wecc introduction to spp eis market june 26, 2008

WECCIntroduction to SPP EIS Market

June 26, 2008

www.spp.org 3

SPP at a Glance

www.spp.org 4

The SPP Difference

• Relationship Based

• Member Driven

• Independence Through Diversity

• Evolutionary vs. Revolutionary

• Reliability and Economics Inseparable

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SPP Milestones1941: Formed to serve defense needs

1968: NERC Regional Council

1980: Telecommunications network

1991: Operating reserve sharing

1994: Incorporated as non-profit

1997: Reliability Coordination

1998: Tariff Administration

2001: Regional Scheduling

2004: FERC Approved RTO

2006: Contract Services

2007: Launched EIS Market, NERC Regional Entity

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SPP at a Glance

• Little Rock based

• 300+ employees

• $101M operating,$24M capital (2008)

• 24 x 7 operation

• Full redundancy and backup site

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SPP at a Glance

• 255,000 square miles of service territory

• $4.6 billion in transmission gross investment

• 52,301 total miles of transmission lines

• 4.5 million customers served

• 42.4 GWs of peak demand

• 55 GWs of generation capacity

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SPP Members

12 Investor-Owned Utilities

11 Cooperatives

8 Municipals

2 State Agencies

2 Independent Transmission Companies

4 Independent Power Producers/Wholesale Generation

1 Contract Participant

11 Marketers

51

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SPP Transmission Map

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Markets 101EI Market Overview

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What is a “Market”?

• General Concept• An interaction between buyers and sellers

• RTO Facilitated Market• Spot energy market required by FERC• Allows participants to offer resources into the market• Designed to promote use of least cost generation for

Imbalance

• SPP Market• SPP facilitates the marketplace, overseeing the activities of

the market, insuring reliability, and forecasting supply requirements and providing Market Monitoring oversight.

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Benefits of the SPP EIS Market

• Asset owners benefit from pooling their resources and gaining access to lower, more transparent pricing.

• GenCos benefit by having the option of reducing their generation and buying lower cost energy from the SPP market to serve their load, and by offering their generation into the marketplace for exposure to an increased customer base.

• GenCos are also able to more closely operate to their economical efficiency point.

• LSEs benefit from more efficient competition among suppliers (generators) which should lower spot energy prices.

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• Spot Balancing energy market• Locational Imbalance Pricing (nodal)• Voluntary Offers on Resources• Charges on Imbalance Energy• Uninstructed Deviation Charge• Hourly Settlement• Weekly Invoicing• Physical Transmission Rights• Self-commitment of Resources by Owners

SPP EIS Market Highlights

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• All Load and resources within SPP tariff footprint are subject to financial settlement of Imbalance Energy.

• The EIS market is not, by its nature, thick or thin. The participation by resources in selling energy into the market and setting price is based upon each participant's evaluation of the benefits of selling energy to the market, and submitting offers accordingly.

• The financial impact on both resources and load is within the “control” of the participants through the use of energy schedules.

• Participants with both load and resources have the hourly imbalance settlement for both load and resources netted prior to invoicing.


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• Resources may either be:• Sellers into the market (Available status) or;• Self-dispatched to serve scheduled transactions and/or native load.

• Dispatch is regional and calculated using a security constrained economic dispatch (SCED) every 5 minutes.

• If a resource is Self-dispatched, it is still subject to imbalance settlement if actual output does not match scheduled output.

• Any resource that is offered for SPP dispatch has the entire asset subject to dispatch (within the "Dispatchable Range").

• SPP EIS market does not supersede any MP’s obligations to any other capacity or ancillary service obligations.

• Control Areas (CA) and asset owners will continue to use the same procedures used today to manage capacity adequacy, reserves, and other reliability-based concerns.

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“Market” Comparison

• Real-time Energy Market• Locational Pricing• Day-Ahead Energy Market -

• Financial Transmission Rights

• Security Constrained Unit Commitment

• Mandatory Offers• Energy Schedules without

reservations (FinSched/eSched)

• Real-time Energy Market• Locational Pricing

• No Day-Ahead Market -- Bilateral Markets Used

• Physical Transmission Rights

• Unit Commitment by Owner

• Voluntary Offers

• Energy Schedules using reservations

MISO PJM SPP

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What is “Imbalance Energy”?

