20030815Comment.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSIONIN THE MATTER OF THE INVESTIGATIONTIME-OF - USE PRICING FOR IDAHOPOWER RESIDENTIAL CUSTOMERS.CASE NO. IPC-O2-Comments of the Demand Response and Advanced Metering Coalition (DRAM)The Demand Response and Advanced Metering Coalition (DRAM) is a policyorganization comprised of utilities , public interest groups, metering and communicationscompanies and demand response providers. DRAM's interest is in providing input andinformation to parties that are examining or implementing advanced metering anddemand response programs. DRAM previously filed comments in the subj ectproceeding on December 6, 2002. We appreciate the opportunity now to provideadditional comments to the Commission and other interested parties in Idaho and hopethat they will be of assistance relative to this proceeding.BackgroundDRAM's comments are submitted pursuant to Commission Order No. 29291. In that
order, the Commission sought comment on the Automated Meter Reading Report, Idaho
Power Company, May 2003" filed May 9 2003 , (hereinafter "2003 AMR Report"
).
The
Commission in particular sought comment on five questions:
Should the Commission direct the Company to implement AMR on its
system?
How can advanced metering technology enable Idaho Power Company and
ratepayers to make the most of future "smart grid" transmission and
distribution technology?
As part of a wise investment , what features or technology should the
Company employ?
Under what timeframe should the Company implement AMR?
How should the Company recover the costs associated with AMR?
Overview
DRAM commends the Commission and the other parties to this proceeding for their
persistence and dedication to what , as DRAM identified in it previous comments , is a
new and challenging undertaking - assessing how to move forward to provide consumers
and electricity providers with advanced metering technology that provides each with new
previously unavailable benefits and capabilities.
As DRAM has previously discussed , the challenge in part comes from the fact that ametering decision is no longer simply a question of how to best accomplish the historicalmetering function i. eo measuring and retrieving simple usage data for billing purposes.Today, advances in metering and communications technology mean that a meteringsystem can become an informational gateway between an electricity provider and itscustomers as well an a key enabling tool that provides both with new benefits andcapabilities that have not historically been associated with the metering function. Addthe fact that these benefits accrue in areas that have historically had nothing to do withmetering and the challenge becomes apparent identifying, quantifying and evaluatingall of these benefits in a cohesive and comprehensive manner.In terms of a conceptual approach, a useful analogy may be that of the transition from useof adding machines or calculators to personal computers for performing calculations andother computational functions. An adding machine satisfactorily met the purpose forwhich it was primarily, perhaps even singularly, designed i. eo number "crunching . Butthat is all it did. It provided no added value nor new capabilities , either related orunrelated to its primary function. With the introduction of personal computers, a newtechnology arrived that did the basic function of the adding machine and calculator, butof course was capable of much much more. In terms of the business world, theadditional functions and benefits that computers introduced created a new world ofbusiness operations and a new level at which businesses could perform. While it maystill be possible for certain small companies to use adding machines in their businessoperations, it is a rare business today that can be competitive and produce and support itsproducts and services without the added value and additional capability of computersparticularly with respect to the media storage and communication abilities that they
provide.
For decades , electricity meters have had a simple job to perform: accurately and reliably
measure the amount of electricity used at a particular location such that correct and
accurate bills based on total usage can be rendered to the electricity customer by the
electricity provider. While electricity costs have always been much higher during peak
periods, technology did not exist or was too expensive to record time-based usage.
Accordingly, regulators designed rates based on total consumption, and required nor
expected any further functionality from the meter.
The cost of a computer is obviously higher than an adding machine. Yet almost every
business has replaced its still-functional adding machines with computers, understanding
the cost as an investment, where the return on that investment would not be measured
simply by the ability of the computer to replicate the computational functions of the
adding machine.
