Presentation on theme: "ArtsQuest – Steel Stacks"— Presentation transcript:
1ArtsQuest – Steel Stacks The 3rd Electric Generation Supplier (EGS) Conference Wednesday, May 16, 2012ArtsQuest – Steel Stacks101 Founders WayBethlehem, Pennsylvania 18015
2Welcome & Introduction Renae YeagerManager, Energy AcquisitionPPL Electric Utilities
3Today’s Agenda 8:15 AM Welcome & Introduction PPL Electric Utilities -Renae YeagerSupplier Coordination and Settlement Introduction - Domenic BreiningerPUC Welcome – Karen Moury9:00 AM Demand Response - Glenn Dickerson9:30 AM Mid-Morning Break10:00 AM Issues and Resolutions:System Enhancements- Susan ScheetzInterval Usage/ Meter information- Dave VanArsdalePPL Settlement Process- Gary HartmanQ&A11:30 AM PPL Smart Meter Plan Overview - Dave Glenwright12:00 PM Lunch
4Today’s Agenda 1:00 PM RMI (Retail Market Investigation) - Doug Krall 2:00 PM Customer Education Programs - Tom Stathos2:30 PM Mid-Afternoon Break2:45 PM Net MeteringProgram Overview – Jim RoulandEDI Implementation – Sue Scheetz3:15 PM Question & Answer
5Introduction Supplier Coordination and Settlement Team Panel Members Domenic Breininger -- ManagerSue Scheetz -- EDI AnalystDonna Hirst – Sr. Analyst Business OperationsJen Ainsworth -- Analyst Business OperationsShannon Schwarte -- Analyst Business OperationsGary Hartman -- Sr. Analyst Business OperationsCheryl Oehler -- Sr. Analyst Business OperationsNicole Leh -- Staff Analyst Business OperationsPam Harris -- Analyst Business OperationsPanel MembersSharon Armbruster – Supervisor Business AccountsDeborah Keiser – Project Manager Revenue AssuranceLouise Gross – Advanced Metering SpecialistJim Bowman – Supervisor Information Systems
6Introduction and Market Overview Domenic BreiningerManager – Retail Supplier Coordination, Scheduling and SettlementElectric Generation Supplier ConferenceMay 16, 20122011 PPL Electric Utilities Corporation
7Market Activity – Planning to Meet Market Needs April 201269 suppliers with active & pending customers99 suppliers certified
11Market Activity – Planning to Meet Market Needs Requests for Monthly IU
12Market Activity – Planning to Meet Market Needs Market ObservationsMore TOU Programs being made availableFree daysOff Peak incentivesPrice response incentivesDemand Side Management incentivesNet Metering customers shopping2,634 customer have net meters as of 4/20/12Few suppliers offering products currentlyBilling Transactions are complex3rd Party Curtailment Service ProvidersECL Opt-outs higher,000 customers opted out2012 – 177,000 customers opted out
13Pennsylvania Public Utility Commission Welcome Karen MouryDirector of Regulatory OperationsElectric Generation Supplier ConferenceMay 16, 20122011 PPL Electric Utilities Corporation
14Demand Response Glenn Dickerson Senior Analyst Business Ops Analysis – Energy Procurement 2011 PPL Electric Utilities Corporation
15Demand Response at PJMPJM’s Economic Load Response program enables demand resources to voluntarily respond to PJM locational marginal prices (LMP) by reducing consumption and receiving a payment for the reduction. Using the day-ahead alternative, qualified market participants may offer to reduce the load they draw from the PJM system in advance of real-time operations and receive payments based on day-ahead LMP for the reductions.The economic program provides access to the wholesale market to end-use customers through CSPs to curtail consumption when PJM LMPs reach a level where it makes economic sense.
16Capacity MarketWith the implementation of PJM’s forward capacity market, the Reliability Pricing Model (RPM), demand resources can offer demand response as a forward capacity resource. Under this model, demand response providers can submit offers to provide a demand reduction as a capacity resource in the forward RPM auctions.If these demand response offers are cleared in the RPM auction, the demand response provider will be committed to provide the cleared demand response amount as capacity during the delivery year and will receive the capacity resource clearing price for this service.In addition to the forward RPM auction, demand response can be committed as Full Emergency Load Response three months before the delivery year begins in order to offset capacity payments. Both load-serving entities (LSEs) and CSPs can aggregate and register demand resources as Full Emergency Load Response on a nearer-term basis.