• Imbalance energy (or Energy Imbalance) is the difference between what actually happens for each generator and load location, and what they prearranged through schedules.

Energy Imbalance = Actual Production/Usage – Scheduled Production/Usage

• SPP instructs asset owners to move their generation output based on offer curves while maintaining reliability and balance (matching generation to load).

• The amount of increase or decrease in generation is paid for by the asset owner needing the energy.

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What is the “Energy Imbalance Service”?

• EIS is the dollar amount associated with the imbalance energy.

• EIS is calculated by taking the amount of Energy Imbalance and multiplying by the price at a specific point on the energy grid.

Energy Imbalance Service = Imbalance Energy x Locational Imbalance Price (LIP)

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Let’s say that Generator A is scheduled to provide Load B 100 MWh of energy.

But at the end of the hour, the energy output of Generator A was only 90 MWh, and the energy consumption of Load B was also only 90 MWh.

Has an imbalance occurred in this situation?

Gen A 100 MWh

Gen A 90 MWh

Load B 100 MWh

Load B 90 MWh

Scheduled

Actual

Note: Generation Injections are (-) and Load Withdrawals are (+) as viewed from an SPP settlement reference frame for EIS.

Imbalance Energy Example

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Imbalance Energy ExampleImbalance (Gen A) = (-90 MWh Actual) – (-100 MWh Scheduled)Imbalance (Gen A) = 10 MWh

Imbalance (Load B) = (90 MWh Actual) – (100 MWh Scheduled)Imbalance (Load B) = -10MWh

Notice that even though the system was in balance (generation matched load), by definition there was an imbalance at each location. Actual and Scheduled were not equal.

Actual minus

Scheduled

Actual minus

Scheduled

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Pricing Imbalance Energy in an Unconstrained & Constrained System

• Imbalance energy is priced depending on which resources are deployed to meet the load requirements. This is known as Locational Imbalance Pricing or LIP.• An unconstrained system will have a single system wide price,

or a System Marginal Price.

• LIP recognizes that cost may vary at different times and locations based on real-time system conditions.• Constraints on the system can cause price divergence among

the various nodes due to the out-of-order dispatch needed to prevent operating limit violations.

• With LIP, asset owners know the price per MWh of electricity at various intersections on the system (nodes).

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• Here’s an example…Generator A offers 10 MW @ $15/MWhGenerator B offers 10 MW @ $30/MWhGenerator C offers 10 MW @ $20/MWh

• To supply 15 MWh of energy to a load in an unconstrained system, the market selects the most economical generation within current reliability standards. In this case, Generators A and C.Generator A 10 MW @ $15/MWhGenerator C 5 MW @ $20/MWh (sets price as providing the “next”

increment of energy)

• In this case, Generators A and C would both get paid $20/MWh to serve 15 MWh of load

Locational Imbalance Price (Unconstrained)

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• But what if it is impossible to deliver power economically within current reliability standards?

• Binding constraints (preventing a limit violation) usually result in:• Generation being dispatched out of economic order• Different prices for energy at different points in the system

(or price divergence)

• When there are constraint violations, action must be taken to maintain reliability standards.

Post-Market Energy Imbalance Process

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Pricing Imbalance EnergyKnowing that constraints can cause different load points in the system to have different prices, let’s revisit a previous example:

Imbalance (Gen A) = (-90 MWh Actual) – (-100 MWh Scheduled)Imbalance (Gen A) = 10 MWh

Imbalance (Load B) = (90 MWh Actual) – (100 MWh Scheduled)Imbalance (Load B) = -10MWh

This nets to zero, but a system constraint could cause the LIP at Gen A to be different than the LIP at Load B.

A System Marginal Price would net to zero dollars between these two nodes

For settlement purposes, an energy injection is a negative value

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Settling an Imbalance Financially• Suppose the following:

LIP @ (Gen A) = $30/MWhLIP @ (Load B) = $40/MWh

The resulting charges would be:

EIS (Gen A) = $30/MWh x 10 MWh = $300 (MP pays SPP)EIS (Load B) = $40/MWh x -10 MWh = -$400 (SPP pays MP)

• The net imbalance is zero (generation equaled load), but there is a net payment of $100 ($300+(-$400)) to Load B because of different prices at different points in the system.

