Market Settlements
Virtual and Financial
Schedules
(VF 201)
2011
Henry Chu
Technical WebEx Issue
Please contact
• Kevin Krasavage
• Email: kkrasavage@midwestiso.org
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1
Market Settlement Training Series
Market Settlements Training Modules:
–
–
–
–
–
–
–
Overview O101
(Feb. 2011)
ARR/FTR AF201
(Mar. 2011)
Virtual and Financial Schedules VF201 (Apr. 2011)
Physical Schedules PS201
(May 2011)
Load L201
(Jul. 2011)
Generation G201
(Aug. 2011)
Overview O101
(Sep. 2011)
2
Agenda
Morning - Virtual Schedules
Virtual Market Overview
Virtual Market Settlements
Virtual Examples
Virtual RSG Calculation Pre vs Post April 2011
Summary /Quiz
Lunch - Provided
Afternoon - Financial Schedules
Financial Bilateral Concepts
Financial Bilateral Transactions Overview
Break
Financial Schedules - Fixed
Financial Schedules - Option B
Financial Schedules - GFA Carve-Out
Financial Schedules - Pseudo Tie
Break
Financial Schedules - Charge Type Calculation
Financial Schedules - RSG Calculation
Summary
Time
10:45
11:00
11:15
11:30
12:00
12:15
12:45
13:10
13:45
14:00
14:15
14:30
14:45
15:00
15:10
15:45
16:15
3
MISO Disclaimer
The following training materials are intended for
use as training materials only and are not intended
to convey, support, prescribe or limit any market
participant activities. These materials do not act as
a governing document over any market rules or
business practices manual. The data used in the
examples is test data and should not be used to
support market analyses.
4
Key Assumptions
• This material will discuss Settlements concepts
centered on the Energy and Operating Reserves
Markets
• This is not a stakeholder meeting. The purpose of this
training is NOT to make or to debate market design
decisions, policies, or rules
• Participants will actively participate in the training by
asking constructive questions in an effort to improve
the overall learning experience
5
Virtual and Financial Schedules
Introduction
Introduction
• Both Virtual Transactions and Financial
Bilateral Transactions are financial
instruments and have no impact on the
physical flow of energy.
7
Introduction
Virtual Transactions and Financial
Bilateral Transactions are two different types
of financial instrument; therefore each type
will have its own set of Settlement charges
and is independent of each other.
8
Course Objectives
• Provide a brief overview of the attributes of
the Virtual and Financial Scheduling Systems
and their role in the MISO
• Review the charges that are impacted by
Virtual and Financial Schedules in the DayAhead and Real-Time Markets
9
Virtual Transactions
Virtual Transactions
Introduction
Virtual Market
Uncertainty
12
Virtual Market
Risk
Today
Tomorrow
13
Virtual Market
Hedge
Today
Forward
Contract
Tomorrow
14
Virtual Market
MISO Virtual Market
$40
$55
DA LMP
RT LMP
CIN HUB
CIN HUB
Today
Tomorrow
15
Virtual Market
Day Ahead
Real Time
Market
Market
$40
$ 55
DA LMP
DA LMP
CIN HUB
CIN HUB
Buy 1 MW
Sell 1 MW
$15 profit
Sell 1 MW
Buy 1 MW
$15 loss
Today
Tomorrow
16
Virtual Market
Virtual Transactions
• Outline
 Virtual Energy Market Function
 Virtual Energy Market Concepts
 Virtual Market Rules
 Virtual Market Benefits
 Virtual Positions
 Virtual Market Settlements
 Virtual Market Disputes
 Virtual Market Settlements Example
18
Virtual Market
Function of a Virtual Market
• Virtual trading tends to cause Day-Ahead prices to converge to
real-time prices, contributing to increased efficiency in the DayAhead Market.
• It provides an additional hedging mechanism for market
participants with physical loads and generation.
• Opens the wholesale electric market to more participants, ideally
increasing market stabilization and liquidity.
• The above also contribute to a reduction in the market price of
risk.
19
Virtual Market
Virtual Market Concepts
• Submission of bids, either Load or Supply, for the financial
purchase or sale of energy in the Day-Ahead Market.
• Virtual trading is undertaken by participants that do not
necessarily have physical load to serve or physical
resources to offer. These are strictly financial transactions.
• Virtual transactions established in the Day-Ahead Market
are settled in the Real-Time.
20
Virtual Market
Virtual Market Concepts
• Virtual transactions involve the purchase and/or sale of
energy only.
• Physical energy is neither supplied nor consumed.
• There is no effect on Real-Time physical energy
consumption.
• Physical commitment of generation may be required since
they are treated like physical energy in the Day-Ahead
Market.
21
Virtual Market
Virtual Market Rules – Virtual Supply Offers
• MW, at least 0.1 MW, subject to credit limits and
Independent Market Monitor (IMM) volume limits
• Location (any CPNode)
• Hours over which the Offer applies
• Offer price (the minimum price the market seller is willing
to accept for Energy sold into the Day-Ahead Energy
Market, (-$500/MWh to $1,000/MWh)
• Up to 9 (MW/Price) blocks per Virtual Supply Offer
Energy and Operating Reserve Markets Business Practices Manual BPM-002-r9 -4.4.1
22
Virtual Market
Virtual Market Rules – Virtual Demand Bids
• MW, at least 0.1 MW, subject to credit limits and
Independent Market Monitor (IMM) volume limits
• Location (any CPNode)
• Hours over which the Bids applies
• Up to 9 (MW/Price) blocks per Virtual Demand Bids
• Bid price (the maximum price the market buyer is willing to
pay for Energy purchased in the Day-Ahead Energy and
Operating Reserve Market, (positive or negative without
price caps)
Energy and Operating Reserve Markets Business Practices Manual BPM-002-r9 -4.4.1
23
Virtual Market Benefits
•
Individual Market Participant benefits:
– Hedge physical supply availability
– Hedge load uncertainty
– Arbitrage away the non-stochastic differences between
DA & RT prices
•
Market benefits:
– Enhanced liquidity
– Improved Day-Ahead/Real-Time price conversion
24
Virtual Market Position
Virtual Sale/Purchase Net Position Chart
DA > RT LMP
DA < RT LMP
DA = RT LMP
Sale
Net Credit
Net Charge
Zero
Purchase
Net Charge
Net Credit
Zero
25
Virtual Market - Settlements
Settlement:
• Cleared virtual transactions take a position at a
CPNode in the Day-Ahead and are settled at DayAhead prices at that node.
• In the Real-Time, the cleared Day-Ahead position is
automatically reversed and settled at the Real-Time
price at the node.
• Essentially, cleared Virtual Bids and Offers will pay or
be paid the difference between the Day-Ahead and
Real-time prices multiplied by the number of MW
cleared in the Day-Ahead at the relevant Commercial
Pricing Node.