17Synchronous ReservesThe PJM Synchronized Reserve Market provides PJM members with a market-based system for the purchase and sale of the synchronized reserve ancillary service. Demand resources that choose to participate in the Synchronized Reserve Market must be capable of dependably providing a response within 10 minutes and must have the appropriate metering infrastructure in place to verify their response and compliance with reliability requirements and market rules.Synchronized reserve service supplies electricity if the grid has an unexpected need for more power on short notice. The power output of generating units supplying synchronized reserve can be increased quickly to supply the needed energy to balance supply and demand; demand resources also can bid to supply synchronized reserve by reducing their energy use on short notice.
18Regulation MarketPJM added the capability of accepting demand reduction bids in the Regulation Market in Regulation service corrects for short-term changes in electricity use that might affect the stability of the power system. It helps match generation and load and adjusts generation output to maintain the desired frequency.Curtailment Service Providers (CSPs) that bid demand reductions into the Regulation Market must meet all the requirements of regulation, including the real-time telemetry requirement. Current reliability council rules limit demand resources to 25 percent of the regulation requirement in the ReliabilityFirst Corporation region.
19FERC Order 745Proposed Rule: All RTOs allowing DR in energy markets must pay Demand Response Resources Full LMP at All Hours.FERC’s Cited Benefits of DR:Can lower pricesCan mitigate generation market powerCan support system reliability and address resource adequacy
20FERC Order 745 FERC’s Support for Proposal Compensate DR reflecting its marginal valueComparable to treatment of generationPJM experienceRemove barriers
21FERC Order 745 PJM Plans for implementation: Net Benefits Test (“NBT”) used to determine compensation based on full LMPDR must clear in DA market or be dispatchable to balance supply and demandDR to set LMP without need for telemetryCost allocation to LSE plus real time exportEnhance measurement and verification to improve accuracy (Customer Baseline or “CBL” and associated process)Implement optional Dispatch Group to aggregate DR registrations for dispatchNew rules effective 4/1/12
22PPL Electric Utilities Support of DR PPL EU has dedicated resources that will provide the needed information for CSP’s to have customers participate in the PJM DR Markets.CSP’s and EGS’s may request customer-level PLC information needed to submit registrations for the DR programs via the Supplier Coordination box at:The information requested will be provided back in spreadsheet format.
24PPL Electric Utilities Support of DR PPL EU has dedicated resources that will review registrations and activity in the PJM programs to ensure that customers get timely approval of their submissions.PJM Information:Manual 11 Energy & Ancillary Services Market OperationsSection 10 has all of the business rules that must be followed in order to participate in the PJM programs.Link to Manual 11:
25PPL Electric Utilities Support of DR Questions???
27Issues and Resolutions: System Enhancements Susan ScheetzEDI Analyst – Supplier Coordination2011 PPL Electric Utilities Corporation
28Eligible Customer List Interim Guidelines for ECLPPL Electric Utilities placed into production on January 23, 2012 an Eligible Customer List that contains additional data elements as Ordered by the PA PUC on Docket No. MThe new elements are:Transmission and Capacity Obligations, current and future.Net Metering indicator.Sales Tax Status to indicate sales tax obligation.ECL updates are run on the second Sunday of every month.
29Eligible Customer List The new net metering indicator, for example, includes information regarding customers that have co-generation or net metering at their premise.Suppliers should pay special attention to customers with net metering and discuss the shopping implications regarding the cash out process at the end of the PJM year.PPL is required to reimburse any ACT 129 customer that generates more than they consume, Suppliers are not.Also included, when available, will be "preliminary" future ICAP and NITS values as well as On Peak and Off Peak Consumption.The additional tax obligation data element will be populated by end of year, 2012.
30867 Monthly Interval Usage Transactions Interval vs. Summary VarianceLate 2010, a project labeled Customer Choice Controls Phase II completed improving interval usage availability.Held 867 IU transactions two days in order to populate the last two days of the bill period.Reprogrammed the interface between Meter Data Management (MDM) and our billing system (CSS). This increased the availability of the IU data and improved data integrity.Control reports and processes were improved to correct meter configuration issues affecting the data.Interval vs. Summary
31867 Monthly Interval Usage Transactions Interval vs. Summary VarianceCustomer Choice Controls Phase III has been identified to support intervals that cannot be handled through the current VEE process as part of PPL’s Smart Meter Plan.Intervals that are out of high/low tolerance (alias reads) will be deleted and re-estimated using profiles and usage factors.Severe storms and widespread outages encountered in 2012 resulted in estimated reads. An interface to the Outage Management System will incorporate outage data and provide more accurate true zero reads.
