s business and technology strategiesresource adequacy and markets work group

TechSurveillanceBusiness &TechnologyStrategies

article snapshot:

Advances in metering technology and data analytics enable a more dynamic approachto rate design and cost recovery. Advanced Metering Infrastructure (AMI) providescooperatives opportunities for innovative rate design and retail pricing that are betteraligned with fixed and variable power supply costs and changes in consumer behavior.

What has changed? Expanding adoption of advanced metering and communication infrastructures (AMI) byelectric utilities has ushered in a new era of increasingly granular, time-differentiated,energy usage data with near real-time access to that data. This technology-enabled revolution comes none too soon as fundamental changes are transforming the electricutility industry:

• Flat or declining kWh sales. For the past 100 years, electric utilities have relied onvolumetric rates to recover the majority of their costs. Fixed costs and margins wererolled into the energy charge. Now that demand for electricity has leveled off or evendeclined in some areas, volumetric rates based on kWh sold can no longer providerevenue stability.

subject matter expert for questions on this topic

Allison Hamilton, Sr. Principal Markets and Rates: allison.hamilton@nreca.coop

Michael Leitman, Strategic Analyst and Lead of NRECA’s Resource, Adequacy, and Markets work group: michael.leitman@nreca.coop

Jan Ahlen, Sr. Regulatory Affairs Manager, Government Relations: jan.ahlen@nreca.coop

AMI Enables Flexible Pricingand Helps Co-ops MaintainRevenue Stability BY ERIC P. CODY, CODY ENERGY GROUP OCTOBER 2017

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AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 2

article snapshot (cont.):

• Power costs typically make up 65 percent of an electric cooperative’s total cost ofservice. The structure of wholesale power pricing increasingly reflects the daily and seasonalvariability inherent in power generation costs. Indeed, a portion of some electric cooperatives’electricity supplies may now even be sourced directly from the wholesale market.

• Rapid penetration of distributed energy resources, like solar, is impacting energy flowsacross the power delivery system and undermining traditional utility assumptions about costallocation in rates as more members become net providers of electricity to their cooperative.

• Many cooperatives already offer programs that incentivize peak-demand reduction, energyshifting to off-peak hours, and greater energy efficiency. Newly available AMI data allows“mass customization” of these programs — co-ops are able to target segments of the memberpopulation more precisely based on data analytics, while individual members can applyprogram and pricing options in ways that meet their specific needs and preferences.

What is the challenge for electric cooperatives?Because of these tectonic shifts in the utility landscape, the days of one-size-fits-all rate designsand pricing structures may be coming to an end. Moreover, the typical load profiles of residentialand commercial class customers, which have underpinned cost allocations in rates for decades,may no longer be valid or representative for individual members whose usage patterns havechanged. In the absence of careful rate design, this mismatch could lead to unwanted cross-subsidies within rate class populations. Cooperatives themselves may see under-recovery ofpower supply and delivery costs. AMI systems give co-ops the opportunity to proactivelyaddress these challenges.

What do cooperatives need to know and what can they do?AMI technologies come with capabilities that can help address these challenges. The availabilityof AMI data enables innovative business applications and helps usher in new pricing optionsthat hold promise for fuller recovery of power supply and fixed costs. However, electric co-opsneed to understand the relationship between AMI capabilities and their changing electricitysupply and demand patterns to formulate the right pricing options and program incentives.Appreciating the role that AMI data analytics can play is key to success.

How can this article help? This article and the four utility case studies it contains shed light on critical rate design issuesthat have emerged from the ongoing evolution in metering and data communications technology.It highlights innovative ways co-ops and their members can use AMI data and system capabilitiesto successfully respond to the challenges.

RATE-RELATED CHALLENGES ABOUNDElectric cooperatives face challenges to theirtraditional ratemaking practices, not the leastof which is wholesale pricing arrangements

that are being restructured by power suppliers.A diverse set of further challenges to ratemak-ing comes from across the utility landscape, asindicated by the extensive list in Table 1.

AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 3

For example, uneven load growth can be onesource of pressure as indicated in the table. Itcan result from fewer new members, more effi-cient appliances and building systems, or mem-bers investing in distributed generation technolo-gies such as solar...or a combination of thesefactors. Revenue losses can result from the coop-erative’s own member-programs as well — thelost revenue from energy efficiency and peaksaving programs needs to be accounted for inrate designs or periodically recovered if wholesalecosts do not drop by a corresponding amount.

AMI HELPS ELECTRIC CO-OPS ALIGN RATES WITH COSTSA basic premise of the electric utility businessis that the prices consumers pay for the energythey use should closely reflect the way theirutility incurs power costs and, of course, thesecharges should fully recover those costs. Align-ing retail prices with wholesale costs, mosteconomists agree, sends the right signals toencourage efficient use of the product. Tradi-tionally, this has meant co-ops charging theirmembers to a flat, volumetric kWh-based rateto recover the cost of kWh produced by genera-tion plants. Delivery and fixed costs also factorinto rates, but wholesale power cost is gener-

ally the largest contributor to an electric coopera-tive’s cost of service, as noted above.