• Participants can make or lose money on any
transaction.
26
Virtual Market Disputes
Possible Virtual Market Disputes:
Volume Related Disputes
1) Dead Bus
2) Marginal Bids or Offers
3) Netting Bids and Offers
Price Related Disputes
1) Combined Cycle
2) Price updates
27
Virtual Market Disputes
Volume - Dead Busses Issue:
• Virtuals at dead busses/CP Nodes will clear 0 MWs due to
power balance constraint in the power flow.
• Dead-bus logic calculates LMPs for dead CP Node locations
after the power flow solves.
• Dead-busses are created by transmission outages.
• Planned transmission outages are posted on the OASIS.
28
Virtual Market Disputes
Volume - Dead Busses Result:
• This will result in 0 MWs clearing for virtuals that
appear to be “in-the-money”.
• Virtuals submitted at single bus CP Nodes are at
risk of not clearing if the location is dead in the
model.
29
Virtual Market Disputes
Volume - Marginal Bid/Offer Issue:
• When a cleared Virtual Bid or Offer clears at exactly
the same price as the DA LMP at the node
bid/offered, the associated cleared virtual volume
can be any value up to the MW volume bid/offered
(also referred to as “partial clearing”).
30
Virtual Market Disputes
Volume – Netting Bid/Offer Issue:
• It is possible for a Market Participant (MP) to submit
both a bid and an offer at a CPNode unintentionally.
An MP wants to replace its bid with an offer. Instead
of zeroing out the bid, they submit an offer only. If
the bid/offer clears, the volume will be netted
together.
31
Virtual Market Disputes
Volume - Marginal Bid/Offer Result:
• Even though MPs think their bid/offer is “in-themoney”, they may not clear the entire virtual MW
volume of their bid/offer because their bid/offer is
the marginal one.
32
Virtual Market Disputes
Volume – Netting Bid/Offer Result:
• An MP may have unintentional results with both a
bid/offer are submitted together or updating
bid/offer incorrectly.
• MPs must submit all 24 hours of the bid or offer
again with updated values. Submission of only one
hour of data will cause the appropriate systems to
overwrite the previously submitted values for the
excluded hours to 0 MWs.
33
Virtual Market Disputes
Price - Combined Cycle Nodes Issue:
• MPs may have a virtual bid/offer at a Combined
Cycle child node but the virtual transaction would
settle at the aggregate Combined Cycle LMP and
not at the child node LMP.
34
Virtual Market Disputes
Price - Combined Cycle Nodes Result:
• The MP may believe it should have received
the Combined Cycle Child node LMP instead
of the Aggregate Unit LMP. Unfortunately,
this is not the case.
35
Virtual Market Disputes
Price - Incorrect LMP used Issue.
• Market Participant shadow settlement cleared
virtual volumes may not match because the DayAhead or Real-Time Pricing Data is not the final or
correct version.
36
Virtual Market Disputes
Price - Incorrect LMP used Result.
• Common price disputes occur when the MP
shadow system settles using preliminary instead of
final RT LMPs, which may affect associated
clearing volumes.
• Check the Market Report for the latest Posted LMP
37
Virtual Market
Virtual Day Ahead Market Settlement Charges
Virtual Related Day-Ahead Charges
Charge Type
Acronym
Type
Day-Ahead Virtual Energy Amount
DA_VIRT_EN
Energy
Day-Ahead Market Administration
Amount
DA_ADMIN
Admin
Day-Ahead Schedule 24 Allocation
Amount
DA_SCHD_24_ALC
Admin
Day-Ahead Revenue Sufficiency
Guarantee Distribution Amount
DA_RSG_DIST
Deviation
38
Virtual Market
Virtual Real Time Market Settlement Charges
Virtual Related Real-Time Charges
Charge Type
Type
Acronym
Real-Time Virtual Energy Amount RT_VIRT_EN
Energy
Real-Time Revenue Sufficiency
Guarantee 1st Pass Distribution
Amount
Deviation
RT_RSG_DIST1
Real-Time Miscellaneous Amount RT_MISC*
Distribution
Real-Time Net Inadvertent Amount RT_NI_DIST
Distribution
39
Virtual Transactions Summary
Two types of virtual transactions:
– Virtual Supply Offers
– Virtual Demand Bids
Definition:
– Offers to supply Energy or Bids to purchase Energy at
any CPNode in the Day-Ahead Energy Market
• Day-Ahead transactions that have no physical backing and
will never actually flow in Real-Time.
• There are no virtual transactions for Ancillary Services.
40
Virtual Energy Example
Virtual Example
• Market Participant A cleared 90 MW virtual supply
at Node A and cleared 10 MW virtual demand bid at
Node B.
Did MP- A make money or loose money at node A? node B?
What are all the charges related to these two transactions?
42
Virtual Market Demand Example
Real Time Market
Day Ahead Market
Struck/Cleared
Actual Load
Virtual Demand Bid
0 MW
10 MW
LMP $ 25 LMP
LMP $20/ MW
10 MW
X
$ 20.00
LMP
=
$200
Charge
(
Net to Market Participant
0
-
10MW
)x
$ 25.00
LMP
$250
=
Credit
$ 50 Credit
43
Virtual Market Supply Example
Day Ahead Market
Real Time Market
Struck/Cleared
Actual Load
Virtual Supply Offer
0 MW
90 MW
LMP $ 11 LMP
LMP $10/ MW
-90 MW
X
$ 10.00
LMP
-$900
=
Credit
(
0
Net to Market Participant
-
-90MW
)
x
$ 11.00
LMP
=
$990
$ 90 Charge
44
Day- Ahead Virtual Energy
Amount (DA_VIRT_EN)
DA_VIRTUAL_EN - Purpose
•
Day-Ahead Virtual Energy Amount (DA_VIRT_EN)
• Net charges or credits for all cleared virtual Bids and Offer
virtual energy schedules at a particular CPNODE
Who gets the
charge/credit?
Where does it go?
• Asset Owners with cleared DA virtual
energy schedules
• Asset Owners with Day Ahead Market
energy schedules
46
DA_VIRT_EN - Hierarchy
47
DA_VIRT_EN - Formula
*DA_VIRT_EN
( (
=∑ ∑
H
DA_VSCHD
x
*DA_LMP_EN
Transactions
Determinant
*DA_VSCHD
))
Formula
= ΣCPN(*Cleared Bids + *Cleared Offers)
48
DA_VIRT_EN Example
Intermediate Calculations
Determinant
Formula
=ΣTransactions [ (DA_VSCHDbuy) x (*DA_LMP_EN) ]
Purchase
$200
=ΣTransactions [ (10) x ($20) ]
=ΣTransactions [ (DA_VSCHDsell) x (*DA_LMP_EN) ]
Sale
-$900
=ΣTransactions [ (-90) x ($10) ]
DA_VIRT_EN
-$700 Credit
49
DA_VIRT_EN – Summary
• Day-Ahead Virtual Energy Amount is the credit or charge
for the net cleared bids and offers at a commercial pricing
node within the MISO footprint and are settled at the DayAhead Prices for that node.
