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The first part of this two-part article discusses meter reading practices and benchmarking performance for the study's purposes.
Meter reading is the critical first step in the utility revenue collection process, and for most utilities, a labor-intensive activity. While the use of automated meter reading technologies (AMR) is increasing, the majority of meters are still read manually, once a month. Any errors or delay in the meter reading process negatively impacts customer satisfaction.
Not only is it critical to effectively and efficiently read meters every month, the meter reader also plays an important community relations role -- the "gatekeeper" who looks for leaks, problems, hazards, safety issues, and serves as a neighborhood watch. For many customers, the meter reader is often the only utility employee ever seen. These customer touch-points form the basis of customer opinion.
The meter reader position is usually an entry-level job. As such, meter reading departments can incur high turnover, thereby increasing the cost to hire and train effective and efficient meter readers, and ultimately, increasing the cost to read a meter.
With all the changes in the industry and the economy, most utilities have been forced to reduce operating costs. At the same time, companies are being asked by regulators, customers, members, and shareholders to increase customer service and satisfaction -- essentially, to "do more with less." This is a daunting challenge for any organization.
Utilities are also faced with growing need for more timely access to energy usage information: to support real-time pricing initiatives, load forecasting, demand-side management, load control, competition, and customer demand. Additionally, status and usage information is needed on an event basis to improve reliability and power quality, and to identify outages. These more complex data requirements are driving the need for advanced metering infrastructures, smart metering, and further automation.
The American Recovery and Revitalization Act (ARRA) Smart Grid Investment Grant Program is also spurring interest in "smart" metering, "smart grid", and advanced metering infrastructure projects. The overall purpose of the Smart Grid Investment Grant Program (SGIG) is to accelerate the modernization of the nation's electric transmission and distribution systems and promote investments in smart grid technologies. The ARRA was signed into law in February 2009. In late June 2009, The U.S. Department of Energy announced the availability of $3.4 billion in stimulus funding under the SGIG program. Interested parties must file a letter of intent to be eligible to apply for funding. There are three application periods with letters of intent deadlines. One was last month, in July, and the other two are October 23, 2009, and February 10, 2010. Several utilities have already announced filing letters of intent for grant applications of matching funds, including Westar Energy, Delmarva Power, Atlantic City Electric, and PEPCO.
Clearly the meter reading organization is evolving with the introduction of automation. The diversity of metering and AMR equipment, complexity of accounts and billing, the challenges of service territory, and needs of different customer classes dictate different solutions for different companies.
Regardless of the implementation rate, the transition from manual reading to automated is challenging from a technology and people perspective. Routes must be consolidated and optimized, employee roles and responsibilities change with changing priorities, performance measurement metrics shift to accommodate the mix of automation and manual effort, processes and systems change... it's a challenging time for any organization. Even after automation, metering devices must be visited periodically to ensure proper operation and to protect assets. Access problems that were solved through automated meter reading will soon challenge meter maintenance and revenue protection initiatives.
In this transition to automation and the quest for reduced operating expenses, most utilities are focusing on three basic approaches to meter reading improvement:
Automated meter reading -- large-scale implementation as well as strategies to pinpoint "high read cost" meters, unsafe meter locations, and high-turnover premises. Some companies have automated "key accounts" and commercial accounts to accommodate real-time pricing and/or prepare for the competitive market.
Contract meter reading to reduce overhead, tackle seasonal peaks, and as a strategy to transition to automation.
Reducing costs of manual reads through contract negotiations, rerouting, more sophisticated hand-held equipment and meters, productivity improvement, and lowering overhead; many have maxed out these options; Some utilities have reduced costs to a point that makes it difficult to justify AMR, for residential accounts.
The promise of automation -- AMR/AMI implementation remains the top plan for the future, partial or complete, for our utility panel. Other automation plans indicate a continuing interest in route optimization software and handheld technology upgrades.
To better understand how utilities are dealing with the challenges facing the meter reading function and its day-to-day operations, the Ascent Group conducted its sixth annual benchmarking project to evaluate Meter Reading performance and practices. Forty-three utilities participated in the research.
Benchmark Study of Meter Reading Practices
The main objective of the study was to evaluate the various tactics and strategies used today to read customer meters in order to identify best practices or opportunities for improvement. Secondary objectives included understanding:
The practices linked to "best-in-class" performance;
The range of performance by company and by industry segment;
How utilities are using technology to reduce costs and improve customer satisfaction;
Other effective process improvement or cost-reduction techniques;
How utilities measure individual, team, and center-level performance and encourage high productivity and performance;
The role of meter reading training and its impact on performance;
How companies are resolving the hard issues, such as inaccessible meters; and
To know what is possible.
Participants were asked to share management tactics and strategies, as well as identify any improvement in performance. The study also asked utilities to include considerations, successes, and plans moving forward.