32Billing Enhancements Rate Ready Billing implemented early 2011 11 registered Rate Ready Suppliers> 1,500 active rate codes174,334 Active Rate Ready Customers814 C Transactions ICAP/NITSJanuary, 2012 began sending a change transaction when there is a change in the existing tag value.Suppliers will be notified of ICAP and NITS tag changes for individual shopping customers via 814Cs. For this process, an 814C will be sent to the active Supplier, any pending active Supplier and any pending inactive Supplier.We will still continue to do the twice a year mass changes for only the value that is changing.
33Billing Enhancements 814 E Supplier Start Date PPL's Enrollment Response, Drop Response and Reinstatement Response Service Period Start Date historically contained the third day in the customer's 4-day billing window. Since PPL has an automated meter reading system, the majority of our meters are actually read on the first day of the billing window.The systems were changed on 12/12/2011 to return the first day of the billing window to populate the EDI to coincide with the submissions to PJM for Scheduling.
34Supplier Communications Supplier Communication ProcessProactively communicate issues affecting suppliers when they are identified.Continue to provide information on the supplier web site.Target communications based on issue:Enrollments/Drops/ChangesBilling/UsageGeneralEDIRegulatoryCustomer ServiceEtc.
35No Bills – BackgroundNo Bill is defined as any account that is not billed to the current bill period, which falls into one of three categories:Accounts in progress (cancel/rebills, back billing, etc).Pending Business action (enter reads, work orders, etc.).Pending IT action.No Bill Backlog:Prior to 2010, averaged about 350 no bills per month.By mid-2011, no bills peaked at 2000.There are currently ~900 no bill accounts.
36No Bills – BackgroundThe factors contributing to increased no bill volume were:Regulatory changes and Competitive enhancements.Enhancements to the System increased:= 8,000 average IT hours per year.2008 = 15,000 IT hours.2009 – 2011 = 26,000 average IT hours per year.Market pricing lead to large % of customers shopping.
37No Bills – Common Causes Meter mixRate rebillingConnect at wrong addressChange Meter OrdersCompetitive IssuesTOUTechnical issuesBudget billing, bill month (primary), season peak, etc.
38No Bills - Process No Bill Monitoring: Corporate Issues tracking tool. No bills database.No Bill team:Business and IT represented.Weekly priority list published.Prioritization factors:Age of account since account successfully billed.Large Power customer or High dollar revenue impact.PUC complaints or frequent customer complaint escalation.Other mass volume issues as a result of changes or system problems.
39No Bills – Activity 2011 1-2 full time IT resources were assigned. Monthly IT No Bill Blitzes:Dedicated two day focus across multiple resources.Address highest priority accounts as determined by business.Established and achieved the 180 day goal for September 2011.Averaged ~450 hours per month through final three Quarters 2011.Addressed root cause items in Q4, 2011.
40No Bills – Activity 2012 Established 120 day goal for September 2012. 3.5 full time IT resources assigned.Limited additional weekly allocations based on capacity and/or need:Subject Matter Experts (SME’s).Business Analysts.Monthly Blitzes – Q1, 2012 only.Budgeted ~550 hours per month.Will continue to assess root cause as needed.The Future Desired State is a 30 day goal.
42Issues and Resolutions: Interval Usage/ Meter Information Dave VanArsdale Manager – Information Systems2011 PPL Electric Utilities Corporation
43Customers and Meter Types Industrial and Large Commercial CustomersMV90 Meters (Itron)15 minute usageIncludes power quality dataPPL has about 2000 MV90 MetersRead using cellular phone communicationsEach meter is read dailyResidential and Other Commercial CustomersTNS Meters (Aclara)Hourly usagePPL has 1.4 million TNS MetersRead over power linesMeters can not be read when power lines are outEach meter’s Daily reading is collected once a dayEach meter’s Hourly readings are collected 3 times a day (8 hours at a time)
44Metering Reading Overview PPL ComputerSystemsTelecommunications LinkMV90TNSDistributionSubstationTelecommunications LinkTWACS - Two-Way Automatic Communications SystemsTNS - TWACS Network SystemSubstation Control EquipmentPowerLinesMeter withTWACS ModuleService To Home
45Meter Data ManagementMV90 and TNS meter readings are stored in PPL’s MDM system.MDM is a very large database holding the last 2 years of history.MDM detects and fills in bad hourly usage using VEE, keeping track of original “working usage” and “approved” usage.VEE – Validation, Estimating, and EditValidation – Missing, Negative, Spike, Static, SumEstimation – Scale to Daily, Linear Interpolate, Scale to ProfileApproved usage is normally available before billing and EDI.Approved usage isavailable to customers on the Websent to suppliers via EDIused in PJM Settlementis increasingly used to determine monthly customer billMDM includes PPL’s Retail Choice Forecasting and Settlement application.