Today, new technologies have entered the metering arena. With the advent of new
electronic and digital metering technology, as well as the introduction of new data
communication media and technologies, the modern electricity metering system is
longer simply an "adding machine It is a combination of hardware and software that
goes far beyond the historical metering requirement and provides new capabilities and
new benefits. But it is not only the technology that is different, today. The electricityindustry is different. It is an industry that whether or not it may be moving towholesale and retail competition in a particular state or region, is changing in terms of theexpectations placed upon it by electricity customers and by those who legislate andregulate on behalf of those customers.Importantly, many of the benefits of advanced metering, if not most accrue directly toratepayers in the form of lower peak power costs and higher reliability. Since thesebenefits typically do not accrue to utility shareholders, the benefits are usually excludedfrom metering business cases. Since ratepayers are receiving these benefits ratepayershave an interest in paying for the technology that enables them.It is in this context that DRAM recommends parties to this proceeding view the questionsand the issues at hand. The advanced meters that the Commission believes should bedeployed in Idaho provide a number of different types of benefits that accrue to differentparties in different ways - benefits that go beyond the core task of "revenue" metering. Itis DRAM's contention that when all of the benefits are considered against correctappropriate and up-to-date costs , that advanced metering is prudent and properinvestment by Idaho utilities on behalf of their customers.Question 1: Should the Commission direct the Company to implement AMR on itssystem?Before this question can be answered, it is necessary to define what is meant by "AMR"
While sometimes mistakenly interpreted as an acronym for "advanced" meter reading,
AMR in actuality is an acronym used within the metering and energy industries for
automated" meter reading. Whereas a Automated Meter Reading system provides only
one advantage over basic , historical metering technology, in that it allows the collection
of measured data to be done via a mobile
, "
drive-" system, a true "advanced metering
AMR, (hereinafter "Advanced Metering System ) provides many additional benefits.
DRAM discussed these benefits in its December 6 , 2002 filing and it will refer to such in
these comments as well.
It is important to note that these benefits are in addition to the automation of meter
reading. Remote meter reading is a standard part of either an AMR system or an
Advanced Metering System; it is not an either/or factor between the two.
If the Commission is asking Question # 1 in the context of basic Automated Meter
Reading, DRAM would submit that the answer is no. To invest in such technology
would not provide the additional technological and functional capabilities that Idaho
electricity consumers will desire nor provide Idaho providers with additional capabilities
with which to modernize and optimize their operations. It may the case that an
expenditure on such a system may not be an investment at all , where an investment is
defined as an outlay of capital that will provide future returns and benefits.
To the question of whether the Commission should direct the deployment of anAdvanced Metering System, the rebuttable presumption should be yes , in the sense thatabsent such metering being in place , meter reading costs will be higher than necessary,customers will still be receiving only minimal data about their consumption and will notbe able to choose to manage their usage according to time-varying prices and Idahoproviders will not have any enhanced data or functionality with which to improve andoptimize their operations and performance.A variation on this question, which is raised by the 2003 AMR Report, is the question ofwhether the Commission direction should be to immediately proceed to a fulldeployment of advanced metering or whether it should proceed in stages. Idaho PowerCompany (hereinafter "Idaho Power" or "the Company ) suggests in the subj ect reportthat it may be appropriate for the Company to undertake an implementation in a phasedmanner. Metering deployments often occur over a period of years and such an approachmakes sense in this case.There is an important caveat that accompanies the answer to this question, however. Ifthe Commission is to direct electricity providers in Idaho to deploy and implementadvanced metering, it must also provide a means of recovery by the regulated provider ofthe cost of such investment. In the case of Advanced Metering System where many the benefits accrue , either directly or indirectly, to the ratepayer, it is proper for the costsof this investment to be recovered in rates and for the utility to receive regulatorycertainty that those costs will be recovered.
Question 2: How can advanced metering technology enable Idaho Power Company
and ratepayers to make the most of the future "smart" grid transmission and
distribution technology?
The term smart grid" is not defined in the Order; while this term is frequently being used
in the energy industry today, it is subj ect to broad interpretation. DRAM would offer that
however defined many of the non-billing and customer services capabilities that
Advanced Metering System provides are functions that help create a "smart grid"i. eo
that a grid cannot be considered "smart" unless it includes a "smart" metering system.
These functions include, but are not limited to:
Interfacing with an outage management system to respond more
efficiently to outages and provide better information to customers on the
scope and status of outages particularly automatic verification of
restoration at the individual customer level.
Collecting meter information and matching this with connectivity
information in order to construct system loading models that can be used
for both long-term planning and daily operations decision-making.