NOTE: A (+) EIS indicates that SPP will receive payment from the Participant (a charge)A (-) EIS indicates that SPP will pay out to the Participant (a credit)

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Example 1: No Market Participation

• GenA has a bilateral contract with Load A and schedules 200 MWh at $40/MWh to Load A.

• It costs GenA $30/MWh to produce the energy.• Generator A has a profit of:

($40/MWh - $30/MWh) x 200 MWh = $2,000

Gen A 200 MWh $30/MW

Load A 200 MWh Scheduled

Bi-Lateral

Contract $40/Mw

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Example 2: Market Participation• GenA and Load A have a bilateral schedule for 200 MWh.• GenA also decides to offer its generation into the SPP

market @ $40/MWh.• The SPP Market can provide energy @ $25/MWh from

other resources.• Therefore, SPP instructs GenA to go to Min MW (10 MW)

because its price is higher than the LIP.

Gen B MWh

$25/MW


Load A 200 MWh

Scheduled = 200 MW @ $40/MWActual = 10 MW @ 40/MW

Bi-Lateral

Contract $40/Mw

Scheduled = 0 MWActual = 190 MW @ $25/MW

Market

Dispatch $25/Mw

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Example 2: Market ParticipationGen A EIS = (Actual – Scheduled) x LIPGen A EIS = [-10 MWh – (-200 MWh)] x $25/MWhGen A EIS = 190 MWh x $25/MWhGen A EIS = $4,750 (Paid to SPP)

GenA pays SPP $4,750SPP disperses this money to the generator(s) that provided

the 190 MW of energy.

Gen B MWh

$25/MW


Load A 200 MWh


Bi-Lateral

Contract $40/Mw


Market

Dispatch $25/Mw

$4750 $4750

A positive value

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Example 2: Market Participation

Gen B EIS = (Actual – Scheduled) x LIP

Gen B EIS = [-190 MWh – (0 MWh)] x $25/MWh

Gen B EIS = -190 MWh x $25/MWh

Gen B EIS = - $4,750 (paid to this resource)

SPP pays Gen B $4,750

Gen B MWh

$25/MW


Load A 200 MWh


Bi-Lateral

Contract $40/Mw


Market

Dispatch $25/Mw

$4750 $4750

A negative value

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Load A EIS = (Actual – Scheduled) x LIP

Load A EIS = (200 MWh – 200 MWh) x $25/MWh

Load A EIS = 0 MWh x $25/MWh

Load A EIS = $0

Load A pays no EIS

Gen B MWh

$25/MW


Load A 200 MWh


Bi-Lateral

Contract $40/Mw


Market

Dispatch $25/Mw

$4750 $4750

No change to scheduled withdrawal

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• GenA paid SPP $4,750 in lieu of spending $5,700 to generate the 190 MWh of energy itself.

• This saved GenA $950 by offering the resource to the Market

• GenA continues to receive compensation from load A under its bilateral agreement (200MWh x $40/MWh) of $8000.

• GenA profits increased from $2000, to $2950

Gen B MWh

$25/MW


Load A 200 MWh


Bi-Lateral

Contract $40/Mw


Market

Dispatch $25/Mw

$4750 $4750

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• Only schedules with a source and sink associated with registered settlement locations will be used in market settlement. NERC registry entries in the tag must be mapped to valid settlement locations.

• Schedules can be Tags (Point to Point) or Native Load Schedules (NLS)• Scheduling reduces the imbalance charges as a result of actual meter

values not matching schedule values. • Market participants typically NLS schedule from their generators to their

loads to avoid price exposure.• Market Participants need to schedule their native load at a settlement

location level.

Introduction to Interchange Scheduling

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Physical and Market Schedules

• Energy Schedules are classified depending on the Resource Status submitted in the Resource Plan.

• If Self-Dispatched Resource, the schedule will be a Physical Schedule. • If the Resource is offered into the Market (Available) or the source is a

Settlement Location for Load, the schedule will be considered a Market Schedule.

• If the MP submits both a schedule and an offer, the dispatch system will ignore the scheduled output for each Resource and calculate a Dispatch Instruction for the Resource based on the Offer Price and the information in the Resource Plan.

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Satisfying Energy Requirements

Example: • A Market Participant has an obligation of 500 MW at a

Settlement Location(s) in a particular hour and two Resources, each having a minimum operating limit of 60 MW and a maximum operating limit of 300 MW.

