Regulators and legislators build momentum for AMI studies and deployment
The Energy Policy Act of 2005 Section 1252 (EPAct) requires electric utilities to consider time-based rates and smart metering options for all customer classes. Since the EPAct enactment in August 2005, it has built a lot of momentum for the smart metering industry. Not only does EPAct bring smart metering discussions to the policy forefront, it provides nationally unified guidance to state regulators and utilities.
Although few state commissions have adopted the demand response and smart metering policies as specified by EPAct, many are conducting cost-benefits studies and pilot programs to further explore the merits of smart metering in their unique territories. In December 2007, Congress enacted The Energy Independence and Security Act of 2007 that further supports Smart Grid technologies. As a result, state and federal regulators announced earlier this month that they will convene a collaborative dialogue on facilitating the country’s transition to a smart electric grid.
This article explores how different agencies, regulatory bodies, and Congress are contributing to moving utilities toward implementation of advanced metering infrastructure (AMI).
Department of energy report and recommendations on demand response
EPAct requires the Department of Energy to educate consumers, work with states to remove barriers, and report annually on state adoption status. On Feb. 4, 2006, the DOE published a report on “Benefits of Demand Response in Electricity Markets,” which included its recommendations for achieving those benefits. The report concludes that it is impossible to quantify national demand response benefits; these benefits are best estimated by service territory or region because the magnitude of potential benefits is directly tied to local conditions such as market design, demand growth, and resource balance. Nevertheless, the report provides specific recommendations for the electric industry to enhance demand response programs and their enabling technologies.
FERC annual report on demand response and advanced metering
EPAct also requires the Federal Energy Regulatory Commission (FERC) to publish an annual report, by appropriate region, that assesses electric demand-response resources, including those available from all customer classes. FERC published its first report, Assessment of Demand Response and Advanced Metering, in August 2006. The report presented results of a comprehensive nationwide survey of existing demand response programs and penetration of advanced meters.
In September 2007, FERC published its second report on demand response and advanced metering. The report updates the results from 2006 and further identified three important challenges associated with advanced metering —Technological Obsolescence Concerns, Interoperability and Open Standards, and Deployment Decisions. The forewarning of these issues enables utilities and state regulators to make informed decisions during their AMI implementation. Notably, as a result of the technological obsolescence concerns, utilities can mitigate these risks by including warranties requirements in their request for proposal (RFP) process and by requiring firmware be remotely upgradeable.
NARUC resolution in support of AMI
EPAct requires state commissions to investigate whether it is appropriate for their regulated utilities to implement the standards set out by the EPAct. As of early February 2007, only eight states have made a determination via formal proceedings, and most of these states decided not to adopt EPAct as written. On Feb. 21, 2007, the Board of Directors of the National Association of Regulatory Commissions (NARUC) approved a resolution that offers recommendations for states that are facilitating cost-effective AMI technologies. NARUC further resolves that the federal tax code regarding to depreciable lives for AMI investments should be amended to reflect the speed and nature of change in metering technology. Moreover, NARUC supports movement toward an appropriate level of open architecture and interoperability of AMI to enable cost-effective investments, avoid obsolescence, and increase innovations in technology products.
State regulators vary on AMI direction
The EPAct deadline for AMI determinations was August 2007. To date, most of the states have opened a proceeding and made a determination. Some states do not have a formal proceeding on EPAct but already have dockets opened to explore real-time pricing and advanced metering with larger Demand Side Management or Integrated Resource Planning processes.
Seven states are already complying with EPAct
Seven states determined that they have already complied with EPAct and no further deliberation is necessary. Compliance with EPAct is interpreted as either (1) meeting the EPAct standards to offer time-based rates and smart metering to all customer classes; or (2) having met EPAct standards to the extent applicable. Therefore, no further EPAct- related deliberations are needed.
Alabama concluded that its public utility commission had already approved numerous time-based rates. Its regulated utility Alabama Power Company provides appropriate meters to customers choosing to receive service under them. In addition, Alabama Power is currently implementing an advanced metering program across all customer classes.
