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The 3rd Electric Generation Supplier (EGS) Conference Wednesday, May 16, 2012 ArtsQuest – Steel Stacks 101 Founders Way Bethlehem, Pennsylvania 18015.

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Presentation on theme: "The 3rd Electric Generation Supplier (EGS) Conference Wednesday, May 16, 2012 ArtsQuest – Steel Stacks 101 Founders Way Bethlehem, Pennsylvania 18015."— Presentation transcript:

1 The 3rd Electric Generation Supplier (EGS) Conference Wednesday, May 16, 2012 ArtsQuest – Steel Stacks 101 Founders Way Bethlehem, Pennsylvania 18015

2 2011 PPL Electric Utilities Corporation 2 Welcome & Introduction Renae Yeager Manager, Energy Acquisition PPL Electric Utilities

3 2011 PPL Electric Utilities Corporation 3 Todays Agenda 8:15 AM Welcome & Introduction –PPL Electric Utilities -Renae Yeager –Supplier Coordination and Settlement Introduction - Domenic Breininger –PUC Welcome – Karen Moury 9:00 AM Demand Response - Glenn Dickerson 9:30 AM Mid-Morning Break 10:00 AM Issues and Resolutions: –System Enhancements- Susan Scheetz –Interval Usage/ Meter information- Dave VanArsdale –PPL Settlement Process- Gary Hartman –Q&A 11:30 AM PPL Smart Meter Plan Overview - Dave Glenwright 12:00 PM Lunch

4 2011 PPL Electric Utilities Corporation 4 Todays Agenda 1:00 PM RMI (Retail Market Investigation) - Doug Krall 2:00 PM Customer Education Programs - Tom Stathos 2:30 PM Mid-Afternoon Break 2:45 PM Net Metering –Program Overview – Jim Rouland –EDI Implementation – Sue Scheetz 3:15 PM Question & Answer

5 2011 PPL Electric Utilities Corporation 5 Introduction Supplier Coordination and Settlement Team –Domenic Breininger -- Manager –Sue Scheetz -- EDI Analyst –Donna Hirst – Sr. Analyst Business Operations –Jen Ainsworth -- Analyst Business Operations –Shannon Schwarte -- Analyst Business Operations –Gary Hartman -- Sr. Analyst Business Operations –Cheryl Oehler -- Sr. Analyst Business Operations –Nicole Leh -- Staff Analyst Business Operations –Pam Harris -- Analyst Business Operations Panel Members –Sharon Armbruster – Supervisor Business Accounts –Deborah Keiser – Project Manager Revenue Assurance –Louise Gross – Advanced Metering Specialist –Jim Bowman – Supervisor Information Systems

6 Introduction and Market Overview 2011 PPL Electric Utilities Corporation Domenic Breininger Manager – Retail Supplier Coordination, Scheduling and Settlement Electric Generation Supplier Conference May 16, 2012

7 2011 PPL Electric Utilities Corporation 7 Market Activity – Planning to Meet Market Needs April suppliers with active & pending customers 99 suppliers certified

8 2011 PPL Electric Utilities Corporation 8 PTC Res: 9.27 Sm C/I: PTC Res: Sm C/I: PTC Res: Sm C/I: PTC Res: Sm C/I: PTC Res: Sm C/I: Market Activity – Planning to Meet Market Needs

9 2011 PPL Electric Utilities Corporation 9 Market Activity – Planning to Meet Market Needs

10 2011 PPL Electric Utilities Corporation 10 Market Activity – Planning to Meet Market Needs

11 2011 PPL Electric Utilities Corporation 11 Requests for Monthly IU Market Activity – Planning to Meet Market Needs

12 2011 PPL Electric Utilities Corporation 12 Market Observations –More TOU Programs being made available Free days Off Peak incentives Price response incentives Demand Side Management incentives –Net Metering customers shopping 2,634 customer have net meters as of 4/20/12 Few suppliers offering products currently Billing Transactions are complex –3 rd Party Curtailment Service Providers –ECL Opt-outs higher ,000 customers opted out 2012 – 177,000 customers opted out Market Activity – Planning to Meet Market Needs