Questions?
50
Day-Ahead Revenue Sufficiency
Guarantee Distribution Amount
(DA_RSG_DIST)
DA_RSG_DIST - Purpose
•
Day-Ahead Revenue Sufficiency Guarantee Distribution Amount
(DA_RSG_DIST)
– This charge funds the Day-Ahead Make Whole
Payments paid to the generation asset owners
– Charges load Asset Owners for a portion of the total
market-wide Make Whole Payment amount based on the
percentage of their load to the overall market load
Who gets the
charge/credit?
Where does it go?
• Asset Owners with Load, Virtual
Schedules and/or Exports
• Asset Owners with cleared Energy
Offers (via Make Whole Payment)
52
DA_RSG_DIST – Hierarchy
53
DA_RSG_DIST - Formula
*DA_RSG_DIST
((
=∑
*MISO_DA_RSG_MWP
x
DA_RSG_DIST_FCT
H
)x(-1))
Hourly MISO Day-Ahead RSG MWP Amount ($)
*MISO_DA_RSG_MWP
=
ΣMISO ( DA_RSG_MWP_HR )
Hourly Day-Ahead RSG Distribution Factor by AO (factor)
DA_RSG_DIST_FCT
=
( DA_RSG_DIST_VOLAO / MISO_DA_RSG_DIST_VOL )
= DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP
54
DA_RSG_DIST – Formula
Intermediate Calculations
Hourly Day-Ahead RSG Distribution Factor by AO (factor)
DA_RSG_DIST_FCT
=
( DA_RSG_DIST_VOL / MISO_DA_RSG_DIST_VOL )
= DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP
Determinant
Formula
= ΣAO-CN MAX { [ MAX (DA_SCHD, 0 ) - ΣTransactions ( DA_GFACOBuyer) ] , 0 }
DA_ASSET_DEMD
* IF { DA_RSG_DIST_XMPT = “Y”, THEN 0, ELSE 1 }
= ΣCN [ MAX ( DA_VSCHD, 0 ) ]
DA_VIRT_DEMD
* IF { DA_RSG_DIST_XMPT = “Y”, THEN 0, ELSE 1 }
= ΣTransactions [ MAX ( DA_PHYS_TRNS, 0 ) ]
DA_PHYS_EXP
DA_PHYS_TRNS = DA_PHYSBuyer + [ DA_PHYSSeller x (-1) ]
55
DA_RSG_DIST – Load Example
Intermediate Calculations
Determinant
Formula
= ΣAO-CN MAX { [ MAX (DA_SCHD, 0 ) - ΣTransactions ( DA_GFACOBuyer) ] , 0 }
DA_ASSET_DEMD
= ΣAO-CN MAX { [ MAX ( 0, 0 ) - ΣTransactions ( 10 ) ] , 0 }
0
= ΣCN [ MAX ( DA_VSCHD, 0 ) ]
DA_VIRT_DEMD
= ΣCN [ MAX ( 10, 0 ) ]
10
DA_RSG_DIST_FCT
=
( DA_RSG_DIST_VOL / MISO_DA_RSG_DIST_VOL )
= DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP
.00013
=
( 10 / 76577 )
56
DA_RSG_DIST – Load Example
Charge Type Calculation
*DA_RSG_DIST
((
*MISO_DA_RSG_MWP
x
DA_RSG_DIST_FCT
)x(-1))
((
-$3694
x
.00013
)x(-1))
=∑
H
$.48
=∑
H
Results in a $.48 charge for HE 18
57
DA_RSG_DIST – Summary
• The Day-Ahead Revenue Sufficiency Guarantee
Distribution Amount funds the Make Whole Payments paid
to the generation Asset Owners.
• This charge type issues a charge to Load AOs for a
portion of the total market-wide Make Whole Payment
amount based on the percentage of their Load to the
overall market Load.
• This amount is calculated hourly for an AO by multiplying
the MISO Day-Ahead RSG MWP Amount times the DayAhead RSG Distribution Factor for that AO to arrive at
their proportional share of the DA RSG MWP.
Questions?
58
Real -Time Virtual Energy Amount
(RT_VIRT_EN)
RT_VIRTUAL_EN - Purpose
• Real-Time Virtual Energy Amount (RT_VIRT_EN)
• Net charges or credits for all cleared virtual Bids and Offer
virtual energy schedules at a particular CPNODE
Who gets the
charge/credit?
Where does it go?
• Asset Owners with cleared RT virtual
energy schedules
• Asset Owners with RT Market
energy schedules
60
RT_VIRT_EN - Hierarchy
61
RT_VIRT_EN - Formula
*RT_VIRT_EN
( (
=∑ ∑
H
Transactions
Determinant
*DA_VSCHD
DA_VSCHD
x
*RT_LMP_EN
x
-1
))
Formula
= ΣCPN(*Cleared Bids + *Cleared Offers)
62
RT_VIRT_EN Example
Intermediate Calculations
Determinant
Formula
=ΣTransactions [ (DA_VSCHDbuy) x (*RT_LMP_EN) ]
Sale
-$250
=ΣTransactions [ (10) x ($25) ] * -1
=ΣTransactions [ (DA_VSCHDsell) x (*RT_LMP_EN) ]
Purchase
$990
=ΣTransactions [ (-90) x ($11) ]* -1
RT_VIRT_EN
$740 Charge
63
RT_VIRT_EN – Summary
• Real-Time Virtual Energy Amount is the reciprocal credit
or charge for the net cleared Day-Ahead bids or offers at a
commercial pricing node within MISO footprint and are
settled at Real-Time Prices at that node.
Questions?
64
Real-Time Net Inadvertent
Distribution
(RT_NI_DIST)
RT_NI_DIST - Purpose
• Real-Time Net Inadvertent Distribution (RT_NI_DIST)
• Represents daily allocation to AOs of any energy dollars that result
from the MISO BA Net Inadvertent for an Operating Day
• On an hourly basis each LBA is tasked with balancing their energy
generation supply, load, and Net Scheduled Interchange (NSI)
• The difference between the NAI and the NSI is Net Inadvertent
• Calculated by averaging the LMP from all generators in the LBA
multiplied by the volume of the Inadvertent and summing to a daily
total. This amount is allocated based on market participation using
the Net Inadvertent Distribution Factor for each AO
Who gets the
charge/credit?
Where does it come
from?