Collecting and analyzing circuit and transformer loading and outage datato improve distribution system planning and optimize distribution systeminvestmentsCombining the advanced metering system with load control capability tocreate a fully functioning demand response program, capable of managingloads as well as validating load reductions and results.Collecting and analyzing selected voltage data to ensure proper operationof the distribution system.The Company benefits from lower meter reading costs and savings on distributioninvestments. Ratepayers will from higher quality service , reduced personnel cost , moredemand response options and a better managed system that will decrease the need forexpensive new generation.Question 3: As part of a wise investment, what features or technology should theCompany employ?By completing a detailed market analysis in the context of its own specific geographicand other requirements , the Company has correctly determined the appropriatetechnology for it Advanced Metering System. In addition, the Company has conducted apilot to ensure that its Idaho ratepayers would have coverage over the great , and varied
terrain of its service territory. Company s 2003 Report shows that the results of its
analysis has led it to focus on a technology option which is indeed an Advanced Metering
System according to the energy industry s generally accepted definitions of Advanced
Metering. This analysis also involved a pilot of the technology to ensure that it would
serve all of the Company s customers throughout the dispersed area, and varied terrain of
its service territory.
Members of the DRAM Coalition agree that an appropriate advanced metering and
communications technology should be capable of meeting the following definitions:
Demand Response Retail
Pricing programs or rate structures , including time-of-use and real-time prices
which provide energy consumers with a price per unit of energy that varies
according to the period in which the energy is purchased or consumed.
Time-Based Pricing
Retail prices for energy consumed that offer different prices during different time
periods and reflect the fact that power generation costs and wholesale power
purchase costs vary during different time periods. Includes Time-of-Use Pricing
and Real-Time Pricing.
Time-Of- Use Pricing
Energy prices that are set for a specific time period on an advance or forwardbasis, typically not changing more often than twice a year (summer and winterseason). Prices paid for energy consumed during these periods are pre-established and known to consumers in advance of such consumption, allowingthem to vary their demand and usage in response to such prices and manage theirenergy costs by shifting usage to a lower cost period, or reducing consumptionoverall. The time periods are pre-established, typically include from two to nomore than four periods per day, and do not vary in start or stop times.Real- Time PricingEnergy prices that are set for a specific time period on an advance or forwardbasis and that may change as often as hourly. Prices paid for energy consumedduring these periods are typically established and known to consumers a dayahead ("day-ahead pricing ) or an hour ahead ("hour-ahead pricing ) in advanceof such consumption, allowing them to vary their demand and usage in responseto such prices and manage their energy costs by shifting usage to a lower costperiod, or reducing consumption overall.Advanced MeterAn electric energy or natural gas meter, new or appropriately retrofitted, whichmeasures and records usage data, at a minimum, in hourly (electric) or daily (gas)intervals , and which allows electric energy or natural gas consumers, suppliersand service providers to participate in price-based demand response programsand manage the purchase , sale , and use of electricity or natural gas in response toenergy usage data that consumers , suppliers and service providers receive on atleast a daily basis.
Advanced Metering Device
Equipment, systems , software, and/or related devices which have as a purpose
the measurement and recording of usage data, at a minimum, in hourly (electric)
or daily (gas) intervals , and which allows electric energy or natural gas
consumers , suppliers and service providers to participate in price-based demand
response programs and manage the purchase , sale , and use of electricity or
natural gas in response to energy usage signals that consumers , suppliers and
service providers receive on at least a daily basis.
Retrofitted Meter
An electric energy or natural gas meter or metering device that has been modified
by the addition of equipment, systems , software and/or related devices which
have as a purpose the measurement and recording of usage data, at a minimum
in hourly (electric) or daily (gas) intervals , and which allows electric energy or
natural gas consumers , suppliers and service providers to participate in price-
based demand response programs and manage the purchase, sale , and use of
electricity or natural gas in response to energy usage signals that consumers
suppliers and service providers receive on at least a daily basis.
The technology being focused on by the Company is capable of meeting the metering
definitions and supporting the pricing structures above. It therefore meets the technology
test of being a wise investment.