Historically, electric rate tariffs for most electricityconsumers rarely reflected the fact that it costsmore to supply power at some times of the dayand in certain seasons of the year than others,nor have rates always reflected the cost of gener-ating capacity needed to meet the utility’s peakdemands. Standard, off-the-shelf metering tech-nology has, until recently, not been able to sup-port time-differentiated tariffs.1 With AMI’s ad-vanced meters and digital communicationshow ever, a host of new pricing options becomepossible — time-of-use (TOU) rates, kW-demand-based rates, demand response (DR) incentives onpeak days, and a nearly limitless set of other ratedesigns. AMI can measure, track, and report amember’s electri city usage on a variety of time in-tervals (5-minute, 15-minute, hourly, or in anynumber of ways that can be configured remotelyby the AMI system’s operator). These capabilitiesarrive just-in-time as organized wholesale mar-kets, which value electricity in a highly time-differ-entiated manner, now cover about two-thirds ofthe electricity consumed nationwide.2 Capacitymarkets, for example, value generation units thatare available and ready to meet peak MW demands.

Aligning retailprices with

wholesale costssends the right

signals toencourage efficientuse of electricity.

With AMI, a host ofnew pricing optionsbecome possible.

1 Clock-controlled water heaters, an early form of TOU rate, were common for many years; however, these have largelybeen phased out. Power outages required that clocks be reset manually by a metering person. Some utilities with thesecontrols in place even saw an increased system peak due to the all-at-once nature of the recharge when the control pe-riod ended.

2 Detailed discussion of this and many other facets of modernizing rate designs are discussed in the recently releasedNRECA/CFC Retail Rate Guide – Volume 1.

TABLE 1: Drivers of Rate Challenges in Today’s Business Environment

• Rising construction costs

• Peer pressure

• Political pressure

• Growing interest in energy efficiency and renewables

• State and federal mandates

• Climate change mitigation proposals

• Volatile fuel prices

• Increased use of distributed generation

• Uncertain load growth

• Development of smart grid

• Potential penetration of PHEVs and electrical vehicles

• Competition from other utilities or forms of energy

• New technology

• Reduced use of electricity

• Consumer reaction to higher rates

• Higher cost of generation

Courtesy of National Rural Utilities Cooperative Finance Corporation. © 2017. All Rights Reserved.

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AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 4

In an ideal world then, retail prices might bedesigned to reflect a customer’s kW demand atthe time the utility’s system peak occurs, theso-called coincident peak. While that may be a future option, time-based kWh rates andrates reflecting the customer’s non-coincidentdemand (individual kW peak regardless of whenit occurs) are now coming into play, enabled byAMI. These rates provide co-op members with

information and incentives to reduce their energyconsumption and peak usage during high-costperiods. Many electric co-ops that have installedAMI are experimenting with TOU rates (seecase study of Kaua‘i Island Utility Cooperative).Electric cooperatives for the first time have theability to look deeply into the usage patterns oftheir members, and to provide their memberswith access to this information.

Kaua‘i Island Utility Cooperative (KIUC), America’s newestelectric cooperative, serves about 25,700 active mem-bers on a 562-square-mile island in the Hawaiian chain.This former, investor-owned utility (KIUC purchased Con-necticut-based Citizens Communications’ Kauai Electricin 2002) today faces a challenge that few other electricutilities can easily relate to — renewable energy sourcesplay such a significant role in its resource mix that avail-able, “must-run” units are down to their minimum levelsin the middle of the day. This is because 44 percent ofthe kilowatt-hours KIUC delivers to its members comefrom renewables, with more than 50 megawatts of electricity generated during the day by utility-scale androoftop photovoltaic systems on Kaua’i. So, shiftingloads from the peak evening hours to the daytime allowsKIUC to use less diesel-fired generation, which potentiallysaves money based on the price of oil. This challenge will only grow over time, as the co-op’s goal is to have renewables account for 70 percent of the production mix by 2030.

According to Member Services Manager, Maile Alfiler, thesituation has encouraged the cooperative to think creativelyabout its future and determine whether time-of-use ratesare beneficial to the cooperative and its members. “Wehave a Time-of-Use (TOU) Solar Rate Pilot Program under-way whose objective is to shift energy usage into the 9 am

to 3 pm period each day. We offer our members a 25 per-cent discount on each kWh they use during this window.”KIUC’s pilot program encompasses 350 member accountsdetermined by the cooperative to have favorable loadshifting potential based on their AMI-generated load pro-files. The pilot is, according to the co-op’s rate schedule,designed “to broaden direct customer participation in renewable energy programs and to test whether reducedrates for usage during peak solar periods are effective insufficiently modifying usage patterns, thereby contribut-ing toward a solution to the curtailment issue associatedwith the large amount of photovoltaic resources that havebeen added to the Company’s system.” The pilot ran fromMarch 2016 through March 2017.