Gen 1Max 300 MWMin 60 MW

Gen 2Max 300 MWMin 60 MW

500 MW Obligation

BA Load

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The MP could:• Self Dispatch both of its Resources• Indicate it intends to operate its Resources (on its Resource

Plan) at an aggregate 500 MW• Generate in real time 500 MW, consistent with the sum of its

schedules• The MP must also schedule an aggregate of 500 MW from its

Resource Settlement Locations to meet its Load obligations

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• Dispatch value will be the sum of schedules includes all tagged (energy and dynamic) schedules, NLS schedules and Reserve Sharing Schedules that are contained in RTO_SS.

• These resources may only be dispatched outside of the sum of the schedules in a system emergency (a manual “out of merit energy” or “OOME” dispatch instruction sent by the Market Operator).

Self-Dispatched ResourcesIntroduction

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OR the MP could:• Make both Resources available for SPP dispatch • SPP can then calculate economic base points within the

operating range of 60 MW to 300 MW on each unit• While not explicitly required, the MP could also choose to

schedule from its Resource Settlement Locations (and still allow the SPP MOS to dispatch unit)

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OR the MP could:• Make one of its Resources available for SPP dispatch. • Self-Dispatch its other Resource by indicating on its

Resource Plan that it intends to operate that Resource at 200 MW (and Scheduled as such) and generate in real time at the dispatched 200 MW value.

• Self-Dispatch of the second unit at 200 MW is required so that the remaining load requirements can be covered by the other Resource (made available) being dispatched by SPP MOS

• While not explicitly required, the MP could also choose to schedule from its offered Resource Settlement Location (300 MW).

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Reserve Sharing Event

• Market Participants providing assistance for a reserve sharing event deploy specific Resources at their discretion to respond to the event.

• Schedules of energy deployment from the Reserve Sharing System (RSS) will ensure that Self-dispatched Resources are sent consistent instructions.

• Schedules allow the MOS to utilize the withheld capacity from Market Resources allocated as carrying Spinning and/or Supplemental Operating Reserves.

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• With the implementation of an energy market not all schedules/tags represent physical/actual flows.

• NERC has made modifications to the Interchange Distribution Calculator (IDC) to reflect MISO/PJM market design. SPP has complied with the same modifications made for MISO/PJM.

• Due to SPP’s use of schedules as a physical transmission rights and the resulting difference from MISO implementation, SPP has developed the Curtailment Adjustment Tool (CAT)

• TLR used to relieve flowgate loading when flow levels approach the Security Operating Limit (SOL), or the Interconnect Reliability Operating Limit (IROL) of that flowgate. Uses both the NERC IDC and the SPP CAT tools in the schedule curtailment process

Transmission Loading Relief (TLR)

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• TLR curtails two types of constraint flow:

• Tagged Schedules by the NERC IDC

• Market Flows using the SPP CAT

• Market flow is determined by the MFC (Market Flow Calculator) and sent to NERC IDC every 15 minutes

Transmission Loading Relief (TLR)

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SD = Self Dispatched

MD = Market Dispatched

Control Area

Red = SPP Market Flow

(CAT curtailed)

CA

SPP

Green = NERC IDC

Curtailment

SPP Market Footprint

SD

MD

SD

MD

SD

MD

NLS

EIS

TAGSTAGS

TAGS

EIS

Market Flow vs. IDC Transactions

TAGS

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Five-Minute Deployment0000 0005 0010 0015 0020 0025

Calculations Communications Ramp

Deployment MW reached

Calculations Communications RampSnapshot

Calculations Communications RampSnapshot

Note: for Manual status: Snapshot = Deployment

Snapshot

T T- 5 minutes T-10 minutes T-15 minutes

T T- 5 minutes T-10 minutes T-15 minutes

T T- 5 minutes T-10 minutes



Deployment MW sent

Deployment MW sent

Deployment MW sent

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EIS Market Experience

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Depth of MarketGWh

Scheduled Transactions

92%

Load EI2%

Resource EI6%

Other8%

FEB 2007 - MAR 2008

Total Energy = 378,988 GWh

EIS Fund Exchange = $1,585 Million

EIS Market is a Marginal Market

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But Robust, Capacity Available to the EIS Market