46PPL Metering and Related Systems PJMMV90MetersForecast & SettlementMDMStorageVEETNSMetersCSSCustomersEDISuppliersTWACS - Two-Way Automatic Communications SystemsTNS - TWACS Network SystemMDM - Meter Data ManagementCSS – Customer Service SystemEDI – Electronic Data Interchange
47Issues and Resolutions: PPL Scheduling & Settlement Process Gary HartmanSenior Analyst Business Ops AnalysisScheduling & Settlement2011 PPL Electric Utilities Corporation
48Settlement A (Backcast) Forecast Settlement B (Reconciliation) ProcessesCapacity TagsZonal LoadSettlement A (Backcast)ForecastSettlement B (Reconciliation)Settlement CFinancial SettlementCancel / Rebill Process
4915 day forecasts run & submitted daily No reconciliation exists Capacity TagsPredicting the amount of capacity each supplier will be responsible forInstalled Capacity (ICAP) – generation capacityNetwork Integration Transmission Service (NITS)Each customer meter is assigned a fixed tag value which remains constant for one yearCalculated using 5 highest hourly peaks on system over previous year15 day forecasts run & submitted dailyNo reconciliation existsBilling Impact:Supplier receives ICAP charges for each meter assigned to them
50LOAD (INCLUDING LOSSES) = ∑GEN + ∑TIE(IN) - ∑TIE(OUT) Zonal LoadLOAD (INCLUDING LOSSES) = ∑GEN + ∑TIE(IN) - ∑TIE(OUT)Hourly load values calculated for previous dayCalculation derived from PJM eMTR submissions by PPL & counterpartiesCorrection period available at end of each monthTie LineGeneratorTie LineTie LineGeneratorGeneratorTie Line
51LSE’s estimated hourly load for previous day Aggregation Process: Settlement ALSE’s estimated hourly load for previous dayAggregation Process:All meters in our zone for all hours of previous day / days are assigned a usage value and summed by supplierIncludes actual meter reads for largest customers (MV-90 meters) – LP4, LP5, LP6, MUNI’sAll other meters are estimatedProfiles – typical hourly demand for rate classUsage Factors – adjusts profile based on consumption patternsWeather – adjustment based on temperatureIncludes loss adjustment based on customer rate class
52Interface Process: Submission Process: Billing Impact: Settlement A UFE is calculated and applied to contractsUFE = zonal load hourly value – aggregation hourly valueAllocated to suppliers and POLR providers on load ratio basisPOLR load is allocated to POLR suppliersSubmission Process:Daily file sent to PJM eSchedules which includes MWh hourly total by contract numberBilling Impact:Supplier is charged for load being served
53LSE’s estimated hourly load for future dates Aggregation Process: ForecastLSE’s estimated hourly load for future datesPlaceholder for settlement A submissionAggregation Process:All meters in our zone for all hours of previous day / days are assigned a usage value and summed by supplierIncludes no actual meter readsAll meters are estimatedProfiles – typical hourly demand for rate classUsage Factors – adjusts profile based on consumption patternsWeather – adjustment based on forecasted temperatureIncludes loss adjustment based on customer rate class
54Interface Process: Submission Process: Billing Impact: Forecast No UFE calculationSubmission Process:File sent to PJM eSchedules which includes MWh hourly total by contract numberGenerally run and submitted twice a week with 10 days of forecasted data included in each fileBilling Impact:No financial impact
55LSE’s actual hourly load for previous month Settlement BLSE’s actual hourly load for previous monthSubmission deadline is two months after original Settlement A monthEx. January Settlement B is due March 31Aggregation Process:All meters in our zone for all hours of previous day / days are assigned a usage value and summed by supplierIncludes actual reads for nearly 100% of metersIncludes loss adjustment based on customer rate class
56Interface Process: Submission Process: Billing Impact: Settlement B UFE is calculated and applied to contractsZonal load values are updated if necessaryAverage UFE of 0.61% since January 2010POLR load is allocated to POLR suppliersDelta is calculatedDelta = Settlement A MWh – Settlement B MWhSubmission Process:Monthly file sent to PJM eSchedules which includes hourly deltas by contract numberBilling Impact:Adjustment to supplier charges based on +/- delta
57Only done in extreme cases Settlement CRe-submission of Settlement B with more accurate data after the two month windowRecalculation of delta valuesOnly done in extreme casesExample: Large Metering ErrorPJM requires sign off from all affected parties before they’ll accept correctionPJM generally makes corrections involving long time periods over an extended period of time
