New trends emerging for AMI cost recovery
Based on findings from a study that KEMA conducted earlier this year, the average cost for an Automated Meter Infrastructure (AMI)/Smart Grid utility project is approximately $775 million. While the costs of the project may be easy to quantify on the front end, the long-term benefits of technology improvements may not be as clear to regulators, particularly because the benefits may be spread over multiple customer classes and may not be fully realized for years. The unfortunate result is that state regulators may be reluctant to approve cost recovery or even the implementation of AMI/Smart Grid technologies without specific guarantees that benefits of the technologies will exceed the costs in the long-term. The challenge for all utilities planning technology upgrades, however, is determining the amount of cost that will be received in rates.
This article provides an overview of the current regulatory polices regarding AMI / Smart Grid technologies. While some new trends are emerging, it is interesting to note the variety of ways in which regulators are treating utility investments.
How to calculate costs
The way in which regulators add up the costs and provide rate recovery for AMI / Smart Grid investments will largely determine how utilities and their shareholders perceive AMI investments. A public utility commission might easily justify rate-basing capital costs for new metering hardware, but the way a utility should bear the costs of retooling its internal processes to pursue the Smart Grid vision, as well as the marketing strategy for the new program and educating customers to ensure that maximum benefits continue flowing are less certain.
Both utilities and regulators are uncertain about how AMI costs should be recovered. The California Public Utility Commission (CPUC) recently approved PG&E's proposal to put $1.4 billion of its AMI investment in its rate base. The CPUC also approved nearly $400 million more in rate recovery for business risk, marketing and other expenses. In Texas, however, TXU told the state Public Utility Commission (PUC) that it would prefer AMI costs to be collected through a separate surcharge. "The costs should not be shifted to base rates," TXU stated in its response to the PUC's AMI inquiry. "Having all such costs be recovered through the surcharge will make it easier to track the recovery of advanced metering costs as compared to other metering costs that will still be incurred."
From the utility perspective, there appears to be a consensus that utilities should have the certainty of knowing that they can include the actual costs of investing in Smart Grid systems in their rates. Further, utilities generally believe that they should be permitted to earn an enhanced return on their investment in Smart Grid systems, including a return on a portion of their operating and maintenance expenses. Utilities also generally assert that they should be able to recover the costs of equipment that is replaced by the deployment of AMI / Smart Grid technologies based on the remaining depreciable life of the obsolete equipment. If this approach does not meet regulatory muster, then an alternative is often to allow the utility to retain a portion of the savings. This derives from such technology-upgrade expenses that they result in efficiencies that otherwise would be passed on to end users (thereby producing a return on the utility’s expenditure).
From the regulators’ perspective, commissioners are charged with considering the fairness of allowing utilities to rate-base the costs of programs that will not benefit all stakeholders equally. Many regulators are concerned about distributional impacts of the technology benefits. In other words, if changes are made in dynamic pricing tariffs that help facilitate the technology upgrades, regulators may spend significant time examining the ways in which the rate-design changes will impact customers with different levels of consumption and income. These economic and political dimensions complicate the effort for regulators, and make it difficult for them to confidently define the importance of AMI investments in the broader energy policy context.
Cost recovery means
Some trends are beginning to emerge regarding the approaches that utilities and regulators often take. In fact, cost recovery strategies appear to fall into one of the following categories, regardless of state jurisdiction:
Trackers: A mechanism that follows or “tracks” unpredictable costs that the utility incurs. Typically, trackers are determined at the end of the year and then recovered over a 12-month period.
Balancing Accounts/Rate Base: A balancing account is an accounting procedure developed by the governing utility commission to track and recover reasonable and prudent costs unrecovered through retail bills due to the application of applicable rate freezes or ceilings. The rate base of a utility is established by governing utility commission. It determines the value of the physical assets of the utility which are used to provide services and can be recovered from customers in rate structures.
Customer Surcharge: A mechanism that has no standard statutory definition, but typically is a charge defined by the governing utility commission and imposed on customers to recover utility expenses.
State Funding: It varies state-by-state, but this approach includes funding for projects provided from existing or newly created state accounts.
Assessment
Trackers appear to represent the most common trend for two reasons:
They offer a good manner for focused cost recovery, in the absence of going through the full rate case process.
Trackers presumably save time and limit the risk exposure for the utility, which is important given the uncertainty surrounding estimates of total project costs.
The second most common approach is recovery through surcharges, as noted below in the recent CenterPoint and TXU filings in Texas. Most utilities appear to be taking a marginal-costs approach when proposing either a surcharge or rate-base recovery option. In other words, they are claiming that the determination of a class customer-related distribution cost responsibility should be based on estimates of marginal customer costs (costs to serve that class) multiplied by the number of customers in that class. Whether it is a surcharge or an increase to the rate base, most cost recovery within rate design appears to be taking place at the distribution level so that the costs are non-bypassable.