Evaluation results for KIUC’s pilot have been filed withthe Hawaii Public Utilities Commission and are availableonline.* According to CEO David Bissell, “While the resultsdidn’t demonstrate a significant shift in usage, the studyis valuable in that it demonstrates that a 25 percent dis-count may not be enough to change behavior when itcomes to energy use.” He adds “that the current differen-tial in the cost of generation between daytime and night-time hours is negligible, and that imposing a significantlyhigher cost to members for evening usage could bepunitive for members who cannot shift their usage todaytime, while returning minimal savings in energy costs.”

ami enables kiuc to steer members’ energy usage to hours of peak sunshine

* KIUC’s evaluation report can be found at: http://kiuc.coopwebbuilder2.com/sites/kiuc/files/PDF/pr/Letter%20to%20PUC%20submitting%20TOU-S%20Pilot%20Final%20Evaluation%20Report.pdf

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Kaua‘i IslandUtility Cooperative

AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 5

AN OPPORTUNITY FOR GREATER REVENUE STABILITY An electric cooperative’s revenues these dayscan reach a tipping point at which revenues nolonger fully cover costs. A striking illustration of revenue erosion can be seen in an overlaycomparison of a typical day in the life of a co-op member with solar and one without (see Delaware Electric Cooperative (DEC) casestudy). The comparison uses AMI data to showneighboring households served by DEC. In thecase of the solar account, the co-op not onlyloses revenue when the sun is out, but mustalso buy the excess kWh sent onto the gridwhenever on-site production exceeds the

member’s electric load (see Net Metering sidebar). Notwithstanding an often-beneficialeffect on the environment, solar and other dis-tributed energy resources may erode revenuesand can lead to unwanted cross-subsidiesamong ratepayers.

Most of today’s AMI systems enable electricutilities to fashion time-differentiated rates tocounter these effects. The technology collectsmore detailed usage information, allows forbilling of rates with multi-tiered pricing win-dows, and facilitates evaluation of DR andother load shifting programs.

Net metering is the name commonly associatedwith electric metering that is capable of runningforward when power is being drawn from theutility grid and backward when power in excessof the customer’s current demand is being pro-duced on-site, typically by rooftop solar. Thisexcess power flows back into the utility’s systemand, in most cases, net metering customers arecompensated for injections to the grid at the fullretail rate. Prior to the arrival of AMI meters thecustomer’s standard meter had to be replacedand registered on the utility’s metering data-base as a special meter. Why special? Because

the challenge of net metering

many of the hourly energy values coming froma net meter are negative and monthly energyfor billing purposes may be lower than the pre-ceding month. Net metering is often controver-sial, as it may lead to cross-subsidization of solar customers by non-solar customers, unlessrates are adjusted to reflect this new reality.What the utility must pay for excess electricityproduced by customers — wholesale or retailprice — is also contentious. Many in the energyindustry agree that load and generation shouldbe metered separately and some states aremoving in that direction.

Time-differentiatedrates enabled by AMIsystems can counter

the negative effects ofdistributed energy

resources in erodingrevenue and creating

cross-subsidies.

How did AMI enable KIUC’s novel pilot program?

The cooperative’s Landis+Gyr GridstreamTM RF mesh network interfaced with NISC’s Meter Data ManagementSystem to pull 15-minute interval load data from partici-pating members’ meters. Member characteristics wereextracted from the customer information system for usein data analytics related to the pilot, which were per-formed at the hourly level. Participating members couldalso gain access to their hourly energy usage data viaNISC’s Smart Hub, updated by KIUC on a daily basis. Absent the hourly interval usage data that is acquired

on a daily basis using AMI, KIUC would be unable to support its members’ decision making about when touse appliances, calculate participants’ bills, or evaluateprogram effectiveness.

For additional case studies on KIUC, see: Tom Lovas,“Kauai Island Utility Cooperative: The Impact of Extensive PV Penetration,” TechSurveillance, July 2015,and Eric Cody, “Smart Grid Brings Load Research toKaua‘i =Island Utility Cooperative,” TechSurveillance,June 2014.

ami enables kiuc to steer members’ energy usage to hours of peak sunshine (con’t)

AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 6

Delaware Electric Cooperative (DEC) serves 90,000 mem-bers in Kent and Sussex Counties of Delaware. The coop-erative is not rate-regulated; however, it is subject to staterules requiring net metering to encourage solar develop-ment. DEC currently serves about 1,200 of its memberson this basis, and their daily load patterns are strikinglydifferent from those of their non-net-metered neighbors(see graphs). Net metering sites include individual mem-bers’ solar installations, homeowner associations, andSolar City interconnected sites. The cooperative has threenet metering tariffs that correspond with these — individ-ual, allocated, and aggregated, respectively. Mark Nielson,DEC’s Vice President of Staff Services, is realistic about therole his co-op’s AMI system plays in addressing the netmetering issue. “We don’t necessarily need a high-speedAMI communication system to address our net meteringchallenge.” However, he quickly adds, “Detailed, hourlyload data we get from the system does help us when weperform allocated cost of service studies and try to main-tain rates that are fair and equitable to all our members,especially as the situation intensifies with respect to solar.”

Along these lines, DEC’s monthly residential customercharge was $7.95 until recently. The co-op’s allocated cost-of-service analysis, which reflects data for the increasingnumber of solar-powered accounts, indicated that a chargeof around $19.00 was appropriate. The co-op’s board recently voted to increase the customer charge to $14.00.

How Does AMI Enable DEC to Reflect the Impact ofSolar Penetration in its Rates?

