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

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

3. Today’s 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. Today’s 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. Introduction Supplier Coordination and Settlement Team Panel Members
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
Domenic Breininger
Manager – Retail Supplier Coordination, Scheduling and Settlement
Electric Generation Supplier Conference
May 16, 2012
2011 PPL Electric Utilities Corporation

7. Market Activity – Planning to Meet Market Needs
April 2012
69 suppliers with active & pending customers
99 suppliers certified

8. Market Activity – Planning to Meet Market Needs
PTC
Res: 9.27
Sm C/I: 9.766
PTC
Res: 8.774
Sm C/I:
PTC
Res: 8.411
Sm C/I:
PTC
Res: 7.769
Sm C/I: 6.775
PTC
Res: 6.935
Sm C/I: 6.387

9. Market Activity – Planning to Meet Market Needs

10. Market Activity – Planning to Meet Market Needs

11. Market Activity – Planning to Meet Market Needs
Requests for Monthly IU

12. Market Activity – Planning to Meet Market Needs
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
3rd Party Curtailment Service Providers
ECL Opt-outs higher
,000 customers opted out
2012 – 177,000 customers opted out

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

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

15. Demand Response at PJM
PJM’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.

16. Capacity Market
With 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.

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. 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. FERC Order 745
Proposed 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 prices
Can mitigate generation market power
Can support system reliability and address resource adequacy

20. FERC Order 745 FERC’s Support for Proposal
Compensate DR reflecting its marginal value
Comparable to treatment of generation
PJM experience
Remove barriers

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. PPL 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.

23. PPL Electric Utilities Support of DR

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:
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:

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. 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. 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. 867 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. 867 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 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.

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. 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. 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. 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 2000.
There are currently ~900 no bill accounts.

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.
2008 = 15,000 IT hours.
2009 – 2011 = 26,000 average IT hours per year.
Market pricing lead to large % of customers shopping.

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. 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. No 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.

40. No 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.

41. Questions?

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

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 meter’s Daily reading is collected once a day
Each meter’s Hourly readings are collected 3 times a day (8 hours at a time)

44. Metering Reading Overview
PPL Computer
Systems
Telecommunications Link
MV90
TNS
Distribution
Substation
Telecommunications Link
TWACS - Two-Way Automatic Communications Systems
TNS - TWACS Network System
Substation Control Equipment
Power
Lines
Meter with
TWACS Module
Service To Home

45. Meter Data Management
MV90 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 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 PPL’s Retail Choice Forecasting and Settlement application.

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

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

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

49. 15 day forecasts run & submitted daily No reconciliation exists
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. LOAD (INCLUDING LOSSES) = ∑GEN + ∑TIE(IN) - ∑TIE(OUT)
Zonal Load
LOAD (INCLUDING LOSSES) = ∑GEN + ∑TIE(IN) - ∑TIE(OUT)
Hourly load values calculated for previous day
Calculation derived from PJM eMTR submissions by PPL & counterparties
Correction period available at end of each month
Tie Line
Generator
Tie Line
Tie Line
Generator
Generator
Tie Line

51. LSE’s estimated hourly load for previous day Aggregation Process:
Settlement A
LSE’s 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, MUNI’s
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. Interface Process: Submission Process: Billing Impact: Settlement A
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. LSE’s estimated hourly load for future dates Aggregation Process:
Forecast
LSE’s 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. Interface Process: Submission Process: Billing Impact: Forecast
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. LSE’s actual hourly load for previous month
Settlement B
LSE’s 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. Interface Process: Submission Process: Billing Impact: Settlement B
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. Only done in extreme cases
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 they’ll accept correction
PJM generally makes corrections involving long time periods over an extended period of time

58. Process exists for opportunity to settle dollar amounts only
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. 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. Questions?

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

62. Overview of Smart Meter Projects / Pilots
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. Smart Meter Plan Projects

64. Smart Meter Plan Projects

65. Smart Meter Plan Projects - Proposed

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. 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. Improved VEE Process
Enhance the quality if IU data through changes to VEE
Leverage Outage Manage Data
Use outage information so that VEE doesn’t profile or estimate usage during outages

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. Discuss technical issues and delays at a high level.
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 customer’s home
Technical issues have delayed the pilot
Delivery of technology delayed to late-2012
Overview of the pilot
Discuss technical issues and delays at a high level.

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. Screen Shot Example

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. 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. 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. 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. Current Status – Phase 1
Phase 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.

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. 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 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; and
Increased coordination between EDCs and EGSs.

82. Current 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; 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. 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. 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. Questions?

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

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

88. Background: Expiration of rate caps
Dedication to energy efficiency
Smart meters on all 1.4 million customers since 2004
Expiration of PPL EU’s 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
Fast Facts:
A 42-inch plasma TV can draw three times more electricity than traditional TV
A digital photo frame in every home would require five mid-sized power plants
Swapping the old frig for a new one can save enough power to light a home 4 months
If every American home replaced just one bulb with a compact fluorescent, it would be equivalent of taking 800,000 cars off road 88 88

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 89

90. Electric choice: Good for customers90

91. Electric Choice: Good for customers91

93. Electric Choice: By the Numbers
Rate Group
Active
Pending
Total Shopping Customers
% of Rate Group Total Customers
Residential
485,285
4,613
489,898
39.90%
Small Com. & Ind.
89,356
666
90,022
50.70%
Large Com. & Ind.
1,105 5
1,110
86.20%
TOTAL
575,746
5,284
581,030
41.30% 93

94. Electric Choice: Trends94

95. Electric Choice: Trends
Launched new TV ad on April 30, 2012 95

96. Efficiency Matters 96

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 97

98. Customers: Power to manage electricity use98

99. Energy Analyzer: Monthly website visitors99

100. Energy Analyzer: Energy graphs viewed
100

101. Questions? Tom Stathos 610-774-3760 tcstathos@pplweb.com
Director – Customer Programs & Services
PPL Electric Utilities
101

102. Mid-Afternoon Break

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

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. 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:
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 necessary
Secondary: support renewable energy development at the customer premise
**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. PPL Electric Process
Customer 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 needed
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.
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.

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. 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 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?

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. 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. 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. Net Metering – Timeline
Interim Guidelines for Eligible Customer List
Docket M
11/10/2011 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. 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:
ASUN Act 129 Compliant - Solar
AWIN Act 129 Compliant - Wind
AHYD Act 129 Compliant - Hydro
ABIO Act 129 Compliant - Biomass
AWST Act 129 Compliant - Waste
ACHP Act 129 Compliant - Combined Heat and Power
AMLT Act 129 Compliant - Multiple Different Sources
NSUN Not Act 129 Compliant - Solar
NWIN Not Act 129 Compliant - Wind
NHYD Not Act 129 Compliant - Hydro
NBIO Not Act 129 Compliant - Biomass
NWST Not Act 129 Compliant - Waste
NCHP Not Act 129 Compliant - Combined Heat and Power
NFOS Not Act 129 Compliant - Fossil Fuel
NMLT Not 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. 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. 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. 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. 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. Questions?

120. Question & Answer