NOTICES
PENNSYLVANIA PUBLIC UTILITY COMMISSION
Implementation Order
[39 Pa.B. 3574]
[Saturday, July 11, 2009]Public Meeting held
June 18, 2009Commissioners Present: James H. Cawley, Chairperson; Tyrone J. Christy, Vice Chairperson; Kim Pizzingrilli; Wayne E. Gardner; Robert F. Powelson, Statement
Smart Meter Procurement and Installation; Doc. No. M-2009-2092655
Implementation Order By the Commission:
The Pennsylvania General Assembly (General Assembly) has directed that electric distribution companies with more than 100,000 customers file smart meter technology procurement and installation plans with the Commission for approval. 66 Pa.C.S. § 2807(f). This Implementation Order will establish the standards each plan must meet and provide guidance on the procedures to be followed for submittal, review and approval of all aspects of each smart meter plan. This Implementation Order will also establish minimum smart meter capability and guidance on the Commission's expectations for deployment of smart meters.
Background and History of this Proceeding
Governor Edward Rendell signed Act 129 of 2008 (''the Act'' or ''Act 129'') into law on October 15, 2008. The Act took effect 30 days thereafter on November 14, 2008. Among other things, the Act specifically directed that within 9 months of its effective date, electric distribution companies (''EDCs'') are to file, with the Commission for approval, a smart meter technology procurement and installation plan. 66 Pa.C.S. § 2807(f)(1). Each EDC smart meter plan must describe the smart meter technologies the EDC proposes to install, upon request from a customer at the customer's expense, in new construction and in accordance with a depreciation schedule not to exceed 15 years. 66 Pa.C.S. § 2807(f)(1) and (2). The Act also establishes a requirement for EDCs to make available to third parties direct meter access and electronic access to meter data by third parties, upon customer consent. 66 Pa.C.S. § 2807(f)(3). The Act further defines minimum smart meter technology capabilities. 66 Pa.C.S. § 2807(g). Finally, the Act establishes acceptable cost recovery methods. 66 Pa.C.S. § 2807(7).
On March 30, 2009, the Commission issued a Secretarial Letter seeking comments on a draft staff proposal and additional questions regarding EDC smart meter procurement and installation. Comments were due by April 15, 2009, with reply comments due April 27, 2009. On April 9, 2009, the Commission, at the request of several interested parties, issued a Secretarial Letter extending the comment period to April 20, 2009, and the reply comment period to April 29, 2009.
The following parties filed comments: West Penn Power Company, d/b/a Allegheny Power (''Allegheny''); Citizen Power (''Citizen''); Constellation NewEnergy, Inc. (''Constellation''); Duquesne Light Company (''Duquesne''); Elster Integrated Solutions (''Elster''); The Energy Association of Pennsylvania (''EA''), Exelon Energy (''Exelon''); Metropolitan Edison Company, Pennsylvania Electric Company, Pennsylvania Power Company (collectively ''FirstEnergy''); the Industrial Energy Consumers of Pennsylvania (''IECPA''); Office of Consumer Advocate (''OCA''); PECO Energy Company (''PECO''); PPL Electric Utilities Corporation (''PPL''); Sensus Metering Systems (''Sensus''); Tendril Networks, Inc. (''Trendril''); and Trilliant, Inc. (''Trilliant''). The following parties filed reply comments: Duquesne; EA; FirstEnergy; IECPA; PECO; and PPL.1
Discussion
In this section the Commission will outline the standards each plan must meet and provide guidance on the procedures to be followed for submittal, review and approval of all aspects of each smart meter plan. This section will also establish guidance on the Commission's expectations for the deployment of smart meters, as well as minimum smart meter capabilities. This section will also describe requirements regarding access to smart meters and data. Finally, in this section the Commission will provide guidance on EDC smart meter technology cost recovery.
A. Plan Approval Process
Within 9 months after the effective date of Act 129, each EDC with more than 100,000 customers is to file a smart meter technology procurement and installation plan with the Commission for approval. 66 Pa.C.S. § 2807(f)(1) and (6). As Act 129 became effective on November 14, 2008, the smart meter plans must be submitted on or before August 14, 2009. Each smart meter plan shall include: a summary of the EDC's current deployment of smart meter technology, if any; a plan for future deployment, complete with dates for key milestones and measurable goals; and such other information as is required by this Order. The plans shall be served on the Office of Consumer Advocate, the Office of Small Business Advocate, the Office of Trial Staff, and Electric Generation Suppliers licensed to provide service in the Commonwealth.
Comments to the smart meter plans will be permitted to be filed by September 25, 2009. Following the receipt of comments, the plans will be referred to the Office of Administrative Law Judge for such proceedings as may be deemed necessary. There will be at least one technical conference scheduled for each plan during October, 2009, at which the filing EDC will present personnel with in-depth knowledge of the plan who can respond to questions regarding all aspects of the plan. The technical conference(s) shall be transcribed and the transcript(s) will become part of the record in the proceeding.2 Any evidentiary hearings that may be necessary shall be held during November 2009.
At the conclusion of the technical conference and any evidentiary hearings that may be necessary, an initial decision will be issued resolving all issues raised in the proceeding. It is anticipated that an Initial Decision will be issued on or before January 29, 2010. Parties will be permitted to file Exceptions and Reply Exceptions as set forth in Section 5.533 of the Commission's Regulations, 52 Pa. Code § 5.533. Parties are strongly encouraged to pursue settlement opportunities during the proceeding. It is expected that the comments and technical conference(s) will promote settlement efforts.
Several parties provided comments on the staff proposal's plan approval process. The EA asserted that the plan approval process should be a collaborative process rather than an adversary proceeding. We note that, after smart meter plans are referred to the OALJ, the proceedings will be conducted in accordance with the Commission's Rules of Administrative Practice and Procedure. This does not mean that the plan approval process must be a contentious adversary proceeding. We encourage parties to seek collaborative solutions to issues that arise during the plan approval process. Nevertheless, due process considerations require that we preserve the right of the parties to litigate if cooperative solutions cannot be reached and obtain an adjudication from the Commission.