13 Pennsylvania Public Utility Commission Welcome 2011 PPL Electric Utilities Corporation Karen Moury Director of Regulatory Operations Electric Generation Supplier Conference May 16, 2012

14 Demand Response Glenn Dickerson Senior Analyst Business Ops Analysis – Energy Procurement 2011 PPL Electric Utilities Corporation

15 15 Demand Response at PJM PJMs 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.

16 2011 PPL Electric Utilities Corporation 16 Capacity Market With the implementation of PJMs 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.

17 2011 PPL Electric Utilities Corporation 17 Synchronous Reserves The 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.

18 2011 PPL Electric Utilities Corporation 18 Regulation Market PJM 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.

19 2011 PPL Electric Utilities Corporation 19 FERC Order 745 Proposed Rule: All RTOs allowing DR in energy markets must pay Demand Response Resources Full LMP at All Hours. FERCs Cited Benefits of DR: Can lower prices Can mitigate generation market power Can support system reliability and address resource adequacy

20 2011 PPL Electric Utilities Corporation 20 FERC Order 745 FERCs Support for Proposal Compensate DR reflecting its marginal value Comparable to treatment of generation PJM experience Remove barriers

21 2011 PPL Electric Utilities Corporation 21 FERC Order 745 PJM Plans for implementation : Net Benefits Test (NBT) used to determine compensation based on full LMP DR must clear in DA market or be dispatchable to balance supply and demand DR to set LMP without need for telemetry Cost allocation to LSE plus real time export Enhance measurement and verification to improve accuracy (Customer Baseline or CBL and associated process) Implement optional Dispatch Group to aggregate DR registrations for dispatch New rules effective 4/1/12

22 2011 PPL Electric Utilities Corporation 22 PPL Electric Utilities Support of DR PPL EU has dedicated resources that will provide the needed information for CSPs to have customers participate in the PJM DR Markets. CSPs and EGSs 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.

23 2011 PPL Electric Utilities Corporation 23 PPL Electric Utilities Support of DR

24 2011 PPL Electric Utilities Corporation 24 PPL 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: ops/dsr/ end-use-customer-fact-sheet.ashx Manual 11 Energy & Ancillary Services Market Operations Section 10 has all of the business rules that must be followed in order to participate in the PJM programs. Link to Manual 11: response/~/media/documents/manuals/m11.ashxhttp://www.pjm.com/markets-and-operations/demand- response/~/media/documents/manuals/m11.ashx

25 2011 PPL Electric Utilities Corporation 25 PPL Electric Utilities Support of DR Questions???

26 Mid-Morning Break

27 Issues and Resolutions: System Enhancements Susan Scheetz EDI Analyst – Supplier Coordination 2011 PPL Electric Utilities Corporation

28 28 Eligible Customer List Interim Guidelines for ECL –PPL 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. M – The 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.

29 2011 PPL Electric Utilities Corporation 29 Eligible 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.

30 2011 PPL Electric Utilities Corporation Monthly Interval Usage Transactions Interval vs. Summary Variance –Late 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

31 2011 PPL Electric Utilities Corporation Monthly Interval Usage Transactions Interval vs. Summary Variance –Customer Choice Controls Phase III has been identified to support intervals that cannot be handled through the current VEE process as part of PPLs 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.

32 2011 PPL Electric Utilities Corporation 32 Billing Enhancements Rate Ready Billing implemented early 2011 –11 registered Rate Ready Suppliers –> 1,500 active rate codes –174,334 Active Rate Ready Customers 814 C Transactions ICAP/NITS –January, 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.

33 2011 PPL Electric Utilities Corporation 33 Billing 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.