Question 4: Under what time frame should the Company implement AMR?DRAM believes the Company s proposed timeline of four years is reasonable. TheCompanys plan, particularly as it pertains to working out the inevitable hiccups and bugsof a new system before it deploys in the denser urban areas seems prudent. The onecaveat is that the tax benefits of the accelerated depreciation under the EconomicStimulus Bill are scheduled to expire in 2005. Further, if the proposed Federal EnergyBill is passed it provides an accelerated depreciation tax deduction for AdvancedMetering deployed from 2004 through 2007. The Company may desire to calculate thesetax benefits to analyze the cost/benefit of delayed or accelerated deployment.Generally, electric utility equipment such as meters and related substation equipment isdepreciated, for income tax purposes , over a 20-year recovery period. Software istypically depreciated over a 3-year (36 months) period. Due to recently enactedlegislation, there are potentially significant current income tax benefits that accrue tosuppliers of electric energy (such as Idaho Power) if such suppliers purchase and place inservice equipment , including software, meters and related substation equipment. Currenttax law provides for 50% bonus depreciation on certain property that is placed in serviceprior to January 1 2005. Thus 50% of the cost of such property, including softwarewhich is placed in service prior to January 1 , 2005 , is recovered in the 1 s1 year. Theremaining cost is then depreciated over its applicable recovery period. This cost recoveryprovision can generate substantial tax cash benefits by reducing Federal income taxes the year such property is placed in service. The greater the amount of software , meters
and equipment placed in service prior to January 1 , 2005 , the greater the current tax
benefit accruing to the electricity supplier.
These benefits will be magnified further if pending legislation is enacted. Pending
legislation (the Federal Energy Bill) would , in addition to the 50% bonus depreciation
allow a current tax deduction (up to a maximum deduction of $3 a per device) for
Advanced Metering Systems placed in service during the years 2004 through 2007.
Further, additional pending legislation would decrease the recovery period for such
systems from 20 years to 3 years. Thus , there could soon be available potential tax
deductions of up to $30 per meter in the 1 s1 year placed in service, plus 50% bonus
depreciation in the 1 s1 year placed in service , with the remaining cost of each meter being
depreciated over a 3-year period (as opposed to a 20 year period). These additional
income tax benefits provided by pending legislation would further reduce Federal income
taxes in the first year and would provide increased tax depreciation deductions for the
remaining 3 years.
Question 5: How should the Company recover the costs associated with AMR?
DRAM will refrain from making a specific recommendation in terms of how the revenuerequirement of the investment should be determined and how that rates relative to suchshould be specifically designed. The important point is that the costs should berecovered, subj ect to cost verification, as a prudent and appropriate investment in aproviders core infrastructure which will provide both future and current benefits to theprovider and , either directly or indirectly, to its customers.One issue that should be considered is that the metering systems in question are no longersimply mechanical hardware devices. Advanced metering systems represent state-of-the-art combinations of electronic/digital hardware and software. As such, they need tobe considered for treatment of such in terms of depreciation and other cost recoverycomponents. As noted above pending legislation in the U.S. Congress recognizes thisdevelopment by providing advanced metering systems with special tax deductionsincluding accelerated depreciation.Another issue is the anticipated savings. Since many of the savings will accrue toratepayers in the form or lower power costs in the long term, it may be appropriate toconsider including any incremental cost in per kWh (as opposed to per customer)charges. In any case, Idaho Power is in the best position to make a specific cost recoveryrecommendation.Additional CommentsCost Allocation over the Four-Year Deployment Period
The May 9 , 2003 AMR Report of Idaho Power raises questions as to how the costs are
allocated over the four-year deployment. Based on the number of units expected to be
deployed in the first year, and taking into consideration the specific characteristics of that
part of the Company s service territory, it appears that the cost indicated in the Report for
this first year may be high. This could result in two problems. First it may
inappropriately raise the cost estimates based on different assumptions as to when an
outlay must be made i. eo presently or discounted as a future outlay. Second, it may
distort the comparison of costs and benefits , when certain benefits , particularly those not
related to meter reading savings , occur in later years.
This again brings focus to the need to balance costs and benefits. In that vein, DRAM
finds insufficient assessment and quantification of the benefits of the Advanced Metering
System in the report. The only benefit that appears to be included is that of savings on
the meter reading function. Yet other benefits will accrue.