Several commentators, including the OCA, expressed concern that the plan approval process described in the staff proposal did not provide adequate time for review of smart meter plans. They noted that Act 129 does not prescribe the period for reviewing and approving smart meter plans. Consequently, they argued that the plan approval process can and should be extended so that the review of smart meter plans is not unduly constrained.
In addition, the OCA and other commentators asserted that the proposed plan approval process should be modified to improve coordination with other proceedings required by Act 129. They point out that, under the plan approval process as described in the staff proposal, comments would be due and technical conferences would be held during August and September, 2009. During that same period, the EDCs, the statutory advocates, the ALJs and many other interested stakeholders will be engaged in Act 129 proceedings regarding Energy Efficiency and Conservation Plan approvals. These commenters conclude that the plan approval process should be modified so that it is better integrated with Energy Efficiency and Conservation Plan approvals.
Allegheny, on the other hand, asserted that Initial Decisions should be issued quickly due to the time necessary to implement plans following their approval. In addition, Duquesne expressed its support for the plan approval process described in the staff proposal.
While the Commission agrees with the need to complete the plan approval process expeditiously, we are persuaded that the process, and its results, will be improved considerably if we extend the time period for reviewing and approving plans. We will not, however, adopt OCA's proposal as that proposal does not provide the ALJs with adequate time to prepare an initial decision following the receipt of briefs and reply briefs in December 2009.
Accordingly, as outlined previously, we will require smart meter plans to be filed with the Commission on or before August 14, 2009. Comments may be filed with the Commission on or before September 25, 2009. Technical conferences will be held during October 2009, with evidentiary hearings, if necessary, to be held during November 2009, and Initial Decisions to be issued on or before January 29, 2010. Any party may file Exceptions and/or Reply Exceptions to the Initial Decisions, in accordance with Commission Regulations, before the Commission issues its final decision.
B. Smart Meter Deployment
Act 129 requires EDCs to furnish smart meter technology: (1) upon request from a customer that agrees to pay the cost of the smart meter at the time of the request; (2) in new building construction; and (3) in accordance with a depreciation schedule not to exceed 15 years. 66 Pa.C.S. § 2807(f)(2). The Commission recognizes that a fully functional smart meter involves more than just the meter hardware attached to the customer's premises. A fully functional smart meter that supports the capabilities required by Act 129 and as outlined as follows, involves an entire network, to include the meter, two-way communication, computer hardware and software, and trained support personnel. The Commission also recognizes that it may take time for EDCs to select and install the required smart meter network components, and to train support personnel.
1. Network Development and Installation Milestones
As EDCs will need time to develop and install the entire smart meter network, the Commission is granting a network development and installation grace period of up to 30 months following plan approval. During this grace period the Commission will not require EDCs to install a smart meter at a customer's premises. However, during this grace period, the Commission will require EDCs to provide interval data capable meters, if the existing meter is not capable of providing interval data, and direct access to the customer's interval data to third-parties, such as EGSs or CSPs, upon customer request.3 The access to this interval data should be available in real-time, if requested, and in a manner consistent with RTO requirements. In addition, EDCs will be permitted to continue to offer their already established and approved time-of-use rate programs.
The Commission also directs all covered EDCs to include in their smart meter procurement and installation plan filing a proposal for meeting specific milestones within this 30 month grace period. Each covered EDC must include a justification and its plan for meeting the following milestones:
* Assessment of needs and technological solutions.
* Selection of technologies and vendors.
* Establishment of network designs.
* Establishment of plans for training personnel.
* Establishment of plans for installation, testing and rollout of support equipment and software.
* Installation, testing and rollout of support equipment and software.
* Establishment of plans to design, test and certify EDI transaction capability consistent with this order.
* Establishment of plans for installation of meters consistent with the rollout requirements described as follows.
Each plan must include a schedule to meet each of these milestones, as well as specific reporting deadlines when the EDC will provide this Commission with reports on the status of its plan.
Several commentators provided input regarding the proposed 18 month network development and installation grace period. Overall, the topic of an 18 month grace period was the issue that generated the most consensus. The general take on the issue was that 18 months was not nearly enough time for the EDCs to have their smart meter networks up and running. Among those holding this position was: the EA, Allegheny, PPL, FirstEnergy, PECO and Duquesne. Specifically, PPL noted that just the selection and procurement process for the meters would take 18 months, while a separate 18 month period would be required for planning and development associated with meter data management and an additional couple of years for the installation and integration of such systems.
FirstEnergy urged the Commission to remain flexible with its time lines, due to the inherent differences of the EDCs' service territories and starting points. The EA, FirstEnergy and PECO asserted that the 18 month grace period should not commence until a vendor contract is approved. PECO anticipated delays in the marketplace due to the high number of EDCs purchasing smart meters and network equipment at the same time and suggested delaying the start of the grace period until a final vendor contract is signed and approved. The EA supports the use of key goals and milestones for each EDC and encourages flexibility of such goals, as all EDCs are unique.
It seems clear that the suggested 18 month grace period is not a sufficient amount of time for the EDCs to design and install their smart meter networks. The Commission agrees that some flexibility must be provided in the design and installation of a smart meter network, as some EDCs face greater logistical challenges than others do. Therefore, the Commission has established a period of up to 30 months for each EDC to assess its needs, select technology, secure vendors, train personnel, install and test support equipment and establish a detailed meter deployment schedule consistent with the statutory requirements. This grace period will commence upon Commission approval of an EDC's smart meter plan. This will afford each EDC more time and flexibility in the design and development process to ensure that it can meet the demands and challenges unique to each service territory.
2. Customer Request
As pointed out previously, the Commission will not require EDCs to deploy smart meters until after the EDC's Commission approved network development and installation grace period ends. Once this grace period expires, each covered EDC must supply a smart meter upon request by a customer, per Act 129.
The Commission recognizes that deployment of smart meters on a piecemeal or individual basis could involve greater costs than a systematic systemwide deployment. The General Assembly recognized this as well when it included the proviso that the customer requesting the smart meter must agree to pay for the cost of the smart meter. However, the Commission does not believe it was the intent of the General Assembly for this customer to pay the entire cost of the smart meter and its supporting infrastructure. Such a requirement would be so cost-prohibitive that no customer would request a smart meter. Furthermore, the customer would be paying for the smart meter directly and also through the EDC's cost recovery mechanism. Such a result would be an absurd, impossible and unreasonable outcome, which is contrary to the rules of statutory construction. See 1 Pa.C.S. § 1922(1). To avoid this absurd result, the Commission believes that only the incremental costs over and above the cost for systemwide deployment are to be paid by customers requesting early deployment of a smart meter.