Florida concluded that its public utility commission has continued to explore and implement time-based customer programs where these options are cost-effective.
Georgia determined that it has already implemented a comparable standard through processes such as integrated resource planning and base rate cases.
Hawaii concluded that “current and proposed time-of-use rates are generally consistent with the PURPA standards and that adoption of one size fits all standards may have unintended consequences.”
Missouri determined that individual companies already have time-based tariffs that satisfy the EPAct standard.
New York stated that it “has already implemented a sufficient time-based metering and communications standard to comply with PURPA...We interpret the comparable standard to include time-based metering and communications devices that are made available to some, but not all, electric customer classes.”
South Carolina’s regulated utilities all have offered time-based rate schedules for some time and a number of large load customers take advantage of programs that provide real-time load data to facilitate the ability of customers to manage their power requirements.
Only four states adopted EPAct or modified version of EPAct
New Hampshire and Ohio have decided to adopt the EPAct standards. Commissions in both of these states ordered their electric utilities to file time-based tariffs and report on their associated metering capabilities.
The Arizona Corporation Commission adopted the time-based rate portion of EPAct but only requires its regulated utilities to implement AMI if it is cost-effective.
The North Dakota Public Service Commission only requires its utilities to offer time-based schedules and smart meters to large commercial and industrial customers. However, it requests the utilities to report annually on the progress towards the feasibility of making smart metering available for all customers.
Most state commissions decided not to adopt EPAct (at this time)
The majority of states (in fact, 22 of the 43 states with an EPAct proceeding) decided not to adopt EPAct at this time. Although, in general, all states support the idea of time-based pricing and smart metering, most states decided not to adopt the EPAct standards based on lack of demand in existing programs, the universality of the EPAct requirement, or the scarcity of cost-benefit analyses.
Many of these states, like Colorado and Indiana, are now conducting pilot programs. Vermont opened a proceeding to conduct cost-effectiveness analysis of smart metering to support advanced time-of-use pricing. Kentucky and Iowa joined the Midwest Demand Resource Initiative (MWDRI) to facilitate the development of a demand side program.
It is clear that the rejection of EPAct from most states is not a rejection of the policy itself, but rather the timeline the federal law has set for the states to determine its applicability.
Nine states and DC are pending in EPAct decision
While some states decided not to adopt EPAct before pilot programs and cost-benefit studies are completed, other states decided to defer the decision.
The District of Columbia is currently conducting a two-year PowerCentsDC Smart Meter Pilot Program and will defer the EPAct decision until findings from the pilot program are analyzed.
The Illinois Commerce Commission will not decide on EPAct until its staff has information on the cost and benefits of ubiquitous deployment of time-based meters.
The Nevada Public Utilities Commission directed its utilities to file cost-benefit analyses and research on AMI.
New JerseyBoard of Public Utilities and the Pennsylvania Public Utilities Commission have separately formed working groups to consider the requirements of EPAct.
Montana and the Washington Utilities and Transportation Commission are deferring the determination until the general rate cases for each utility.
New Mexico and Rhode Island have solicited comments and held technical workshops. However, no determination has been made in either state.
Although Texas has active rulemakings to determine the functionality criteria for advanced metering requirements, it has not progressed on making a determination on EPAct.
States with no proceedings
Eight states have no formal proceedings to address EPAct Section 1252 compliance: California, Connecticut, Maine, Massachusetts, Nebraska, Oklahoma, Oregon, and Wisconsin. However, most of these states already have dockets opened to explore time-based rates and smart metering.
The California Public Utilities Commission has existing proceedings that direct utilities to address demand response and AMI issues. All of California’s regulated utilities have submitted and received approval for their system-wide AMI deployment strategies.
The Connecticut legislature enacted the Electricity and Energy Efficiency Act in 2007. It requires each electric distribution company to submit a plan to the Department of Public Utility Control to deploy an advanced metering system that is capable of tracking hourly consumption to support proactive customer pricing signals through innovative rate design all customer classes.
