1. 1 Andrew L. Ott General Manager, Market Coordination PJM Interconnection, L. L. C. PJM Energy Market Model

2. 2 Section 1 - Agenda 3 Overview of PJM 3 Overview Locational Marginal Pricing 3 Overview Financial Transmission Rights 3 Overview Day-ahead Market 3 Overview of Ancillary Services 3 Overview Installed Capacity

3. 3 Electric Distributors Members Committee Sector Voting Generation Owners Transmission Owners Other Suppliers End-Use Customers PJM Independent Board - (Elected by Members) Governance

4. 4 PJM and PJM West Control Areas Generating Units594 Generation Capacity66,100 MW Peak Load62,443 MW Annual Energy 298,011 MW Transmission Miles13,000 Area (Square Miles)79,000 Customers11 Million Population Served 25.1 Million States (+ D.C.)8 Generating Units594 Generation Capacity66,100 MW Peak Load62,443 MW Annual Energy 298,011 MW Transmission Miles13,000 Area (Square Miles)79,000 Customers11 Million Population Served 25.1 Million States (+ D.C.)8 PJM RTO with PJM West PJM - Full Service RTO Control Area Operator Transmission Provider Market Administrator Regional Transmission Planner NERC Security Coordinator PJM West PJM RTO

5. 5 What is LMP?  Pricing method PJM uses to …  price energy purchases and sales in PJM Market  prices transmission congestion costs to move energy within PJM Control Area  Physical, flow-based pricing system  how energy actually flows,  NOT contract paths

6. 6 Definition: Locational Marginal Pricing Transmission Congestion Cost Transmission Congestion Cost = Generation Marginal Cost Generation Marginal Cost LMP ++ Cost of Marginal Losses Cost of Marginal Losses Cost of Marginal Losses = Not currently implemented Cost of supplying next MW of load at a specific location, considering generation marginal cost, cost of transmission congestion, and losses.

7. 7 Said Another Way...  The marginal cost to provide energy at a specific location depends on:  marginal cost to operate generation  total load (demand)  cost of delivery on transmission system

8. 8 Transmission System Congestion  Transmission system congestion occurs when available, low cost supply cannot be delivered to the demand location due to transmission limitations  As Market Participants compete to utilize the scarce transmission resource, the RTO needs an efficient, non-discriminatory mechanism to deal the congestion problem Thermal Limits Voltage Limits Stability Limits

9. 9 Control Actions ED Brighton Sundance 240 MW A BC Thermal Limit Solitude Alta Park City System Reconfiguration Transaction Curtailments Re-dispatch Generation

10. 10 When Transmission Constraints Occur  Delivery limitations prevent use of “next least-cost generator”  Higher cost generator closer to load must be used to meet demand  Cost to operate more expensive generation are translated into transmission congestion costs in LMP calculation  LMP results in cost causation for congestion pricing to market participants

11. 11 Managing Congestion on the Power Grid  LMP is not a new concept to power system operators, For many years, system operators have managed congestion using least-cost security constrained dispatch which is the same program that calculates LMP values  The PJM LMP-based market provides an open, transparent and non-discriminatory mechanism to manage transmission congestion under open transmission access.

12. 12 Transmission System Congestion  The PJM Market uses Locational Marginal Pricing to manage transmission congestion  The PJM Market also includes overlying trading hubs and zones to provide standard energy products for the commercial markets (i.e. it can reduce the number of pricing points that participants need to use)  The PJM Market includes Financial Transmission Rights to allow participants to manage congestion risk

13. 13 How Are LMP Values Calculated ?  The following examples demonstrate how LMP values are determined at all locations  The LMP values are a result of security- constrained economic dispatch actions  LMP values are calculated based on generation offer data and the power flow characteristics of the Transmission system.