58Process exists for opportunity to settle dollar amounts only Financial SettlementProcess exists for opportunity to settle dollar amounts onlySign off from each impacted party requiredForm is provided to PJMFinancial adjustment shows up on monthly PJM BillCan be used for long term zonal load adjustment or long term customer meter adjustment
59Cancel / Rebill Process No formal process currently exists to reconcile dollars for adjustments beyond the settlement windowCurrently evaluating options for implementing a standard processReviewing approach of other utilitiesPotential to utilize the Financial Settlement processDollar only settlement
61PPL Smart Meter Plan Overview Dave Glenwright Project Manager – Advance Metering 2011 PPL Electric Utilities Corporation
62Overview of Smart Meter Projects / Pilots AgendaOverview of Smart Meter Projects / PilotsReview of Proposed Projects / PilotsUpdate on:Price and Usage Information PilotAccelerated Supplier SwitchingImproved VEE processCustomer and Meter Data AvailabilityIn Home DisplayRemote Connect / DisconnectAddendum FilingQuestions
66Price and Usage Information Pilot Pilot methods for communicating pricing and usage data to customers3 communication channels implemented (Phone, , Text)Customers can enroll through the CSR or websiteAvailable alertsPrice to Compare (1,290 customers enrolled)Bill to Date (806 customers enrolled)Abnormal Usage (998 customers enrolled0
67Accelerated Supplier Switching PPL looking to use Smart Meter technology to shorten the switching windowCustomers will be allowed 1 mid-cycle switch per monthSeeks to reduce switch timeline from 16 – 45 days to 10 daysProject will compliment any guidelines in the upcoming final PUC order on Accelerated Supplier Switching
68Improved VEE ProcessEnhance the quality if IU data through changes to VEELeverage Outage Manage DataUse outage information so that VEE doesn’t profile or estimate usage during outages
69Customer and Meter Data Availability 3 new projects seeking to improve availability of customer and usage dataMDM Data Warehouse and AnalyticsFaster Data Presentment to Customers and SuppliersSupplier PortalBenefits:Make energy usage data available in less than 48 hours from meter readPilot website for suppliers to download usage data
70Discuss technical issues and delays at a high level. In Home DisplayObjectivesProvide direct real-time access to electric usage and cost informationEvaluate available technology, customer behavior and customer satisfactionInstall meters with a Wi-Fi moduleReal-time usage data can be retrieved from any Wi-Fi enabled device in a customer’s homeTechnical issues have delayed the pilotDelivery of technology delayed to late-2012Overview of the pilotDiscuss technical issues and delays at a high level.
71Hardware Use Wi-Fi as the communications link Small web-server on meter module shows real-time usageUse web browser as IHDMac, PCiPhone, iPod Touch, iPadBlackberry, Android, etc.Gaming consoles Internet devices (Sony dash, etc.)
78Background Need first identified during AE-FE merger proceeding. Order entered 4/29/2011 initiating a two (2) phase investigation:First phase consisting of written comments (June 3) and en banc hearing (June 8).Second phase consisting of working group efforts to (1) address issues identified in first phase and (2) develop recommendations for Commission action.Docket No. I
79Current Status – Phase 1Phase 1 concluded with an Order entered 7/28/11:The Commission concluded that “Pennsylvania’s current retail market requires changes in order to bring about the robust competitive market envisioned by the General Assembly when it passed the Electricity Generation Customer Choice and Competition Act….”Outlined Phase 2 activities.
80Current Status – Phase 2 (Slide 1 of 2) Phase 2 activities documented in several Orders:Tentative Order on Accelerated Switching (11/14/11):Reduce 16-day to 45-day delay by eliminating 10-day confirmation waiting period;“Off-cycle” switching;Comments filed; awaiting Final Order;Docket No. MFinal Order on Default Service Plans (12/16/11):Procurement of shorter-term products timed to minimize the “overhang” of contracts beyond May 31, 2015 in an effort to permit additional changes to be made to the default service model at that time;Approaches to time-of-use;Reconciliation period and frequency of rate changes:Hourly priced default for non-residential > 100kW;Initiation of a customer referral program;Initiation of a retail opt-in auction program.
