The 3rd Electric Generation Supplier (EGS) Conference Wednesday, May 16, 2012 ArtsQuest – Steel...

The 3rd Electric Generation Supplier (EGS)

Conference

Wednesday, May 16, 2012

ArtsQuest – Steel Stacks101 Founders Way

Bethlehem, Pennsylvania 18015

22011 PPL Electric Utilities Corporation

Welcome & Introduction

Renae Yeager

Manager, Energy Acquisition

PPL Electric Utilities


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


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


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

Introduction and

Market Overview


Domenic Breininger

Manager – Retail Supplier Coordination, Scheduling and Settlement

Electric Generation Supplier Conference

May 16, 2012


Market Activity – Planning to Meet Market Needs

Suppliers with Active & Pending Customers

0

10

20

30

40

50

60

70

80

April 2012• 69 suppliers with active & pending customers• 99 suppliers certified


Total Number of Shopping CustomersApril 2011 - March 2012

480,000

500,000

520,000

540,000

560,000

580,000

600,000

Apr-1

1

May

-11

Jun-

11

Jul-1

1

Aug-1

1

Sep-1

1

Oct-11

Nov-11

Dec-11

Jan-

12

Feb-1

2

Mar

-12

Total

PTC Res: 9.27Sm C/I: 9.766

PTC Res: 8.774Sm C/I: 13.028

PTC Res: 8.411Sm C/I: 10.184

PTC Res: 7.769Sm C/I: 6.775

PTC Res: 6.935Sm C/I: 6.387



Shopping Customers by Bill TypeApril 2012

Dual bill, 4.0%

Rate Ready, 30.2%

Bill Ready, 65.6%

Supplier Consolidated, 0.2%



Customer Switching Activity

-

10,000

20,000

30,000

40,000

50,000

60,000

Jan-11

Feb-11

Mar-11

Apr-11

May-11

Jun-11

Jul-11

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-12

Feb-12

Mar-12

Apr-12

Month

Nu

mb

er o

f 81

4 T

ran

sact

ion

s

Enrollments

Drops



MIU Requests

2434930097

36648 33259 36225

58013

90591

104935

8977894735 95167 93795

9899093398

10448494143

0

20000

40000

60000

80000

100000

120000

Jan-11 Feb-11

Mar-11 Apr-11 May-11

Jun-11 Jul-11 Aug-11

Sep-11

Oct-11 Nov-11

Dec-11

Jan-12 Feb-12

Mar-12 Apr-12

Month

Nu

mb

er o

f R

equ

ests

Requests for Monthly IU



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• 2010 - 71,000 customers opted out

• 2012 – 177,000 customers opted out


Pennsylvania Public Utility Commission Welcome


Karen Moury

Director of Regulatory Operations

Electric Generation Supplier Conference

May 16, 2012

Demand Response

Glenn Dickerson

Senior Analyst Business Ops Analysis –Energy Procurement



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.


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.


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.


Regulation Market

• PJM added the capability of accepting demand reduction bids in the Regulation Market in 2006. 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.


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


FERC Order 745

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


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


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 email box at:

[email protected]

The information requested will be provided back in spreadsheet format.

mailto:[email protected]



PPL Customer Peak Load Contributions

Starting Date 6/1/2010 1/1/2011 6/1/2011 1/1/2012End Date 5/31/2011 12/31/2011 5/31/2012 12/31/2012

Customer Name Account Number Rate Class Current ICAP Current NITS Future ICAP Future NITS Status Bill CycleABC Company 123456789 LP-5 13514.2294 4618.33474 4354.17797 999999999 Active 20123 Company 12345678 LP-5 12103.8859 12505.27502 12106.5628 999999999 Active 3

Please Note: - Transmission PLCs are assigned on a calendar year basis (1/1 to 12/31) as designated in the PJM Open Access Transmission Tariff. - Capacity PLCs are assigned on a planning year basis (6/1 to 5/31) as designated in the Reliability Assurance Agreement.

- Values provide are Peak Load Contribution and represent the customer average contribution to the highest hour on the five highest peak load days.

- PLCs do not include any scaling factors or reserves adjustments to obtain obligations make by PJM.

- A PLC of 999999999 indicateds that no PLC is avaliable for this period or no PLC has been create for the account.

- Applicable Transmission Loss FactorsLoss Factors

Transmission 1.0268Primary 1.0536

Secondary 1.0805

Loss Factors by Rate Class are available on our Supplier Web Site by clicking here.



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:

http://www.pjm.com/markets-and-operations/~/media/markets-ops/dsr/20101203-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:• http://www.pjm.com/markets-and-operations/demand-response/~/me

dia/documents/manuals/m11.ashx



http://www.pjm.com/markets-and-operations/demand-response/~/media/documents/manuals/m11.ashx

http://www.pjm.com/markets-and-operations/demand-response/~/media/documents/manuals/m11.ashx



Questions???

Mid-Morning Break

Issues and Resolutions:System Enhancements

Susan Scheetz

EDI Analyst – Supplier Coordination



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-2010-2183412.