14. Constrained Case E A BC D 240 MW Thermal Limit Solitude Alta Park City Brighton 600 MW $10/MWh 110 MW $14/MWh 100 MW $15/MWh 520 MW $30/MWh 200 MW $30/MWh 300 MW Dispatched at 600 MW Dispatched 100 MW Dispatched at 110 MW Dispatch Solution Ignoring Thermal Limit Dispatched 90 MW Total Dispatched 900 MW 253 174 216 38484 348 14 Sundance

15. E A BC D 240 MW Thermal Limit Solitude Alta Park City Brighton 600 MW $10/MWh 110 MW $14/MWh 100 MW $15/MWh 520 MW $30/MWh 200 MW $30/MWh Sundance 300 MW Constrained Case 600 MW 110 MW 240 159 223 37777 360 124 MWLMPs$10.44 $23.51$21.14 $15 $30 Marginal Generators 15 66 MW

16.  Park City and Sundance supply the next increment of load on the system  Attempt to serve an additional increment of load (1 MW)  Resulting Sensitivity Factors determine LMP Bus Location Sensitivity Factors for 1 MWh of Load Supplied from: Calculation Details Park City@ $15/MWh Sundance@ $30/MWh A1.00 MWh0.00 MWh1.00($15) + 0.00($30) = $15 B0.59 MWh0.41 MWh0.59($15) + 0.41($30) = $21.14 LMPs and Flow Sensitivity Factors 16

17. LMPs and Flow Sensitivity Factors Bus Location Sensitivity Factors for 1 MWh of Load Supplied from: Calculation Details Park City@ $15/MWh Sundance@ $30/MWh C0.43 MWh0.57 MWh0.43($15) + 0.57($30) = $23.51 D0. 00 MWh1.00 MWh0.00($15) + 1.00($30) = $30.00 E1.30 MWh-0.30 MWh1.30($15) + -0.30($30) = $10.44  Least Cost Security Constrained Dispatch Algorithm  Calculates least expensive way to serve load while respecting transmission limit 17

18. 18 What Are FTRs? Financial Transmission Rights are … a financial contract that entitles holder to a stream of revenues (or charges) based on the hourly energy price differences across the path

19. 19 Purpose of FTRs  To protect firm transmission customers from increased cost due to transmission congestion, when energy deliveries are consistent firm reservations *  To allow energy traders to purchase protection from transmission congestion charges on a specified path  To facilitate a forward energy market by providing a mechanism to manage basis risk caused by LMP differences during periods of transmission congestion * Note: Risk-averse customers can enter into long-term supply contracts and purchase FTRs to become indifferent to the hourly LMP values

20. 20 Characteristics of FTRs  Defined from source to sink (point to point * )  MW level based on transmission reservation  Financially binding - an Obligation  Financial entitlement, not physical right  Independent of energy delivery * Note: FTR Sources and Sinks can be single nodes or aggregated points such as Trading Hubs, Zones or Aggregates

21. 21 Obtaining FTRs  Network service  based on annual peak load  designated from resources to aggregate loads  Firm point-to-point service  may be requested with transmission reservation  designated from source to sink  Secondary market -- bilateral trading  FTRs that exist are bought or sold  FTR Auction -- centralized market  purchase “left over” capability

22. 22 Energy Delivery Consistent with FTR Thermal Limit FTR = 100 MW Congestion Charge = 100 MWh * ($30-$15) = $1500 FTR Credit = 100 MW * ($30-$15) = $1500 LMP = $30LMP = $15 Source (Sending End) Sink (Receiving End) Bus B Bus A Energy Delivery = 100 MWh

23. 23 Energy Delivery Not Consistent with FTR FTR Credit = 100 MW * ($30-$10) = $2000 Congestion Charge = 100 MWh * ($30-$15) = $1500 Bus A LMP = $10 Bus C LMP = $15 LMP = $30 Bus B Energy Delivery = 100 MWh FTR = 100 MW

24. 24 FTR Revenue Adequacy  In the PJM market, if congestion charges collected are less than the target value of the FTRs then the FTR credits are reduced proportionately  Reasons for FTR credit deficiency have been:  Unexpected transmission outages  Conservative operations due to unexpected Solar Magnetic Storms  Lower than expected voltage performance  Increased loop flows from neighboring control areas

25. 25 What is the Day-ahead Market? A Day-ahead hourly forward market for electric energy. It provides the option to ‘lock in’:  scheduled quantities at day-ahead prices  scheduled energy deliveries at day-ahead congestion price  Fully financial, allows virtual demand and supply bids

26. 26 Two Settlements  Day-ahead Market Settlement  based on scheduled hourly quantities and day- ahead hourly prices  Real-time Market Settlement  based on actual hourly quantity deviations from day-ahead schedule hourly quantities and on real-time prices