81Current Status – Phase 2 (Slide 2 of 2) Order on Intermediate Term Measures (3/2/12):Additional detail not provided in the December 16 Final Order on Retail Opt-In Auction and Standard Offer Referral Program in default service plans.Expansion of consumer education to drive electric customers to the PUC’s website dedicated to helping consumers shop for electricity, and to increase general awareness of competitive markets and how to shop;Revisions to call center and IVR scripts to encourage shopping;Acceleration of the switching timeframe when a customer shops for an alternative supplier (reference to Docket No. M ;Inclusion of the EDCs’ price to compare on customer bills; andIncreased coordination between EDCs and EGSs.
82Current Status – Phase 3 Phase 3 instituted via e-mail dated 12/22/11: Purpose of Phase 3 is to address:Possible long-term changes to the default service model intended to minimize the impact of that model on the competitive retail market;Possible enhancements to the retail market for small and mid-sized commercial customers; andPossible statewide consumer education efforts.Informal comments on these subjects before and after a third en banc hearing conducted, on 3/21/12Staff to provide the Commissioners a report on these subjects.
83PPL Electric Response (Slide 1 of 2) Sent PUC postcards encouraging shopping to all customers in FebRequested approval of Competitive Enhancement Rider in Mar base rate filing to provide cost recovery for consumer education and retail markets enhancements.Default Service Plan filed May 1, 2012 addresses:Procurement of shorter-term products timed to minimize the “overhang” of contracts beyond May 31, 2015;Approaches to time-of-use;Reconciliation period and frequency of rate changes:RTP default service for non-residential > 100kW;Initiation of a customer referral program;Initiation of a retail opt-in auction program.
84PPL Electric Response (Slide 2 of 2) Smart Meter Plan Addendum filed May 2012 requests approval to pursue system changes and cost recovery associated with:RTP default service for non-residential > 100kW;Off-cycle switching.Items underway/awaiting further PUC direction:Mailing of tri-fold brochure and EDC letter with FAQs;Revisions to call center and IVR scripts to encourage shopping;Inclusion of the EDCs’ price to compare on customer bills; andIncreased coordination between EDCs and EGSs.
86Customer Education Programs Tom StathosDirector – Customer Programs and Svcs2011 PPL Electric Utilities Corporation
87What We Believe Information is key Electric choice is good for customersEfficiency mattersCustomers have the power to manage electricity use87
88Background: Expiration of rate caps Dedication to energy efficiencySmart meters on all 1.4 million customers since 2004Expiration of PPL EU’s generation rate cap in 2010 created significant challengesTotal rates were expected to rise significantly for all customer classesLarge increases for residential customers (~30%)Opportunity for customers to “shop” for generation supplyStrong corporate culture to satisfy customers, with 17 JDPower awardsFast Facts:A 42-inch plasma TV can draw three times more electricity than traditional TVA digital photo frame in every home would require five mid-sized power plantsSwapping the old frig for a new one can save enough power to light a home 4 monthsIf every American home replaced just one bulb with a compact fluorescent, it would be equivalent of taking 800,000 cars off road8888
89Electric choice: Good for customers Shopping for a generation supplierCustomers could save money or find options and terms that better suit their individual needsCompare supplier offers atUnderstand terms of your agreementPPL Electric remains your delivery companyShopping will not affect service reliability89
93Electric Choice: By the Numbers Rate GroupActivePendingTotal Shopping Customers% of Rate Group Total CustomersResidential485,2854,613489,89839.90%Small Com. & Ind.89,35666690,02250.70%Large Com. & Ind.1,10551,11086.20%TOTAL575,7465,284581,03041.30%93
97Customer Education Programs (Non-Act 129) E-power TeamCommunity Education Team – 225,000 customers reached in 2011THINK! Energy School ProgramProvide teachers and students with FREE energy educationContinuous Energy ImprovementWork with businesses in the PPL Service Territory on how they can become more energy efficientAgriculture Education ProgramHelp family farms drive down their operating costs, while still maintaining their productivityInstitutional Benchmarking ProgramsPPL Electric Utilities has offered energy benchmarking services for K-12 public and non-public schools, as well municipalities and local non-profits97
103Net Metering What It Means For PPL Electric And Its Customers 2011 PPL Electric Utilities Corporation
104Topics Covered What is Net Metering? What it means to PPL Electric Customers – Both Default Service & ShoppingPPL Electric processesThings for EGSs to consider
105What Is Net Metering?Net metering, in general, is a customer program, which serves to reconcile electricity produced from a customers renewable system (e.g. solar PV panels or a wind turbine) against electricity a customer uses in a month.3 purposes of the program:Primary: To pay a customer for the electricity they supply to PPL Electric through the grid (electricity in excess of what they use at their home or business)Secondary: to give customers distribution benefits where necessarySecondary: support renewable energy development at the customer premise**Also, of course, to conform with Pennsylvania Net Metering rules and PPL Electric Tariff ProvisionsCustomer EligibilityCustomer premise (the house, barn, business) must have had load prior to installing the facilityMaximum facility size: Residential Customer <= 50kW; GS-1, GS-3 or LP-4 <= 3,000kWAll interested customers must complete an interconnection agreement (and have it approved by PPL) and provide diagrams and other engineering materials of the system, including the system specsAll customers must have the facility inspected by a certified electrician and have a completed cut-card and supplemental paperwork (PPL Electric may also conduct a Method of Accommodation)The facility must meet IEEE and other relevant engineering and legal standardsCustomer must submit financial information – specifically a W-9 – for tax purposesNOTE: Even if a customer is shopping with an EGS, the customer must meet all PPL Electric eligibility requirements.