It is significant that our research found no instances in which an AMI/Smart Grid project had not developed a cost recovery plan. Still, however, some other states and utilities have no clear AMI cost recovery policy at this point, as they prefer to take a “wait and see” approach regarding the technology advances. This approach is rather dangerous considering the clear imbalance between supply and demand that continues to increase in addition to the need for demand response (DR) programs to assist in reducing the need for peak capacity. DR programs are greatly enhanced by AMI/Smart Grid technology, while AMI/Smart Grid business cases most often require DR programs to be successful and result in a positive investment. Hopefully, at this point, most utilities are including technology upgrades in their long-term business plans and are planning cost-recovery strategies for subsequent regulatory filings.
A summary of the decisions made by some of those states in which AMI/Smart Grids are advancing follows.
Summary: decisions made by some states with advancing AMI/smart grids
CALIFORNIA
San Diego Gas & Electric (SDG&E)
The CPUC’s 2005 Energy Action Plan established a framework for implementing AMI plans by mid-2006. CPUC’s May 13, 2005 order approved SDG&E’s plan to implement and obtain cost recovery for AMI. The plan was based on vendors’ responses to an RFP. When The CPUC approved the plan, SDG&E had not yet selected the technology it would use.
In 2007, SDG&E will develop a new information technology system, integrate that system into the company's existing information and billing systems, and begin preparing for AMI meter installation. In 2008-2010, SDG&E will then install 1.4 million new electric meters and 0.9 million AMI-enabled gas modules, and add supporting communications infrastructure.
The CPUC required a cost/benefit analysis over 17-year period, e.g., based on useful life of the longest-lived asset. The estimated project costs were $652 million, which were exceeded by the estimated direct customer benefits of $660 million. The CPUC allowed consideration of non-quantifiable benefits (for items such as public safety benefits, by accepting a reasonable quantification) and societal benefits.
The revenue requirement for the project costs is recoverable through a tracker with no after-the-fact prudency review for the authorized costs. Shareholders receive incentives of 10% of the first $50 million in project cost savings, and shareholders pay 10% of first $50 million in project cost overruns. SDG&E can recover cost overruns caused by: force majeure, changes in project scope/functionality required by governmental/regulatory action, cost increases due to CPUC delay in approving a project beyond date certain, and delays due to permitting or local government inaction.
Southern California Edison (SCE)
SCE is taking a phased approach to AMI deployment, seeking CPUC approval for cost recovery in three stages.
In Phase I, The CPUC approved a settlement in 2005 allowing SCE to recover $12 million in costs through a tracker for evaluating and testing AMI technology.
SCE has a pending application seeking approval for tracker recovery of $67 million in Phase II costs for expanded pre-deployment testing. SCE will test AMI meters in 5,000 to 25,000 homes during Phase II. SCE will submit a detailed business case in 2007 after Phase II is completed.
SCE’s preliminary cost/benefit analysis indicates that benefits will exceed costs by $106 million.
In Phase III, SCE will replace 5 million meters; preliminary cost estimate is $1.3 billion.
Pacific Gas & Electric (PG&E)
In 2005, The CPUC authorized PG&E to spend and recover in rates up to $49 million for AMI pre-deployment investigation and testing.
In 2006, The CPUC authorized PG&E to deploy 5.1 million electric and 4.2 million gas smart meters and AMI infrastructure by 2011; cost = $1.74 billion.
Cost/benefit analysis: costs included project management costs and a significant risk contingency.
Benefits included savings for meter reading, electric T&D operations, meter operations, customer contact, billing, gas T&D operations, software licensing, and remote connect/disconnect costs.
Other benefits included critical peak pricing and demand response, including avoided generation cost.
PG&E’s analysis indicated that PG&E’s AMI proposal was cost-effective, over a 20-year useful life, with 90% of project costs covered by operational savings and 10% of the costs covered by demand response benefits provided by a critical peak pricing tariff.
PG&E had a pending base rate case using a 2007 test year, which excluded AMI costs. For 2008-2010, The CPUC approved balancing accounts for PG&E to recover the AMI revenue requirement.
The balancing accounts record the revenue requirement as the meters are placed in service. PG&E guaranteed a certain level of benefits, which is factored into the revenue requirement calculation.
PG&E is scheduled to file its next base rate case using a 2010 test year. At that time, The CPUC will decide whether to recognize AMI costs in 2010 rate base or to continue the balancing accounts.
COLORADO
Public Service Company of Colorado (PS Colorado)
The Colorado Public Utilities Commission approved a pilot AMI program for PS Colorado, involving 4,000 customers, with estimated costs of $4 million.
The pilot program was deemed cost-effective under the Ratepayer Impact Measure test, which factors in the system-wide benefit of reduced peak power costs, assuming the program was available to all customers.
