KEMA analysis finds many utilities starting to develop AMI and utility-of-the-future strategies
According to some projections, the North American AMI market will grow about 20% annually through 2010. However, to date, AMI or related SmartGrid initiatives have not been implemented on anything resembling a large scale in the United States. Thus, although in many ways AMI technologies are maturing, they can hardly be characterized as being fully mature at this point. While concerns about inadequate technologies and customer interest linger, a significant number of U.S. electric utilities – including many of the industry’s major players – are taking leaps of faith toward developing AMI/Smart Grid strategies.
Recently, KEMA gathered proprietary intelligence, which included informal surveys and in-depth research, on about 14 U.S. utilities developing or implementing AMI/Smart Grid pilots or projects. The intelligence gauged common trends, challenges, budgets, technology selections, and general market approaches. Our findings confirm many commonly held market assumptions but also reveal some surprising insights. We hope this intelligence will provide readers a pulse on where the U.S. AMI market stands and where it’s heading. The U.S. utilities from which we gathered AMI data were:
Because we wanted a diverse sampling of utilities with regard to current project status, regulatory climate, and technologies, other utilities pursuing AMI/SmartGrid technologies may have been omitted from this list.
The time is now
One sentiment echoed repeatedly among utilities we studied was that “the time is now” for AMI deployments. Many companies believe the technology is either near maturity or has evolved sufficiently enough that it is reasonably priced and can justify utility cost exposure. The increasing cost of electricity and energy efficiency are also drivers forcing many utilities to look closer at the impact of not developing TOU rates or other energy efficient programs that AMI technology supports.
In its regulatory filing before the Oregon Public Utilities Commission, Portland General Electric stated, “AMI is quickly becoming a mature technology. If we were to deploy AMI now, PGE would not be a pioneer in the field of AMI; we would be following the lead of a host of other utilities, both large and small, that have seen the value of AMI. Second, we understand from the attention that has been paid to AMI in Oregon that this is a policy issue many parties would like to see addressed.”
Pepco shared a similar attitude toward the belief that the timing for deployment is right. In regulatory filings, the company stated that “meter technology has evolved sufficiently to make this practical. AMI equipment is currently available from vendors at a reasonable cost, but availability may become more limited in the future as more utilities deploy AMI. Near-term AMI deployment will provide significant benefits to our electricity customers. The cost of electricity has risen significantly in recent years, thereby greatly increasing the need for detailed consumption data for all Pepco customers.”
Data we compiled related to current or planned AMI pilots and large-scale deployments. The data collected offered the following market averages available for download.
With a pilot lasting 36 months, Pacific Gas & Electric had the longest duration. Regarding full deployment, Southern Company had the longest deployment schedule with nine years, and Portland General Electric and Baltimore Gas & Electric had the shortest deployment schedules, each with three years. Pacific Gas & Electric has the largest planned deployment with a total of 9.3 million endpoints. All utilities we studied are deploying AMI in phases, typically based either on geographic region or customer class.
Technology preferences
Electric utilities appear to be choosing different technologies based on their specific requirements and geography characteristics. In the world of AMI solutions – whether limited to collecting meter data or extended to broader SmartGrid applications – utilities are faced with a growing and maturing technology mix. Among the current options are radio frequency (RF), power line communications (PLC), broadband over powerlines (BPL), cellular communications, WiFi, or some combination therein.
Some technologies have been designed with a vendor’s unique protocol or language, which can make integrating products from different vendors arduous and costly. Many utilities appear to be seeking commonality as a way to bridge differences between technologies. Most utilities want to have a “mix and match” approach to their future AMI technology needs. To prevent obsolescence, most utilities are keeping their options open, as they search for technologies that are upgradeable and able to easily interface with other products.
RF appears to be the dominant choice for the utilities on which KEMA focused, though it is often used in combination with BPL or PLC interfaces. RF is planned to support AMI Systems at Con Edison, Pacific Gas & Electric, Southern California Edison, and Xcel Energy. PG&E plans to use PLC technology to retrieve meter data and a fixed RF network for collecting and transmitting daily gas usage data. PG&E has opted to use a wide area network to control and manage interval data transmitted to its information systems for billing and customer viewing. Portland General Electric plans a similar approach.
Wireless mesh technology – a relatively new version of RF that allows meters to pass along reads from other meters – is gaining widespread significance in part due to its ability to incorporate high functionality at lower risks and competitive costs. It also appears to be better suited for some urban areas than traditional RF-configured systems that typically allow meters report to only one collector point.
Many utilities are looking toward industry standards before selecting technology solutions. For instance, many referred to the expected announcement later this year from the American National Standards Institute (ANSI) about publishing a new standard (C.12.22) that provides an application layer standard for network communications. This standard is designed to transport C.12.19 standard data tables in electric metering over any physical medium.
As a result, the open protocol in the ANSI C.12.22 standard will provide the same opportunity for meter communications over various networks, enabling each endpoint to communicate meter data in a similar manner. The manner by which the AMI network delivers the data packet – whether by use of cellular communications, WiFi, powerline communications, or RF – should not matter to the receiver, and the data content should not concern the AMI network. Put another way, the ANSI C.12.22 standard achieves the goal of being agnostic to the communications technology chosen by a particular utility.
Costs
Utilities are understandably concerned about the expense of AMI, given that AMI systems typically cost hundreds of millions – or even billions – of dollars. More specifically, utilities are examining how to recover costs for AMI/SmartGrid implementations. Historically, most utilities in the United States – many of which still operate in a heavily regulated environment or quasi-deregulated market structure – are inherently risk averse and pursue only large capital investments likely to receive cost recovery approval from regulators.