– 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.


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.


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


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.


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.


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.


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.


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.


No Bills – Background

• The factors contributing to increased no bill volume were:

– Regulatory changes and Competitive enhancements.

– Enhancements to the System increased:

• 2005 - 2007 = 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.


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.


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.


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.


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.


Questions?

Issues and Resolutions:Interval Usage/

Meter Information

Dave VanArsdaleManager – Information Systems



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)


Metering Reading Overview

Meter with TWACS Module

DistributionSubstation Telecommunications

Link

PowerLines

Substation Control Equipment

ServiceTo Home

TNS

MV90

Telecommunications Link

TWACS - Two-Way Automatic Communications Systems

TNS - TWACS Network System

PPL Computer Systems


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 EditValidation – Missing, Negative, Spike, Static, SumEstimation – 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 Websent to suppliers via EDIused in PJM Settlementis increasingly used to determine monthly customer bill

MDM includes PPL’s Retail Choice Forecasting and Settlement application.


PPL Metering and Related Systems

TNS

Forecast & Settlement

MDMStorage

VEE

CSS

EDI

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

Meters

Issues and Resolutions:PPL Scheduling & Settlement Process

Gary Hartman

Senior Analyst Business Ops Analysis

Scheduling & Settlement



Processes

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


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


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

Tie Line

Tie Line

Tie Line

Generator

Generator

Generator


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


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


Forecast

• LSE’s estimated hourly load for future dates– Placeholder for settlement A submission


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



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


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


usage value and summed by supplier• Includes actual reads for nearly 100% of meters



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


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


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


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


Questions?

PPL Smart Meter Plan Overview

Dave Glenwright

Project Manager – Advance Metering



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


Smart Meter Plan Projects

Pilot-Evaluation Name Pilot-Evaluation Description

Load Control PilotThis pilot was to demonstrate the capability of the AMI infrastructure to support the automatic control of a customer’s electric consumption.

Customer Owned Generation PilotThis project was to better support the net metering tariff end-to-end (metering, Meter Data Management (MDM), Billing), and also to develop a process to ensure that net metering customers have the correct meter installed.

In Home Display / Home Area Network PilotThis pilot is to provide a customer with direct real-time access to electric usage and cost information by using a WiFi chip located within the customer's meter.

Price and Usage Information Pilot

The purpose of this pilot was to evaluate various channels of communication to provide price and usage information to customers. As a result of this project customers can now receive alerts via three channels of communication: phone, email, and text. Three alerts were generated as a result of this project: Price to Compare, Bill to Date, and Abnormal Usage. Customers can enroll in these alerts via CSR or via the Self Serve website.

Telecommunication Substation Modem Implementation

This pilot and implementation was to improve substation communication reliability and address obsolescence of modem equipment used in the regional offices and all the substations.

Voltage Monitoring Pilot

This pilot was to retrieve customer voltage reads at regular intervals, and then to provide the business with voltage information to assist in monitoring the overall electrical health of PPL EU’s distribution system, and to use this information to ensure our system is designed for optimal performance. This pilot is also to help identify and correct customer voltage issues, in many instances, before the customer realizes they have an issue.

Next Generation Technology (TWACS 20 Pilot)Pilot the ability of ACLARA’s next generation TNS protocol (TWACS 20) to relieve bandwidth constrained substations within PPL EU’s metering system.

Proactive Outage Detection Evaluation

This project is to evaluate and pilot the ability to become more proactive in outage detection by further integrating the Outage Management System (OMS) and AMI system whereby SCADA data is monitored to detect a drop on a circuit. Once the drop is identified the AMI meters will be polled to determine if the drop is due to a power outage. If an outage is suspected, the outage will be reported to dispatch to send a crew to restore.


Smart Meter Plan Projects

Pilot-Evaluation Name Pilot-Evaluation Description

Remote Disconnection/Reconnection Pilot This pilot is to automate the use of a remote disconnect / reconnect device within the meter.

On-board Meter Data Storage PilotThis project is being piloted to identify if there is a business benefit for historic daily reads and historic hourly interval usage. The pilot will evaluate historic meter reading data and compare this data to the approved data in MDM.

Real Time Pathmapping EvaluationThis evaluation is to establish functionality to detect feeder load changes and automatically adjust TNS path information.

PLC-based System Enhancement

This evaluation was to estimate the effects on performance, read rates, and reliability of installing next generation SCPA, and of installing additional MTUs. As a result, PPL will replace the current SCPA model 93 with model G2, and will also construct additional TWACS trailers to restore AMI capability at substations during switching and outage events.

Momentary Outage Monitoring Pilot

This pilot is to determine if the company can further develop uses for this data. Momentary outages called “Blinks” accumulate in the meter each time the meter sees a specified incremental drop in power for a specified duration. Meter blinks can be used as an indicator of possible power equipment issues by providing momentary outage data for distribution system devices.

Service Extender PilotService Extender is a program that allows customers in a difficult credit position the ability to maintain a reduced level of electric service as they work through their credit issue

Pre-Pay Metering PilotPre-Pay is a program that offers customers a new payment method that offers additional flexibility as well as potential energy savings.