One of the challenges with advanced metering when it is employed to enable customers
for demand response (which was and presumably still is a major driver for the
Commission s action in what began as a TOU proceeding) is that is that some of the
benefits accrue more directly to the customer than to the provider itself. For example , in
a TOU program, customers benefit by shifting their load to lower their bill, and in doing
so other non-participating customers also benefit from the downward pressure on peakwholesale prices that such shifting yields. While this customer behavior can also be benefit to a utility in terms of its ability to optimally and reliably operate its system, it canalso lead to lost revenue for the utility, particularly through the conservation effect thatnormally occurs in addition to that of load shifting.The important point here is that the benefit to customers is real. It should be recognizedas such and included as a benefit of advanced metering to be weighed against the cost.This should be the case even if a demand response pricing program is not immediatelyimplemented since the capability for such will have been implemented via thedeployment of advanced metering.By comparing a cost for an Advanced Metering System that is not "plain vanilla" to thesole benefit that comes with a "plain vanilla i. e. basic Automated Meter Readingsystem, the 2003 AMR Report may have created an apples to oranges situation. DRAMbelieves the Commission should review and discuss both the cost and benefit data withthe Company to remedy this situation before making a decision.The example above also ties to the question of cost recovery for the utility. Utilitiesshould be allowed to recover the costs of an Advanced Metering deployment in rates inrecognition of the benefits to its customers that are provided and/or enabled as a result ofsuch.Storage of Hourly Interval Data
In addition to further quantification of the benefits , there are questions to be raised
regarding the some of the costs alluded to in the 2003 AMR Report. DRAM questions
the need to store all hourly data, per Idaho Power s 2003 AMR Report (see p.21). On one
hand Idaho Power included only the benefits of MONTHLY reads but on the other
included the costs of data storage for HOURLY reads. Given the redaction of the Report
DRAM is unable to ascertain:
The costs associated with "Additional Data Storage to Handle Hourly Meter
Readings
The methodology IP chose to store the data
Whether the hourly data stored was to be incorporated/integrated directly into
IP's CIS.
Whether the costs included ALL hourly reads from ALL meters , or only hourly
reads from that subset of Customers who would be on a Critical Peak Pricing rate
and only those relevant hourly reads
It does not seem logical to include cost of hourly data storage, unless one also
calculates the benefit. Since, the Commission has not yet created a Critical Peak Pricing
(or other Demand Response type) rate utilizing hourly data, it does not seem fair to
impose upon the Company an obligation to store such data. Once , a Demand Response
rate has been created then "an apples to apples " comparison of cost/benefit may be
undertaken. For example , the Oregon Public Utilities Commission ordered PacifiCorp
and Portland General Electric to "evaluate demand response programs on par with otheroptions for meeting energy and capacity needs." (Order 03 -408 , In re Demand ResponseProgramsOregon Public Utility Commissionh11p:/ /www. puc. state. or. us/ orders/2003 ords/03 -408 .Q1Lf)If this Commission believes nonetheless , that this cost should be included , the questionsremain "how and how much of the hourly reads should be stored?" in order to accuratelyassess the cost impact. The hourly data could be archived on tape drive for a, relativelyspeaking, nominal amount. If the Company is not required to bill off the hourly data, thismay be a completely acceptable solution. The question also arises as to how much of thedata must be stored. DRAM cannot ascertain how the Company calculated its storageneeds. DRAM is under the assumption that the storage would be of 3 years data. If theCompany simply took each meter and multiplied by 24 and then by 365 and then by (24x365x3) that results in storing 26 280 meter readings. However, if the Companyrequirement to store data only related to the Hourly readings during a Critical PeakPricing ("CPP") period it would be substantially less. Usually, CPP rates are onlyimposed on customers for a limited number of days during the year (generally ten totwenty days) and only for a portion of the day (usually between 4 to 8 hours). If one took20 days by 8 hours for 3 years (20x8x3) that results in storage of 480 meter readingssubstantially less than 26 280.DRAM does not know exactly how the Company quantified the costs, but in any casebelieves this cost component if included should not be constructed in such a way as toimpose unreasonable costs on the Company.