PS Colorado will recover costs through its DSM tracker.
When the pilot program is completed, PS Colorado will file a business plan for full deployment of AMI, and a proposal for cost recovery, which is contingent upon meeting the goals of the pilot program.
CONNECTICUT
Connecticut Light and Power Company (CL&P)
On March 30, 2007, CL&P filed an application for approval of AMI deployment plan, Docket No. 05-10-03.
CL&P submitted an array of different technologies for the 1.2 million AMI meters it intends to replace by 2010, each with different costs and functionalities; its plan has been deemed cost-effective.
CL&P seeks approval for one of the plans for AMI deployment and for cost recovery through an annual rate surcharge.
DISTRICT OF COLUMBIA
PEPCO
As part of a 2006 Pepco/Connectiv merger, Pepco committed to invest $2 million in a smart metering plan, and the PSC approved a two-year smart meter pilot limited to 2,250 residential customers.
Pepco has a pending application for approval to install 256,000 smart meters. Pepco proposes an AMI tracker, adjusted annually to recover costs.
The tracker would be based on actual costs during the prior 12-month period. The tracker will pass through to customers the net savings resulting from AMI deployment. The tracker would also recover cost of retiring existing meters. The impact on monthly bill is estimated at $7.00 per customer.
GEORGIA
Georgia Power
Georgia Power has deployed approximately 100,000 AMI meters and has issued an RFP for an additional 800,000 smart meters. Georgia Power is using an Itron MDM System to obtain time-of-use meter reads which provides data to a customer information system.
Costs are recovered through Georgia Power’s earning sharing mechanism.
HAWAII
Hawaiian Electric Company (HECO)
HECO deployed a 500-meter AMI pilot study and is currently pursuing a 3,000 meter AMI pilot study using Sensus meters. No approval from the Hawaii Public Utilities Commission was required for the pilot programs, and HECO does not have any order allowing cost recovery.
IDAHO
Idaho Power
Due to rate increases resulting from lower water levels and higher purchased power costs, the Idaho Public Utilities Commission opened an investigation into whether Idaho Power should implement residential TOU rates.
Idaho Power had previously conducted an AMI pilot using Power Line Carrier (PLC) technology in 1998.
The Idaho PUC ordered Idaho Power to develop a Phase I AMI plan. Idaho Power’s plan was based on PLC technology, installed over four years, at a cost of $86.5 million. Idaho Power concluded that projected benefits would not exceed costs for 21 years; therefore, the program was deemed not cost-effective based on a shorter life expectancy.
Idaho Power proposed to purchase PLC-enabled meters for all new installations, and to do a limited PLC pilot program. The PUC approved full recovery of pilot program costs, contingent on Idaho Power making a sincere effort to install and evaluate the technology.
In 2006, Idaho Power reported that it installed PLC-based AMI devices for 23,500 customers, but encountered some project difficulties; therefore, the PUC continued the pilot program another year.
INDIANA
Indianapolis Power & Light (IPL)
IPL has deployed smart meters to all of its customers, beginning in 1998.
IPL uses Cellnet fixed network equipment based on radio frequency technology. Cellnet owns the equipment and leases it to IPL.
IPL does not have any cost recovery mechanism for these meters. IPL justified the investment on the grounds that the benefits exceed the costs. It would also appear that this financing option resulted in no capital outlays for IPL, and thus there was no need to recover capital expenditures through the regulatory process.
IOWA
Iowa Utilities Board Generic Order (IUB)
In a March 6, 2007 order in Docket No. NOI-06-3, the IUB declined to adopt mandatory time-based metering standards in response to the EPAct 2005 mandated investigation; however, the IUB concluded that it was presented with insufficient information regarding the cost-effectiveness of AMI.
The IUB ordered Staff to conduct informal discussions with utilities to implement pilot AMI programs.
KENTUCKY
Duke Energy (Kentucky)
The Kentucky Public Service Commission approved an electric general rate case settlement which included cost recovery of $6.5 million in electric base rates for AMI deployment.
Duke Energy-Kentucky will deploy PLC-based AMI technology to approximately 120,000 electric and 90,000 gas customers over three years.
Total estimated project cost is $24 million. Duke Energy-Kentucky projected that the benefits would exceed the costs by $10 million through 2020.
The costs exceeded savings by $6.5 million during the first year of deployment; the savings were not projected to exceed costs until the AMI system was fully deployed.
Louisville Gas & Electric Company (LG&E)
LG&E has a pending application for approval of a three-year smart metering pilot program. LG&E proposes to enroll up to 100 residential electric and up to 50 residential gas customers on time-of-use rates. LG&E will also install 2,000 additional smart meters to develop usage data.
Total cost estimated is $1.9 million, which LG&E proposes to recover through its DSM tracker.