DEC’s current AMI system is based on technology origi-nally provided by Cannon Technologies, a powerline-carrier (PLC) based system. Cannon has since been acquired by Cooper Power Systems and the cooperativehas begun upgrading its large commercial customer sites to Cooper’s radio-frequency (RF) mesh network AMIarchitecture. DEC uses its AMI system on a daily basis torespond to member inquiries and view hourly loads. Themain benefits DEC derives from its existing AMI are thedetailed data it provides in support of cost-of-service allocation studies and its ability to provide answers tomembers’ billing questions.

net metering impacts the delaware electric cooperative

Solar output exceedscustomer’s currentrequirements

Day 1

-3

-2

-1

0

1

2

3

4

kWh/

Hr I

nter

val

Non-Net Metered

Solar output exceedscustomer’s currentrequirements

Day 2

Comparison of Usage Patterns — Solar/Net Metered Household vs. Non-Net Metered Household

Non-Net MeteredSolar

Net MeteredNon-Net MeteredSolar

Net Metered

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AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 7

NO ONE-SIZE-FITS-ALL AMI SYSTEM What exactly is AMI and how does it differ fromearlier-generation Automated Meter Reading(AMR) technology? How does it compare withSmart Grid technology? Is it a tool for use pri-marily by the electric co-op or by co-op mem-bers? What capabilities do the advanced metershave? What role does the communication sys-tem play? When industry insiders are askedthese questions, the answers often vary.

Industry literature generally portrays AMR as alimited-capability system which allows cumula-tive data, such as monthly kWh, and for someaccounts kW demand, to be retrieved electroni-cally by any one of a variety of methods — ameter reader walking past the meter with ahandheld device, a specially equipped, short-range-radio van driving by, or via a one-waycommunication path, such as powerline carrieror radio frequency transmission.3 AMI, in com-parison, usually refers to a system with greaterfunctional capabilities, such as multiple storageregisters for maximum kW, accumulated kWh,time-interval kWh, voltage and power factor, as

well as programmable alerts and conditionflags. The meters can be set up to record total,minimum/maximum, last event occurrence,and other parameters. However, the real advantage that AMI offers over earlier AMRtechnology lies in the networked two-way communication system that ties the meters andother intelligent devices together across theelectrical system. This network gives the AMIsystem operator access to a widening range ofdata in a timely, if not necessarily real-time,way and enables a host of new business appli-cations, including the ability to offer, support,and evaluate more flexible pricing structures.So, while a past AMR investment might havebeen justified by improvement in the effi-ciency and cost of meter reading, this benefit is hardly mentioned when AMI investments arebeing considered.

There is no one-size-fits-all AMI system. As Figure 1 suggests, metering and data commu-nications technology has evolved over severaldecades. As typical customer meters have beenupgraded to collect and store more granulardata (e.g., time-interval), and data communica-tions have trended toward two-way data flowsand higher bandwidths, more and more pricingoptions have become feasible.

Local conditions come into play in determiningwhich data communications systems a particu-lar utility can adopt and also to some extent thelevel of business benefits a utility can expect torealize from its AMI investment. Different AMItechnology solutions come with varying levelsof capability and sophistication. Broadbandcommunication links, such as optical fiber, pro-vide greater data carrying capacity and fasterdata transmission compared with other com-munication choices, such as powerline carrier,which uses the electrical wires themselves fordata transmission. There are multiple choices

The real advantage thatAMI offers over earlierAMR technology lies inthe networked two-waycommunication systemthat ties the meters andother intelligent devices

together across theelectrical system.

3 A fairly thorough, although somewhat dated, discussion can be found in: Jim Roche, “AMR vs AMI,” Electric Light andPower, 10/01/2008.

FIGURE 1: Underlying Trends in AMI Technology.

Bandwidth/Data Carrying Capacity HighLow

Data Availabilty/Timeliness On-DemandAccess

CollectedMonthly

Data Communications Two-WayOne-Way,Inbound

Data GranularityTime Interval/Multifuntion

Data

CumulativekWh

Early Systems(AMR)

Advanced Systems(AMI)

AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 8

for broadband communications — fiber optic,radio frequency, cable, cellular, and a numberof emerging technologies.4 The constantlychanging field of technology choices makesutility decisions involving broadband invest-ment a significant challenge.5

AMI is most often described by what it is, as isthe case in the definition offered by the U.S. Department of Energy (see sidebar “Definition ofAMI). But, it can also be defined by what it does.Basic systems are capable of retrieving energyusage data on a monthly basis — today’s elec-tronic meters generally enable hourly data to becollected, stored, and retrieved daily or hourly.More advanced AMI systems enable communi-cation and control features that allow co-ops toperform remote connection and disconnection,

“pinging” of the meter to see if power is on atthe home or business, theft detection features,and on-demand retrieval of a host of usage parameters. An increasing number of utilitiescollect and retrieve hourly kWh data for all oftheir members on a daily basis, some evenmore frequently, for the purpose of updatingusage graphs and tables on customer web por-tals. Two-way communication enables the util-ity to interrogate a meter “on demand” when,for example, the customer calls in with a high-bill complaint or other meter-related question.The high-resolution quality of AMI meteringdata also allows utility personnel to troubleshootcustomer equipment remotely.

Anecdotal accounts from within the electric co-op community describe co-op staffers usingAMI to help members identify failures involvingmajor, end-use equipment, such as heating orcooling systems, when there were no obvious“symptoms” other than atypically high energyconsumption or erratic power demand. Someco-ops even use AMI to look at energy usagepatterns in seasonal homes when residents arenot there to determine if the power is on. Thereis a wide array of potential business applica-tions of AMI that have yet to be discovered andco-op personnel are creatively exploring andtesting promising options. An even broader setof business and operational applications areenabled by Smart Grid. These include distribu-tion automation, smart feeder switching, powerfactor improvement, outage management, andother applications.6

4 For a discussion of these options, see: “Meeting Telecommunications Challenges: Cooperative CEOs’ ThumbnailGuide,” NRECA Business and Technology Strategies, May 2015. Parts 2 and 3 are also available on Cooperative.com.

