placement of facilities in spp rate zones

SouthwestPowerPool SPPorg southwest-power-poolHelping our members work together to keep the lights on... today and in the future.

PLACEMENT OF FACILITIES IN SPP RATE ZONESJUNE 30, 2021

2

ATTACHMENT AI

• Above the voltage threshold (excluding transformer isolation equipment)

• Non-radial or multi-customer (wholesale) radial facilities• Open loops are considered radial

• Interconnections between zones or to another transmission provider

• Control and protection equipment

• DC ties owned by an SPP TO

• Seven-factor test with determination by FERC

3

ZONAL PLACEMENT PROCESS• Applicability to: 1) Integration of a potential SPP TO’s existing

facilities with resulting impact on Zonal ATRR under Schedule 9, or 2) Purchase by a current SPP TO of existing facilities that were not previously included in Zonal ATRR under Schedule 9

• Four-stage process: 1) Notification, 2) Information request from SPP, 3) Integration analysis including a rate impact assessment (45 days), 4) Affected parties’ negotiation (45 days)

• Data provided includes: Identification of facilities, Integration of facilities and operations in SPP, Reliability and comparability of the facilities, ATRR and its components, Loads served, Line miles and number of substations, Service area

• At the end of the process, a filing is submitted to FERC

4

ZONAL PLACEMENT CRITERIA

• FERC has stated that placement of facilities in a zone is a case-by-case determination

• Criteria applied by SPP in recent reviews include the following:• To determine whether to place the facilities in a new zone—

• (i) whether the ATRR is less than a minimum threshold based on a 3-year average. Recently, this has been around $13 million

• (ii) extent to which the facilities substantively increase the SPP regional footprint

• (iii) nature of transmission service to serve load prior to the facilities transfer date

5

ZONAL PLACEMENT CRITERIA

• If a new zone is not created, the determination of which existing zone the facilities are placed in is based on—

• (i) the extent to which the facilities are embedded in an existing zone

• (ii) the extent to which the facilities are integrated with an existing zone

• (iii) nature of transmission service to serve load prior to the facilities transfer date.

• Ultimately, FERC makes the determination as to whether the proposed zonal placement is just and reasonable

6

SECTION 30.9 CREDITS

• Provides that a network customer can offset its transmission service bill by the revenue requirement of transmission facilities it owns

• To qualify, the facilities must be integrated with the SPP transmission system as specified in Section 30.9. Among other things, the facilities should qualify under Attachment AI

• There is no credit over and above the customer’s network transmission service charge amount—i.e., no payment to customer

• The cost of the credit is included in the zonal revenue requirement paid by all customers in the zone

• SPP must submit filings to FERC in order to effectuate the crediting arrangement

SouthwestPowerPool SPPorg southwest-power-poolHelping our members work together to keep the lights on... today and in the future. 7

SPP RESOURCE ADEQUACY POWER PURCHASE AGREEMENT REQUIREMENTSCHRIS HALEY

8

WHO IS RESPONSIBLE FOR RESOURCE ADEQUACY?

• LRE is an asset owner with registered load in the SPP Integrated Marketplace

• Entities with load-serving obligations in the SPP Balancing Authority (BA) will be responsible for complying with SPP’s Resource Adequacy Requirement (RAR)

• Attachment AA requires a LRE to maintain capacity required to meet its load and planning reserve obligations.

• If an LRE serves load both internal and external to the SPP BA, compliance with the RAR does not affect an LRE’s obligation to maintain distinct and separate amounts of resources to cover planning reserve obligation for load external to the SPP BA

• Market Participant is responsible to ensure the LRE’s compliance

Load-responsible entity (LRE)

9

DEMAND TYPES

• The highest demand including a) transmission losses for energy, b) the projected impacts of non-controllable and non-dispatchable behind-the-meter generation, and c) the projected impacts of non-controllable and non-dispatchable demand response programs measured over a one clock hour period.

Peak demand

Net peak demand (NPD)• The forecasted peak demand less the a) projected impacts of a

demand response program and b) adjusted to reflect the contract amount of firm power with another entity as specified in section 8.2 of this Attachment AA.

• SPP’s RAR is applied to each LREs NPD.

10

CAPACITY AND POWER PURCHASE TYPES

• The accredited capacity of commercially operable generating units, or portions of generating units, adjusted to reflect purchases and sales of capacity with another party and is deliverable with firm transmission service to the LRE’s load.

Firm capacity

Firm power• Power purchases and sales deliverable with firm transmission

service to serve the LRE’s load with capacity, energy and planning reserves, which must be continuously available in a manner comparable to power delivered to native-load customers.

