A year ago, in its formal investigation of state policy on smart meters, the Florida Public Service Commission conceded that while three of the state’s five major investor-owned electric utilities offered an optional time-of-use rate to residential customers, participation in fact remained “typically quite small,” averaging only about 1 percent.
“This is most likely,” the commission ruled, “because the broad on-peak periods are difficult to avoid for most households.” In Florida, the typical TOU tariff charges higher peak prices from noon to 9 p.m. in summer, and between 6 and 9 a.m. and 6 and 10 p.m. in winter.
Nevertheless, despite this apparent lack of success, the PSC saw its approval of TOU rate options as “ample proof of our continued commitment” to demand response and time-based pricing for residential electric customers. With such policy already on the books, the commission saw no reason to go further. Thus, as many other states have done, it declined to adopt the new uniform federal standard on utility smart metering, otherwise known as the “time-based metering and communications standard,” or “PURPA Standard 14” for short, as enacted by Congress in the Energy Policy Act of 2005 (EPAct). (See Fla.P.S.C. Order No. PSC-07-0212, Docket No. 070022-EU, issued March 7, 2007.)
In fact, a careful reading of the regulatory decisions shows that the majority of state PUCs that have completed formal investigations of EPAct’s smart metering standard have followed Florida’s lead, opting to just say no. Their reasons are varied. Many cite a lack of convincing evidence that smart meters can prove cost-effective, especially for residential ratepayers. Others assert that customers aren’t very interested, as suggested by the Florida numbers, and by the similar and very modest 6 percent penetration rate for advanced meters across the country shown in surveys conducted by the Federal Energy Regulatory Commission. (See, e.g., “Advanced Metering Penetration by State,” Nov. 6, 2006, at www.ferc.gov/industries/electric/indus-act/demand-response/2006/survey).
Finally, many other PUCs simply echo the Florida argument—that since customers currently enjoy the option to choose a TOU rate, with installation of an interval meter, the state in effect already has a “comparable” policy on the books, and therefore need not consider or formally adopt the EPAct standard.
Three points stand out from the PUC rulings.
• Cost-Effectiveness: First, regulators insist that any state-sponsored deployment of smart meters must pass a cost-benefit test, even though the 2005 EPAct law appears mute on the point.
• Local Concerns: Second, while the EPAct standard might appear as a nationwide call for smart metering, the reality finds each PUC ignoring larger national concerns over energy independence, efficiency, and the environment, and instead focusing on its unique set of customer demographics and utility company characteristics.
• Technology vs. Tariffs: Third, the PUCs still appear to place greater faith in rate design and top-down programs for load management and demand response, than in bottom-up customer empowerment through whiz-bang technology.
These points bear remembering. For example, in the original PURPA law, the Public Utility Regulatory Policies Act of 1978, Congress first imposed a TOU rate standard on state-regulated electric utilities:
“The rates charged … shall be on a time-of-day basis which reflects the cost of providing electric service to such class of electric consumers at different times of the day unless such rates are not cost-effective with respect to such class.”
And yet, by contrast, the 2005 EPAct law (which amends the 1978 PURPA statute) contains no such explicit requirement.
Second, note that Congress in EPAct sec. 1252 actually required states to consider two different smart metering goals. First, it encouraged state action to broaden reliance on TOU pricing for all customer classes (not just commercial and industrial). Second, it invited wider and perhaps even ubiquitous deployment of “advanced” or “smart” meters—that is, meters capable of reading customer usage at hourly or even shorter intervals, with an added capability of two-way communications:
“Each state regulatory authority shall conduct an investigation and issue a decision whether or not it is appropriate for electric utilities to provide and install time-based meters and communications devices for each of their customers.” (EPAct, sec. 1252(b)(3)).
Nevertheless, as was seen in Florida, the state PUC rulings have tended to treat smart-meter deployment as sort of an extra bonus option. In nearly all cases, they have ruled that availability of load-management and demand-response programs, along with an offering of TOU tariffs (regardless of actual participation) are sufficient to show that current state policies satisfy the intent of Congress.
The PUC rulings suggest that states openly can oppose any sponsored deployment of smart meters, and yet if they find that TOU rate options are available to customers, they can (and do) claim that they support the spirit of EPAct and the smart metering standard.
PUCs in at least ten states said they wanted more comprehensive and persuasive cost-benefit analyses before mandating deployment of smart meters, and in some cases called for workshops or pilot programs to gather the needed information (see sidebar, “More Study Needed”).
Other states were less equivocal. Regulators in Kentucky, Alaska, and Virginia cited a lack of volatility in wholesale power purchase costs as a factor in deciding not to adopt the EPAct smart metering standard.
The Kentucky PSC declined even though it found that few utilities in the state offered TOU rates to residential customers:
“As shown by the testimony … Kentucky’s low electricity rates and the minimal difference between current rates and real-time prices … make it inappropriate … to mandate a statewide smart metering standard. Those same factors also make it questionable whether Kentucky’s electricity consumers could enjoy reduced costs from mandated smart metering or real-time pricing.” (Ky.P.S.C., Admin. Case No. 2006-0045, Dec. 21, 2006, also reported at 254 PUR4th 124.)