106PPL Electric ProcessCustomer must complete PPL Electric Eligibility Requirements (submit all forms & complete inspections)PPL Electric reviews all forms and inspection requirements – PPL will also review the premise to determine if a new meter is neededPPL Electric begins tracking the system to determine if excess generation is produced in a month. If excess generation is produced in a month (and no cash-out event occurs), the generation is banked for consumption and/or cash-out at a later time.If a customer consumes more electricity than it generates in a month, any excess generation in the customers bank is applied excess the consumption. The customer also receives the associated distribution benefit for that month.During a cash-out event (e.g. Annual May Cash-out, when a customer goes from Default Service to Shopping, etc.) PPL Electric issues a credit to customers for banked excess generation at the PTC at that time.Once cash-out event occurs, bank is reset and begins anew.If a customer is shopping with an EGS, PPL Electric still tracks the customer bank so it may apply the distribution benefit to the customer account. No additional credits or payments are made by PPL Electric.
107What Does Net Metering Mean for Default Service Customers? Source of Revenue (from excess electricity & distribution benefit)Electric rate stabilityOffsets some or all of a customers electric consumption – results in a comparison to the PPL Electric PTC.Alternative Energy Credits (AECs)“Green” power prospectiveTaxes (Credits? Costs?)
108What Does Net Metering Mean for Shopping Customers? Similar to Default Service customers, shopping customers still get to offset their power, may get tax credits and AECs, and still get a distribution benefit.Due to the current Pennsylvania Net Metering rules, compensation from EGSs to customers for excess generation is on a case-by-case basis, and not mandated.Top 5 questions from Shopping Customers to PPL Electric:Can I shop with an EGS if I’m a Net Metering customer on PPL Electric service now (asked prior to shopping)?Will my EGS pay me for excess generation in a ‘cash-out” like PPL Electric does in May?Will PPL Electric pay me for excess generation if my EGS won’t?Will I still get a distribution benefit on my monthly bill if I produce excess electricity and bank it, even though I’m shopping?Why are there size limitations and forms for me to fill out, if I’m putting the facility on my property and not getting another meter?
109Things for EGSs to Consider Do I have customers with renewable generation?If so, have I identified them in my system? (given the different load profile they have based on renewable generation type and season/weather)?If I know a customer has renewable assets, are they identified as such through the PPL Electric EDI system of data/information I request/receive?Have I communicated with my customers about their renewable generation?What contract terms do I have with my customers?Does my contract(s) cover the renewable facility?What expectations exist with the customer?Am I going to compensate customers for excess generation?How do I coordinate my efforts with PPL Electric?
110PPL Net Metering EDI Implementation Susan ScheetzEDI Analyst – Supplier Coordination2011 PPL Electric Utilities Corporation
111Net Metering – Timeline Change Control #7711/1/2010 EDEWG Change Control #77 submitted.11/12/2010 EDEWG special meeting to discuss CC#77 Was “approved”.12/22/2010 PPL sends announcement to Suppliers.1/5/2011 PPL Implemented CC#77. PPL began sending “87” indicators for customer generation.
112Net Metering – Timeline Change Control #821/13/2011 EDEWG Change Control #82 submitted.2/3/2011 CC#82 was “approved”.3/11/11 EDEWG Change Control #85 was submitted.EDEWG unable to reach consensus regarding mandatory statewide implementation, presented to Charge. PPL “approved” to move ahead.8/29/2011 PPL sends announcement to Suppliers.9/23/2011 PPL Implemented CC#82 and CC#85. PPL sent 814 Change transactions to all suppliers with Net Meter customers.