• AOs participating in the DA and RT
Energy Markets (by LBA)
• Uses energy dollars that result from
the MISO BA Net Inadvertent for an OD
66
RT_NI_DIST - Hierarchy
67
RT_NI_DIST - Formula
*RT_NI_DIST
=
*MISO_NI
x
*NI_DIST_FCT
MISO Daily Total Net Inadvertent Cost ($)
*MISO_NI
=
ΣH ( ΣMISO ( ( NAI - NSI ) x RT_GEN_BA_LMP) )
= AVG [ IF ( CPNode = Gen
Asset, RT_LMP_EN, 0 ) ]
Daily Net Inadvertent Distribution Factor by AO (factor)
*NI_DIST_FCT
= AO_MKT_VOL / MISO_MKT_VOL
= ΣH ( RT_ADMIN_VOL + DA_ADMIN_VOL )
68
RT_NI_DIST – Example
Intermediate Calculations
Determinant
Formula
= ΣH ( ΣMISO ( ( NAI - NSI ) x RT_GEN_BA_LMP) )
MISO_NI
$100
NI_DIST_FCT
= ΣH ( ΣMISO ( ( 450 - 425 ) x $4) )
= AO_MKT_VOL / MISO_MKT_VOL
.001333
= 100 / 75,000
*Note that only the MISO_NI and NI_DIST_FCT values are given on the Real-Time
Settlement Statement, not the determinants that go into the calculations. The MISO_NI
amount can be found in the Market Wide Determinants section of the Statement and the
NI_DIST_FCT value can be found in the Asset Owner Determinants section.
69
RT_NI_DIST – Example
Charge Type Calculation
*RT_NI_DIST
=
*MISO_NI
x
*NI_DIST_FCT
$0.133
=
$100
x
.001333
Results in a $.133 charge for the OD
70
RT_NI_DIST – Summary
• Real-Time Net Inadvertent Distribution represents the daily
allocation to AOs of any energy dollars that result from the
MISO BA Net Inadvertent for an Operating Day.
• The hourly energy cost of the Net Inadvertent is calculated
by averaging the LMP from all generators in the LBA
multiplied by the volume of the Inadvertent (NAI – NSI) for
that same Hour.
• The dollar impact for all hours in an OD for all the MISO
LBAs is summed and is allocated to AOs based on their
participation in the DA and RT Energy Markets for the OD
using the Net Inadvertent Distribution Factor.
Questions?
71
Real-Time Revenue Sufficiency Guarantee
First Pass Distribution Amount
(RT_RSG_DIST1)
Pre April 2011
RT_RSG_DIST1 - Purpose
• Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount (RT_RSG_DIST1)
– This charge funds the RSG Make Whole Payments paid to the
generation Asset Owners
– Charges Load Asset Owners for a portion of the total market -wide
Make Whole Payment amount based on their load differential in the
RT market
– Charges generation Asset Owners based on Real-Time deviations
from DA
– Charges Virtual Supply and Physical Schedule (In & Out, not
Through) real-time deviations from DA
Who gets the charge?
Where does it go?
• Asset Owners with additional RT
Load, Generation, Import/Export,
Virtual that have deviations from the
DA market
• Asset Owners with generation (via
Make Whole Payment)
73
RT_RSG_DIST1 – Hierarchy
74
RT_RSG_DIST1 - Formula
*RT_RSG_DIST1
(
=∑
H
*MISO_RT_RSG_DIST_RATE
x
*RT_RSG_DIST_VOL
)
Hourly MISO Real-Time RSG First Pass Distribution Rate ($/MWh)
*MISO_RT_RSG_DIST_RATE
=
(-1) x *MISO_RT_RSG_MWP /
( MAX ( *MISO_RT_RSG_DIST_VOL , MISO_RT_COMMIT_MW ) )
Hourly Real-Time RSG First Pass Distribution Volume for an AO (MWh)
*RT_RSG_DIST_VOL
=
DA_VIRT_SUPPLY + RT_NET_LOAD_IMB + PHYS_IMB_VOL +
RT_DERATE_VOL + RT_MR_VOL + RT_NET_EXE_VOL +
RT_NET_DFE_VOL
75
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly MISO Real-Time RSG First Pass Distribution Rate ($/MWh)
*MISO_RT_RSG_DIST_RATE
Determinant
(-1) x *MISO_RT_RSG_MWP /
= ( MAX ( *MISO_RT_RSG_DIST_VOL , MISO_RT_COMMIT_MW ) )
Description
*MISO_RT_RSG_MWP
Hourly MISO Real-Time RSG MWP Amount ($)
(total MISO MWP credit amount)
= ΣAO (RT_RSG_MWP_HR)
*MISO_RT_RSG_DIST_VOL
Hourly MISO Real-Time RSG First Pass Distribution Volume (MWh)
(sum of all AO deviations for all of the MISO)
= ΣAO (RT_RSG_DIST_VOL)
MISO_RT_COMMIT_MW
Hourly MISO Real-Time RSG Committed MW (MWh)
= ΣGen_Assets { IF [ (RT_RSG_ELIGIBILITY = “Y”) , THEN RT_MAX_DSP , ELSE 0 ] }
76
RT_RSG_DIST1 – Formula
Intermediate Calculations
*RT_RSG_DIST_VOL
Determinant
Hourly Real-Time RSG First Pass Distribution Volume for an AO (MWh)
DA_VIRT_SUPPLY + RT_NET_LOAD_IMB + PHYS_IMB_VOL +
RT_DERATE_VOL + RT_MR_VOL + RT_NET_EXE_VOL +
RT_NET_DFE_VOL
=
Description
DA_VIRT_SUPPLY
Hourly Day-Ahead Net Cleared Virtual Supply Volume (MWh)
= ΣAO-Schedules { ABS [ MIN ( DA_VSCHD , 0 ) ] }
RT_NET_LOAD_IMB
Hourly Real-Time Net Load Schedule Imbalance (MWh)
= ΣAO-Asset (ABS (RT_LOAD_IMB) x (1 - RT_CO_LOAD_PCT) x IF (DEV_EXEMPT = “Y”,
THEN 0, ELSE 1))
= ΣAO-Asset (RT_BLL_MTR - RT_ADJ_MTR - DA_SCHDLoad - D1_NI_PBK)
PHYS_IMB_VOL
Hourly Real-Time Physical Transaction Deviation (MWh)
= ΣAO-Phys-Transactions { ABS [ (RT_PHYSBuyer - RT_PHYSSeller) - (DA_PHYSBuyer - DA_PHYSSeller) ] }
RT_DERATE_VOL
Hourly AO Real-Time Derate Volume Deviation (MWh)