34 2011 PPL Electric Utilities Corporation 34 Supplier Communications Supplier Communication Process –Proactively communicate issues affecting suppliers when they are identified. –Continue to provide information on the supplier web site. –Target communications based on issue: Enrollments/Drops/Changes Billing/Usage General EDI Regulatory Customer Service Etc.

35 2011 PPL Electric Utilities Corporation 35 No Bills – Background No 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 –There are currently ~900 no bill accounts.

36 2011 PPL Electric Utilities Corporation 36 No Bills – Background The 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 = 15,000 IT hours – 2011 = 26,000 average IT hours per year. –Market pricing lead to large % of customers shopping.

37 2011 PPL Electric Utilities Corporation 37 No Bills – Common Causes Meter mix Rate rebilling Connect at wrong address Change Meter Orders Competitive Issues TOU Technical issues –Budget billing, bill month (primary), season peak, etc.

38 2011 PPL Electric Utilities Corporation 38 No 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.

39 2011 PPL Electric Utilities Corporation 39 No Bills – Activity 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 Averaged ~450 hours per month through final three Quarters Addressed root cause items in Q4, 2011.

40 2011 PPL Electric Utilities Corporation 40 No Bills – Activity 2012 Established 120 day goal for September full time IT resources assigned. Limited additional weekly allocations based on capacity and/or need: –Subject Matter Experts (SMEs). –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.

41 2011 PPL Electric Utilities Corporation 41 Questions?

42 Issues and Resolutions: Interval Usage/ Meter Information Dave VanArsdale Manager – Information Systems 2011 PPL Electric Utilities Corporation

43 43 Customers and Meter Types Industrial and Large Commercial Customers –MV90 Meters (Itron) –15 minute usage –Includes power quality data –PPL has about 2000 MV90 Meters –Read using cellular phone communications –Each meter is read daily Residential and Other Commercial Customers –TNS Meters (Aclara) –Hourly usage –PPL has 1.4 million TNS Meters –Read over power lines –Meters can not be read when power lines are out –Each meters Daily reading is collected once a day –Each meters Hourly readings are collected 3 times a day (8 hours at a time)

44 2011 PPL Electric Utilities Corporation 44 Metering Reading Overview Meter with TWACS Module Distribution Substation Telecommunications Link Power Lines Substation Control Equipment Service To Home TNSMV90 Telecommunications Link TWACS - Two-Way Automatic Communications Systems TNS - TWACS Network System PPL Computer Systems

45 2011 PPL Electric Utilities Corporation 45 Meter Data Management MV90 and TNS meter readings are stored in PPLs 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 Edit Validation – Missing, Negative, Spike, Static, Sum Estimation – Scale to Daily, Linear Interpolate, Scale to Profile Approved usage is normally available before billing and EDI. Approved usage is available to customers on the Web sent to suppliers via EDI used in PJM Settlement is increasingly used to determine monthly customer bill MDM includes PPLs Retail Choice Forecasting and Settlement application.

46 2011 PPL Electric Utilities Corporation 46 PPL Metering and Related Systems TNS Forecast & Settlement MDM Storage VEE CSSEDI PJM Suppliers Customers MV90 TWACS - Two-Way Automatic Communications Systems TNS - TWACS Network System MDM - Meter Data Management CSS – Customer Service System EDI – Electronic Data Interchange Meters

47 Issues and Resolutions: PPL Scheduling & Settlement Process Gary Hartman Senior Analyst Business Ops Analysis Scheduling & Settlement 2011 PPL Electric Utilities Corporation

48 48 Processes Capacity Tags Zonal Load Settlement A (Backcast) Forecast Settlement B (Reconciliation) Settlement C Financial Settlement Cancel / Rebill Process