Alaska raised a similar point: “The evidence ... reflects minimal incremental cost fluctuation per kilowatt-hour … [Anchorage Muni. L&P] provided specific analysis suggesting that the maximum variation in the incremental cost of energy is only 1.5 percent of the current residential energy charge.” (Alaska R.C.A., No. R-06-5, Aug. 8, 2007.)
On a similar point, Virginia opposed mandating time-based metering or equipment for utilities that purchase wholesale power through long-term contracts or other arrangements that offer no options for the purchasing utility to obtain time-based cost variations. (Va.S.C.C., Case PUE-2006-00003, July 18, 2006, at 251 PUR4th 350.)
In declining the EPAct standard, several states declared that retail electric customers simply don’t have any real enthusiasm for smart meters or the constant tracking of real-time or hourly prices that such technology would allow.
• Kentucky: “All the electric utilities testified that they have found little or no interest in TOU rates by residential customers.”
• Minnesota: “A smart metering system could have potentially negative consequences for low- and fixed-income and low-usage utility customers, who have limited ability to access information sources such as the Internet.” (Case E-999/CI-06-a59, Aug. 10, 2007.)
• Virginia: “Customers may not be capable of or willing to, among other things, vary demand and usage in response to changes in prices based on specific time periods, manage costs by shifting usage to lower cost or [sic] off-peak time periods, or reducing consumption.”
• Wyoming: “This section [the EPAct standard] is not a real opportunity for Wyoming ratepayers because the economic and social makeup of the state does not make smart metering a useful tool.” (Docket No. 90000-95-XR-06.)
North Carolina regulators worried that mandatory deployment of smart meters could force the state’s major electric utilities to phase-out newly installed AMR-capable meters that had been installed only recently to replace old-fashioned, manual-read meters. “The AMR meters are in the early years of their life-span,” the commission noted. “It would not be cost-effective to remove large numbers of relatively new meters.”
Utah gave voice to the strong undercurrent found in many PUC cases—the persistent belief among state regulators that administrative, top-down tariffs and load-management programs might achieve more energy conservation and efficiency, lower rates, and customer welfare, than bottom-up metering deployments that rely on effective decision-making by empowered consumers:
“We suggest, however, there is a larger issue which will not be addressed by a cost-benefit analysis … whether adoption of a smart metering standard is more effective in addressing PURPA goals than, say …new or existing demand management programs or modifications to the existing time-of-day rate schedules.”
Bucking the tide is South Carolina, which directed utilities both to make smart meters “available” to customers, and to initiate a PR campaign to win loyalty from customers:
“We note conspicuous lack of focus on residential and commercial customers with respect to smart metering.
“We therefore order the utilities to … inform all customers of the availability and capability of smart meters, how they may use those capabilities to better manage their power requirements.” (Dockets 2005-385-E, 2005-386-E, Order 2007-618, Aug. 30, 2007.)
It may be that smart-meter deployment never will pan out as cost-effective unless meter proponents are allowed to cite societal or intangible benefits to prove cost-effectiveness. Indeed, some regulators—and not just those in progressive states like California—are encouraging such an approach. The Ohio PUC, for example, ruled the smart metering cost-benefit analysis “should include system benefits that may accrue to the electric distribution utility,” plus “customer benefits and societal benefits.”
To perform such an analysis, the commission staff said the first priority “should be to conduct the cost-benefit analysis in a uniform, transparent format,” and recommended that utilities employ the so-called “McKinsey Model.”
The commission agreed on the use of the McKinsey Model (or any demonstrably superior model), but the problem remains on how to measure societal and intangible benefits.
The McKinsey Model is available to the public for download from the McKinsey & Co. web site. It includes a 26-page user guide plus some 40 pages of Excel spreadsheets. Those spreadsheets provide real-world numbers for costs, benefits, net present values and internal rates of return that might be expected over 20-years for a hypothetical, 5-year project to deploy 1.1 million smart electric meters (1 million residential; 100,000 C&I), plus 550,000 smart gas meters. That’s a pace of 1,374 meters per day.
The model recognizes and analyzes virtually all conceivable categories of costs and benefits, including taxes, equipment, software, labor (both union and contract), and O&M (meter reading, billing, and of course collection).
Speaking on condition of anonymity, a veteran utility consultant (not from McKinsey) explained that the model has gained popularity with many state PUCs, but is not designed to be an off-the-shelf model requiring only a set of input data to produce an immediate result. And it doesn’t resolve doubts about intangible factors.
“As yet the McKinsey model doesn’t provide any framework to capture societal benefits such as impacts on reliability, energy efficiency, reduction of greenhouse gases and overall carbon footprint,” he said. Nor does it currently analyze intangible customer benefits such as increased satisfaction due to better service and billing, or wider offerings and choices.
“Depending upon the regulatory environment,” he added. “These benefits … can be credited even though not all directly impact the bottom line.
“These benefits, though hard to quantify, are benefits nevertheless.”