= ΣAO-Gen [ ABS( MIN { 0, IF [ EEEF = “Y”, THEN 0, ELSE (DA_SCHDGEN + RT_MAX_DSP)
x (1 – RT_CO_GEN_PCT) ] } )
RT_MR_VOL
Hourly AO Real-Time Must-Run Volume Deviation (MWh)
= ΣAO-Gen MAX [ 0, IF { EEEF = “Y”, THEN 0, ELSE IF[ RT_RSG_ELIGIBILITY = “Y”, THEN
0, ELSE (DA_SCHDGEN + RT_MIN_DSP) x (1 - RT_CO_GEN_PCT) ] } ]
RT_NET_EXE_VOL
Hourly Net Excessive Resource Energy Volume (MWh) for an AO at a CPNode
= ΣCN { IF [ EEEF = “Y”, THEN 0, ELSE EXE x (1 - RT_CO_GEN_PCT) ] }
RT_NET_DFE_VOL
Hourly Net Deficient Resource Energy Volume (MWh) for an AO at a CPNode
= ΣCN { IF [ EEEF = “Y”, THEN 0, ELSE DFE x (1 - RT_CO_GEN_PCT) ] }
77
RT_RSG_DIST1 – Formula
Intermediate Calculations
*RT_RSG_DIST_VOL
Determinant
Hourly Real-Time RSG First Pass Distribution Volume for an AO (MWh)
DA_VIRT_SUPPLY + RT_NET_LOAD_IMB + PHYS_IMB_VOL +
RT_DERATE_VOL + RT_MR_VOL + RT_NET_EXE_VOL +
RT_NET_DFE_VOL
=
Description
DA_VIRT_SUPPLY
Hourly ABDay-Ahead Net Cleared Virtual Supply Volume (MWh)
DA_VIRT_SUPPLY
= ΣAO-Schedules { ABS [ MIN ( DA_VSCHD , 0 ) ] }
= 90 MW
78
RT_RSG_DIST1 – Load Example
Charge Type Calculation
*RT_RSG_DIST1
H
$202.63
(
*MISO_RT_RSG_DIST_RATE
x
*RT_RSG_DIST_VOL
)
(
$2.2514
x
90 MW
)
=∑
=∑
H
Results in a $202.63 charge for HE 1
79
RT_RSG_DIST1 – Rate Info
• The Revenue Sufficiency Guarantee Report and RSG
Metrics provide MPs with historical RSG information such
as market totals and hourly RSG Distribution Rates.
• These reports can be found on the MISO website at:
https://www.misoenergy.org/Library/MarketReports/Pages/MarketReports.as
px
80
RT_RSG_DIST1 – Summary
• The Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount funds the RSG Make Whole
Payments paid to the generation Asset Owners
• This charge type issues a charge to AOs for the total
market-wide Make Whole Payment amount based on
Real-Time Load, Generation, Virtual Supply and Physical
Bilateral Transaction deviations from DA
• This amount is calculated hourly for an AO by multiplying
the MISO Real-Time RSG First Pass Distribution Rate
times the Real-Time RSG First Pass Distribution Volume
for that AO
Questions?
81
Real-Time Revenue Sufficiency
Guarantee First Pass Distribution Amount
(RT_RSG_DIST1)
Post April 2011
RT_RSG_DIST1 - Purpose
• Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount (RT_RSG_DIST1)
• This charge funds the RSG Make Whole Payments paid to the generation
Asset Owners
• Charges Asset Owner’s assets and schedules with an adverse impact on
a constraint based on the amount of deviation and the Constraint
Contribution Factor (CCF) for the Active Transmission Constraint
• Charges Asset Owner’s sum total of asset-related deviations and demand
changes which are deemed to be a cause for Real-Time RAC generation
commitments
Who gets the
charge/credit?
• Asset Owners with assets and
schedules which adversely impact
Constraints and deviations and
demand changes resulting in
commitments
Where does it go?
• Asset Owners with generation (via
Make Whole Payment)
83
RT_RSG_DIST1
Commonly Used Acronyms
AO
Asset Owner
ATC
Active Transmission Constraints
CCF
Constraint Contribution Factor
CMC
Constraint Management Charge
DDC
Day-Ahead Deviation & Headroom Charge
MP
Market Participant
NDL
Notification Deadline
RAC
Reliability Assessment Commitment
84
RT_RSG_DIST1 – Hierarchy
85
RT_RSG_DIST1 - Formula
*RT_RSG_DIST1
(
=∑
H
*RT_RSG_DIST1_HR
)
Hourly Real-Time RSG Distribution Amount
*RT_RSG_DIST1_HR
=
CMC_DIST + DDC_DIST
86
RT_RSG_DIST1
CMC_DEV_VOL =
NDL Dev
RT Dev
DDC_DEV_VOL =
CMC_NDL_ VOL
DDC_NDL_ VOL
+
+
CMC_RT_VOL
DDC_ RT_VOL
87
RT_RSG_DIST1
CMC_DEV_VOL =
NDL Dev
CMC_NDL_ VOL
+
RT Dev
CMC_RT_VOL
Sum of All +/- Deviation X CCF
Net Positive Total is added to RT Dev.
+ +
++
Sum of all Positive (Deviation x CCF)
88
RT_RSG_DIST1
DDC_DEV_VOL =
NDL Dev
Sum of All +/- Deviation
Net Positive Total is added to RT Dev
+
Sum of all MAX(NDL Deviation,0 ) or
RT Dev
ABS( RT Deviation)
DDC_NDL_ VOL
+
DDC_ RT_VOL
89
RT _RSG_DIST1
CMC1
CMC2
DDC
CMC4
CMC3
CMC_DEV_VOL is for individual constraints
DDC_DEV_VOL is for whole MISO constraints
90
RT_RSG_DIST1 – Hierarchy
91
RT_RSG_DIST1
Constraint Management Charge Distribution Calculation (CMC_DIST)
• Funds Real-Time RSG MWP amount credits paid to units committed
in the RAC to manage Active Transmission Constraints (ATCs).
• AO’s assets and schedules with an adverse impact on a constraint
are charged based on the amount of deviation and the Constraint
Contribution Factor for the ATC.
• Calculates deviations from the Day-Ahead to the Notification
Deadline.
• Calculates deviations from the Notification Deadline to the RealTime.