The Commission directs each covered EDC to include in its smart meter plan a proposal to install individual smart meters in advance of the EDC's systemwide deployment and after the network installation grace period. This proposal should include an itemization of the incremental costs. If an EDC cannot provide the incremental costs at the time of its initial filing, it will have to seek Commission approval of these incremental charges prior to the expiration of the approved network grace period. If an EDC does not obtain approval of these incremental costs prior to the end of the grace period it must install individual smart meters at its own expense. Such costs are not recoverable from ratepayers.
Several commentators expressed concerns regarding the costs associated with installing smart meters at customer request under 66 Pa.C.S. § 2807(f)(2)(i). OCA agreed that a customer should pay for the incremental costs of installing a meter prior to the scheduled rollout. However, OCA does not feel that the customer should have to provide payment upfront to cover the costs, but rather the costs should be recovered through an increased customer charge on the customer's monthly bill. OCA also warns that care must be taken to ensure that the customer is not being subjected to any sort of double recovery. PECO and FirstEnergy maintain that the customer must pay these costs as a lump sum at the time of the request, as stated in Act 129.
FirstEnergy submits that 52 Pa. Code § 57.20(h) provides that ''a service watt-hour meter which is removed from service shall be tested for 'as found' registration accuracy.'' FirstEnergy requests that the Commission provide EDCs with a blanket waiver of this requirement, as the meters are not being replaced due to any perceived malfunction and will not be put back into service. FirstEnergy posits that such a waiver will eliminate unnecessary costs associated with systemwide smart meter installation.
Duquesne states that the incremental costs to an individual customer would be astronomical because reading the new meters without having deployed the entire infrastructure would require the purchasing of trucks and the hiring of meter readers and administrative office workers to manually enter the meter reads.
The Commission interprets the Act to mean that a customer must pay the costs of installing a meter at the time of the request, and hence disagrees with OCA's assertion that the costs should be embedded in a customer charge. The EDC needs to be reimbursed for the task of installing a meter on a piecemeal basis, and the easiest way to accomplish that recovery is not through a customer charge increase, but rather by receiving an upfront payment from the customer.
As for Duquesne's worry about the incremental costs being astronomical, the Commission believes there is confusion when Duquesne says it is worried about reading meters before the new infrastructure is in place. The Commission is not requiring an EDC to do anything extraordinary during this smart meter procurement and installation grace period. The requirement to install interval capable meters during the grace period or smart meters at the request of a customer is intended to support rate structures, energy efficiency or demand response programs offered by the EDC or a third party at the request of a customer. These types of programs have been in place and offered to customers for decades. All the Commission is requiring is that EDCs facilitate these programs in a cost effective manner that provides access to the data needed to support these programs without unnecessary or unreasonable barriers. Therefore, the Commission expects the EDCs to provide a plan for supporting these programs in such a manner that does not require unreasonable or imprudent costs. Furthermore, all incremental costs that EDCs plan on recovering from a customer must first be reviewed and approved by the Commission. Staff believes these costs will be reasonable and by no means astronomical.
The Commission agrees with FirstEnergy that the costs of complying with 52 Pa. Code § 57.20(h) are unnecessary and will grant a waiver of this provision for watthour meters that are being replaced with smart meters in accordance with an approved plan. The Commission believes it would add unreasonable and unnecessary costs to require the EDCs to test every meter removed for the purposes of upgrading to a smart meter.
3. New Construction
As with all equipment, meters have a useful life. EDCs determine how much to invest in meter equipment based on its useful life and have an opportunity to depreciate that investment over the useful life of the meter. In addition, EDCs have an opportunity to recover the cost of the meter from ratepayers. Therefore, if a meter is replaced prior to the end of its useful life, the EDC will not be able to take advantage of the full depreciation of that meter or the ratepayers will pay an increased rate to cover the cost of both meters. The Commission believes that the intent of the Act's provision for installing smart meters in new construction was to avoid this waste and added expense.
Again, the Commission will not require deployment of smart meters in new construction during an EDC's approved network grace period. However, the Commission will direct all covered EDCs to develop a plan to install smart meters in new construction that is begun after the network grace period. Therefore, the Commission directs each covered EDC to include in its smart meter plan a proposal for deployment of smart meters in new construction. Such a proposal should include a plan to identify new developments and construction early enough to incorporate it into the system-wide deployment proposal.
Several parties commented on the proposed rollout of smart meters in new construction. OCA posits that smart meters should be installed on new construction from the beginning, even during the network installation grace period. OCA asserts that while the smart meters will not be fully functional, the smart meters should still be able to provide the necessary billing data. FirstEnergy, PECO and PPL disagree, noting that while the meter may be able to provide billing data, the method for providing that data may not be compatible with its existing systems. FirstEnergy does not object to providing smart meters on new construction after the grace period, provided that the Commission allows for flexibility in making the smart meters fully functional and that the customer pays the incremental costs. Duquesne asserted that installation of smart meters should be addressed in the same manner as installation at customer request. Duquesne notes that customer preference should determine which meter to install between the end of the grace period and system-wide deployment.
The Commission agrees with FirstEnergy, PECO and PPL that installation of smart meters on new construction during the grace period would not be practical or cost-effective as the EDCs will not have selected the technology they will employ. Furthermore, the smart meter may not be compatible with its existing meter reading technology. As such, the Commission directs EDCs to handle any new construction customer that requests a smart meter during the grace period under to the procedures addressed above for customer requested meters.
4. Systemwide Deployment
The Commission believes that it was the intent of the General Assembly to require all covered EDCs to deploy smart meters systemwide when it included a requirement for smart meter deployment ''in accordance with a depreciation schedule not to exceed 15 years.'' It is this systemwide deployment that will provide the foundation for the EDCs' smart meter installation plans. Therefore, it is crucial for the EDCs to develop a plan that will best meet the needs of their service territory, while at the same time operating in a manner that is both cost and time effective.