27. 27 Example 1:LSE with Day-ahead Demand less than Actual Demand Day Ahead Market Real-time Market 100 MW Scheduled Demand Actual Demand 105 MW = (105 - 100)* 23.00 = $115.00 Real-time LMP = $23.00Day Ahead LMP = $20.00 = 100 * 20.00 = $2000.00 if Day-ahead Demand is 105MW = $2100.00 as bid = $2115.00

28. 28 Day Ahead Market Real-time Market 200 MW Scheduled MW Actual MW 100 MW Day Ahead LMP = $20.00 = 200 * 20.00 = $4000.00 Real-time LMP = $22.00 = (100 - 200) * 22.00 = $2200.00 payment Example 4:Generator with Day-ahead MW greater than Actual MW

29. 29 Implications of Day-ahead Market  Day-ahead schedules are financially binding  Demand scheduled day-ahead  pays day-ahead LMP for day-ahead MW scheduled  pays real-time LMP for actual MW above scheduled  paid real-time LMP for actual MW below scheduled  Generation scheduled day-ahead  paid day-ahead LMP for day-ahead MW scheduled  paid real-time LMP for actual MW above scheduled  pays real-time LMP for actual MW below scheduled

30. 30 Ancillary Service Markets  Energy and energy transportation (transmission service) are the commodities that RTO customers need in the RTO market.  Ancillary Services (regulation, reserves, etc.) are services that the RTO needs to ensure reliable system under RTO market operations  Since Energy is the desired commodity, Ancillary Services should not dominate or distort the market  The market design should provide an efficient mechanism to acquire Ancillary Services without distorting the energy market

31. 31 PJM Regulation and Reserve Market Philosophy  Separate Real-time markets for Regulation and Spinning Reserve are co-optimized with the Energy market are the most efficient mechanism to acquire these services.  Day-ahead Energy market includes regulation and reserve constraints but does not have separate financial settlements for regulation and reserves.  Product substitution problem (substitution of regulation or reserves for forward energy) is handled by including lost opportunity cost component in regulation and reserve pricing

32. 32 Day-ahead Ancillary Service Model  In theory, Day-ahead Ancillary Service markets with separate availability bids are more efficient.  In practice, the added complexity of separate Day- ahead Markets for regulation and reserve does not result in efficiency gains.  With separate Day-ahead markets for these products, the complex interaction and product substitution issues make real-time dispatch less efficient

33. 33 Installed Capacity (ICAP) Requirement  Needed to ensure long term generation adequacy and short-term generation availability  In theory ICAP is not needed but in practice it is required for a variety of reasons  Generation receives revenue for selling ICAP service which is essentially a call on energy during periods of generation shortage

34. 34 Installed Capacity (ICAP) Requirement  ICAP resources in PJM have additional obligations:  Must submit offers into Day-ahead Market  Must be available to PJM in-day if not sold outside PJM or on forced outage  Energy can be sold outside PJM but is subject to recall under capacity emergency conditions

35. 35 Section 2 - Agenda 3 Day-ahead Market Details 3 Real-time Market Details 3 Transmission Service and Transactions 3 Ancillary Markets 3 Demand Response 3 Mitigation Measures

36. 36 Spot & Ancillary Markets  Market Flexibility  Support bilateral transactions  Self scheduling of supply  Spot Market access  Market Information  Internet posting system  Market Incentives  Market Adaptation

37. 37 PJM Market Mechanisms  The PJM Market supports a variety of financial contracts that are separate from the physical spot market.  Day-ahead Energy Market  Virtual supply offers  Virtual Demand Bids  Price-sensitive Demand bids  “Up to” congestion bids for external transactions  External transactions may submit separate Day-ahead financial energy profile  Financial Transmission Rights  Financial Energy Contracts  PJM eSchedules

38. 38 Day-ahead Market Data Flow u Generation Offers u Demand Bids u Increment Offers & Decrement Bids (virtual supply & demand) u Load Forecast and Reserve Requirements u Hydro Unit Schedules u Scheduled Transmission Outages u Bilateral Transactions u Facility Ratings u Net Tie Schedules u PJM Network Model Technical Software u Schedules for Next Day (generation & demand) u Transaction Schedules u Day-ahead LMPs u Day-ahead Binding Constraints u Day-ahead Net Tie Schedules u Day-ahead Reactive Interface Limits u Day-ahead Summary