46

MonthAvailable Capacity

Available and Self-Dispatch Capacity

SPP-Wide Availability

from MMP

February 17,945 23,443 77%March 16,142 20,758 78%April 17,002 21,154 80%May 17,885 22,696 79%June 21,278 26,156 81%July 23,155 28,164 82%August 24,226 29,860 81%September 20,196 24,625 82%October 17,688 21,075 84%November 18,041 21,176 85%December 19,198 22,658 85%Average* 19,357 23,806 81%

* Average is weighted by the number of days in each month** If Manual was included in the SPP-Wide Availability calculation, the average SPP-Wide Availability would be approximately 73%.

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% Total Capacity Dispatchable

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Electricity Sales in the EIS Market

48

MonthMWh Sold by Market

ParticipantsDollars Received by Market Participants

February 982,439 $52,552,411March 1,084,657 $49,846,702April 1,052,692 $52,640,111May 1,103,790 $52,296,674June 1,413,136 $83,835,716July 1,515,464 $79,063,516August 1,717,694 $99,278,662September 1,236,895 $56,661,578October 998,315 $49,455,937November 1,042,553 $48,699,623December 1,064,088 $49,144,201Total 13,211,723 $673,475,131

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Share of EIS Market Sales (Anonymously Ranked)

49

Market Participant

Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total

1 16.4% 14.0% 14.8% 18.8% 25.4% 17.3% 12.0% 16.2% 20.1% 23.5% 26.2% 18.38%2 10.7% 17.1% 14.2% 15.5% 17.3% 12.3% 14.6% 18.2% 15.8% 13.5% 12.0% 14.71%3 17.0% 15.7% 12.1% 12.4% 11.7% 13.3% 11.2% 14.6% 16.9% 18.0% 17.5% 14.25%4 19.1% 15.6% 16.5% 14.8% 10.6% 7.4% 10.7% 10.8% 8.4% 12.0% 11.2% 12.12%5 7.0% 8.2% 9.7% 1.7% 4.8% 14.6% 18.6% 5.8% 3.3% 2.8% 4.4% 8.07%6 3.9% 5.9% 6.2% 8.5% 7.6% 8.3% 8.0% 10.3% 9.3% 9.4% 8.8% 7.89%7 0.9% 1.6% 2.5% 7.7% 5.8% 10.3% 9.7% 5.2% 2.0% 0.2% 0.1% 4.77%8 7.8% 5.4% 7.0% 2.9% 3.0% 2.3% 2.5% 4.1% 4.3% 4.2% 3.4% 4.04%9 5.7% 2.9% 3.4% 4.4% 3.7% 2.9% 2.9% 3.7% 4.9% 4.3% 4.3% 3.79%

10 3.4% 2.4% 2.4% 2.0% 2.1% 2.1% 2.5% 2.3% 3.1% 2.5% 2.1% 2.42%11 1.6% 2.6% 1.8% 1.7% 1.5% 1.6% 1.2% 1.4% 2.1% 1.8% 1.3% 1.66%12 0.7% 1.7% 1.2% 1.3% 0.9% 1.1% 1.0% 1.2% 2.5% 3.3% 3.4% 1.59%13 1.6% 1.7% 3.0% 3.4% 1.2% 0.9% 0.9% 1.0% 1.0% 0.9% 0.8% 1.43%14 1.7% 1.9% 1.4% 0.8% 1.1% 1.2% 1.7% 0.9% 2.0% 0.8% 1.4% 1.35%15 1.0% 0.9% 1.2% 1.4% 1.1% 0.9% 0.7% 1.0% 1.5% 1.4% 1.3% 1.09%16 0.3% 0.2% 1.6% 1.4% 0.7% 2.0% 0.5% 2.0% 1.7% 0.3% 0.5% 1.02%17 0.3% 1.0% 0.4% 0.3% 0.3% 0.9% 0.8% 0.6% 0.4% 0.5% 0.5% 0.56%18 0.7% 0.7% 0.3% 0.4% 0.5% 0.4% 0.4% 0.5% 0.4% 0.4% 0.3% 0.44%19 0.4% 0.4% 0.4% 0.6% 0.8% 0.4% 0.2% 0.4% 0.3% 0.4% 0.3% 0.41%20 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.02%21 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.00%