The EDCs shall detail their systemwide deployment plans to the Commission, including any type of tiered rollout the company proposes, as well as the associated costs and benefits incurred from such a rollout. This systemwide plan should also incorporate a coordination element with the new construction deployment component. Furthermore, the Commission will require all EDCs to file a ''Smart Meter Progress'' report on an annual basis that will update the status of their installation plans, including the number of customers who received meters in the prior year, the estimated number of customers scheduled to receive meters in the coming year, and all costs associated with the meter plan incurred during the previous year.
It should also be noted that Act 129 uses the language ''not to exceed 15 years.'' An EDC is encouraged to expedite the deployment process if it will provide increased customer benefits in a cost-effective manner. Again, the primary goal of the EDC deployment plan should be to implement a deployment and installation schedule that best balances the overall efficiency and timeliness of the smart meter installations with the costs incurred.
OCA commented that the Commission needs to clarify whether the 15 year depreciation schedule outlined in Act 129 commences upon plan approval or following the grace period. The Commission believes that the 15 year depreciation period should commence upon plan approval, and that the grace period is simply a period of time within that 15 year time frame.
C. Smart Meter Capabilities
Act 129 defines smart meter technology as including metering technology capable of bidirectional communication that records electricity usage on at least an hourly basis, including related electric distribution system upgrades to enable the technology. 66 Pa.C.S. § 2807(g). The Act further states that the smart meter technology must provide customers with direct access to and use of price and consumption information, to include: (1) direct information on their hourly consumption; (2) enable time-of-use rates and real-time price programs; and (3) effectively support the automatic control of electricity consumption by, the customer, the EDC or a third-party, at the customer's request. 66 Pa.C.S. § 2807(g).
The Act further requires that default service providers submit time-of-use rates and real-time pricing plans by January 1, 2010, or at the end of the applicable generation rate cap period, whichever is later. Default service providers must offer the time-of-use rates and real-time pricing plans to all customers that have been provided with smart meter technology. 66 Pa.C.S. § 2807(f)(5). Real-time pricing is defined as ''a rate that directly reflects the different cost of energy during each hour.'' 66 Pa.C.S. § 2806.1(m). A time-of-use rate is defined as ''a rate that reflects the costs of serving customers during different time periods, including off-peak and on-peak periods, but not as frequently as each hour.'' Id.
The Commission believes that the smart meter capability requirements set out in Act 129 are minimal requirements. The Commission also recognizes that smart meter technology can support more than demand response and pricing programs. Smart meters have the ability to support maintenance and repair functions, theft detection, system security, consumer assistance programs, customer-generator net metering, and other programs that increase an EDC's efficiencies and reduce operating costs. Therefore, the Commission directs that a covered EDC's smart meter technology must support the following capabilities:
1. Bidirectional data communications capability.
2. Remote disconnection and reconnection.
3. Ability to provide 15-minute or shorter interval data to customers, EGSs, third-parties and the regional transmission organization (''RTO'') on a daily basis, consistent with the data availability, transfer and security standards adopted by the RTO.
4. A minimum of hourly reads delivered at least once per day.
5. Onboard meter storage of meter data that complies with nationally recognized nonproprietary standards such as ANSI C12.19 and C12.22 tables.
6. Open standards and protocols that comply with Nationally recognized nonproprietary standards, such as IEEE 802.15.4.
7. Ability to upgrade these minimum capabilities as technology advances and becomes economically feasible.
8. Ability to monitor voltage at each meter and report data in a manner that allows EDC to react to the information.
9. Remote programming capability.
10. Communicate outages and restorations.
11. Ability to support net metering of customer-generators.
12. Support automatic load control by EDC, customer and third-parties, with customer consent.
13. Support time-of-use and real-time pricing programs.
14. Provide customer direct access to consumption and pricing information.
While the Commission believes that all of the previously-listed capabilities will further facilitate the consumer's ability to intelligently control their electric use and costs, we are cognizant that the costs of some of these added capabilities may exceed any benefit they may provide. Therefore, the Commission reserves the authority to waive the requirement for any of the Commission imposed requirements as described in section E.1. This waiver authority does not extend to the minimum requirements delineated in 66 Pa.C.S. § 2807(g).
Several commentators provided input regarding the smart meter capabilities listed in the staff proposal. We will address each of the major issues raised by commentators relating to smart meter capabilities.
1. Remote disconnect, reconnect, service limiting and prepay capabilities
In their comments, Allegheny and PECO favor requiring smart meters to support remote disconnect and reconnect, as well as service limiting and prepaid service programs. Duquesne supported remote disconnect and reconnect for single phase, self-contained and class 200 or less meters, but suggested that revisions to Chapter 56 need to be considered before committing to these capabilities. PPL noted that there are institutional impediments to deployment of remote disconnect and reconnect capability. In addition, PPL and OCA noted that remote disconnect and reconnect, as well as, service-limiting and prepay functionality involves significant public policy considerations that raises process and safeguard issues. OCA is further concerned that by requiring smart meters to support remote disconnect, service limiters and prepaid service sends a strong signal to EDCs to implement these capabilities. OCA specifically stated that ''the use of smart meter technology to terminate customers, limit service, or require prepayment of service raise significant concerns for the health and safety of the residents of the Commonwealth.''4
The Commission agrees in part with Allegheny, OCA, PECO and PPL. Specifically, the Commission agrees that the significant policy implications of service limiting and prepaid service should be addressed in another proceeding prior to requiring such capability in smart meters. Therefore, we have removed support for service-limiting, and prepaid service as a minimum capability requirement. This does not preclude EDCs from including these capabilities, however, an EDC cannot employ these capabilities unless it is approved by the Commission and consistent with regulations governing such programs, such as 52 Pa. Code § 56.17.
The Commission does not believe that the same policy uncertainties exist with regard to remote disconnect and reconnect. The policy issues and procedures regarding termination and reconnection of service are addressed in the Public Utility Code (''Code''), at 66 Pa.C.S. §§ 1401--1418 and this Commission's regulations. Requiring the ability to remotely disconnect and reconnect service in no way abrogates an EDC's obligation to adhere to the Code or this Commission's regulations. Therefore, the Commission will require that smart meters have a capability to remotely disconnect and reconnect service as it provides the ability to increase safety, efficiency and cost benefits.
