop, BGE petitioned for expedited re-hearing and amended its plan to address the PSC’s concerns—most notably by deferring and limiting BGE’s proposed capital-expense “tracker”; eliminating shareholder incentives for achieving demand-reduction targets; accelerating the depreciation of the new meters; making time-of-use rates voluntary instead of mandatory; and proposing a customer communication and education plan. The commission agreed to schedule hearings for early August.

OHIO: The Westerville city council voted in a closed-door meeting on July 20 to postpone a final vote on the municipal utility’s federal stimulus-funded smart-grid project. Chairman Mike Heyeck announced afterward that the postponement would allow the council to field questions and comments from Westerville residents, and to “provide additional opportunity to learn more about advanced metering” via a series of public events and outreach efforts.

The council’s decision came in the wake of growing public discontent, expressed at a July 6 city council meeting, where the residents who showed up spoke overwhelmingly against smart meters. ThisWeek newspaper quoted resident Charles Voight Jr. expressing outrage over the remote disconnection capabilities of smart meters, and the city’s decision to accept federal stimulus dollars. “This process seems to have been predetermined, with the grants being applied for without the public giving their full consent,” Voight reportedly said. “I personally will not let you into my home, remember that.”

Andy Boatright, electric utility manager for the city of Westerville, told Fortnightly in a phone interview that many of the 30-plus people who have expressed opposition to the project have focused on the federal government’s role. “I think it’s primarily a function of the federal grant,” Boatright said.

COLORADO: Xcel Energy awaits a decision by the Boulder city council on whether to recommend that voters renew Xcel’s utility franchise. That’s right; the celebrated Smart Grid City might actually walk away from its utility partner.

Xcel’s 20-year agreement expires at the end of 2010, and the utility wants Boulder to sign up for another 20 years. But surveys indicate voters would reject such an agreement, as well as an alternative plan that would impose an excise tax on Xcel—which the company would pass through to customers in monthly bills. Council members reportedly are considering municipalizing Boulder’s utility services if voters reject both initiatives.

Negative public sentiment over Xcel’s franchise agreement might be tied to the company’s Smart Grid City project, which has encountered its share of problems—from ballooning capital costs to disappointing participation in its demand-response program. Xcel CEO Dick Kelley told Fortnightly in June, “There’s huge value on the utility side of the meter, but it hasn’t been that successful on the customer side. I guess some people thought Boulder residents were super-environmentalists, but in fact they just want their TV to work and their beer to be cold when they get home.”-Michael T. Burr

Business-as-Usual Will Stifle Nuclear, Coal Development

In a letter dated July 21, Duke Energy CEO James Rogers urged Senate Majority Leader Harry Reid (D-Nev.) to “include a carbon title in your base energy bill that allows this country to move forward.” Rogers argued that a business-as-usual approach to carbon regulation would stifle development of new nuclear and coal-fired power plants and make America dangerously dependent on volatile natural gas markets.

Rogers also referred Sen. Reid to a McKinsey analysis that showed U.S. GDP would grow more under a “utility first” carbon regulation scenario than it would without any carbon regulation, and that carbon allowances and efficiency improvements would actually reduce electricity bills on average by 7 percent.

Rogers’ letter arrives just as Senate Democrats were convening to debate whether to include a carbon title in an energy bill sponsored by the majority leader. The San Francisco Chronicle’s website quoted Senate sources predicting that a scaled-down bill would proceed in late July and would not include carbon regulation, but some legislators—including Sen. Joe Lieberman (I-Ct.)—are hoping to retain the carbon title in Reid’s bill.-Michael T. Burr

NY PSC Phases-In Hike to Soften Blow in Weak Economy

July 22, 2010 - Weekly Update From Utility Regulatory News #3977: In recognition that the local economy remains in an underperforming mode, the New York Public Service Commission, in authorizing new rate schedules for an electric and natural gas utility, has postponed as long as possible certain of the rate increases approved therein. The commission said the new three-year plan for Central Hudson Gas & Electric Corp. (CHG&E) takes into account the torpid economy and seeks to mitigate the impact on ratepayers by delaying a substantial portion of the increase to the plan’s second and third years, in the hopes that the economy will have improved by then.