Study participants range in size from 2,258 meters to be read to as many as 18.7 million. Eighty-one percent of participants read less than the participant average of 966,900 meters per month. The majority of study participants were from the United States, however we did have four utilities from Canada, two from the U.K., and one from India. Bargaining units represent 51 percent of participants' meter readers.
Benchmarking Meter Reading Performance
When evaluating performance of any organization, it is best to look at performance from three perspectives: Productivity, Cost, and Service.
We asked companies to report meter reading operational data so we could calculate several performance benchmarks. The following benchmark metrics were collected and calculated, based on participant feedback:
Unit cost (cost per meter read -- Operational & Maintenance costs only -- direct labor, contractor costs, overtime, and non-labor O&M; no capital costs or overheads)
Meter Reading Accuracy (for a representative month)
Percent Meters Read (for a representative month)
Meter Reading Productivity [meters read per FTE (per month)]
Based on these benchmark metrics, we identified the "best performers" for each industry segment (electric, natural gas, combination utility, and water/wastewater). Best performers were identified as those companies that deliver low cost meter reading, high productivity, and high service (low errors, low skips). We then calculated a "best performer" average for these high performing companies.
The "best performer" averages are depicted on the chart appearing below. This is one of seven benchmarking metrics analyzed. We also calculated an industry-segment average for each of the benchmark metrics, to demonstrate the performance of industry, by segment.
"Cost per Meter Read" was calculated based on cost data submitted by each participant. Unit cost in this analysis represents Operational & Maintenance costs only -- direct labor, contractor costs, overtime, and non-labor O&M -- no capital costs or overhead.
Because AMR heavily influences labor and other O&M costs, we included two Best Performer averages for comparison -- best performers with "Full AMR" and "Minimal AMR". In this analysis, "Full AMR" best performers averaged 91 percent AMR meters and "Minimal AMR" best performers averaged .7 percent AMR meters.
Similar analysis was conducted on six other meter reading benchmark metrics captured by this research.
Characteristics of a Best Performer
Use AMR Strategically -- to address inaccessible meters, unsafe meter locations, high turnover premises, and other high-read cost meters.
Continually Optimize Routes -- to maximize productivity and reduce costs.
Implement Clear and Concise Measures of Meter Reader Performance -- give employees a clear idea of job expectations and performance.
Encourage High Performance through Incentives and Rewards -- encourage the right behavior through incentive programs and/or informal or formal reward programs.
Train and Equip Meter Readers -- provide employees with the tools, safety equipment, clothing, and training to do the job right the first time.
The second part of this article will discuss the study's findings and recommendations for utilities.
For information on purchasing reprints of this article, contact Tim Tobeck ttobeck@energycentral.com. Copyright 2010 CyberTech, Inc.
Anyone who thinks automating in any way other than incremental installation, should really read H.F. Brown's 1960's analysis of the railroad industry after mass dieselization. His synopsis showed that after accounting for all other variables, the rail industry's mass dieselization resulted in ROI being cut in half, from 4% industry average to 2% industry average. The moral of story: Junking equipment that has not maxed it's useful service life will end up costing the industry more than the ostensible savings from force feeding new technologies.
Dave Smith
Don Hirschberg 8.11.09
Here in the Ozarks we hillfolk have had automaic meter reading for quite a few years. The Co-op said they they would send a guy around every year or so to take a look-see, and not be alarmed if we see him nosinng around.
The Co-op can also shut down our A/C and water heater for 20 minutes during near peaking conditions.
Bob Amorosi 8.12.09
David,
"Junking equipment that has not maxed it's useful service life will end up costing the industry more than the ostensible savings from force feeding new technologies."
This is the crux of the whole problem with introducing new technologies to just about anything where there is a legacy of old equipment still in use. It applies to the utility industry, automobiles, manufacturing plants, building environmental systems everywhere, and even home owners.
If one can afford to wait for old legacy equipment to be phased out normally, there is no problem, but problems arise when one cannot wait. And when it comes to utility customer metering, old equipment especially the electromechanical meters lasts a very long time before they reach the end of their useful service life.
If an electronic service meter instead offered uses and some value to the customer like a personal computer has value, and if universal interface standards to an electronic meter and home automation technologies were adopted from the outset, analogous to a personal computer coming equipped with e.g. USB ports, disk drives, modems, etc., then lust like in the computer industry the equipment would become heavily commoditized where their production costs continually come down, becoming much easier to replace more often. This is even more true for any software running on them.
Imagine utilities taking traditional business risks by investing in new energy-related product developments and marketing, in addition to delivering electricity. Much like CATV and telephone companies have done for decades, in addition to providing a basic essential service they could potentially commercialize optional real-time energy data services and the in-home devices to consumers and businesses for demand management. The potential extra money they make off consumers would help to pay for installing their infrastructure to handle it i.e. the AMI systems.