11

QUALIFICATION OF CAPACITY (ATTACHMENT AA, SECTION 7)

• Firm capacity/power from a resource(s) internal to the SPP BA must:• Demonstrate the resource(s) is:

• Registered in the Integrated Marketplace or• Listed as a designated resource in the Network Integration Transmission Service

Agreement• Submit current operational and capability test results as performed in accordance with

the SPP Planning Criteria• Demonstrate that there is firm transmission service from the internal resource(s) to the

LRE’s load• Firm capacity/power from a resource(s) external to the SPP BA must:

• Demonstrate ownership or contractual rights• Submit current operational test results per the requirements of the BA where the

resource(s) is located• Demonstrate firm transmission service from the external resource(s) to the LRE’s load• Attest that any external capacity identified is not otherwise being used as capacity in

any other BA or in another resource adequacy construct

Firm capacity and firm power requirements

12

QUALIFICATION AND VERIFICATION OF POWER PURCHASE AGREEMENTS (ATTACHMENT AA, SECTION 8)• (8.2) When a PPA qualifies as Firm Power and the purchaser and seller

are both LREs:• Purchaser deducts the contract amount from its Net Peak Demand • Seller adds the amount to its Net Peak Demand • The responsibility to maintain the RAR and the Winter Season

obligation transfers from the purchaser to the seller

• (8.3) When a PPA qualifies as Firm Power and the seller is not an LRE:• Purchaser cannot deduct the contract amount from its Net Peak

Demand• Purchaser remains responsible for the RAR and Winter Season

obligation for load served by the agreement• Purchaser reflects the contract amount plus the purchaser’s PRM

multiplied by the contract amount as Firm Capacity • Firm transmission service is only required for the contract amount

8.2: Contract is for 10 MWsPurchaser LRE 1: 100 MWs of NPD100(NPD)– 10 = 90 MW NPDSeller LRE 2: 100 MWs of NPD100(NPD) +10 = 110 MW NPD

8.3: Contract is for 10 MWsPurchaser LRE 1: 100 MWs of NPDCannot deduct = 100 MW obligationAdds the 10 MW plus reserve amount to their generation portfolio

13

QUALIFICATION AND VERIFICATION OF POWER PURCHASE AGREEMENTS (ATTACHMENT AA, SECTION 8)

• (8.4) When a PPA qualifies as Firm Power and the purchaser is not an LRE, seller is LRE• Seller cannot include the purchased contract

amount in its Net Peak Demand• Seller reflects the contract amount plus the

seller ’s PRM multiplied by the contract amount as Firm Capacity

• Firm transmission service is only required for the contract amount

Contract is for 10 MWsPurchaser is not an LRESeller LRE 1: 100 MWs of NPDSubtracts the 10 MW plus reserve amount from their generation portfolio

SouthwestPowerPool SPPorg southwest-power-poolHelping our members work together to keep the lights on... today and in the future. 14

SPP OPERATIONSOVERVIEW

16

Primary Control Center

17

Back-up Control Center

18

OperatingReserves Posted

0600

Bidding Closes

0930

DA Market Results Posted

1300

Re-Offer Period Closes

1345

DA RUC Results Posted

1615

DA MARKET TIMELINE

19

INPUTS INTO THE DA MARKET? Activated Flowgates

Instantaneous Load Capacity

Interchange Transactions

Load Forecast

Multi-Day Reliability Assessment (MDRA) Commitments

Resource and Transmission Outages

Virtual Bids and Offers

P.34

20

DA MARKET INPUTS AND OUTPUT

20

DA Market

Cleared OffersCommitment for Energy

Cleared Bids, OR, Virtuals, & Trans.

DA Market Prices

Bids & Offers (DA & Virtual)

MDRA Commitments

DA Confirmed Interchg. Trans.

SPP OR Requirements

Trans. System Topology

Trans. and Resource Outages

Activated Flowgates

Parallel Flow Forecasts


21

PURPOSE OF RUC

Commit resources to meet forecasted RT capacity

requirement

Key inputs include RT offers, forecasts, & OR req.