5 A helpful resource for cooperatives considering broadband investment is available: “Due Diligence of High-SpeedBroadband Investment and Business Creation by an Electric Cooperative,” © 2017 NRECA, CoBank, NRTC, and National Rural Utilities Cooperative Finance Corporation.

6 See the TechSurveillance series of articles on NRECA’s nationwide Smart Grid Demonstration Project for examples of these.

“Advanced metering infrastructure (AMI) is an inte-grated system of smart meters, communications net-works, and data management systems that enablestwo-way communication between utilities and cus-tomers. Customer systems include in-home displays,home area networks, energy management systems,and other customer-side-of-the-meter equipmentthat enable smart grid functions in residential, com-mercial, and industrial facilities.”

– AMI as defined by the U.S. Department of Energy.

definition of ami

AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 9

TRANSLATING COSTS OF SERVICE INTORATES WITH AMIHow do the varying costs of power supply become translated into retail rates? There is awell-established methodology that accountsfor all the fixed and variable costs of providingelectric service and reflects them in rates tofully recover costs. However, not all electric cooperatives apply this detailed approach,called a “cost-of-service study (COSS).” Whetheror not a co-op is rate-regulated often determinesthe level of its technical sophistication with respect to COSS and rate design. A detailedand definitive explanation of COSS, as well asother rate design methodologies and issues, iscontained in the recently released NRECA/CFCRate Guide.

To boil COSS down to its basics, the utility firstdetermines its total revenue requirement for aparticular year (called the ‘test year’), includingtotal, annual operating cost, and margin require-ment. It then breaks down, or “functionalizes,”the revenue requirement in a way that allows it to be allocated fairly and equitably across

customer classes according to their specific energy and demand characteristics — inessence, the extent to which they drive thecosts that the cooperative incurs.

What information is needed for this allocationprocess? Each rate class is represented by adetailed set of load profiles (hourly kWh typi-cally; 15-minute or 5-minute interval load datacan be specified to obtain a closer approxima-tion of kW demand) to match up the timing ofthat population’s demands for energy with thehour-by-hour costs of power. A sample residen-tial, non-electric-heating load profile is shownin Figure 2. Load sampling is used to developclass profiles that are valid and representative;however, in the past, only large utilities couldafford to replace sample customers’ meterswith devices that would record loads on anhourly basis. AMI has fundamentally changedthe economics of load sampling. Utilities withAMI, generally speaking, have the ability tochoose sample customers dynamically andmonitor their hourly usage without the need to do an expensive meter exchange.7

Whether or not a co-op is rate-

regulated oftendetermines the level

of its technicalsophistication withrespect to COSS and

rate design.

FIGURE 2: Sample Residential Class Average Daily Load Profile Obtained from AMI

7 For an illustrative case study on this topic, see: https://www.smartgrid.gov/files/NRECA_TPR2_AMI_KIUC.pdf andhttps://www.cooperative.com/interest-areas/CRN/products-services/TechSurveillanceMagazine/Documents/TS_SGDP_Load_Research_AMI_June_2014.pdf.

AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 10

AMI’S GRANULAR DATA ENABLES FLEXIBLE PRICINGThere are a multitude of ways in which AMI sys-tems support and enable innovative pricingand customer rate incentive programs designedto signal co-op members when power supply is more costly. The time-interval, energy usagedata today’s meters can store and transmitback to the utility are highly valuable, althoughimmediate retrieval of these data by the co-opis not necessarily required for many rate appli-cations. AMI typically offers electric utilities theability to look at hourly (or sub-hourly) energyusage by every individual customer fitted withan advanced meter, allowing retail pricingstructures that closely reflect the wholesalecost profile of the co-op’s power supply. Inessence, the electric utility industry has beenpropelled into the “high-resolution” era.

Cooperative rate planners and member serv-ices people can use AMI’s remote data accesscapabilities to “zoom in” on member-usagepatterns, the way one can zoom in on individ-ual buildings using Google satellite images.Here are some of the direct benefits of havingthis all-the-time, everywhere measurement capability in place. Electric cooperatives can:

• Collect the hour-by-hour, metering determi-nants necessary to calculate bills for mem-bers participating in TOU rates, critical peakpricing (CPP), and DR incentive programs.

• Use detailed load information to proactivelyidentify segments of the member popula-tion for whom TOU, CPP, or DR offeringsmight be attractive.

• Determine the volume of kWh shifted fromon-peak to off-peak hours by individual co-op members.

• Determine kW demand reductions for peak-day rebate programs.

• Determine the hourly load shift or reductionachieved by program participants by com-paring their load patterns with non-programparticipants.

• Determine kW demand reduction duringpeak alerts by comparing the member’shourly, or sub-hourly, load patterns on peakdays vs. non-peak days.

• Measure and verify kW demand reductions in peak hours.

• Measure and verify performance, e.g., peak-demand reductions by interruptible rate pro-gram participants.

• Determine kW demand at the time of class or system peak for customer billing under coincident peak pricing.

• Provide current hourly usage and power demand directly to members to enhance demand reduction, energy shifting, and rate response.

• Verify that customers received peak alert notifications.

This list does not reflect the benefits of havinga massive trove of detailed data not previouslyavailable for analysis. Those benefits aretouched upon in the section, “Data Analyticsare the Key to Unlocking AMI Value.”