The trouble is utility companies typically have no interest in becoming the BestBuy store for residential consumer products, and probably shudder at the mere thought of having to invest serious money into marketing and support of such a venture. Most are probably quite comfortable with the status quo where the only way to raise their incomes is to win rate increse cases from regulators. Any hope of change therefore rests with our governments and utility regulators, but until such change happens it should be no surprise why our governments and regulators appear to be forcing new technologies onto the utility industry.
chester johnson 8.13.09
Bob A. Raising rates in a regulated utility, and I daresay in many co-ops, is not how profit is improved. Rate increases are generally after-the-fact indexes to deal with rising cost. Value-added improvements such as better customer satisfaction and improved accuracy along with strategically adding remote metering or meter reading can effect profit however. Sometimes there are incentives built into the tariff structure for this along the lines of efficiency, CSat surveys, and improved safety to encourage stronger effort on the part of utilities. As far as equipment upgrades; for many years as noted, mechanical meters held up beautifully. Now there is increasing need for more detailed and more timely data collection that is not a function of the old standard meter. Along with that there is the issue of ever improving technology, such that a physically long enduring device is not practical past the point where its technology capability has been out-dated. Computers are a fine example, since that is exactly what I am expressing an opinion about. Dos machines are not up for the high level computing required in todays internet world, and since electronic meters are basically computers, expect to see shorter life designs and turnover of equipment from time to time. The improved meter function can and will be increasingly a benefit to the customers, but that is not the main thrust for utilities. Remember, it is quite enough work to keep up with the changing landscape for the utility core functions of providing reliable power, reducing outage times and billing accurately. Therefore, "status quo" is not a term that benefits a utility. Spending rate-payer money to offer consumer products must be done with regulator approval, and that is where the road-block exists. Don't hold your breath hoping in the gov't or regulators to mandate improvements and change. The utilities have been the strongest force to push the regulators to allow progress. To their defense, regulators are charged with seeing that rates are held down and consumers get a fair value for their rate. Business risks you mentioned above are not part of a tariff by design, but you will notice that many utilities are spinning off unregulated partners or subsidiaries that utilize stockholder funds for these ventures. I hope this has lessened your dislike of 'utilities' assumed motives, and enlightened you about who is really the force behind progressive improvements and that the regulators by mandate are the opposite. CJM
Bob Amorosi 8.13.09
Chester J.,
Very enlightening comments indeed. I tend to believe you because here in Ontario I have seen first hand some utility executives who are all in favor of overcoming the "road-blocks" you refer to, and point to our politicians and government administrators as the key people that can effect regulatory change but fail to do so very often.
I fully understand that the mandates behind the new electronic meters in most places are to enable implementing future TOU billing rates, and enhance the other changing core utility functions you talk about. No doubt utilities are preoccupied just trying to keep up with maintaining core functions. The other possible consumer benefits the electronic meters offer are typically viewed as secondary by both utility companies and by regulators.
However what regulators and perhaps some utility companies both may not fully realize (yet) is there is potential for consumers to fund the spin-off ventures you talk about directly with rate-payer money without the need to spin-off other companies. The answer is by permitting non-uniform customer rates just as CATV and telephone companies do.
The real underlying problem, in my humble opinion, is that regulation not only demands that rates are purposely held down, but that they must be uniformly applied to all utility customers. If a utility company wants to incur added costs for ANYTHING, be it expanded infrastructure or additional consumer benefits that are beyond the core status quo of delivering power and outage management etc., these extra utility costs must be borne by ALL ratepayers whenever a rate increase is approved. This regulatory regime only perpetuates the demands by government policymakers and hence regulators to hold rates down, and hence be inclined to not want to change regulation.
The nice thing about non-uniform billing rate structures in the CATV and telephone industries is that consumers who want and can afford the extra benefits offered read extra services, they are given the choice to purchase them by ordering them and paying higher bills. We have never had such a choice when it comes to buying electrical energy.