39. 39 Day Ahead Energy Market  The PJM Day-ahead energy market is a day- ahead hourly forward market  Objective is to develop a set of financial schedules that are physically feasible  Full transmission system model  Unit commitment constraints  Reserve requirements model  Day-ahead market results based participant demand bids and supply offers

40. 40 Develop day-ahead financial schedules Coordinate financial schedules with reliability requirements Provide incentive for resources & demand to submit day-ahead schedules Provide incentive for generation to follow real-time dispatch Fundamental Requirements

41. Day-Ahead Market closes Day-ahead Results Posted & Balancing Market Bid period opens Balancing Market Bid period closes Day-ahead Market  determines commitment profile that satisfies fixed demand, price sensitive demand bids, virtual bids and PJM Operating Reserve Objectives  minimizes total production cost Reserve Adequacy Assessment  focus is reliability  updated unit offers and availability  Based on PJM load forecast  minimizes startup and cost to run units at minimum Transmission Security Assessment  focus is reliability  performed as necessary starting two days prior to the operating day  Based on PJM Load Forecast Unit Commitment Analyses41

42. 42 Day-Ahead Market  Financial model - degree of similarity to physical dispatch is determined by participant bids and offers  Full transmission model assures revenue adequacy for day-ahead schedules  Economic incentives drive convergence of day-ahead market and real-time market

43. 43 PJM Energy Market Options for energy supply CUSTOMERS IndustrialCommercialResidential Bilateral Transactions PJM Spot Market Load Serving Entities obtain energy to serve customers Self-schedule their own resources

44. 44 PJM Spot Market  Voluntary Bid Based Market  Unit Specific (start-up, no-load and energy bids)  External Transactions: Unit specific or Slice of System (energy only)  generation may offer or self-schedule  Bids “locked in” by noon day before with rebid period for generation not selected day-ahead  Generation Offer curves are for entire 24 hour period (no hourly changes in offer prices are permitted)  Generation status and self-scheduled quantities can change in-day with 20 minute notice

45. 45 PJM Spot Market  Voluntary nature of spot market is a critical design feature to provide maximum number of options for participant  Transparent spot price and open, flexible spot markets are necessary to provide the maximum ability for participants to react to price signals. This allows the market to compliment reliable operations rather then hinder it.  PJM design provides both spot and bilateral options  Risk-averse participants can lock in forward bilateral energy contracts and acquire Financial Transmission Rights to become indifferent to the spot market prices.  Municipalities with on-site generation can self supply and be indifferent to spot market price or can react to market signals.  Spot and bilateral and self-supply options are critical in all markets (i.e. energy, regulation, spinning reserve, etc.)

46. 46 Real-time Economic Dispatch  Least-cost security-constrained dispatch optimizes energy and reserves and calculates unit specific dispatch instructions for the next five-minute period. (ex-ante dispatch)  LMP values calculated every five minutes based on actual generation response to dispatch instructions that were sent in the previous five minute period (ex-post pricing)  Real-time performance monitoring software determines if generator is following dispatch instructions.

47. 47 Real-time Market Incentives  Generation is incented to follow real-time dispatch instructions:  If generation is following real-time dispatch instructions then it is eligible to set LMP, otherwise it become a price taker.  If generation is scheduled by PJM and is following real- time dispatch instructions then it receives a revenue guarantee of at least its specified offer data, otherwise there is not revenue guarantee.  No penalties are imposed for over or under generation

48. 48 Efficient Real-time Markets  LMP pricing, pricing based on actual system operating conditions  State estimator updated continuously (every minute)  Same model for day-ahead market, system scheduling, dispatch, and settlements  High degree of consistency between generator LMP values and dispatch instructions  Consistency results in market confidence  A large amount of real-time operational data is posted quickly, this also gives market participants confidence

49. 49 Efficient Real-time Markets  The price of energy at each location is calculated and posted on the PJM website at five minute intervals. u Settlements are performed based on hourly integrated LMPs u Self-scheduled generation and transactions are price-takers u Generator and transaction status can change in real-time with 20 minute notice

50. 50 Look-ahead Dispatch  Performs least-cost security-constrained dispatch looking forward over the next four hours  Provides capability to view solutions at 15 minute intervals over the four hour period  Performs calculations of 15 minute integrated load forecast  Reserve models are consistent between Day-ahead market, look-ahead dispatch and real-time dispatch