49 2011 PPL Electric Utilities Corporation 49 Capacity Tags Predicting the amount of capacity each supplier will be responsible for –Installed Capacity (ICAP) – generation capacity –Network Integration Transmission Service (NITS) Each customer meter is assigned a fixed tag value which remains constant for one year –Calculated using 5 highest hourly peaks on system over previous year 15 day forecasts run & submitted daily No reconciliation exists Billing Impact: –Supplier receives ICAP charges for each meter assigned to them

50 2011 PPL Electric Utilities Corporation 50 Zonal Load Hourly load values calculated for previous day Calculation derived from PJM eMTR submissions by PPL & counterparties Correction period available at end of each month LOAD (INCLUDING LOSSES) = GEN + TIE (IN) - TIE (OUT) Tie Line Generator

51 2011 PPL Electric Utilities Corporation 51 Settlement A LSEs estimated hourly load for previous day Aggregation Process: –All meters in our zone for all hours of previous day / days are assigned a usage value and summed by supplier Includes actual meter reads for largest customers (MV-90 meters) – LP4, LP5, LP6, MUNIs All other meters are estimated –Profiles – typical hourly demand for rate class –Usage Factors – adjusts profile based on consumption patterns –Weather – adjustment based on temperature –Includes loss adjustment based on customer rate class

52 2011 PPL Electric Utilities Corporation 52 Settlement A Interface Process: –UFE is calculated and applied to contracts UFE = zonal load hourly value – aggregation hourly value Allocated to suppliers and POLR providers on load ratio basis –POLR load is allocated to POLR suppliers Submission Process: –Daily file sent to PJM eSchedules which includes MWh hourly total by contract number Billing Impact: –Supplier is charged for load being served

53 2011 PPL Electric Utilities Corporation 53 Forecast LSEs estimated hourly load for future dates –Placeholder for settlement A submission Aggregation Process: –All meters in our zone for all hours of previous day / days are assigned a usage value and summed by supplier Includes no actual meter reads All meters are estimated –Profiles – typical hourly demand for rate class –Usage Factors – adjusts profile based on consumption patterns –Weather – adjustment based on forecasted temperature –Includes loss adjustment based on customer rate class

54 2011 PPL Electric Utilities Corporation 54 Forecast Interface Process: –No UFE calculation Submission Process: –File sent to PJM eSchedules which includes MWh hourly total by contract number Generally run and submitted twice a week with 10 days of forecasted data included in each file Billing Impact: –No financial impact

55 2011 PPL Electric Utilities Corporation 55 Settlement B LSEs actual hourly load for previous month Submission deadline is two months after original Settlement A month –Ex. January Settlement B is due March 31 Aggregation Process: –All meters in our zone for all hours of previous day / days are assigned a usage value and summed by supplier Includes actual reads for nearly 100% of meters –Includes loss adjustment based on customer rate class

56 2011 PPL Electric Utilities Corporation 56 Settlement B Interface Process: –UFE is calculated and applied to contracts Zonal load values are updated if necessary Average UFE of 0.61% since January 2010 –POLR load is allocated to POLR suppliers –Delta is calculated Delta = Settlement A MWh – Settlement B MWh Submission Process: –Monthly file sent to PJM eSchedules which includes hourly deltas by contract number Billing Impact: –Adjustment to supplier charges based on +/- delta

57 2011 PPL Electric Utilities Corporation 57 Settlement C Re-submission of Settlement B with more accurate data after the two month window –Recalculation of delta values Only done in extreme cases –Example: Large Metering Error PJM requires sign off from all affected parties before theyll accept correction PJM generally makes corrections involving long time periods over an extended period of time

58 2011 PPL Electric Utilities Corporation 58 Financial Settlement Process exists for opportunity to settle dollar amounts only Sign off from each impacted party required –Form is provided to PJM –Financial adjustment shows up on monthly PJM Bill Can be used for long term zonal load adjustment or long term customer meter adjustment

59 2011 PPL Electric Utilities Corporation 59 Cancel / Rebill Process No formal process currently exists to reconcile dollars for adjustments beyond the settlement window Currently evaluating options for implementing a standard process –Reviewing approach of other utilities Potential to utilize the Financial Settlement process –Dollar only settlement

60 2011 PPL Electric Utilities Corporation 60 Questions?