92
RT_RSG_DIST1 – Formula
Intermediate Calculations
Constraint Management Charge Distribution
ATC
*CMC_DIST
=
ATC_CMC_DIST_HR
=
Σ (ATC_CMC_DIST_HR)
Hourly Constraint Management Distribution
(CMC_DEV_VOL * ATC_CMC_RATE)
93
RT_RSG_DIST1 – Formula
Intermediate Calculations
*CMC_DEV_VOL
Hourly Active Transmission Constraint Management Charge Deviation Volume
= MAX ( CMC_NDL_MR_VOL + CMC_NDL_DR_VOL + CMC_NDL_LOAD_VOL +
CMC_NDL_VIRT_VOL + CMC_NDL_PHYS_IMP_VOL + CMC_NDL_PHYS_EXP_VOL
+ CMC_NDL_FIN_VOL + CMC_NDL_DRR1_VOL + CMC_NDL_NDSP_VOL, 0 ) +
CMC_RT_MR_VOL + CMC_RT_DR_VOL + CMC_RT_EXE_DFE_VOL +
CMC_RT_LOAD_VOL + CMC_RT_PHYS_IMP_VOL + CMC_RT_PHYS_EXP_VOL +
CMC_RT_DRR1_VOL + CMC_RT_NDSP_VOL
Determinant
Description
Hourly Constraint Management Charge Notification Deadline Virtual Transaction Imbalance
Volume (MWh);
CMC_NDL_VIRT_VOL
= ( DA_VSCHDSeller +
DA_VSCHDBuyer ) * CCF *-1
The – 1 is added per FERC Order
94
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly Active Transmission Constraint Management Charge Rate ($/MWh)
*ATC_CMC_RATE
= ATC_CMC_MWP / MAX ( ATC_CMC_DEV_VOL +
ATC_CMC_TA_TDR_VOL, ATC_CMC_MAX_DSP_VOL )
Determinant
ATC_CMC_MWP
Description
Hourly Active Transmission Constraint Management Charge MWP ($)
= ∑ATC ( IF CANCEL_FL = ‘Y’ THEN 0 ELSE ( RT_RSG_ASSET_CR_HR*( -1 ) )* ( MIN (
CCF,0 ) * -1 ) )
ATC_CMC_DEV_VOL
Hourly Active Transmission Constraint Management Charge Deviation Volume (MWh)
ATC_CMC_TA_TDR_VOL
Hourly Active Transmission Constraint Management Charge Topology
Adjustment/Transmission De-rate Volume (MWh)
= ∑ ATC ( CMC_DEV_VOL)
Represents the total Megawatt volume of Topology Adjustments or
Transmission De-rates for a given Active Transmission Constraint.
ATC_CMC_MAX_DSP_VOL
Hourly Active Transmission Constraint Management Charge Maximum Dispatch Volume
(MWh)
= ∑ RAC_ATC ( RT_MAX_DSP * ( MIN ( CCF, 0 ) * -1 ) )
95
RT_RSG_DIST1 – Example
• Market Participant A cleared 90 MW virtual supply at
Node A and cleared 10 MW virtual demand bid at Node B.
• The Constraint Contribution Factor is -.5 for both A and B
• The ATC_CMC_RATE is $3.89
• What is the CMC_DIST?
96
RT_RSG_DIST1 – Formula
Intermediate Calculations
DA
NDL
DA_VSCHDNode A Seller = 0
DA
Deviation
DA_VSCHDNode A Seller = -90 * -1
-90
NDL
DA_VSCHDNode B Buyer = 10
DA_VSCHDNode B Buyer = 0
10
DA_VSCHDSeller = -90
Impact 90 decreased (Short) in Supply – Negative Dev. Impact
DA_VSCHDBuyer = 10
Impact 10 increased (Long) in Supply – Positive Dev. Impact
CCF
CCF = -.5
Positive
Hurt if Increased Supply, Help if Decreased Supply
Negative
Help if Increased Supply, Hurt if Decreased Supply
97
RT_RSG_DIST1 – Formula
Intermediate Calculations
*CMC_DEV_VOL
Hourly Active Transmission Constraint Management Charge Deviation Volume
= MAX ( CMC_NDL_MR_VOL + CMC_NDL_DR_VOL + CMC_NDL_LOAD_VOL +
CMC_NDL_VIRT_VOL + CMC_NDL_PHYS_IMP_VOL + CMC_NDL_PHYS_EXP_VOL
+ CMC_NDL_FIN_VOL + CMC_NDL_DRR1_VOL + CMC_NDL_NDSP_VOL, 0 ) +
CMC_RT_MR_VOL + CMC_RT_DR_VOL + CMC_RT_EXE_DFE_VOL +
CMC_RT_LOAD_VOL + CMC_RT_PHYS_IMP_VOL + CMC_RT_PHYS_EXP_VOL +
CMC_RT_DRR1_VOL + CMC_RT_NDSP_VOL
Determinant
Description
Hourly Constraint Management Charge Notification Deadline Virtual Transaction Imbalance
Volume (MWh);
CMC_NDL_VIRT_VOL
-40
= ( DA_VSCHDNode A Seller ) * CCF + ( DA_VSCHDNode B Buyer ) *
CCF
= ( -90 + 10 ) * - .5 *-1
Because the CCF is negative -.5 , the impact of CMC
deviation is only half of the 80.
98
RT_RSG_DIST1 – Formula
Intermediate Calculations
*CMC_DEV_VOL
*CMC_DEV_VOL
*CMC_DEV_VOL
Hourly Active Transmission Constraint Management Charge Deviation Volume
= MAX ( CMC_NDL_MR_VOL + CMC_NDL_DR_VOL + CMC_NDL_LOAD_VOL +
CMC_NDL_VIRT_VOL + CMC_NDL_PHYS_IMP_VOL + CMC_NDL_PHYS_EXP_VOL
+ CMC_NDL_FIN_VOL + CMC_NDL_DRR1_VOL + CMC_NDL_NDSP_VOL, 0 ) +
CMC_RT_MR_VOL + CMC_RT_DR_VOL + CMC_RT_EXE_DFE_VOL +
CMC_RT_LOAD_VOL + CMC_RT_PHYS_IMP_VOL + CMC_RT_PHYS_EXP_VOL +
CMC_RT_DRR1_VOL + CMC_RT_NDSP_VOL
= MAX ( 0 + 0 + 0 + 0+ -40 + 0 + 0 + 0, 0 ) + 0 + 0 + 0 + 0 + 0+ 0 +
0+0
=
0 MW
99
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly Constraint Management Distribution
ATC_CMC_DIST_HR
=
(CMC_DEV_VOL * ATC_CMC_RATE)
ATC_CMC_DIST_HR
=
(0 * 3.89)
ATC_CMC_DIST_HR
=
$ 155.60
100
RT_RSG_DIST1 – Formula
Intermediate Calculations
Constraint Management Charge Distribution
*CMC_DIST
*CMC_DIST
=Σ
=
ATC
(ATC_CMC_DIST_HR)
$0
* Note – This example has only one Constraint.
101
RT_RSG_DIST1 – Hierarchy
102
RT_RSG_DIST1
Day-Ahead Deviation and Headroom Charge Distribution
Calculation (DDC_DIST)
• Charges Asset Owners for asset-related deviations and
demand changes for RAC-Committed Resources.
• Calculates deviations from Day-Ahead to the
Notification Deadline.
• Calculates deviations from the Notification Deadline to
Real-Time.