51. 51 Look-ahead Dispatch  Accounts for unit operating constraints and for transaction ramp limits  Optimizes energy, reserves and regulation with full transmission model (DC model linearized every five minutes from AC operating point)  Surrogate voltage constraints are recalculated at 15 minute intervals using on- line AC security analysis software

52. 52 Look-ahead Dispatch  The following program modules have the capability to improve look-ahead performance by automatically adjusting input data based on recent operational performance:  Load Forecast - adjust Load Forecast for future intervals by measuring forecast performance over the last 30 minutes of operation  Generation Performance Monitor - Adjusts generation status and ramp capability based on recent operational performance (i.e. last 30 minutes)

53. 53 Transmission Service  PJM sells long-term and shorter Transmission Service (Network, Firm Pt-to-Pt and Non-firm)  Transmission service reservations enable market participants to reserve physical capacity to import, export or wheel through energy  Transmission Service rates are license plate and the rates are known at the time of purchase  Participants have the option to specify a dispatch price for imports/exports or to be a price taker (self-schedule)

54. 54 Transmission Service for External Transactions  Transmission Service is required to schedule energy transactions through PJM or to export energy from PJM.  Transmission Service is not required for Imports  Transmission service reservations reserve ramp room for external transactions  At Market boundaries, seams problems can occur if energy transactions between markets are curtailed with short notice by the market operator without coordination with neighbors

55. 55 Transaction Management  LMP efficiently controls transmission congestion while allowing a large degree of flexibility in the Market.  PJM sells unlimited non-firm transmission service  LMP values encourage market behavior to be consistent with efficient power system operations  eSchedules system allows participants to enter internal financial bilateral transactions up to noon day-after the operating day

56. 56 A B C D Implicit Net Congestion Result between D and A LMP (D-A) LMP (B - A) LMP (C - B) LMP (D - C) Calculated Congestion LMP [(D-C)+(C-B) +(B-A)] = LMP (D-A) Calculated Congestion LMP [(D-C)+(C-B) +(B-A)] = LMP (D-A) Implicit Bilateral Transaction SourceSink Load and generation implicitly pay congestion by paying (receiving) LMP Transactions explicitly pay congestion by paying (receiving) LMP difference Anatomy of a PJM Bilateral Transaction

57. 57 PJM’s Regulation Market  Regulation requirement set by PJM ISO at 1.1% of PJM forecast peak or valley demand  Obligation can be satisfied by:  Bilateral contract  Self-scheduling  Spot purchase  Generators submit regulation offer data by 1800 day before

58. 58 The Energy Balance 5862 5961 60 DEMANDGENERATION Losses Interchange Power Generated Load Hertz

59. 59 What is Regulation?  Definition  A variable amount of generation capability under automatic control which is operated independent of the economic dispatch signal and can respond within five minutes  Generating units that provide fine tuning that is necessary for effective system control  Governors respond to minute-to-minute changes in load  Regulating units correct for small load changes that cause the power system to operate above and below 60 Hz for sustained period of time

60. 60 PJM’s Regulation Market  PJM executes regulation adequacy assessment and sets Regulation Market Clearing Price (RMCP) for each hour of next day at 2200 day before  Actual assignment of regulation to generators is made in real-time operations  Payment for regulation is higher of  RMCP  OR  Offer Price + Opportunity Cost

61. 61 PJM’s Regulation Market  This design provides an real-time efficient market for regulation while recognizing the practical realities of system operation.  The forward floor price mechanism (RMCP) tends to reduce oscillation (switching units on and off regulation frequently) that can sometimes occur from the optimization results

62. 62 Successful Regulation Market Implementation  Prior to implementation  insufficient regulation available in some situations  Post implementation observations  sufficient regulation available  purchase price remained the same  significant improvement in system control  Results  Reduced transaction notification times  Evaluating regulation requirements

63. 63 Opportunity Cost Payments Regulation Market Clearing Price (Average Price per MWh of Regulation Purchased) Regulation Market Prices Before Market Implemented After Market Implemented

64. 64 Spinning Reserve Market  Scheduled for implementation in late 2002  Similar in concept to regulation market  Two types of products  Tier 1: Marginal, unloaded steam  Tier 2: Condensers (CTs and hydro), steam reduced to provide spinning, and load  Tier 1 response is paid by event  Tier 2 is a capacity payment  Tier 2 hourly clearing price (SRMCP) is calculated hour-ahead