For electric distribution service, CHG&E is allowed to raise rates by $11.8 million in the first year, $9.3 million in the second year, and $9.1 million in the final year. Of the initial increase, the commission estimated that approximately 80 percent of the higher charges were necessary to cover additional local property taxes, the capital costs of infrastructure projects, and uncollectibles expenses, which have grown as the economy has soured. For natural gas delivery service, CHG&E is permitted to raise rates by $5.7 million in the first year, $2.3 million in the second year, and $1.6 million in the third year. According to the commission, about 50% of the first year increase is attributable to the same three items cited for the electric increase.

The rate plan includes an earnings sharing mechanism that is weighted toward customers, with ratepayers entitled to 50 percent of any earnings exceeding a 10.5 percent return on equity (ROE) in any one year. Should CHG&E’s earnings exceed an 11 percent ROE, the customer share would rise to 80 percent, and that share would go as high as 90 percent if the utility’s ROE reaches 11.5 percent or higher.

The commission expressed optimism that the earnings sharing mechanism will be of significant value to ratepayers should the economy finally begin to recover. Subscribe to URN for the full story.

Cyber security and customer privacy of paramount concern

July 22, 2010 - Weekly Update From Utility Regulatory News #3977: Reiterating its support for the most modernized electric network possible, the California Public Utilities Commission has released an updated plan for transforming the state’s grid into a safer, more reliable, and more efficient interoperable system.

The commission asserted that the measuring sensors, advanced meters, and automated control technology that form the backbone of smart grid networks facilitate communication between electric utilities and the grid as well as between the utilities and their customers. The special equipment allows for more timely collection and dissemination of operational data and also can help utilities integrate greater amounts of renewable energy into their resource portfolios. In the commission’s view, such smart grid technology not only can improve service reliability, by easing transmission congestion for instance, but also can encourage ratepayers to reduce or shift their usage, such that the need for additional new power plants is mitigated. The commission contended that, in turn, air quality can be improved and other environmental benefits achieved when new generating units can be avoided.

However, the commission said, it recognized that the electronic transmission of data has its risks, and it declared security to be a critical policy matter for it as it strives to implement smart grid fixtures. It expressed a commitment to enacting measures that will protect both the physical grid and private consumer information from being manipulated externally. To that end, it instructed the state’s electric utilities to include cyber security in their strategic planning deliberations and to abide by all cyber security rules and recommendations listed by the National Institute of Standards and Technology as well as by the U.S. Department of Homeland Security. 

With such protections in place, the commission said, the state would be poised to bring its electric grid out of the “industrial age” and into the “information age” of technology. It added that its goal is to see not just a smart grid, but also a smart market, a smart utility, and a smart consumer. Subscribe to URN for the full story.

Tax consequences of federal health care reform cited in DPUC’s decision

July 22, 2010 - Weekly Update From Utility Regulatory News #3977: Although acknowledging that the local economy remained sluggish, and that an electric utility seeking additional revenues already had among the highest rates in the country, the Connecticut Department of Public Utility Control (DPUC) has nevertheless authorized the utility, Connecticut Light & Power Co. (CL&P), to raise its rates by more than $100 million over the next two years.

The department explained that the company had demonstrated that it actually had postponed its rate filing by a year out of sensitivity toward its ratepayers and that it also had forgone claims for certain expenses for the same reason. According to the DPUC, the poor economy has taken a toll on the utility, not just its customers, such that a rate increase was warranted. In fact, despite trimming some of CL&P’s operational expenses, it actually boosted one cost category, that of vegetation management. The DPUC said that it was important to keep power lines cleared of overgrown trees so as to reduce the number and duration of service outages caused by downed power lines.