103
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly Day-Ahead Deviation and Headroom Charge Distribution
Amount ($)
*DDC_DIST
= DDC_DEV_VOL * MISO_DDC_RATE
104
RT_RSG_DIST1 – Formula
Intermediate Calculations
*DDC_DEV_VOL
Determinant
DDC_NDL_VIRT_VOL
Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
= MAX ( DDC_NDL_CAP_VOL + DDC_NDL_LOAD_VOL +
DDC_NDL_PHYS_IMP_VOL + DDC_NDL_PHYS_EXP_VOL + DDC_NDL_VIRT_VOL +
DDC_NDL_FIN_VOL + DDC_NDL_DRR1_VOL + DDC_NDL_NDSP_VOL, 0 ) +
DDC_RAC_DR_VOL + DDC_RAC_MR_VOL + DDC_RT_DR_VOL + DDC_RT_MR_VOL
+ DDC_RT_EXE_DFE_VOL + DDC_RT_LOAD_VOL + DDC_RT_PHYS_IMP_VOL +
DDC_RT_PHYS_EXP_VOL + DDC_RT_DRR1_VOL + DDC_RT_NDSP_VOL
Description
Hourly Day-Ahead Deviation and Headroom Charge Notification Deadline
Virtual Volume (MWh);
= ( DA_VSCHDSeller + DA_VSCHDBuyer ) * -1
105
RT_RSG_DIST1 – Example
• Market Participant A cleared 90 MW virtual supply
at Node A and cleared 10 MW virtual demand bid at
Node B.
• The MISO_DDC_RATE is $1.56
• What is the DDC_DIST?
106
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly MISO Day-Ahead Deviation and Headroom Charge Rate ($/MWh)
*MISO_DDC_RATE
= ( MISO_RT_RSG_MWP – MISO_CMC_DIST –
MISO_CMC_TA_TDR_DIST ) / MAX { MISO_DDC_DEV_VOL +
MIN ( HEADROOM , MISO_RAC_MAX_DSP_VOL ) ,
(MISO_RAC_MAX_DSP_VOL - MISO_CMC_MAX_DSP_VOL)}
Determinant
*MISO_RT_RSG_MWP
Description
Hourly MISO Real-Time RSG MWPs Total Amount ($)
=∑ MISO RAC ( IF CANCEL_FL = ‘Y’ THEN 0 ELSE RT_RSG_ASSET_CR_HR * ( -1 ) )
*MISO_CMC_DIST
Hourly MISO Constraint Management Charge Distribution Amount ($)
*MISO_CMC_TA_TDR_DIST
Hourly MISO Constraint Management Charge Topology Adjustment/Transmission De-rate
Charge Distribution Amount ($)
= ∑ MISO ATC ( CMC_DIST_HR )
= ∑MISO ATC ( ATC_CMC_TA_TDR_DIST )
*MISO_DDC_DEV_VOL
Hourly MISO Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
= ∑AO ( DDC_DEV_VOL )
107
RT_RSG_DIST1 – Formula
Intermediate Calculations
Determinant
Description
*HEADROOM
Hourly Headroom Volume (MWh)
*MISO_RAC_MAX_DSP_VOL
Hourly MISO RAC Maximum Disptach Volume (MWh)
*MISO_CMC_MAX_DSP_VO
L
Hourly MISO Constraint Management Charge Maximum Dispatch Volume (MWh)
= ∑MISO ( RT_MAX_DSP – [ -1 * AEI ] )
= ∑ MISO RAC ( RT_MAX_DSP )
= ∑ RAC_ATC ( RT_MAX_DSP * ( MIN ( CCF, 0 ) * -1 ) )
108
RT_RSG_DIST1 – Formula
Intermediate Calculations
*DDC_DEV_VOL
Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
= MAX ( DDC_NDL_CAP_VOL + DDC_NDL_LOAD_VOL +
DDC_NDL_PHYS_IMP_VOL + DDC_NDL_PHYS_EXP_VOL + DDC_NDL_VIRT_VOL +
DDC_NDL_FIN_VOL + DDC_NDL_DRR1_VOL + DDC_NDL_NDSP_VOL, 0 ) +
DDC_RAC_DR_VOL + DDC_RAC_MR_VOL + DDC_RT_DR_VOL + DDC_RT_MR_VOL
+ DDC_RT_EXE_DFE_VOL + DDC_RT_LOAD_VOL + DDC_RT_PHYS_IMP_VOL +
DDC_RT_PHYS_EXP_VOL + DDC_RT_DRR1_VOL + DDC_RT_NDSP_VOL
Determinant
DDC_NDL_VIRT_VOL
Description
Hourly Day-Ahead Deviation and Headroom Charge Notification Deadline
Virtual Volume (MWh);
= ( DA_VSCHDSeller + DA_VSCHDBuyer ) * -1
= ( -90 + 10) * -1
80
109
RT_RSG_DIST1 – Formula
Intermediate Calculations
*DDC_DEV_VOL
Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
= MAX ( DDC_NDL_CAP_VOL + DDC_NDL_LOAD_VOL +
DDC_NDL_PHYS_IMP_VOL + DDC_NDL_PHYS_EXP_VOL + DDC_NDL_VIRT_VOL +
DDC_NDL_FIN_VOL + DDC_NDL_DRR1_VOL + DDC_NDL_NDSP_VOL, 0 ) +
DDC_RAC_DR_VOL + DDC_RAC_MR_VOL + DDC_RT_DR_VOL + DDC_RT_MR_VOL
+ DDC_RT_EXE_DFE_VOL + DDC_RT_LOAD_VOL + DDC_RT_PHYS_IMP_VOL +
DDC_RT_PHYS_EXP_VOL + DDC_RT_DRR1_VOL + DDC_RT_NDSP_VOL
Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
MAX (0 + 0 + 0 + 0 + 80 + 0 + 0 + 0, 0 ) + 0 + 0 + 0 + 0 + 0 + 0 + 0 +
0+0+0
=
*DDC_DEV_VOL
*DDC_DEV_VOL
= 80 MW
110
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly Day-Ahead Deviation and Headroom Charge Distribution Amount ($)
*DDC_DIST
= DDC_DEV_VOL * MISO_DDC_RATE
Assume the MISO_DDC_RATE = $1.56
Hourly Day-Ahead Deviation and Headroom Charge Distribution Amount ($)
*DDC_DIST
= 80 MW * $1.56
*DDC_DIST
= $124.8
111
RT_RSG_DIST1 – Hierarchy
112
RT_RSG_DIST1 - Formula
Hourly Real-Time RSG Distribution Amount
*RT_RSG_DIST1_HR
=
CMC_DIST + DDC_DIST
Hourly Real-Time RSG Distribution Amount
*RT_RSG_DIST1_HR
=
$124.8
*RT_RSG_DIST1_HR
=
$124.8
113
RT_RSG_DIST1 - Formula
*RT_RSG_DIST1
H
$124.8
(
=∑
(
=∑
H
*RT_RSG_DIST1_HR
$124.8
)
)
Results in a $124.8 charge for HE 1
114
RT_RSG_DIST1 – Summary
• The Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount funds the RSG Make Whole
Payments paid to the generation asset owners.