61 PPL Smart Meter Plan Overview Dave Glenwright Project Manager – Advance Metering 2011 PPL Electric Utilities Corporation

62 62 Agenda Overview of Smart Meter Projects / Pilots Review of Proposed Projects / Pilots Update on: –Price and Usage Information Pilot –Accelerated Supplier Switching –Improved VEE process –Customer and Meter Data Availability –In Home Display –Remote Connect / Disconnect Addendum Filing Questions

63 2011 PPL Electric Utilities Corporation 63 Smart Meter Plan Projects

64 2011 PPL Electric Utilities Corporation 64 Smart Meter Plan Projects

65 2011 PPL Electric Utilities Corporation 65 Smart Meter Plan Projects - Proposed

66 2011 PPL Electric Utilities Corporation 66 Price and Usage Information Pilot Pilot methods for communicating pricing and usage data to customers 3 communication channels implemented (Phone, , Text) Customers can enroll through the CSR or website Available alerts –Price to Compare (1,290 customers enrolled) –Bill to Date (806 customers enrolled) –Abnormal Usage (998 customers enrolled0

67 2011 PPL Electric Utilities Corporation 67 Accelerated Supplier Switching PPL looking to use Smart Meter technology to shorten the switching window Customers will be allowed 1 mid-cycle switch per month Seeks to reduce switch timeline from 16 – 45 days to 10 days Project will compliment any guidelines in the upcoming final PUC order on Accelerated Supplier Switching

68 2011 PPL Electric Utilities Corporation 68 Improved VEE Process Enhance the quality if IU data through changes to VEE Leverage Outage Manage Data Use outage information so that VEE doesnt profile or estimate usage during outages

69 2011 PPL Electric Utilities Corporation 69 Customer and Meter Data Availability 3 new projects seeking to improve availability of customer and usage data –MDM Data Warehouse and Analytics –Faster Data Presentment to Customers and Suppliers –Supplier Portal Benefits: –Make energy usage data available in less than 48 hours from meter read –Pilot website for suppliers to download usage data

70 2011 PPL Electric Utilities Corporation 70 In Home Display Objectives –Provide direct real-time access to electric usage and cost information –Evaluate available technology, customer behavior and customer satisfaction Install meters with a Wi-Fi module Real-time usage data can be retrieved from any Wi-Fi enabled device in a customers home Technical issues have delayed the pilot Delivery of technology delayed to late-2012

71 2011 PPL Electric Utilities Corporation 71 Hardware Use Wi-Fi as the communications link Small web-server on meter module shows real-time usage Use web browser as IHD –Mac, PC –iPhone, iPod Touch, iPad –Blackberry, Android, etc. –Gaming consoles Internet devices (Sony dash, etc.)

72 2011 PPL Electric Utilities Corporation 72 Screen Shot Example

73 2011 PPL Electric Utilities Corporation 73 Addendum to August 2011 filing Filed May 4, 2012 Scheduling coordination issues / Project delays Project findings New projects 24 month extension to grace period

74 2011 PPL Electric Utilities Corporation 74 Addendum to August 2011 filing Filed May 4, 2012 Scheduling Coordination Issues/Project Delays Project findings New projects 24 month extension to grace period

75 2011 PPL Electric Utilities Corporation 75 Questions Contact Information David Glenwright AMI Program Manager (484)

76 Lunch

77 Retail Markets Investigation Doug Krall Manager - Regulatory Strategy 2011 PPL Electric Utilities Corporation

78 78 Background 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

79 2011 PPL Electric Utilities Corporation 79 Current Status – Phase 1 Phase 1 concluded with an Order entered 7/28/11: The Commission concluded that Pennsylvanias 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.

80 2011 PPL Electric Utilities Corporation 80 Current 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. M Final 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.