Plain Vanilla " AMR
The 2003 AMR Report claims to have evaluated a "plain vanilla power line carrier
technology that is "capable of replacing the functions currently performed by existing
meter reading technicians . With this definition
, "
vanilla" would appear to clearly refer
to a basic Automated Meter Reading system, as opposed to an advanced system. Yet , as
the 2003 AMR Report goes on to state, the Advanced Metering System referred to does
more than the basic automated reading function.
Advanced Features Requiring Additional Investment
Several comments are in order in response to this section on page 11 of the Report.
Contrary to the Report , the system being contemplated would allow Critical Peak Pricing,
although the report is correct that some modifications to the customer billing system (or
Customer Information System or "CIS"would be necessary. Finally, the Report also
infers that an investment would be necessary to be able to communicate price signals to
customers for "advanced pricing . This is not necessarily the case. Various existing
communication media can be employed in a time-based pricing program, including
conventional Radio and TV and Print for notification of Critical Peak Days and/or TOU
price changes. The Internet and email also can be utilized. Also , the bill itself becomesa communication medium as it begins to provide more information about the magnitudeand frequency of price signals.Potential Risk of ObsolescenceTechnology obsolescence is a valid factor to be cautious about in a decision on anyinvestment in today s world. It is prudent criteria for a provider and regulator toconsider. But at the same time , it cannot be the sole threshold criteria for an investment.If so , it could easily lead to a continuous attempt at "technology-timing whereby aninvestment is never made for fear of something better or cheaper being on the market thenext day.The key with a metering system is to choose a technology that provides the immediatefunctionality desired but which also allows additional functionality to be employed oradded later. It should be platform that can accommodate future technologydevelopments and not require complete replacement to meet anticipated andunanticipated future requirements.In its concluding section with its recommendation, the Company infers that furthertechnological development in metering is necessary. It states that one of the reasons towait to deploy advanced metering is that the technology will increase in functionality.DRAM cannot discern from the report what this increase in functionality might be. fact, all of the functionality that is discussed anywhere in the report is available withtodays advanced metering technology - and more.
Conclusion
The essential question before the Commission, as it always must be, is that of what is best
for ratepayers. DRAM submits, that prima facie the best for ratepayers is to deploy a
metering system that will provide them with benefits now, as well as in the near term and
on into the future. As with many technology investments , the important issue is that of
whether a certain technology will allow the owner or user to reap future benefits
contemplated now or as yet unidentified. The alternative would be to make a technology
expenditure , as opposed to an investment, where the former may address an immediate
need but provide no capability for anything else.
Advanced Metering Systems represent a prudent investment made now on behalf of
Idaho ratepayers. With its present costs and its technological and functional capabilities
there is no need to risk either a shortsighted expenditure on a less-capable metering
system, or the trap of waiting for the next "big breakthrough" on costs and features.
DRAM recognizes a major component of the benefits of an Advanced Metering AMR
system is the automation of the meter reading itself. Those benefits usually are greater in
the rural areas and represent areas where the benefits can often be more quickly captured.
Those areas may also experience a much higher ROI. For example Kootenai ElectricCooperative calculates a 5 year Return on Investment by implementing the same PLCtechnology as piloted by the Company. The 5 year ROI Kootenai hopes to achieve wascalculated on the basis of 1) improvement of its meter stock and 2) the savings on itsmeter reading expenses. (See Systems Watch Summer 2003 , Vol. 17, and Ed., p.Schlumberger Electricity, Inc.). If the Commission allows the Company to implement anAdvanced Metering System in the remote areas , DRAM is confident that the Companycan achieve a much better payback than 21 years.Accordingly, the Commission s Order No. 29210 staying Order 29126 should be liftedand, as previously directed, the Company should file a four (4) year implementation planfor deployment beginning April 2004. The deployment should be in several phases withthe first phase comprised, as proposed , of the Company s rural and operationally isolatedresidential ratepayers.Respectfully signed and submitted this 15 th day of August, 2003Dan DelureyDan DelureyExecutive Director
Dan Delurey
Executive Director
Demand Response and Advanced Metering Coalition (DRAM)
O. Box 33957
Washington, DC 20033
Telephone: [phone]
Email: dan. delurey~dramcoalition. org