While AMI technologies are becoming more mature, there is still no “silver bullet” technology. Thus, many utilities are planning or pursuing AMI/SmartGrid business strategies without guarantee of cost recovery, and making contingent plans to absorb associated costs in other ways.
Rate recovery
Utilities planning or developing AMI System/SmartGrid initiatives are generally seeking to recover the difference between total AMI infrastructure cost and the operational savings it generates. We found that utilities are typically pursuing two regulatory strategies with regard to rate recovery:
Build AMI cost into rates in incremental increases over the deployment lifespan, or
Add a special surcharge to cover utility costs
Specific approaches are outlined in Chart 5 - "Rate Recovery regulatory Strategies" available for download.
As part of the regulatory strategy of their parent company, Pepco Holdings Inc., Pepco and Delmarva Power are seeking permission from the Maryland Public Service Commission to charge customers for planned investments in advanced meters and related DSM efforts. Pepco sought Maryland PSC permission to implement an advanced metering infrastructure surcharge and a DSM surcharge, with an accelerated amortization period for advanced meters. The metering surcharge would be $6/month for each customer, though the utility said the costs "will be offset by energy cost reductions, utility cost reductions and service quality improvements." The DSM surcharge would be 0.0812 cents/kWh for residents and 0.0334 cents/kWh for nonresidential customers. Delmarva Power earlier this year filed similar plans with the Delaware PSC, saying it plans to spend $135 million on advanced metering and demand reductions in its Delaware territory.
Con Edison has proposed recovery of all AMI and AMI-related costs concurrent with initiation of demonstration projects and implementation. Costs would include carrying charges on all capital associated with AMI investments and be recovered from all electric and gas customers.
Chart 5 -"Rate Recovery Regulatory Strategies" available for download.
Market drivers
With little variation, we heard three main drivers for AMI:
Regulatory directives/mandates;
Desire for customer service enhancements; and
Desire for greater operational efficiencies.
The AMI market certainly received a major push from the Energy Policy Act of 2005, which in Section 1252 states that all utilities, not just IOUs, will “provide customers with time-based rates and the ability to receive and respond to electricity price signals.” Although it does not dictate how utilities should do this, it is generally understood that to achieve this mandate, utilities will need more than an intelligent transmission and distribution grid – they will also need an intelligent connection to the customer (hence, smart meters).
Additionally, some state regulators have mandated AMI. The most obvious example includes California, where in 2004 the California Public Utilities Commission (CPUC) directed Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric to develop AMI business cases.
The CPUC’s primary intent was to encourage the three utilities to better manage power loads and encourage conservation. Each of California’s three large utilities is now pursuing unique AMI business models. PG&E is arguably the furthest down the deployment path as it has begun, and plans to achieve, full deployment by 2011. SCE and SDG&E are still testing technologies, and are scheduled to complete deployments by 2012 and 2011, respectively.
But California is far from the only state imposing regulatory mandates related to AMI. The following examples from other states illustrate aggressive regulatory policies on AMI:
Prior to EPAct, the New York Public Service Commission issued an order directing all state utilities to “develop and deploy, to the extent feasible and cost effective, advanced metering systems for the benefit of all customers.” In February and March 2007, utilities filed a plan with New York regulator that calls for some utilities to rollout the new meters starting in 2008.
Michigan’s governor issued an executive directive for the state PSC to develop a comprehensive plan for meeting the state's electric power needs. As part of the Plan, the Energy Efficiency Working Group extensively analyzes Statewide Utility Load Response Programs and smart metering implementation as resource options. In a report issued on Jan. 31, 2007, it recommended that the Commission be authorized to require the immediate use of active load management by utilities. Pilot programs, designed to assist customers in managing the electric load and reducing the costs, are also recommended.
Maryland House Bill 126 would require the Maryland PSC, by Oct. 10, 2007, to establish regulations specifying that electric companies make advanced meters available to residential customers. This bill has not advanced to the full House for a vote as of yet.
And in Texas, although regulators determined that AMI deployment was voluntary, utilities must receive approval from the Public Utility Commission of Texas of AMI six months prior to installation; file deployment progress every six months following filing of initial deployment plan; file number of meters that have been replaced due to malfunction; and use only AMI systems that have been successfully deployed on 5,000 meters or more in North America (excluding pilots). Texas also established certain features that must be included should a utility choose to implement AMI, such as having two-way communication features, remote connect / disconnect; and timestamp meter data that can be sent to independent organizations for settlement purposes.
Those mandates dovetail with utilities’ focus on improving customer service and operational efficiencies. Key internal objectives for AMI include .improving field service efficiencies for remote connects/disconnects, reliability (including both grid congestion and outage restoration/management), and operational cost savings. Others cite “maturing” technology as a driving factor, stating they were driven to evaluate AMI because the technology necessary to support smart metering and networks is finally available. Regulators’ current and future desires to increase demand response and energy efficiency/conservation are also pushing utilities toward AMI.
Other “societal” and other “benefits to customers” often help make the difference in a positive business case. Many utilities cite large projected benefits – sometimes in the hundreds of millions of dollars – related to Demand Response. Demand Response accounts for about $236M, or 30%, of the business case present value benefits at Con Edison. Many, including Con Edison and Portland General Electric, noted that demand response and related benefits will not be realized for several years.
Indeed, utilities are now analyzing how AMI will provide both short- and long-term benefits, improvements that could ultimately change how utilities operate now – and in the future.
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