Smart Meter Plan Projects - Proposed

Pilot-Evaluation Name Pilot-Evaluation DescriptionAccelerated Supplier Switching Project (Off-Cycle)

This project is to allow customers to switch suppliers once between monthly meter reads.

Real-Time Pricing for Mid-Sized C&I customers

This project is to provide real-time pricing as the default service option for customers >100 kW.

Improved VEE process to incorporate outage data

The main objective of this project is to leverage outage management data to improve the VEE process.

Outage Duration Pilot This project is to retrieve outage duration and timestamps directly from the meter.

MDM Data Warehouse and AnalyticsThis project is to copy meter data into a data warehouse (i.e., non-production) environment to improve PPL EU’s analytical capability to support suppliers and customers.

Faster Data Presentment to Customers and Suppliers

This project is to pilot our ability to provide customers and suppliers with energy usage information in less than 48 hours.

Supplier Portal PilotThis project is to pilot and evaluate an alternative method to provide large amounts of energy usage and interval data to suppliers.

VCharge Pilot Ability to support customer participation in PJM regulation market (4 sec. interval data requirement)


Price and Usage Information Pilot

• Pilot methods for communicating pricing and usage data to customers

• 3 communication channels implemented (Phone, Email, 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


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


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


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


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


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.)


Screen Shot Example


Addendum to August 2011 filing

• Filed May 4, 2012

• Scheduling coordination issues / Project delays

• Project findings

• New projects

• 24 month extension to grace period


Addendum to August 2011 filing

• Filed May 4, 2012

• Scheduling Coordination Issues/Project Delays

• Project findings

• New projects

• 24 month extension to grace period


Questions

Contact Information

David Glenwright

AMI Program Manager

[email protected]

(484) 634-3277

mailto:[email protected]

Retail Markets Investigation

Doug Krall

Manager - Regulatory Strategy



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-2011-2237952.


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.


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-2011-2270442.

• 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.


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 www.PAPowerSwitch.com, 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-2011-2270442;

– Inclusion of the EDCs’ price to compare on customer bills; and – Increased coordination between EDCs and EGSs.

http://www.papowerswitch.com/


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.


PPL Electric Response (Slide 1 of 2)

• Sent PUC postcards encouraging shopping to all customers in Feb. 2012.

• Requested approval of Competitive Enhancement Rider in Mar. 2012 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.


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.


Questions?

Customer Education Programs

Tom Stathos

Director – Customer Programs and Svcs


872011 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


• 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

Background: Expiration of rate caps


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 www.papowerswitch.com

• Understand terms of your agreement

• PPL Electric remains your delivery company

• Shopping will not affect service reliability




Electric choice: Good for customers


Electric Choice: Good for customers

91


Electric Choice: By the Numbers

Rate Group Active PendingTotal 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%


Electric Choice: Trends

Active & Pending Shopping Customers

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

1/4/

2010

3/4/

2010

5/4/

2010

7/4/

2010

9/4/

2010

11/4/

2010

1/4/

2011

3/4/

2011

5/4/

2011

7/4/

2011

9/4/

2011

11/4/

2011

1/4/

2012

3/4/

2012


Electric Choice: Trends

• Launched new TV ad on April 30, 2012


Efficiency Matters


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


Customers: Power to manage electricity use


Energy Analyzer: Monthly website visitors

Average Monthly Web Site Visitors

050,000

100,000150,000200,000250,000300,000350,000400,000

2006 2007 2008 2009 2010 2011

Average MonthlyWeb Site Visitors


Energy Analyzer: Energy graphs viewed

Total Daily Energy Use Graphs Viewed

0

200,000

400,000

600,000

800,000

1,000,000

2006 2007 2008 20009 2010 2011

Total Daily Energy UseGraphs Viewed


Tom StathosDirector – Customer Programs & ServicesPPL Electric Utilities

[email protected]

Questions?

Mid-Afternoon Break

Net MeteringWhat It Means For

PPL Electric And Its Customers



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


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.


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.


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?)


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?


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?

PPL Net MeteringEDI Implementation

Susan Scheetz

EDI Analyst – Supplier Coordination



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.



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.


• 9/23/2011 PPL Implemented CC#82 and CC#85. PPL sent 814 Change transactions to all suppliers with Net Meter customers.



Interim Guidelines for Eligible Customer ListDocket M-2010-2183412

• 11/10/2011 Order to include Net Metering indicator on ECL.


• 1/23/2012 PPL Implemented ECL.

• 1/23/2012 PPL Implemented concept of “bank”.


Net Metering – Special Meter Configuration

• The new Special Meter Configuration indicator (REF*KY) was implemented by PPL Electric Utilities on September 23, 2011. 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.


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


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.


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.


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, 2012. Of that total, 2,482 have the correct meter installed.


Questions?

Question & Answer

The 3rd Electric Generation Supplier (EGS) Conference Wednesday, May 16, 2012 ArtsQuest – Steel...

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