Ability to provide 15-minute reads
Duquesne, FirstEnergy, PECO, PPL and OCA do not support the inclusion of 15-minute or shorter interval data capability. Instead the parties support hourly data intervals. Duquesne supports hourly and real time pulse data. OCA and PECO assert that the 15-minute or shorter requirement goes beyond Act 129. PECO notes that this requirement is not practical or useful for residential or small commercial customers and that mandating collection of this data may result in increased costs with no benefits. PPL adds that there is less need today than in the past for 15-minute interval data as settlements are conducted on an hourly basis.
However, PPL also recognized that some demand side management programs require less than hourly data intervals. To accommodate this limited group of customers, PPL recommended that the Commission direct that EDC Smart Meter Plans demonstrate how this need will be met. An example offered by PPL involves access protocols for parties to obtain pulse data when hourly data is not sufficient.
Constellation, Elster and Trilliant support the inclusion of the 15-minute or shorter interval data capability. Constellation contends that each meter should be programmable so that a 1-, 5-, 15-, 30- or 60-minute interval could be set. This interval should be based on customer requirements rather than administratively set by the Commission. Elster notes that typical residential systems are capable of providing 15-minute interval data. The interval selected may be more or less frequent depending on specific utility application. Trilliant adds that systems should be configurable to intervals between 5- and 60-minutes. Elster, however, notes that the shorter data intervals will increase costs.
The Commission agrees with Constellation, Elster and Trilliant and concludes that the ability to provide 15-minute or shorter interval data is appropriate. We stress however, that the ability to provide 15-minute or shorter interval data does not mean that EDCs must collect this data on all customers at all times. The ability to provide 15-minute or shorter interval data will allow for EDCs and third parties with customer consent to offer and support rate plans that utilize this level of granularity. The Commission will therefore require that EDC smart meter plans demonstrate how the need for 15-minute or shorter data intervals will be met.
2. Meter storage
Duquesne supports on board meter storage of meter data that complies with Nationally recognized non-proprietary standards without specifying one particular standard. FirstEnergy supports ANSI C12.22 and C12.19 or their equivalents. PPL indicates that standards should be followed as appropriate, but questions why it is necessary to follow standard protocol for storage in the meter that is unlikely to be communicated anywhere but the EDC repository.
The Commission agrees with FirstEnergy and has added the ANSI C12.22 standard. The ANSI C12.19 and C12.22 are standards for storage and transport of register data over a network. The Commission is aware that a number of factors including memory size, number of data channels being recorded and interval length can impact the number of storage days. The intent of a minimum number of storage days is to ensure that adequate monthly billing data is retrieved before the data is overwritten. Therefore, rather than reference a specific number of days, the Commission requires that EDC smart meter plans incorporate provisions ensuring that all billing data is retrieved before data is overwritten and recoverable following communications outages.
3. Open standards and protocols
Tendril suggests that the Commission should accept any Nationally recognized, nonproprietary standard. Trilliant adds that protocols should be focused at a high level, such as IEEE 802.15.4 (open standard for radio technology). Allegheny notes, for example, that ZigBee is built upon this standard. Elster, however, emphasizes that there is more than one protocol. Duquesne cites the existence of 14 HAN solutions, open or otherwise. The Commission agrees that protocols should be focused at a high level, such as IEEE 802.15.4, and therefore, directs compliance with this standard. The Commission also encourages EDCs to adopt other open protocols and standards that enhance interoperability that are developed subsequent to this order, to the extent available at the time the vendor contract is solicited.
4. Upgradability
Duquesne suggests that technology should be evaluated to accommodate future upgrades, noting that some capabilities can be upgraded as technology advances and becomes economically feasible, while other capabilities are costly to implement without complete meter and system replacement. Duquesne emphasizes that it is difficult to implement a system now to accommodate unknown technical advances. Similarly, PPL notes that it is more important to build flexibility into smart meter systems than it is to anticipate every future need.
The Commission agrees with Duquesne that some capabilities can be upgraded as technology advances and becomes economically feasible, while other capabilities are costly to implement without complete meter and system replacement. The Commission, therefore, directs that EDC smart meter plans identify capabilities that have the potential to be upgraded without complete system replacement as technology advances and becomes economically feasible.
5. Ability to monitor voltage
PPL asserts that it is premature to assume that voltage monitoring has value and that an operations management system and remotely controlled equipment exists to make use of the data. PPL adds that this capability may be appropriate in certain evolutions of the smart grid. The Commission disagrees with PPL in that this feature will serve to enhance reliability aspects associated with the grid. The Commission, therefore, will require that smart meters have a capability to support the ability to monitor voltage.
6. Direct access to consumption and pricing information
Allegheny noted that most smart metering vendors support two standards for a home-area-network (''HAN'') protocols, proprietary and ZigBee. Duquesne recommended that usage information should be validated and made available within 48 hours through a HAN or Internet. Duquesne also recommended that the pricing information should reflect the tariff rate and be made available through the Internet or HAN. FirstEnergy commented that pricing information should be provided through the Internet, noting that HAN type devices will be a competitive offering that should not be dictated by regulation. FirstEnergy and PECO also recommended that validated usage data should be made available in a minimum of 48 hours. PECO posits that data from the meter to a HAN device be limited to raw consumption data. Tendril comments that the Commission should not establish a single standard protocol for delivery of usage information, noting that this information should be available through any and all means that match customer preferences. Regarding pricing data, Tendril encourages a reliance on open standards such as the Smart Energy Profile data standard established by the ZigBee Alliance.
Regarding the comments related to validated consumption data, the Commission agrees in part with FirstEnergy and PECO. We accept that this data should be made available to customers or their designated third-parties within 48 hours, but we adopt this as a minimum standard, at least initially. Ideally, as noted by various parties, the information should be available the next day. Allegheny has already proposed to do this in 24 hours and FirstEnergy noted a 48 hour delay could be shortened as experience is gained.