The department also found that certain accounting changes required under the federal government’s new health care reform bill would affect the utility’s tax liabilities. Because that new law eliminates the corporate tax deduction for expenses allocable to Medicare Part D subsidies beginning in 2013, CL&P will not be able to realize tax benefits associated with certain deferred tax assets already on its books.

Even though those changes will not take effect until after the instant rate-effective period ends, the DPUC agreed that it would be appropriate to create a regulatory asset now to reflect the total projected impact of the reform legislation. Subscribe to URN for the full story.

Finds they exceed Michigan RPS requirements

July 22, 2010 - Weekly Update From Utility Regulatory News #3978: While not discounting the importance of renewable energy in the resource strategies of electric utilities, the Michigan Public Service Commission nevertheless has reduced an electric utility’s jurisdictional renewable power supply cost for rate-making purposes, to reflect the fact that the company had been exceeding the proportion of renewable power needed to meet the state’s renewable portfolio standard (RPS) requirements.

The utility, Wisconsin Electric Power Co. (WEPCO), is headquartered in neighboring Wisconsin but has a multistate presence. It had allocated $5.4 million in renewable power costs to its Michigan services, based in part on Wisconsin’s RPS requirements, which provide that 4.27 percent of retail sales in 2010 and 8.27 percent by 2015 must qualify as renewable energy. However, the commission pointed out that Michigan had adopted a less ambitious RPS program with a lower minimum purchase term, such that the amounts attributed to WEPCO’s Michigan operations were clearly excessive.

According to the commission, WEPCO actually had been acquiring more renewable energy than it needed even for the Wisconsin RPS targets. The commission said it had discovered that for the period 2011 to 2014, WEPCO’s renewable power commitments ranged from 31 percent to 120 percent more than necessary for meeting Wisconsin’s RPS requirements. As a result, the commission reduced WEPCO’s Michigan revenue requirement by more than $4 million to account for the excess purchases. Subscribe to URN for the full story.

Ratepayers to foot most of cost

July 22, 2010 - Weekly Update From Utility Regulatory News #3978: Deeming smart grid technology to be a prudent investment, the Oklahoma Corporation Commission has preapproved up to $366.4 million in program costs for Oklahoma Gas & Electric Co. (OG&E) to construct a smart grid system.

The estimated costs of the program include a $130 million stimulus grant from the federal government. Although ratepayers will be expected to cover $220 million of the costs, OG&E said the smart grid network will save them money at the same time, including more than $20 million in operation and maintenance (O&M) expenses and $8 million in meter reading costs. The utility was authorized to recoup its project costs from customers via a smart grid recovery rider (SGRR) over a 42-month period, the end of which should coincide with the company’s next scheduled rate case in 2013.

To facilitate reconciliation of the SGRR in that 2013 proceeding, the commission ordered that three regulatory assets be established, one as a smart grid O&M account, one as a stranded meter cost account, and one as a Web portal account. Although ratepayers will be funding the program through the SGRR, they also will be credited with any cost savings achieved as a result of consumption reductions, shifts in usage, or other energy efficiencies made in response to information obtained from the new smart meter equipment.

Despite widespread support for smart grid technology, and in spite of assertions that the smart meters to be used have tested 99.98 percent accurate, one commissioner dissented, saying that a more measured approach should have been taken and that any preapproval of costs should have been limited to incremental stages. Subscribe to URN for the full story.

Weekly update courtesy of URN #3976: Determining that purchases of power from renewable resources are of regional, not just statewide, importance, and citing the possible implications of a recently filed civil lawsuit, the Massachusetts Department of Public Utilities (DPU) has temporarily ceased enforcement efforts of regulations that require electric distribution companies to solicit long-term “green” power supply contracts only from developers within the state.