65. 65 Spinning Reserve Market  Obligations will be calculated based on load ratio share of the spinning requirement  Those with obligations will be able to fulfill them by:  self-scheduling spinning reserve on owned resources  trading spinning capability bilaterally  purchasing from the spinning market  Spinning Reserve clearing price can vary by location when 500 kV reactive interface limits are binding

66. 66 Operating Reserves  Operating Reserve requirements are modeled in both Day-ahead and Real-time Markets  Payments for Operating Reserve are included in uplift that results from all other uneconomic operation of generation that is requested by PJM  Uneconomic operation of generation can occur for a variety of reasons including: Unit commitment constraints, Reserve requirement, Minimum run times, dispatch uncertainty, etc.  All generation make-whole payments are covered in Operating Reserves accounting

67. 67 PJM Ancillary Service Rates for 2001 Regulation, Spinning Reserve are in $ per MWh of load Day-ahead Operating Reserve is in $ per MWh of cleared Day-ahead demand Balancing Operating Reserve is in $ per MWh of Balancing Deviation

68. 68  Active Load Management (ALM)  Participants required to be LSEs, although not necessarily the LSE serving the customer’s load  Participants receive ICAP credit for nominated load – significant financial penalties exist for non-performance  Activated by PJM or LSE a limited number of times per summer period, for limited durations  Emergency Load Response Pilot Program  Participants not required to be LSEs, but must be PJM members (special membership available)  Activated by PJM immediately prior to ALM  Participants receive higher of $500/MWh or LMP  Costs allocated to all entities short to the energy market during the hour of the reduction PJM Demand Response Programs

69. 69  Economic Load Response Pilot Program  Participants not required to be LSEs, but must be full PJM members (no special membership)  Reductions initiated by end-use customers based on LMP  Participants receive LMP minus their retail rate for actual reductions  Costs allocated to the LSE that would have served the customer’s load PJM Demand Response Programs

70. 70 2001-2002 Economic Option  Customer’s LSE charged LMP for reductions  LSE credited customer’s retail rate  Difference credited to the party that signed the load reduction up with PJM time $$ Flat retail energy rate 10 100 30 500 1000 20 Fluctuating wholesale rate

71. 71 Demand Response Issues  Jurisdictional issues regarding end-use customers participating in the wholesale market  Socialization of program costs  How much, if any, should be socialized and to whom?  Is a causal allocation correct?  Metering requirements  Can any customer get an hourly meter (i.e. fixed load profiles)  If no hourly meter exist, what are the options?  Demand Response Incentives  Should these programs mimic response to real time prices or provide additional compensation?

72. 72 PJM Mitigation Measures: Design  Energy market offer cap = $1,000/MWh  Energy market offer cap includes operating reserve payments  Start up and no load costs can be modified only biannually  Regulation market offer cap = $100 plus opportunity cost  Only one market-based offer curve per day  Hourly price offer changes not permitted

73. 73 PJM Mitigation Measures  Local market power mitigation (units built < July 9, 1996)  Must run units are cost capped for determining LMP  Receive greater of cost plus 10% or LMP  Alternative methods to determine payment cap  Required submission of cost data by unit (units built < July 1996)  If maximum economic output specified in day ahead offer is less than in real time, forced outage ticket  If unit classified as Max Emergency in day ahead and not in real time, forced outage ticket

74. 74 PJM Mitigation Measures  Generator interconnection process (RTEP)  Flexible capacity markets  Multiple capacity markets: Daily, monthly, multi-monthly  Bilateral capacity markets  Owned or contracted generation  Capacity markets  Recall option on energy output during emergencies  Day ahead offer requirement  Penalty for withholding energy (forced outage adjustment)  Facilitate retail access  Capacity market effective offer cap = capacity deficiency rate  $177.30/MW-day  Allocation of capacity deficiency payments  Interval market

75. 75 PJM Mitigation Measures  Transmission outage notification requirements and FTR auction  Required notification period for transmission outages  Required coordination of transmission outages  Required coordination of generator outages  Increment offers/decrement bids cannot create day ahead congestion > real time congestion  Publication of bid and other data  Demand elasticity initiatives