Testing the potential attractiveness of TOUrates and peak day pricing is enabled by AMIsystems. In some utilities’ cases, such pilottesting is done before AMI has been fully deployed across the service territory (see National Grid case study).

The electric utility industry has

been propelled into the “high-resolution” era.

Testing thepotential

attractiveness ofTOU rates and

peak day pricing is enabled by AMI systems.

AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 11

National Grid is one of the largest investor-owned energycompanies in the world — operating electric and naturalgas utilities in the northeastern U.S. and throughout theUnited Kingdom. Its operating companies serve approxi-mately 3.3 million electric customers in Massachusetts,New York, and Rhode Island alone. As part of the com-pany’s consideration of a future, large-scale investmentin AMI, it has undertaken an advanced pilot program involving more than 10,000 customers in Worcester,Massachusetts. The purpose of the company’s Smart Energy Solutions (SES) Program was to test customers’receptivity to TOU rates and Critical Peak Pricing that reflects the high cost of generating capacity on peak-demand days. In the words of Bill Jones, National Grid’sDirector of Smart Energy Solutions, “Our intent was to engage customers to see what resonates with them andhow they will respond to the new, time-of-use rate plansand interact with these new technology tools.” Rate provi-sions in SES’s two pricing plans vary with the wholesalemarket prices that influence the company’s energy sup-ply cost, which is reflected directly on customers’ unbun-dled electric bills as a line item.

• The Smart Rewards Pricing Plan offers residential andcommercial customers daytime and evening pricesthat are slightly lower than the current Basic ServiceRate of 9¢ (generation supply and related costs only).However, the price per kWh during so-called PeakEvents is set at 45¢ for the summer of 2017. As manyas 20 peak events can be called per year with up toeight hours per event. Peak rates for commercial cus-tomers in the program are slightly lower. As it is a test,pilot customers are protected against higher bills thatwould have resulted from their participation. However,only about 10 percent of the Plan’s 9,500 participantshave needed this safety net; 90 percent have beenshown to be better off under the plan.

• The Conservation Day Rebate Plan, on the otherhand, offers a reward of 45¢ for each kWh that the customer is able to shift out of the peak period duringPeak Events. Detailed, hourly load data from non-peak

days is compared with same period data during PeakEvents to determine the basis for the credits. About500 customers are participating. In both 2015 and2016, the company notified customers of 20 Con -servation Days, which the company believes is an unprecedented level for dynamic pricing programs.

According to National Grid’s recently released evalua-tion, the SES program achieved a 98 percent customerretention rate, a 69 percent customer satisfaction rate,and total savings of $1.8 million on customers’ electricbills from January 1, 2015 through December 31, 2016.Participating customers also saved a total of 1,573megawatt-hours compared to non-participating cus-tomers. The company has asked the Massachusetts Department of Public Utilities for permission to extendthe pilot program for an additional year.

How Does AMI Enable National Grid’s Dynamic Pricing Program?

Out of the company’s 3.3 million customers across thenortheast, only about 15,000 in Worcester are currentlyequipped with full-featured, high-speed AMI (using Itron’sOpenWay® RF mesh network system). AMI deployment wasconcentrated on selected feeders to isolate the impactsof the program and explore the end-to-end implications ofthe rate incentives being offered. While neither rate optionbeing tested requires the company itself to have real-timeaccess to customer usage data, the AMI system fulfillsseveral critical needs. The energy usage of customers in theprogram is being monitored on a fifteen-minute-intervalbasis (or finer) and this interval data is communicatedback to the utility every eight hours. In addition to havingaccess to timely data via the company’s customer webportal, participants can request a current snapshot oftheir electricity usage to aid in their decision making. Adigital picture frame is also available for customers inter-ested in seeing a continuous display of their usage. Par-ticipants’ bills are calculated using the hourly data pro-vided by the AMI system, including estimation of kWhshifted by those under the Conservation Day Rebate Plan.

national grid tests tou and peak day rates in advance of full ami rollout

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DATA ANALYTICS ARE THE KEY TOUNLOCKING AMI’S VALUEAMI applications related to rates and energypricing (not including operational applications,such as outage management and distributionautomation) include, but are not limited to:

• Rate designs that fully recover power supply costs and reflect the time-varying cost of energy

• Load forecasting by class of customer

• Development of representative class loadshapes for use in COSS

• Revenue analysis and protection

• Customer segmentation for target marketingof rate and incentive program offerings

• Pre-testing of new rates and incentive pro-grams on the member population to predictwinners and losers and understand likely financial and load impacts

• Customized pricing for unique segments of the customer population, ultimately even individual members

In each of these instances, granular, time-differentiated usage data is loaded into the co-op’s meter data management system(MDMS), and analytical software is used to answer a myriad of questions central to

business applications. Data for the entire pop -ulation of customers covered by AMI may beused, or alternatively, sample data can bedrawn “on-the-fly” and for a particular purpose,so-called dynamic sampling.8 Let us assume,for example, that an electric cooperative has recently seen its wholesale power suppliermove to a greater reliance on system peak demand in its wholesale rate. AMI data make itrelatively straightforward for the member co-opto identify individual members that have high(coincident) demands at the time of systempeak, as a starting point for considering newretail pricing options. Analysts can look at demand patterns in the current month, the entire season, or over a different time rangeand can hone in on particular customer segments or individual customers.9

Handling the large volume of data AMI cangenerate (87.6 million hourly kWh data ele-ments alone per year for a typical co-op with10,000 accounts) is not a problem with a prop-erly structured MDMS and the right analyticalsoftware. Linking metering data with customerdata from CIS and bringing in data from othersources, such as a residential appliance satu -ration survey, makes deeper analysis possible.The emergence of data analyst positions in utility organizations attests to the wideningrecognition that this is important, new work(see Great River Energy case study).