Minimizes total commitment costs

22

A CLOSER LOOK

Bid-in Load and Operating Reserve (OR)

cleared in DA Market

Generation committed in DA Market

Hours

Load Forecast and OR Requirements (RUC Input)

Generation Committed in RUC

Generation De-committed

in RUC

Hours

23

Multi-Day Reliability

Assessment (MDRA)

Day-Ahead (DA) RUC

Intra-Day (ID) RUC

Short-Term RUC (ST-RUC)

RUC STUDIES

1 2

3 4

24

Issue start-up orders in advance

PURPOSE OF MDRA

24

Performed daily

At least three (3) days prior to OD

Assesses capacity adequacy

25

MDRA INPUTS: DAY BEFORE DA (DBDA) STUDY

25

DBDA:• Runs everyday at 2200 • Utilizes all algorithms, but focus is

constraint identification• Build new flowgates to enforce in

subsequent studies

26

MDRA INPUTS AND OUTPUT26

Real-Time (RT) Offers

Est. Interchange Transactions

Est. OR Requirements

Mid-Term Load Forecast



Resource Output Forecast (Wind & Solar)

Activated Flowgates

MDRA Suggested Resources for Commitment

27


Assessment (MDRA)

Day-Ahead (DA) RUC

RUC STUDIES

1 2

28

PURPOSE OF DA RUCAssesses capacity adequacy during DA period and remainder of current OD

28

Operating Day (OD) DA Market

NO Forecasts

Virtuals

DA RUC

Forecasts

NO Virtuals

29

DBDAResults

0300

DA Market Closes

0930

DA Market Results Posted

1300

Re-Offer Period Closes

1345

DA RUC Results Posted

1615

DA RUC TIMELINE All resources noton outage

30

DA RUC INPUTS AND OUTPUT30

Resource Commit/ Decommit

RT Offers & Existing Commit.

Confirmed Interchange Trans.

SPP OR Requirements




Mid-Term Load Forecast

Resource Output Forecast

Parallel Flow Forecasts

Activated Flowgates

DA RUC

31

DA RUC ANALYSIS & COMMITMENT

DA Operator analysis

Can the commitment

wait?

Resource(s) added to

COPNotification sent to MP

31

1 2 3 4

32


Assessment (MDRA)

Day-Ahead (DA) RUC

Intra-Day (ID) RUC

RUC STUDIES

1 2

3

33

THE PURPOSE OF ID RUCAssesses capacity adequacy intra-OD

33

Operating Day (OD)

34

ID RUC TIMELINE

ID RUC 1ID RUC 2

ID RUC 3ID RUC 4

ID RUC 5

ID RUC 5

ID RUC 14 hr interval






ID RUC 6

ID RUC 6

DBDA RUC 0000-0300

DA Market0930-1300

DA RUC1345-1615

35

ID RUC ANALYSIS & COMMITMENT

Algorithms run with updated

inputs and cleared RT OR

RUC Operator

analysis of potential

commitments

Can the commitment

wait?

Resource(s) added to COP

1 2 3 4

Notification send to MP

5

36


Assessment (MDRA)

Day-Ahead (DA) RUC

Intra-Day (ID) RUC

Short-Term RUC (ST-RUC)

RUC STUDIES

1 2

3 4

37

PURPOSE OF ST-RUCLooks to extend or commit resource(s) that:

• Help smooth intra-hour transitions

• Reduce manual commitments

• Lower commitment of more costly resources

Designed to more frequently evaluate system conditions

38

ST-RUC PROCESS

Hour 1 Hour 2 Hour 3

Looks at 15-minute intervals over next 3 hours

00 15 30 45 00 15 30 45 00 15 30 45 00

Runs in about 10 minutes

In 3-hr. window, committed resource must:• Start up• Achieve its min. run time• Shut down

SCUC

39

Reliably operate grid; balance RT Demand and Generation

Determined by RT Offers, Load Forecast, and OR requirement

Minimizes total production costs

PURPOSE OF RTBM

40

RTBM INPUTS AND OUTPUT

40

RTBM

Resource Commitments

RT Offers

SPP OR Requirements

Approved/Tagged Inter. Trans.& DC Tie Schedules

Short-Term Load Forecast

State Estimator Data

Current Resource Output & Control Status

Manual or Auto-Activated Flowgates

Regulation-selected Resources Dispatch Instructions

Cleared Operating Reserve (OR)

RT Prices

41

Short-Term Load Forecast (10 minutes out)

System Conditions

RT Resource Data

RTBM runs/solves (interval 0105-0110)

Dispatch Instructions

RT Prices

10 MW

30 MW

0100 0105 01100110 0115

Cleared OR

42

System Conditions

RT Resource Data

RTBM runs/solves (interval 0110-0115)

Dispatch Instructions

RT Prices

25 MW

30 MW

0100 0105 01100110 0115

Cleared OR

Short-Term Load Forecast (10 minutes out)

43

Dispatch Instruction & Cleared OR

Snapshot Data

SetpointInstruction

Control Status

1

23

Market Participant / Asset Owner

Dispatch and Cleared OR

Offer Data

2

5

Indicates ability to follow Setpoint Instructions

4

44

WHAT IS CONGESTION?