Regarding comments on the use of open standards and protocols for meter connectivity with other devices, the Commission will not require compliance with one set of standards. Nor will we establish a new standards working group but will instead allow the industry to continue to develop uniform standards for communications firmware and software that would impact consumer products and services in the marketplace. However, the Commission will require EDC smart meters to have a capability to provide raw near real-time consumption data through a HAN or similarly capable method with open protocols. This delivery method should also be capable of providing pricing signals to support real-time and time-of-use pricing programs, as well as energy efficiency and demand response programs. Smart meters should support EDC and EGS time-of-use and real-time-pricing programs. Similarly, smart meters should support EDC, EGS and CSP energy efficiency and demand response programs. An EDC should not use these systems to gain competitive advantage for only its pricing and demand response programs.
D. Access to Smart Meters and Data
Act 129 requires EDCs to make available to third parties, including electric generation suppliers and providers of conservation and load management services, with customer consent, direct access to the meter and electronic meter data. 66 Pa.C.S. § 2807(f)(3). The Commission believes that the true usefulness of smart meters is to provide information to empower customers to control their electric use, for knowledge itself is power.5
For customers to be empowered they, or their designated representatives, must have direct access to their consumption data and price data. Therefore, the Commission directs that all covered EDCs must provide at least the following access to their smart meters and data:
1. Nondiscriminatory access for retail electric suppliers and third-parties, such as EGSs, and conservation and load management service providers;
2. Open, nonproprietary two-way access for electric suppliers and third-parties, such as EGSs, and conservation and load management service providers; and
3. Full electronic access to customers and their representatives to meter data upon customer consent.
The Commission further directs that each EDC plan must address standards and formats for electronic data communications with customers and third parties. There are many approaches for requesting and providing meter-level data today, such as, electronic bulletin board, pass-key protected web sites, compact disk, and the like. In addition, EDI (ASC X12 standards) capability has been built by the electricity industry in the Commonwealth to facilitate a reliable, secure economic approach for communicating verified customer data for electric choice. Regardless of the standard or format identified, compliance with Commission orders relating to electronic data communications and the approved Internet protocol at Docket No. M-00960890F0015, is required for third-party access to verified EDC meter data. The third-party must be EDI tested and certified with the EDC and is free to transcribe that data into any format to meet the customer's specific needs.
To achieve the capabilities of smart meter technology, however, EDCs are required to implement an EDI transaction relating to enrollment of customers who elect service on a real-time-price or time-of-use rate program, and a new historical interval usage transaction in order to provide customers and their designated agents with 12 months of interval usage data under Commission orders at Docket No. M-00960890F0015. Also, the historical usage data transaction must facilitate third-party exchange of historical interval usage data recorded at the meter level. An EDI transaction will also need to be developed and implemented for the exchange of monthly, billing quality, interval usage data recorded at the meter level versus the current practice of providing usage data at the account level. These and other developments necessary for the implementation of smart meter technology plans require EDC and third-party participation in the Commission's Electronic Data Exchange Working Group (''EDEWG''). Therefore, EDCs are directed to propose EDI capabilities for this purpose through the EDEWG for Commission review no later than January 1, 2010. In developing these proposals, EDCs are encouraged to look at any applicable national standards, such as those developed by the North American Energy Standards Board. EDCs shall identify in their plans target dates for the testing and certification of these EDI transactions with their business partners in order to meet the smart metering implementation deadline as specified in this Order.
In general, most commentators who addressed the direct meter access issue agree that allowing direct access to the meter itself raises security and safety concerns. PPL commented that communications are separate from metering company responsibilities and is concerned that the term ''direct access'' can be interpreted as direct access to raw unvalidated data. Citizen stated that smart meter information should be accessible to customers from a web site and directly from the meter, if not cost prohibitive. Duquesne supports direct access to and use of price and consumption information, but does not support direct access to its meters for security reasons. FirstEnergy posits that access to the meter should be strictly prohibited, but that access to the meter data should be permitted under conditions that protect privacy and security. FirstEnergy also encourages the adoption of Nationally recognized standards and protocols. PECO expressed a concern about network security and management risks and does not want a mandate that provides customers and third-parties unrestricted access to the EDC's metering network.
Constellation noted that curtailment service providers and EGSs require direct access to the meter to poll interval data and that should not be burdened by installing their own equipment to collect this data. Exelon suggests that there should be consistency across service territories regarding technological capabilities, protocols and processes. Tendril commented that direct, near real-time access to information is critical and that it is extremely important to accommodate two-way communication through the meter interface.
In response to comments on this issue, the Commission interprets the phrase, ''make available direct meter access and electronic access to customer meter data,'' at 66 Pa.C.S. § 2807(f)(3), as the customer's or customer designated third-party's ability to receive price and meter data in a timely manner and format that is useful and beneficial to the customer in terms of cost and value. Examples of customer benefits from direct access may include, but not be limited to, direct load control, automated appliance control and demand response pricing through the grid.
Additionally, the Commission notes that the EDC, who owns the meter, is responsible for providing direct access through the installation of a smart meter and infrastructure that will enable the end user to receive metered price and consumption information, at least in near real-time and in a format that is not proprietary or unduly discriminatory. Many industry standards groups are engaged in addressing and defining business practices and requirements for smart metering products, services and open data communications that will preserve the integrity, reliability and security of the National grid, the local distribution system and the consumer's data. The National Institute of Standards Technology, the North American Energy Standards Board, and the Utility Communications Architecture International Users Group are worthy of EDC participation for achieving the smart metering requirements of Act 129. Therefore, we direct EDCs to adhere to common industry and communications standards for providing consumers direct access to smart meters and data under this Order.
Nevertheless, for security reasons we determine that a distinction should be made between access to the physical meter and access to the meter information, and we will not require EDCs to allow customers and their designated agent to tamper or physically access the meter itself. However, this directive is not intended to preclude third-parties, with customer consent, from obtaining raw meter data through meter pulse leads, a secure web-portal or other secure means reasonably available to the customer or designated third-party. We agree with the OCA and Sensus that some residential and small commercial customers may find it beneficial to receive consumption and pricing information, and in this regard we will require all EDCs to install a smart meter that is capable of communicating raw data on at least a near real-time basis to in-home devices installed by the customer or customer designated agent. Additionally, we will require EDCs to provide all customers and their designated third-parties access to the following: validated, bill quality consumption data within 48 hours of the meter read; written detailed disclosure of data definitions and characteristics; and written update notices of changes in data characteristics as the changes become effective.