8 ‘Dynamic sampling’ is the term used by many in the utility industry to describe the process of gathering statistically representative samples, or load profiles, of a customer population where a meter exchange is no longer required and all members of the relevant population have detailed data available, e.g., cost is no longer a barrier to sample data collection.

9 Consultants working with electric cooperatives have noted that granular AMI data are not always retained long enough to enable certain analytical applications. This issue is reflected under “Considerations for AMI Deployment.”

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Great River Energy (GRE) is the fifth largest generation andtransmission (G&T) cooperative in the U.S., providingwholesale electric service to 28 member cooperatives thatdistribute electricity to approximately 685,000 member-consumers in Minnesota — a population of about 1.7 mil-lion people. The G&T has for many years operated directload control programs on behalf of its member co-ops,using radio controlled switches to cycle water heaters andair conditioners and dispatch customer-owned generationon peak-demand days. Among GRE’s members, about athird have AMI systems installed, another third are in theprocess of upgrading to AMI, and the remaining membersare considering AMI for the future. The distribution co-opswith AMI recognized the potential value of the large haulof AMI data coming in and asked GRE for assistance withdata analysis. “This is how my job came about,” saysNathan Grahl, GRE’s Principal Data Analyst. “My position is70 percent focused on working with our members to helpmeet their analytical needs.” Incoming data is predomi-nantly made up of hourly interval, customer load data, although some member co-ops have the capability to col-lect 15-minute data using AMI. How are the data beingused? According to Grahl, the cooperative can do “sam-pling on the fly” to meet the analytical needs of specificprojects identified by the participants. Individual customerload profiles, called “individual sampling units” by Grahl,can be grouped according to business application andsubjected to data analytics without significant, incremen-tal cost.

This is in sharp contrast to traditional utility practice in which a meter exchange was required for every sample point.

Key areas being pursued by the group currently include:

• More effective targeting of special rate programs, e.g.,recognizing that some residential customers havecharacteristic load patterns and demographic charac-teristics likely to make them more receptive to offersand more able to realize program benefits.

• Measurement and verification of individual and classload impacts of control events, such as peak day alertsinitiated by the cooperative.

• Distribution line loss measurements, enabled byplacement of AMI devices at the substation and feederlevel, which will improve cost allocation in rates.

How Does AMI Enable Rate Innovation by GRE’sMember Co-ops?

GRE’s collaboration around AMI data analytics has onlybeen up and running since fall of 2016, so it is too earlyto draw hard conclusions about its effectiveness. How-ever, the novel approach of a multi-cooperative, teamapproach to data analytics promises to address severalkey challenges:

• It recognizes that the massive increase in granulardata produced by AMI requires a careful approach todata management and analysis for the latent businessvalue to be realized.

• It shares a skilled resource among electric distributioncooperatives that individually might find it hard to jus-tify a dedicated position.

• It is “technology-agnostic,” separating data from AMItechnology. This is important where there are manydifferent AMI technology architectures generatingdata, as is the case among GRE’s members.

ami data analytics: great river energy leads a team effort with its members

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CONSIDERATIONS FOR AMI DEPLOYMENTAs is the case with most new technologies,careful planning and implementation are nec-essary to realize the benefits of AMI in rateplanning and flexible pricing. However, gettingthe AMI deployment right is not enough. Agood discussion of pitfalls to be avoided whendeploying AMI is provided in the NRECA/CFCRate Guide.10 Here is a brief selection:

• Other back-office systems must be fully inte-grated with AMI and capable of processing,storing, and transferring the large volumes ofdata being created. See sidebar on Multi-Speak® for guidance on achieving effectiveintegration.

• Communication systems must be carefullydesigned to handle necessary data transfersin the time spans required by specific businessapplications. This is particularly relevant forpeak-day pricing incentives and interruptiblerates. Most other rate applications involvingAMI data are well “after-the-fact.”

• Interval load data, e.g., hourly or fifteenminute kWh usage slices, can be invaluablefor answering a wide range of questions surrounding rate designs, demand impactsand customer usage patterns — often askedwell after-the-fact — so the question of datastorage is key. Electric co-ops should care-fully consider what questions they need answers to when arriving at their specificMDMS requirements.

• Customer web portals must be robust andhighly reliable, if co-op members are to havecontinuous access to the detailed meteringinformation that enables them to obtainvalue from innovative pricing options. In -formation is the “life blood” of most future pricing options.

• Assumptions that AMI enables rate innova-tion at essentially no cost to the coopera-tive are flawed. There are a number of costsassociated with data analysis and the rate-related applications that rely on these dataand these costs may extend years beyondthe initial AMI capital investment.

