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The 3rd Electric Generation Supplier (EGS) Conference Wednesday, May 16, 2012. ArtsQuest – Steel Stacks 101 Founders Way Bethlehem, Pennsylvania 18015. Welcome & Introduction. Renae Yeager Manager, Energy Acquisition PPL Electric Utilities. Today’s Agenda.
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The 3rd Electric Generation Supplier (EGS)ConferenceWednesday, May 16, 2012 ArtsQuest – Steel Stacks 101 Founders Way Bethlehem, Pennsylvania 18015
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 PMCustomer 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 • 2011 PPL Electric Utilities Corporation
Market Activity – Planning to Meet Market Needs April 2012 • 69 suppliers with active & pending customers • 99 suppliers certified
Market Activity – Planning to Meet Market Needs PTC Res: 8.411 Sm C/I: 10.184 PTC Res: 9.27 Sm C/I: 9.766 PTC Res: 7.769 Sm C/I: 6.775 PTC Res: 8.774 Sm C/I: 13.028 PTC Res: 6.935 Sm C/I: 6.387
Market Activity – Planning to Meet Market Needs Requests for Monthly IU
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 • 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 • 2011 PPL Electric Utilities Corporation
Demand ResponseGlenn DickersonSenior Analyst Business Ops Analysis –Energy Procurement • 2011 PPL Electric Utilities Corporation
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: SupplierCoordination@pplweb.com The information requested will be provided back in spreadsheet format.
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: 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/~/media/documents/manuals/m11.ashx
PPL Electric Utilities Support of DR Questions???
Issues and Resolutions:System Enhancements Susan Scheetz EDI Analyst – Supplier Coordination • 2011 PPL Electric Utilities Corporation
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.
Issues and Resolutions:Interval Usage/Meter InformationDave VanArsdaleManager – Information Systems • 2011 PPL Electric Utilities Corporation
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)
MV90 TNS Metering Reading Overview PPL Computer Systems Telecommunications Link Distribution Substation Telecommunications Link TWACS - Two-Way Automatic Communications Systems TNS - TWACS Network System Substation Control Equipment Power Lines Meter with TWACS Module ServiceTo Home
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.
PJM MV90 MDM Forecast & Settlement Meters Meters CSS Customers EDI TNS Suppliers PPL Metering and Related Systems Storage VEE TWACS - Two-Way Automatic Communications Systems TNS - TWACS Network System MDM - Meter Data Management CSS – Customer Service System EDI – Electronic Data Interchange
Issues and Resolutions:PPL Scheduling & Settlement Process Gary Hartman Senior Analyst Business Ops Analysis Scheduling & Settlement • 2011 PPL Electric Utilities Corporation
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
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) Generator Generator Generator Tie Line Tie Line Tie Line Tie Line Zonal Load