E. EDC Cost Recovery
Act 129 allows an EDC to recover reasonable and prudent costs of providing smart meter technology, to include annual depreciation and capital costs over the life of the smart meter technology and the cost of any system upgrades required to enable the use of the smart meter technology, incurred after November 14, 2008, less operating and capital cost savings realized by the electric distribution company from the installation and use of the technology. Smart meter technology is deemed to be a new service offered for the first time under section 2804(4)(vi).
1. Cost Recovery Mechanism
An EDC may recover smart meter technology costs through: (1) base rates, including a deferral for future base rate recovery of current basis with carrying charge as determined by the Commission; or (2) on a full and current basis through a reconcilable automatic adjustment clause under Section 1307. 66 Pa.C.S. § 2807(f)(7). However, in no event shall lost or decreased revenues by an EDC due to reduced electricity consumption or shifting energy demand be considered a cost of the smart meter technology recoverable under a reconcilable automatic adjustment clause under section 1307(b), except that decreased revenues and reduced energy consumption may be reflected in the revenue and sales data used to calculate rates in a subsequent distribution rate base rate proceeding filed under section 1308 (relating to voluntary change in rates), or a recoverable cost. 66 Pa.C.S. § 2807(f)(4).
Act 129 allows an EDC to recover ''all reasonable and prudent costs of providing smart meter technology.'' To determine what these costs are, each EDC will document all costs relating to its smart meter deployment and installation plan. These costs will include both capital and expense items relating to all plan elements, equipment and facilities, as well as an analysis of all related administrative costs. More specifically, these costs would include, but not be limited to, capital expenditures for any equipment and facilities that may be required to implement the smart meter plan, as well as depreciation, operating and maintenance expenses, a return component based on the EDC's weighted cost of capital, and taxes. Administrative costs would include, but not be limited to, incremental costs relating to plan development, cost analysis, measurement and verification, and reporting. In addition, the plan should include cost estimates for testing, upgrades, maintenance and personnel training. The EDC must also provide sufficient support to demonstrate that all such costs are reasonable and prudent with respect to its smart meter plan. Consistent with Section 315(a), the burden of proof shall be on the EDC. 66 Pa.C.S. § 315(a).
The Commission recognizes that some of the requirements for smart meters outlined in Section C of this Order go beyond the minimum requirements set forth in Act 129. To ensure that these additional smart meter functions are cost-effective, we direct that each smart meter plan filing include cost data that quantifies the costs to meet the minimum requirements set forth in Act 129, the costs to meet all of the requirements set forth in section C, and the individual incremental costs of each added function, less any operating and capital cost savings. Specifically, we direct that the plan filing shall quantify the costs to deploy and operate smart meter technology that is capable of the following minimum requirements set forth in 66 Pa.C.S. § 2807(g):
* Bidirectional data communications.
* Recording usage data on at least an hourly basis once per day.
* Providing customers with direct access to and use of price and consumption information.
* Providing customers with information on their hourly consumption.
* Enabling time-of-use rates and real-time price programs.
* Supporting the automatic control of the customer's electric consumption.
In addition, each plan filing shall include the individual incremental costs for deploying and operating the following smart meter technology capabilities:
* Ability to remotely disconnect and reconnect.
* Ability to provide 15-minute or shorter interval data to customers, EGSs, third-parties and an RTO on a daily basis, consistent with the data availability, transfer and security standards adopted by the RTO.
* Onboard meter storage of meter data that complies with Nationally recognized nonproprietary standards such as ANSI C12.19 and C12.22 tables.
* Open standards and protocols that comply with Nationally recognized nonproprietary standards, such as IEEE 802.15.4.
* Ability to upgrade these minimum capabilities as technology advances and becomes economically feasible.
* Ability to monitor voltage at each meter and report data in a manner that allows an EDC to react to the information.
* Ability to remotely reprogram the meter.
* Ability to communicate outages and restorations.
* Ability to support net metering of customer-generators.
The deployment and operating costs to be presented shall include a breakdown of all incremental costs and any associated potential operational and maintenance cost savings for each functionality and configuration. All cost estimates must be supported by estimates from at least two vendors where available. To the extent that an EDC or another party demonstrates that a particular Commission imposed requirement is not cost-effective, the Commission will have the option of waiving a particular requirement for that EDC or all EDCs. This waiver authority does not extend to the minimum requirements delineated in 66 Pa.C.S. § 2807(g). Any EDC that is unable to provide this cost data with its August 14, 2009, filing can petition the Commission for permission to file such data at a later date. Any such filing shall include a proposed filing date.
Furthermore, the Commission recognizes that consideration of these cost issues may benefit from further discussion prior to the August 14, 2009, filing deadline. To facilitate this discussion, the Commission will convene a stakeholder meeting no later than July 17, 2009.
The Commission will allow each EDC to develop a reconcilable adjustment clause tariff mechanism in accordance with 66 Pa.C.S. § 1307 and include this mechanism in its smart meter plan. Such a mechanism shall be designed to recover, on a full and current basis from each customer class, all prudent and reasonable smart meter costs less operating and capital cost savings realized by the EDC from the installation and use of smart meter technology. The mechanism shall be set forth in the EDC's tariff, accompanied by a full and clear explanation as to its operation and applicability to each customer class. The tariff mechanism will be subject to an annual review and reconciliation in accordance with 66 Pa.C.S. § 1307(e). Such annual review and reconciliation will be scheduled to coincide with the submission of the ''Smart Meter Progress'' annual report outlined in section B.1 previously.
2. Allocation of Costs to Customer Classes
The Commission will require that all measures associated with an EDC's smart metering plan shall be financed by the customer class that receives the benefit of such measures. To ensure that proper allocation takes place, it will be necessary for the utilities to determine the total costs related to their smart metering plans, as discussed in section E.1. Once these costs have been determined, we will require the EDC to allocate those costs to the classes whom derive benefit from such costs. Any costs that can be clearly shown to benefit solely one specific class should be assigned wholly to that class. Those costs that provide benefit across multiple classes should be allocated among the appropriate classes using reasonable cost of service practices.