The Maine legislature also introduced a smart metering bill in 2007 that requires the state commission to establish a smart meter program. Although the bill is dead, the smart metering dialogue continues. The Maine Energy Council recommends conducting costs and benefits study of new technologies that can “facilitate demand response programs in which customers can react to real time prices by shifting demand to lower cost periods.”
The Massachusetts Department of Telecommunications and Energy is conducting an investigation on the benefits of dynamic pricing for all default customers. At the same time, the Department of Public Utilities is considering rate structures that will promote efficient deployment of demand resources.
Nebraska utilities are all publicly owned, and therefore not subjected to the utilities board’s jurisdiction. The largest utilities (Omaha Public Power District and the Nebraska Public Power District) are both separately considering EPAct.
The Oklahoma Corporation Commission (OCC) does not have a formal proceeding on EPAct to investigate Section 1252. However, the OCC held a few technical sessions to explore the issues. In October 2007, the OCC issued a notice of proposed rulemaking to establish rules promoting Energy Efficiency and Demand Program requirements and requested its utilities to file Demand Side Management plans.
Oregon State law requires a "market-based" rate for all residential and small business customers. Two of Oregon’s utilities (Portland General Electric and Idaho Power) intend to install two-way AMI throughout their territories within the next 2 years.
Wisconsin does not have a formal determination on EPAct. In a staff recommendation, WI is already in compliance on smart metering.
Federal smart metering and smart grid legislations
Congress has also introduced multiple bills to promote smart metering in 2007.
H.R. 2305 “Smart Meters” Act of 2007 attempts to amend the Internal Revenue Code to assign a five-year recovery period for depreciation of qualified time-based meter and related communication equipment placed in service by an energy supplier or energy service provider.
H.R. 3220, H.R. 3221, and H.R. 3237 (collective known as the “Smart Grid Facilitation Act of 2007”) attempt to establish a “grid modernization commission” to implement Smart Grid technologies; coordinate efforts with states and utilities; and develop and implement a National Action Plan on Demand Response.
H.R.6 “The Energy Independence and Security Act of 2007”, an omnibus energy legislation, was enacted on Dec. 19, 2007. The law requires the Secretary of Energy to:
Report regularly to Congress on the status of the deployment of Smart Grid technologies and any regulatory or government barriers to continued deployment; (Section 1302).
Establish a Smart Grid Advisory Committee to advise the Secretary of Energy on the development of Smart Grid technologies, the deployment of such technologies, and the development of widely-accepted technical and practical standards and protocols (Section 1303).
Develop advanced measurement techniques to monitor peak load reductions and energy efficiency savings from smart metering, demand response, distributed generation, and electricity storage systems; conduct research to advance the use of wide-area measurement and control networks; to test new reliability technologies; investigate the feasibility of a transition to time-of-use and real-time electricity pricing (Section 1304)
Establish a Smart Grid regional demonstration initiative focusing on projects using advanced technologies for use in power grid sensing, communications, analysis, and power flow control (Section 1304).
Establish a program to reimburse 20 percent of qualifying Smart Grid investments (Section 1306).
Report to Congress regarding the results of a study that provides a quantitative assessment and determination of the existing and potential impacts of the deployment of Smart Grid systems on the security of the electricity infrastructure and its operating capability (Section 1309)
The law also establishes that:
The Director of the National Institute of Standards and Technology is primarily responsible for coordinating the development of a framework for protocols and model standards for information management to gain interoperability of Smart Grid devices and systems (Section 1305).
Each state must consider requiring electric utilities demonstrate that, prior to investing in non-advanced grid technologies, Smart Grid technology is determined not to be appropriate. States must also consider regulatory standards that allow utilities to recover Smart Grid investments through rates (Section 1307).
Conclusion
The regulatory and legislative environments have been very favorable to the smart metering technologies since 2005. Although few states are complying with the EPAct standards, all of the states are moving in the direction to decide on AMI strategies that are best for their territories. It is important that the AMI dialogues among federal, state, and utilities continue to be active. This will ensure technology is interoperable, best practices are identified, and wheels don’t get invented twice.
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