81 2011 PPL Electric Utilities Corporation 81 Current 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 PUCs 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; and –Increased coordination between EDCs and EGSs.

82 2011 PPL Electric Utilities Corporation 82 Current Status – Phase 3 Phase 3 instituted via 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; and –Possible statewide consumer education efforts. Informal comments on these subjects before and after a third en banc hearing conducted, on 3/21/12 Staff to provide the Commissioners a report on these subjects.

83 2011 PPL Electric Utilities Corporation 83 PPL Electric Response (Slide 1 of 2) Sent PUC postcards encouraging shopping to all customers in Feb Requested 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.

84 2011 PPL Electric Utilities Corporation 84 PPL 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; and –Increased coordination between EDCs and EGSs.

85 2011 PPL Electric Utilities Corporation 85 Questions?

86 Customer Education Programs Tom Stathos Director – Customer Programs and Svcs 2011 PPL Electric Utilities Corporation

87 87 What We Believe Information is key Electric choice is good for customers Efficiency matters Customers have the power to manage electricity use

88 2011 PPL Electric Utilities Corporation 88 Dedication to energy efficiency Smart meters on all 1.4 million customers since 2004 Expiration of PPL EUs generation rate cap in 2010 created significant challenges –Total rates were expected to rise significantly for all customer classes –Large increases for residential customers (~30%) –Opportunity for customers to shop for generation supply –Strong corporate culture to satisfy customers, with 17 JDPower awards Background: Expiration of rate caps

89 2011 PPL Electric Utilities Corporation 89 Electric choice: Good for customers Shopping for a generation supplier Customers could save money or find options and terms that better suit their individual needs Compare supplier offers at Understand terms of your agreement PPL Electric remains your delivery company Shopping will not affect service reliability

90 2011 PPL Electric Utilities Corporation 90 Electric choice: Good for customers

91 2011 PPL Electric Utilities Corporation 91 Electric Choice: Good for customers 91

92 2011 PPL Electric Utilities Corporation 92

93 2011 PPL Electric Utilities Corporation 93 Electric Choice: By the Numbers Rate GroupActivePending Total Shopping Customers% of Rate Group Total Customers Residential485,2854,613489, % Small Com. & Ind.89, , % Large Com. & Ind.1,10551, % TOTAL575,7465,284581, %

94 2011 PPL Electric Utilities Corporation 94 Electric Choice: Trends

95 2011 PPL Electric Utilities Corporation 95 Electric Choice: Trends Launched new TV ad on April 30, 2012

96 2011 PPL Electric Utilities Corporation 96 Efficiency Matters

97 2011 PPL Electric Utilities Corporation 97 Customer Education Programs (Non-Act 129) E-power Team –Community Education Team – 225,000 customers reached in 2011 THINK! Energy School Program –Provide teachers and students with FREE energy education Continuous Energy Improvement –Work with businesses in the PPL Service Territory on how they can become more energy efficient Agriculture Education Program –Help family farms drive down their operating costs, while still maintaining their productivity Institutional Benchmarking Programs –PPL Electric Utilities has offered energy benchmarking services for K-12 public and non-public schools, as well municipalities and local non-profits

98 2011 PPL Electric Utilities Corporation 98 Customers: Power to manage electricity use

99 2011 PPL Electric Utilities Corporation 99 Energy Analyzer: Monthly website visitors

100 2011 PPL Electric Utilities Corporation 100 Energy Analyzer: Energy graphs viewed

101 2011 PPL Electric Utilities Corporation 101 Tom Stathos Director – Customer Programs & Services PPL Electric Utilities Questions?