10 NRECA/CFC Rate Guide — Volume 1, pp. 56 through 58.

NRECA offers MultiSpeak® to assist cooperatives with technology and system integration.MultiSpeak is the worldwide leading software interoperability standard and solution forelectric utilities enabling data sharing between independent systems in a seamless, cost-effective, secure, and standardized way by simplifying software integration and minimiz-ing expenses for custom interface solutions. MultiSpeak is an enabler of Smart Grid andCybersecurity. For more information, visit our website or contact:

• Alvin Razon, Associate Director of Distribution Optimization: Alvin.Razon@nreca.coop

• Venkat Banunarayanan, Associate Director of Distributed Energy: Venkat.Banunarayanan@nreca.coop

• Tony Thomas, Senior Principal, Distribution Engineering & Operations:Tony.Thomas@nreca.coop

nreca offers multispeak® for cost-effective, secure, and successful technology integration

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AMI Enables Flexible Pricing and Helps Co-ops Maintain Revenue Stability | 15

• AMI is the type of technology solution thatcan impact many areas of the utility businessand as such opportunities are likely to sur-face that hold promise to address the some-times unique challenges faced by an electriccooperative. While it may be tempting to aggressively pursue such opportunities, ameasured approach and small-scale pilottesting are advisable before launching large-scale programs.

• The question of how to fully engage the co-opmember on his or her side of the meter hasnot been resolved. Co-op programs that encourage members to shift energy, reducepeak demands and understand how theirpattern of use influences cost are well estab-lished. However, the increasing popularity ofhome energy networks begs the question,“Where is this leading?” The idea of integrat-ing co-op members’ micro-energy networksinto AMI is full of risks and should only beapproached with great caution and delibera-tion, if at all.

ADVICE FOR COOPERATIVE CEOSThe technology transition within the electricutility industry toward wide adoption of AMI isunmistakable. As many as half of all electricdistribution cooperatives have either made thetransition or begun deployment of advancedmeters and communications networks. Thisraises the obvious question: What are co-ops

going to do with all the granular, time-interval,electric-usage data that will become availableand how will it affect rates? Cooperative leadersshould carefully consider what it means to beable to view members’ usage patterns in high-resolution. Pricing options that more closely reflect wholesale costs become feasible andshould be investigated. Moreover, AMI can giveco-op members access to detailed metering information that encourages them to alter theirusage patterns in ways that reduce those costs.Time-differentiated rates, long studied but rarelyimplemented on a meaningful scale, may finallybe coming to the forefront as the metering information needed for billing customers underthese rates is likely to become widely available.

Where might this lead? One can envision a future utility state in which a menu of flexiblepricing options will allow customized, individualpricing. If this does not seem entirely plausible,consider the technology revolutions taking placein ride sharing, music distribution, or the airlineindustry. Who would have imagined even adecade ago that every seat on a commercialflight would become individually priced, basedon when it is bought and where it is located onthe plane? Or that many of us would get rid ofour landline telephones. Technology enablesbig changes. For better or worse, AMI is remov-ing a major hurdle to a similar future becominga reality in the electric utility industry. n

Cooperative leadersshould carefullyconsider what itmeans to be able to view members’usage patterns inhigh-resolution.

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Legal Notice

This work contains findings that are general in nature. Readers are reminded to perform due diligence in applying thesefindings to their specific needs, as it is not possible for NRECA to have sufficient understanding of any specific situationto ensure applicability of the findings in all cases. The information in this work is not a recommendation, model, orstandard for all electric cooperatives. Electric cooperatives are: (1) independent entities; (2) governed by independentboards of directors; and (3) affected by different member, financial, legal, political, policy, operational, and otherconsiderations. For these reasons, electric cooperatives make independent decisions and investments based upon theirindividual needs, desires, and constraints. Neither the authors nor NRECA assume liability for how readers may use,interpret, or apply the information, analysis, templates, and guidance herein or with respect to the use of, or damagesresulting from the use of, any information, apparatus, method, or process contained herein. In addition, the authors andNRECA make no warranty or representation that the use of these contents does not infringe on privately held rights. Thiswork product constitutes the intellectual property of NRECA and its suppliers, and as such, it must be used in accordancewith the NRECA copyright policy. Copyright © 2017 by the National Rural Electric Cooperative Association.

About the Author

Eric Cody is a consultant who has spent nearly twenty years working with NRECA, theCooperative Research Network and NRECA Business and Technology Strategies, statewidecooperative associations and individual electric cooperatives on how to effectively managecomplex business and technology changes. He has written numerous reports, executive briefsand articles for the electric cooperative community and teaches NRECA’s course, “TechnologyPlanning, Decision Making and Leadership” (781.2). He has more than 35 years of experiencewith electric utilities and served for a dozen years as an officer of several New England ElectricSystem companies, including a five-year stint as vice president of IT. Eric holds a bachelor’sdegree from Amherst College and a master’s degree from Harvard University, where hespecialized in energy planning and policy analysis.

business and technology strategiesresource adequacy and markets work group

The Resource Adequacy and Markets (RA/M) Work Group, part of NRECA’s Business and Technology Strategies department, is focused on monitoring the evolution of marketfundamentals, policies, and regulations affecting the bulk electric system and assessing theirimpact on cooperatives’ abilities to ensure safe, reliable and affordable electricity for consumermembers. For more information please visit cooperative.com, and for the current work of theBusiness and Technology Strategies department of NRECA, please see our Portfolio.

Questions or Comments

• Allison Hamilton, Sr. Principal Markets and Rates: allison.hamilton@nreca.coop

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