The DPU explained that Massachusetts law has established through its renewable portfolio standard program a certain minimum threshold amount of energy that electric utilities must procure from renewable resources, such as wind, solar, and biomass. However, the law presently restricts long-term purchases of such to being from renewable power suppliers whose facilities are located within Massachusetts, or at least within state or federal waters. But the DPU acknowledged that a competitive energy services marketer has challenged that limitation in a federal district court, alleging that the law discriminates against out-of-state generators and thus violates the Commerce Clause of the U.S. Constitution.

In light of that pending litigation, and asserting that it was reasonable to facilitate the ongoing development of renewable energy sources throughout the region, the DPU ruled that existing in-state purchase requirements should be lifted, at least for the interim. It therefore authorized electric utilities to reopen their renewable power solicitations so as to consider bids from eligible out-of-state generators in addition to in-state suppliers. Subscribe to Utility Regulatory News for the full story.

Gas LDC’s proposal deemed insufficient incentive for conservation.

Weekly update courtesy of URN #3976: Following the trend seen in several other states recently, the Tennessee Regulatory Authority (TRA) has become the latest governing body to deny a utility’s petition to institute a revenue decoupling mechanism.

In the case before the TRA, a natural gas local distribution company (LDC), Piedmont Natural Gas Co., had requested permission to implement a decoupling program, claiming that absent the ability to break the link between actual sales and revenues, it would have no impetus for promoting conservation, energy efficiency, and other usage reduction measures. According to the LDC, decoupling would provide it with the means for aligning its own financial objectives with the best interests of its customers.

Piedmont’s proposal was premised on a decoupling program with a true-up mechanism that would allow full recovery of the average per-customer margin. However, in looking at the LDC’s earnings statistics that underlie its plan, the TRA observed that such earnings were based on a benchmark from the company’s last rate case, which had been in 2003. Using a reference point from that long ago could translate into a disincentive for customers to lower their consumption levels, the TRA said.

The TRA explained that Piedmont had structured its decoupling mechanism in such a way that a consumer could reduce usage but not see any decrease in the amount billed. To address its concerns that the LDC’s outdated rate-making data could skew customers’ bills, regardless of their conservation efforts, the TRA ruled that it would be imprudent to authorize a decoupling program in a stand-alone proceeding. Instead, it determined that decoupling should be considered within the context of a full-blown rate case. Subscribe to Utility Regulatory News for the full story.

Weekly update courtesy of URN #3976: Finding that any ratepayer benefits from an electric and natural gas utility’s proposed “smart meter” rollout would be “largely indirect, highly contingent and a long way off,” the Maryland Public Service Commission (PSC) has disapproved the company’s advanced metering infrastructure (AMI) program.

The utility, Baltimore Gas & Electric Co. (BGE), had submitted a plan under which every meter in its service territory would be replaced with a new AMI module. Although BGE professed that a stimulus grant of $136 million from the U.S. Dept. of Energy would be dedicated to the project, the PSC noted that total plan costs were estimated to be $835 million, with the company seeking to hold its customers liable for the difference via a special surcharge mechanism that would go into effect before the meter installation work even began.

The commission expressed displeasure at the utility’s attempt to saddle its ratepayers with the entire cost of the new metering equipment. Explaining that a utility’s metering network is a backbone component of its service system — i.e., part of its infrastructure — and that utilities traditionally have invested their own funds in such plant, the PSC said that it could not authorize the AMI initiative as proposed.

The commission added that it also strongly objected to another part of the plan that would have made time-of-use (TOU) rates mandatory for residential customers during the summer season. In the commission’s view, whatever benefits a customer might receive as a result of a smart meter being installed at his or her premises likely would be greatly mitigated, if not completely negated, by the combination of the surcharge and the mandatory TOU schedules.

The commission emphasized that its rejection of BGE’s smart meter program as presented should not be taken as an indication of the PSC’s nonsupport of AMI programs in general. To the contrary, the commission stated, it fully endorses the concept of AMI deployment, and it invited BGE to return with a revised AMI business plan that was more equitable in cost sharing and not as “untenable” as the present proposal. Subscribe to URN for the full story.