102 Mid-Afternoon Break

103 Net Metering What It Means For PPL Electric And Its Customers 2011 PPL Electric Utilities Corporation

104 104 Topics Covered What is Net Metering? What it means to PPL Electric Customers – Both Default Service & Shopping PPL Electric processes Things for EGSs to consider

105 2011 PPL Electric Utilities Corporation 105 What 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: 1)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) 2)Secondary: to give customers distribution benefits where necessary 3)Secondary: support renewable energy development at the customer premise 4)**Also, of course, to conform with Pennsylvania Net Metering rules and PPL Electric Tariff Provisions Customer Eligibility –Customer premise (the house, barn, business) must have had load prior to installing the facility –Maximum facility size: Residential Customer <= 50kW; GS-1, GS-3 or LP-4 <= 3,000kW –All 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 specs –All 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 standards –Customer must submit financial information – specifically a W-9 – for tax purposes –NOTE: Even if a customer is shopping with an EGS, the customer must meet all PPL Electric eligibility requirements.

106 2011 PPL Electric Utilities Corporation 106 PPL Electric Process 1.Customer must complete PPL Electric Eligibility Requirements (submit all forms & complete inspections) 2.PPL Electric reviews all forms and inspection requirements – PPL will also review the premise to determine if a new meter is needed 3.PPL 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. 4.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. 5.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. 6.Once cash-out event occurs, bank is reset and begins anew. 7.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.

107 2011 PPL Electric Utilities Corporation 107 What Does Net Metering Mean for Default Service Customers? Source of Revenue (from excess electricity & distribution benefit) Electric rate stability Offsets some or all of a customers electric consumption – results in a comparison to the PPL Electric PTC. Alternative Energy Credits (AECs) Green power prospective Taxes (Credits? Costs?)

108 2011 PPL Electric Utilities Corporation 108 What 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 Im 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 wont? –Will I still get a distribution benefit on my monthly bill if I produce excess electricity and bank it, even though Im shopping? –Why are there size limitations and forms for me to fill out, if Im putting the facility on my property and not getting another meter?

109 2011 PPL Electric Utilities Corporation 109 Things 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?

110 PPL Net Metering EDI Implementation Susan Scheetz EDI Analyst – Supplier Coordination 2011 PPL Electric Utilities Corporation

111 111 Net Metering – Timeline Change Control #77 11/1/2010 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.

112 2011 PPL Electric Utilities Corporation 112 Net Metering – Timeline Change Control #82 1/13/2011 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.

113 2011 PPL Electric Utilities Corporation 113 Net Metering – Timeline Interim Guidelines for Eligible Customer List Docket M /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.

114 2011 PPL Electric Utilities Corporation 114 Net 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: –ASUNAct 129 Compliant - Solar –AWINAct 129 Compliant - Wind –AHYDAct 129 Compliant - Hydro –ABIOAct 129 Compliant - Biomass –AWSTAct 129 Compliant - Waste –ACHPAct 129 Compliant - Combined Heat and Power –AMLTAct 129 Compliant - Multiple Different Sources –NSUNNot Act 129 Compliant - Solar –NWINNot Act 129 Compliant - Wind –NHYDNot Act 129 Compliant - Hydro –NBIONot Act 129 Compliant - Biomass –NWSTNot Act 129 Compliant - Waste –NCHPNot Act 129 Compliant - Combined Heat and Power –NFOSNot Act 129 Compliant - Fossil Fuel –NMLTNot Act 129 Compliant - Multiple Different Sources The Rating (populated in REF03) is stated in KW and reflects the maximum generation the equipment can produce at any one time.

115 2011 PPL Electric Utilities Corporation 115 Net 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 Delivered –20 = Unavailable –87 = Actual Quantity Received (Net Metering) –9H = Estimated Quantity Received (Net Metering) –KA = Estimated Quantity Delivered –QD = Actual Quantity Delivered

116 2011 PPL Electric Utilities Corporation 116 Net 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.

117 2011 PPL Electric Utilities Corporation 117 Net 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.

118 2011 PPL Electric Utilities Corporation 118 Net 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.

119 2011 PPL Electric Utilities Corporation 119 Questions?

120 Question & Answer


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