OCA stated that it feels traditional rate base procedures would be the preferred method for recovery, rather than an adjustment mechanism that may be unnecessarily complicated. OCA also says that if an adjustment mechanism is used only reasonable net costs should be included in the surcharge. PECO, FirstEnergy, and EA counter by asserting that including the costs in base rates is the best method for cost recovery. PECO asserts that an EDC should use whatever method it sees fit, as the Act allows for recovery through either method, noting its belief that the methods are not mutually exclusive. FirstEnergy states that OCA's claim that base rates are the preferred method of recovery is premature and that EDCs deserve the chance to design and submit a plan for recovery before it is rejected.
A number of commentators agree that care should be taken to ensure the proper allocation of costs amongst customer classes. IECPA recommends that the Commission should allow any customer or customer class that has previously paid to have smart meters installed to be exempt from all costs of the smart meter program. EA strongly objects to that recommendation, saying that a fully functional smart meter involves an entire network and that these comments ignore the costs of upgrading the systems that support smart meters. They go on to note that eliminating an entire class from paying its share of reasonable costs before the submission of a single smart meter plan is premature, ignores the policy underlying Act 129, and undercuts the role of the Commission in reviewing and approving cost recovery mechanisms. Finally, EA, PECO and Duquesne suggested that under-depreciated abandoned assets need to be recovered as stranded costs and that the Commission should allow for accelerated depreciation of assets that are retired early.
The Commission believes the EDCs should install smart meters in a manner that coincides with the full depreciation of existing meters, so as to minimize the stranded costs. However, in the event that there are stranded costs that need to be recovered the Commission agrees with EA, PECO and Duquesne that the EDCs should be allowed to seek recovery of those costs through an accelerated depreciation schedule, to be included in the EDC's cost recovery plan.
The Commission also agrees with FirstEnergy that it is premature to deem one method of recovery preferable to another. The Commission interprets 66 Pa.C.S. § 2807(f)(7) as permitting an EDC to use either method of cost recovery at its discretion.
The Commission disagrees with IECPA's basic premise that a customer or entire customer class should be exempt from all costs associated with these smart meter plans. We agree with the EA that it is premature to suggest such a blanket exemption.
Conclusion
This Implementation Order establishes the Commission's smart meter technology procurement and installation standards each EDC with greater than 100,000 customers must meet. This Order also provides guidance on the procedures to be followed for submittal, review and approval of all aspects of each smart meter plan. In addition, it establishes the minimum smart meter capabilities and guidance on deployment of smart meter technology. We extend our thanks to those who participated by providing comments on this important and timely energy program. We would especially like to note our appreciation for the cooperation and courtesy extended by all, which was essential in meeting the aggressive timelines established by the General Assembly for Act 129 implementation. Therefore,
Statement of Commissioner Robert F. Powelson Today we take another important step in implementing Act 129 of 2008--setting forth standards for smart meter deployment.
If we are serious about ''consumer-driven'' electricity here in the Commonwealth, we need to work aggressively to ensure advanced metering infrastructure (''AMI'') and dynamic pricing deliver their intended benefits to businesses and residential ratepayers alike.
To achieve that goal, I strongly encourage all EDCs to deploy smart meter technologies and the required communications networks as rapidly as possible in order to give customers the ability to monitor and effectuate changes in their usage patterns.
Further, well-constructed time-of-use and real-time rate structures, implemented on a timely basis, will offer residential and small commercial customers the potential to alter their behavior in response to the true costs of electricity going forward. To be frank, it is pointless to have smart meters if you are still going to have ''dumb'' rates.
Lastly, I would like to compliment the Law Bureau on drafting a very clear and concise Implementation Order for smart meter deployment.
ROBERT F. POWELSON,
CommissionerIt Is Ordered That:
1. The Commission establishes specific smart meter technology minimum capabilities and procedures for submittal, review and approval of all aspects of each smart meter plan to include cost recovery.
2. The electric distribution companies with greater than 100,000 customers adhere to the guidelines for smart meter technology procurement and installation identified in this Implementation Order.
3. The Director of Operations convene a stakeholder meeting no later than July 17, 2009, to discuss issues related to the costs and benefits associated with the Commission imposed smart meter capability requirements.
4. All electric distribution companies that are required to file a smart meter technology procurement and installation plan file such a plan consistent with the directives contained in this order by August 14, 2009.
5. All electric distribution companies that are required to install smart meter technology are exempt from compliance with 52 Pa. Code § 57.20(h) for testing watthour meters that are being replaced with smart meters in accordance with an approved smart meter technology procurement and installation plan.
6. All EDCs may recover the reasonable and prudent costs of providing smart meter technology in accordance with the procedures set forth in this Implementation Order.
7. This Implementation Order be published in the Pennsylvania Bulletin and served on the Office of Consumer Advocate, Office of Small Business Advocate, Office of Trial Staff, all jurisdictional electric distribution companies and all parties that filed comments under this docket.
JAMES J. MCNULTY,
Secretary
[Pa.B. Doc. No. 09-1266. Filed for public inspection July 10, 2009, 9:00 a.m.] _______
1 Wal-Mart Stores East, LP and Sam's East Inc. filed a Petition for Extension of Time to file reply comments, which this Commission denied in a letter dated May 6, 2009. While we rejected Wal-Mart's and Sam's petition, we did receive and consider their reply comments submitted on May 1, 2009.
2 Any technical conference should be conducted as informally as possible, consistent with the good order of the proceedings. Lay persons will be permitted to directly ask questions of the EDC representatives, although such lay persons must be affiliated with an admitted Party of Record.
3 These interval capable meters are not smart meters as they will not have the capabilities outlined in section C of this Order. However, they are capable of providing real-time pulse data that enables the recording of usage at set intervals.
4 OCA Comments at page 10.
5 Francis Bacon.
No part of the information on this site may be reproduced for profit or sold for profit.This material has been drawn directly from the official Pennsylvania Bulletin full text database. Due to the limitations of HTML or differences in display capabilities of different browsers, this version may differ slightly from the official printed version.