chester johnson 8.14.09
That choice was offered, and it was a disaster. Remember de-regulation? It does come down to the difficulty of serving a non-uniform customer uniformly, especially while tightly regulated by committee. Rule by committee is always a burdensome time-consuming process that is far from efficient. By definition, compromise is less than the best idea and includes some part of the worst ideas. I do envision that the major utilities are in the best position to be the delivery agent of good changes, but the conception, R&D and development capital cannot be part of the regulated utility capital. Rates for electricity are set based on the cost of supply and delivery, and should be kept that way. Other services that are individual customer based and individual customer benefiting can be facilitated by the utilities,if allowed, but the capital and the profit must be kept uniquely separate from the utility since that presents some very sticky issues for the utility and it's regulatory milieu. With the emphasis, and the capital input from outside the rate payer money, such as ARRA funds etc, there will be seen infrastructure changes that benefit everyone, and spin-offs that benefit individual customers will not be far behind. Status quo would be a death knell for all interests. I understand that it would be good if non-uniform billed services could be structured, but the underlying reason that they don't work in the electric utility sector is that the infrastructure and it's maintenance was designed so the tariff shared the burden across all participants equally. Playing with that design would unfairly burden those least able to effect adjustments for themselves, the little guy. This is the chief problem with 'de-regulation' if you truly believe it was "de" and not "re"regulation. It was designed in theory to benefit the big players, but messing with the formula has cost every player far more than they ever anticipated. I'm in favor of keeping the Electric utilities simply focused, and leave the customer side usage changes to the private sector beyond TOU and load control management programs. We've already seen many energy saving changes in appliances, A/C units and lighting etc, and I could not imagine that valid efficiency is not being pursued in all areas that use energy. Reliable and cost effective energy production and delivery is a foundation upon which all else rests.
Bob Amorosi 8.14.09
Chester,
From your comments ARRA funds are about the only way utility companies are going to invest in new infrastructure that may offer consumer benefits. I would have to agree if everyone takes your point of view about the need for everyone to share equally the costs of infrastructure through regulation of rates.
Consider this though. The grid's future is pointing to increasing numbers of distributed local generators from renewable sources appearing, some connected to the grid and some not. If a local business sets one up near me connected to the grid, and I want to buy electricity from THAT generator because THAT generator has the lowest cost power available, why should I as a consumer be forced to pay a higher uniform tarrif on the grid set by regulation? If nothing else it discourages THAT generator from connecting to the grid, and indeed it may encourage it as a business to instead connect a private local feed directly to me.
The traditional model of all participants sharing the costs of infrastructure and its maintenance assumes everyone benefits equally by receiving reliable energy supply on demand at any point in the grid. This makes sense when large central generator sources supply large numbers of customers on the grid. However this does not make as much sense for increasingly decentralized generation as the future promises to have.
chester johnson 8.15.09
This is exactly the logic that laid the foundation for the deregulation snafu. Large industrial customers felt they could make out better on their own,then found out that they were dependent on the reliability of the grid. Island generation had its place, but could not compare for overall reliability. How much down-time would you accept under your suggested scenario? What if down-time is big money lost for your operation? Since the grid then saved their bacon, I'd say it is appropriate for them to continue to participate to insure the grid stability and availability. Remember, the smaller (than utility size) got taken to the cleaners by a few easy manipulations of the power market, and the utilities lost their shirt by regulatory mismanagement, or more precisely mis-vision.
Many of the smaller gen's found that a new installation was fine, and saved - until the new wore off and repair and maintenance kicked in. That left them more in the hole in the long run. There were no winners.
One of the best results from that experience is that the complacency about the reliable source has vanished forever, so also for the petroleum business. The resultant new attitude has everyone looking at the future and making prudent preparations to avoid the same hole. Individuals are investing in small generation, inventors are very busy bending their brains to achieve methods to lessen the impact of future problems, and individuals are more aware that a reliable grid, there to back up everyone, is even more a necessity than they had figured.
Distributed generation really is the best tool for now to deal with the missing links. The need for new power paths is painfully apparent, but don't appear on the landscape very easily. I don't think there will be enough major new high power line installations or existing path upgrades to avoid the shortages looming, not due to shortage actually, but due to lack of ability to send it where it is needed from where it is produced. That is the new frontier.
If an individual could make all his own power and be allowed to not share in the grid maintenance cost, would he then be allowed to use the grid for when his source fails or is down for maintenance? How would that be equitable to the others that carry his share of the grid maintenance burden?
Currently the laws do not allow the avoidance of the grid costs, even to those who make and use only their own power, so in your scenario the private local feed would still invoke grid costs, since the laws also mandate that the grid be available to you for when yours fails. I suppose I would be in favor of that method of grid cost avoidance if you then were locked out from using the grid as your back-up. Other than that, the fairness logic above applies in my opinion.
The grid costs are only a minor portion either way. The cost of generating and maintaining your own private source is still comparably high, and the power from the grid remains a good value so far. I would still encourage conservation rather than production at the individual level as the method to get the best bang for the buck. All the consumer energy management and energy efficiency tools you had expressed interest in earlier stand a better chance of benefiting the individual so far.
The article this is under is about a major area where change is occurring more rapidly due to the emerging technology, and will have a more profound impact on the providers and the customers. The spin-off is that it will also impact the subject of our discussion in a positive direction. CJ
Sarah Weldon 8.18.09
ARRA is incorrectly named in this article. It is not called the American Recovery and /Revitalization/ Act, it is called the American Recovery and /Reinvestment/ Act.