MARYLAND
Baltimore Gas & Electric Co. (BG&E)
The Maryland Public Service Commission approved BG&E’s request to create a regulatory asset for costs related to DR costs and Phase I AMI costs, with a return based on the cost of capital from BG&E’s last rate case.
The energy efficiency programs involved Energy Star® products, Energy Star® new homes, Energy Star® home performance platforms (retrofits and home energy audits), residential heating and cooling and expanded information services at an annual cost of $10-12 million.
MICHIGAN
Michigan Public Service Commission Generic Order
PSC opened Case No. U-15278 on April 24, 2007, and directed staff to convene a statewide collaborative workshop to study AMI to improve the state’s electric grid.
Consumers Energy Company
In 2005 rate case, PSC allowed recovery of $100,000 in Consumers’ electric base rates for cost of a pilot program to study Broadband over Power Line (BPL) technology to develop a “smart grid.”
MISSOURI
Ameren UE
Ameren has fully deployed AMI to its Missouri customers, and is in the process of deploying smart meters to selected Illinois customers.
Ameren uses Cellnet fixed network AMI equipment based on radio frequency technology.
Missourideployment occurred during the past five years. Ameren did not request any special rate treatment for the AMI costs, as it was in a period of overall declining costs. Ameren just processed its first base rate case since 1987 and the new rates will take effect in June 2007; these rates will recover the portion of the AMI net costs/cost savings incurred during the test period.
Although 1 million residential customers have smart meters and are eligible for a time-of-use rate, only 100 customers have signed up for the TOU rate.
Commercial and industrial customers are eligible for on-peak and off-peak time-of-day demand rates.
NEW YORK
New York State Energy Research and Development Authority (NYSERDA)
NYSERDA is a state agency that oversees demand response programs.
Funding for the programs comes from a surcharge on utilities’ rates.
NYSERDA awards grants to contractors who bid to curtail load through demand response programs, including grants for each smart meter installed by an end-use customer.
Consolidated Edison, Inc. (Con Ed)
Con Ed will invest $39.3 million in 2007 for a superconducting electrical conduit in downtown Manhattan. This will be the first commercial deployment of superconducting cable in the U.S.
This project is part of Con Ed’s proposed “utility-of-the-future” system upgrade, projected to cost $7.78 billion during 2008-2011. Con Ed seeks to recover the revenue requirement for this investment through a tracker, including recovery for lost revenues, and carrying costs.
Other infrastructure improvements will include AMI, using several technologies, to be deployed to Con Ed’s approximately 5 million customers.
Con Ed filed application on March 28, 2007, for approval of AMI deployment plan and cost recovery. Con Ed plans to use radio frequency communication technology. Con Ed’s analysis demonstrates $713 million in AMI costs and $782.5 million in AMI benefits over a 15-year period. Con Ed requests approval of surcharge, adjusted annually, to recover all capital and O&M costs for AMI deployment plus lost revenues.
OREGON
Portland General Electric (PGE)
PGE has a pending application for approval of a plan to deploy AMI and to obtain cost recovery.
PGE seeks approval for a rate increase of $13.4 million to recover the revenue requirement for the net costs of the initial phase of the AMI deployment.
TEXAS
Texas Legislation and Public Utility Commission of Texas (PUCT) Regulations
Texasenacted S.B. 5 in 2005, removing regulatory restrictions and enhancing cost recovery for utilities seeking to deploy BPL communications systems. The laws authorized tracker recovery for smart metering costs.
The PUCT opened Project No. 31418 to develop rules for AMI deployment, for utilities to submit individual AMI deployment plans, and for approval of trackers for cost recovery.
On May 14, 2007, the PUCT finalized new regulation, § 25.130 Advanced Metering, in Project No. 31418. Section 25.130(k) authorizes cost recovery for advanced metering systems (“AMS”). The rule requires the PUC to approve tracker recovery for AMS costs, following PUC approval of an AMS deployment plan. The utility can also recover costs for PUCT-approved pilot plans, implemented prior to the AMS deployment plan. The PUCT may set the surcharge to recover up to one-third of the utility’s total meters per year, regardless of the number of new meters deployed.
The PUC may also approve amortization of the new meter costs up to seven years, and may reflect actual or project operating cost savings in the surcharge. The rule requires the PUCT to conduct reconciliation proceedings in which non-prudent costs, and costs recovered through the surcharge, but not actually spent by the utility, are refunded to customers. Costs incurred for AMS meter deployment are presumed to be prudent.
CenterPoint Energy
CenterPoint deployed a large-scale pilot program in 2006, using a BPL-based AMI system.
TXU/ONCOR
TXU/ONCOR has started full deployment of smart meters to 3 million customers.
CenterPoint and TXU are expected to file their deployment plans and applications for surcharge recovery in the near future.
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