HHI 1,220 1,145 1,064 1,154 1,346 1,097 1,127 1,134 1,182 1,356 1,414 1,103

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Graphically

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Regional Monthly Average Prices

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Electricity Prices Compared with Neighboring Regions

52

RegionAverage

PriceMax. Price

Min. Price

Median Price

Volatility Average On-Peak Price

Average Off-Peak Price

SPP $49.18 $386.16 ($105.82) $50.28 48% $58.30 $41.25MISO $47.37 $622.63 ($35.75) $36.84 69% $63.37 $33.45ERCOT $53.00 $1,500.00 ($246.05) $48.77 89% $60.74 $46.26

$51.78 $59.94 $43.39SPP weighted avg* The average prices shown here represent simple average prices.

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Interval Prices Beyond Thresholds

53

MonthPercent of Observations

Less Than $0Percent of Observations Between $0 and $100

Percent of Observations Between $100 and $400

Percent of Observations Greater Than $400

February 1.1% 94.0% 4.5% 0.3%March 1.0% 97.2% 1.8% 0.1%April 0.3% 98.6% 1.0% 0.2%May 0.3% 98.6% 1.0% 0.1%June 0.9% 95.8% 2.9% 0.4%July 0.3% 97.9% 1.5% 0.2%August 0.5% 94.9% 4.2% 0.3%September 1.4% 96.4% 1.9% 0.3%October 0.3% 98.2% 1.4% 0.1%November 0.7% 97.5% 1.8% 0.1%December 0.4% 98.5% 1.1% 0.1%Total 0.6% 97.1% 2.1% 0.2%

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Top 10 Congested Flowgates

54

Location Flowgate Name Corridor NameBalancing Authority

Congested Intervals

Binding Intervals

Violated Intervals

% of Total Intervals

Congested

SPP to SPS Ties SPPSPSTIES SPS SPP-SPS 23,910 23,572 338 24.9%SPS North-South SPSNORTH_STH SPS SPS 9,691 9,489 202 10.1%Jeffrey to Summit* TEMP03_14375 Kansas East - West WERE 4,536 4,461 75 4.7%Creswell to Newkirk / Kildare CREKILWICWOO Wichita - Oklahoma City WERE-OKGE 3,822 3,704 118 4.0%Lone Oak to Sardis LONSARPITVAL Texas - Oklahoma East AEPW 3,663 2,644 1,019 3.8%Hugo to Valiant HPPVALPITVAL Texas - Oklahoma East WFEC-AEPW 2,118 1,774 344 2.2%SW Shreveport Transformer SWSXFRSWSXFR Other AEPW 2,112 1,600 512 2.2%S. Philips to W. McPherson SPHWMCSUMEMC Kansas East - West WERE 1,887 1,840 47 2.0%Flint Creek to Tontitown FLITONFLIGEN Arkansas West - East AEPW 1,564 556 1,008 1.6%Kelly to Seneca KELSENEMACON Other WERE 1,196 710 486 1.2%

* Indicates temporary flowgates

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Congestion Resolution

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Transmission/Bi-Lateral Market Unaffected

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EIS Market Benefits Analysis

The SPP Board of Directors approved implementation of the EIS Market based largely upon the benefits to the region projected by the CRA cost/benefit study.

Were they right?

57

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EIS Market Benefits Analysis

The SPP Board of Directors approved implementation of the EIS Market based largely upon the benefits to the region projected by the CRA cost/benefit study.

Were they right?

YES!58

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Incurred Avoided Trade Benefit$286 Million - $ 393 Million = $ 107 Million

Adjustments - $ 4 Million _____

$ 103 Million

A Simplified Regional Calculation

7,560 GWh

@ $38 /MWh

7,560 GWh

@ $52 /MWh

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State of MarketExternal Market Monitor Statements

A. EIS Market is a success – do more marketsB. Significant Transmission Investment – make

more transparentC. Huge wind development – celebrate and

manageD. Keep attracting new competition – lower price,

more innovationE. Manage transmission congestion – a work of/in

progress

Carl Monroe, [email protected]

mailto:[email protected]

wecc introduction to spp eis market june 26, 2008

Documents

imbalance spp market

market spot energy market

energy imbalance

spp dispatch

launched eis market

spp transmission map

ei market overview slide

productionusage spp