• Congestion or “bottlenecks” happen when you can’t get energy to customers along a certain path• Desired electricity flows exceed physical capability

• Congestion caused by:• Lack of transmission, often due to load growth• Line and generator maintenance outages• Unplanned outages such as storms or trees on lines• Too much generation pushed to grid in a particular location• Preferred energy source located far from customers

• Results in inability to use least-cost electricity to meet demand

Flowgate

A transmission facility or transmission element(s) that has been identified as limiting the amount of power that can be reliably transferred over the bulk transmission system.

Shift Factor

A percentage that represents how much

impact an injection (e.g. from a Generator)

or withdrawal at a node causes on a flowgate.

Shadow Price47

How much it costs to reduce

flow on a flowgate

(per megawatt of flow)

Market Clearing Engine (MCE)

An optimization-based application that includes two core algorithms: SCUC and SCED.

Security Constrained Unit Commitment (SCUC)

An algorithm that determines which units are committed.

Security Constrained Economic Dispatch (SCED)

An algorithm that determines unit dispatch andLMP at each node.

Linear Programming (LP)

A mathematical optimization technique used in the Day-Ahead (DA) Market and Real-Time Balancing Market (RTBM)

to determine the dispatch of committed units.

LP Problem

52

LP P

robl

emObjective Function

Parameters to minimize or maximize

ConstraintsThings that should not be violated

Decision VariablesAdjustable parameters

MCCiMLCiMECLMPi

LMP Decomposition – Basic

Marginal cost of Energy

Marginal cost of losses at PNode irelative to Reference Bus

Marginal cost of congestion at PNode i relative to Reference Bus

MCCiMLCiMECLMPi

1. Shift Factors

Sub-component of MCC

1. Shift Factors – Defined

55

How much impact does an injection… or a withdrawal at a node…

cause on Flowgate Y?

Generator: Injection Load: Withdrawal

MCCiMLCiMECLMPi

3. Shadow Price

Sub-component of MCC

MEC is also Shadow Price of balancing power

3. Shadow Price – Defined57

How much it costs to reduce

flow on a flowgate

(per megawatt of flow)

3. Shadow Price – Illustration

Gen 1:250 Max$6/MWh

Load = 200 MW

Gen 2:250 Max

$10/MWhFlowgate YTransfer Limit = 150 MW

Total Cost: ($6 * 150MW) + ($10 * 50MW) = $1,400

150MW

50 MW

Let’s increase the transfer limit on Flowgate Y by 1 MW.

3. Shadow Price – Illustration (cont’d.)

Gen 1:250 MW$6/MWh

Load = 200 MW

Gen 2:250 MW

$10/MWhFlowgate YTransfer Limit = 151 MW151

MW49

MWWhat is the likely change in

output for Gen 1 and Gen 2?


Gen 1:250 MW$6/MWh

Load = 200 MW

Gen 2:250 MW


NEW Total Cost: ($6 * 151MW) + ($10 * 49MW) = $1,396

151MW

49 MW


Gen 1:250 MW$6/MWh

Load = 200 MW

Gen 2:250 MW


Shadow Price (SP): $1,396 - $1,400 = -$4

151MW

49 MW

3. LMP – Illustration No Congestion

Gen 1:250 Max$6/MWh

Load = 200 MW

Gen 2:250 Max

$10/MWh

Load Pays : ($6 * 200MW) = $1,800

200MW

0 MW

Gen 1: ($6 * 200MW) = $1,800 Revenue

($6 * 200MW) = $1,800 Cost

MCCiMLCiMECLMPi

LMP Decomposition – Advanced

LMPi MEC -LossSens MEC SPSFΣ

𝑳𝑳𝑳𝑳𝑳𝑳𝒊𝒊 = 𝑀𝑀𝑀𝑀𝑀𝑀 + (−𝜕𝜕(𝑆𝑆𝑆𝑆𝑆𝑆 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿)𝜕𝜕𝑆𝑆𝑖𝑖

𝑀𝑀𝑀𝑀𝑀𝑀) + (∑𝑘𝑘=1𝐾𝐾 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝐹𝐹𝐹𝐹𝐹𝐹𝑆𝑆𝐹𝐹𝐹𝐹𝑖𝑖𝑘𝑘 ∗ 𝑆𝑆𝑆𝑆𝑘𝑘)

64

DANIEL BAKERSPP RC OperationsPlease feel free to contact me at [email protected]

mailto:[email protected]

placement of facilities in spp rate zones

Documents