113Net Metering – Timeline Interim Guidelines for Eligible Customer ListDocket M11/10/2011 Order to include Net Metering indicator on ECL.1/20/2012 PPL sends announcement to Suppliers.1/23/2012 PPL Implemented ECL.1/23/2012 PPL Implemented concept of “bank”.
114Net Metering – Special Meter Configuration The new Special Meter Configuration indicator (REF*KY) was implemented by PPL Electric Utilities on September 23, This change was documented in EDEWG Change Control #85 and impacted the 867 Historical Usage, 867 Historical Interval Usage, 814 Enrollment Response, 814 Change Request, and the 814 Reinstatement Request transactions.The "type" (populated in REF02) can be one of the following:ASUN Act 129 Compliant - SolarAWIN Act 129 Compliant - WindAHYD Act 129 Compliant - HydroABIO Act 129 Compliant - BiomassAWST Act 129 Compliant - WasteACHP Act 129 Compliant - Combined Heat and PowerAMLT Act 129 Compliant - Multiple Different SourcesNSUN Not Act 129 Compliant - SolarNWIN Not Act 129 Compliant - WindNHYD Not Act 129 Compliant - HydroNBIO Not Act 129 Compliant - BiomassNWST Not Act 129 Compliant - WasteNCHP Not Act 129 Compliant - Combined Heat and PowerNFOS Not Act 129 Compliant - Fossil FuelNMLT Not Act 129 Compliant - Multiple Different SourcesThe Rating (populated in REF03) is stated in KW and reflects the maximum generation the equipment can produce at any one time.
115Net Metering – 867 Interval Usage Qualifiers PPL Electric Utilities implemented two new quantity qualifiers,17 = Incomplete and 20 = Unavailable. To support net metering, two additional codes were implemented as part of the 867 Interval Usage PTD*BQ loop. The quantity qualifiers 87 = Actual Quantity Received and 9H = Estimated Quantity Received went into production on January 5, 2011, as defined in EDEWG Change Control #77.Therefore, the 867 IU PTD*BQ Loop presents the following quantity codes in the QTY01 segment:17 = Partial Quantity Delivered20 = Unavailable87 = Actual Quantity Received (Net Metering)9H = Estimated Quantity Received (Net Metering)KA = Estimated Quantity DeliveredQD = Actual Quantity Delivered
116Net Metering – 867 Monthly Usage On the 867 Summary Monthly Usage for Net Metering, two PTD*PM loops for the same meter will be present.One is the Consumption (labeled as “additive”), where QTY01 = QD (Actual Consumption) or KA (Estimated Consumption).The other is the Generation (labeled as “subtractive”), where QTY01 = 87 (Actual Generation) or 9H (Estimated Generation).The PTD*SU will show the net value and the PTD*BB loop will show what PPL billed the customer. If there was a meter change on the account, the two sets of meter readings will be in date descending order.
117Net Metering – 867 Monthly Usage On January 23, 2012, new Net Metering logic was moved to production. This new logic provides for approved net metering customers the inclusion of a 'bank' of excess generation.For bill periods where a net metering customer 'draws' from their bank, which occurs when the current period's use is positive, we reduce the amount of the bank to offset this current usage.For PPL charges, we bill for the 'reduced' usage and provide this information in the PTD*BB Billed loop. This usage could be zero.With these changes, Suppliers now see the positive usage in their EDI transactions and are billing for the positive kwh amount.We submit “actuals” for net metering customers in our settlement B submission.There are 61 MV90 meters that provide both positive and negative read channels.
118Net Metering – Incorrect Meters Approximately September, 2011, it was determined that for a subset of our small Net Meter accounts incorrect meters remained installed at the premise. The meters were unable to record usage that fell below zero. Therefore, when customers generated more than they consumed, the meter failed to register the generation.A project was initiated to procure replacement meters. Backorder delays occurred and progress was slow. We have recently received additional shipments of GE and Elster meters so we are in a position to now be able to install the correct Net Meter on all the accounts still needing one.There are 118 of accounts still requiring the a meter change. We should make better progress since we are no longer constrained by low stock levels of Net Meters.Overall the number of accounts approved for Net Metering has increased from 2,597 on March 16, 2012 to 2,610 on April 6, Of that total, 2,482 have the correct meter installed.