• This amount is calculated hourly for an AO by adding the
Constraint Management Charge Distribution Amount and
the Day-Ahead Deviation and Headroom Charge
Distribution Amount.
Questions?
115
Pre vs. Post April Virtual RSG
Summary
Pre- April 2011
• Only Virtual Supply volume is used
• Settled at the individual CPNode
• Set RSG rate for every CPNode
Post –April 2011
•
•
•
•
•
Both Virtual Supply and Offer are used
Netting of Volume across Asset Owner CPNodes before NDL
Different Rates for each Active Transmission Constraint
Two distribution buckets - CMC and DCC
New concept of Constraint Contribution Factor (CCF)
116
Virtual Charge Summary
Day Ahead Virtual Charges
Rates
Day-Ahead Virtual Energy Amount
DA_VIRT_EN
Day-Ahead Market Administration
Amount
DA_ADMIN
Day-Ahead Schedule 24 Allocation DA_SCHD_24_AL
Amount
C
Day-Ahead Revenue Sufficiency
Guarantee Distribution Amount
Total Credit
Volume
-Credit/+Charge
-700.00
0.0959
100
9.59
0.0116
100
1.16
DA_RSG_DIST
0.0001306 $ 3,694.00
0.48
$
(688.77)
117
Virtual Charge Summary
Real Time Virtual Charges
Rates
Real-Time Virtual Energy Amount
RT_VIRT_EN
Real-Time Revenue Sufficiency
Guarantee 1st Pass Distribution
Amount
RT_RSG_DIST1
Post -April 2011
Real-Time Miscellaneous Amount
RT_MISC*
Volume
-Credit/+Charge
740.00
124.8
0
0
1000
1.33
Real-Time Net Inadvertent Amount RT_NI_DIST
0.00133
Total Charge
$866.13
118
Virtual Charge Summary
Net Profit/Loss – Post April 2011
Day Ahead
Real Time
Net Loss
- 688.77
866.13
$ 177.36
119
Virtual Charge Summary
Questions?
120
Quiz
Virtual Schedule Quiz
Question 1
Day Ahead Virtual Schedules may set the LMP.
a) True,
b) False,
c) Maybe, Why?
122
Virtual Schedule Quiz
Question 2
Which charge(s) is not related to Day Ahead
Virtuals ?
a)
b)
c)
d)
DA_ADMIN,
DA_VIRTUAL_EN
DA_SCHD_24_ALC
DA_RSG_MWP
123
Virtual Schedule Quiz
Question 3
Which statement(s) is not true related to Day Ahead
Virtuals offers?
a)
b)
c)
d)
MW, at least 1.0 MW
Location (any CPNode)
Hours over which the Offer applies
Up to 9 (MW/Price) blocks per Virtual Supply Offer
124
Virtual Schedule Quiz
Question 4
Submitting a Virtual Offer at a Dead Bus, which statement
is true?
a)
b)
c)
d)
0 MW clears
MW cleared would depend on the offer price
All MW requested clears
None of the above
125
Virtual Schedule Quiz
Question 5
Which Real Time charge(s) is not related to
Virtuals ?
a)
b)
c)
d)
RT_ADMIN
RT_VIRT_EN
RT_NI_DIST
RT_RSG_DIST1
126
Virtual Schedule Quiz
Question 6
How are Day Ahead Virtuals funded?
a)
b)
c)
d)
RT_ADMIN
Real Time Market Participants
Net Virtual Buyer or Seller
Day Ahead Market Participants
127
Virtual Schedule Quiz
Question 7
Can Real Time Virtuals set LMP?
a) Yes
b) No
c) Maybe
128
Virtual Schedule Quiz
Question 8
What type of Virtuals volume are allocated
RT_RSG_DIST1 charge?
a)
b)
c)
d)
Virtual Offer
Virtual Supply
Both
None
129
Virtual Schedule Quiz
Question 9
Which Statement is true regarding Virtual Market?
a) The Day Ahead LMP is usually more than the Real
time LMP
b) A Virtual schedule is a riskless transaction since it is
purely financial
c) Virtual only risk is the difference between Day Ahead
and Real Time LMP
d) None of the above
130
Virtual Schedule Quiz
Question 10
Which of the following is not a Virtual
Demand Bids characteristic?
a)
b)
c)
d)
MW, at least 0.1 MW
Up to 9 (MW/Price) blocks
No price cap
Limit to (-$500/MWh to $1,000/MWh)
131
Questions ?
132
After Lunch
Financial Schedules
133
Afternoon - Financial Schedules
Financial Bilateral Concepts
Financial Bilateral Transactions Overview
Break
Financial Schedules - Fixed
Financial Schedules - Option B
Financial Schedules - GFA Carve-Out
Financial Schedules - Pseudo Tie
Break
Financial Schedules - Charge Type Calculation
Financial Schedules - RSG Calculation
Summary
Time
12:45
13:10
13:45
14:00
14:15
14:30
14:45
15:00
15:10
15:45
16:15
134
Financial Bilateral Transactions
Introduction
Commonly Used Acronyms
MP
AO
OD
CPNode
LMP
FSS
PSS
FBT
PBT
IBS
GFA
TUC
Market Participant
Asset Owner
Operating Day
Commercial Pricing Node
Locational Marginal Price
Financial Scheduling System
Physical Scheduling System
Financial Bilateral Transaction
Physical Bilateral Transaction
Internal Bilateral Financial Schedule
Grandfathered Agreement
Transmission Usage Charge
136
Financial Schedule Transactions
Concept
Introduction
• Virtual Schedules deal with Time .
• Day Ahead LMP vs. Real Time LMP
• Financial Schedules deal with Location and/or
Time.
• Bilateral Price vs. Market Price
138
Introduction
Bilateral Price vs. Market Price
Buyers or Sellers may want to reduce any perceived Market
Price uncertainty by entering into bilateral agreements to lock in
the energy cost over a period of time. This agreements is done
outside the MISO markets.
139
Introduction
Gasoline Prices
$3.74
$3.98
$3.94
$3.89
$3.78
$3.79
140
Introduction
MISO RT LMP
$32.17
$32.89
$31.9
$28.51
$3.79
141
Financial/Internal Bilateral
Transaction
Purpose:
Transfer of the financial responsibility for
Energy (not the physical flow of Energy)
between buyers and sellers within and across
the Market footprint.
FBT Concept
142
Financial Bilateral Transactions
Overview
Delivery
Point Node
Seller
Source
Node
Sink
Node
Buyer
In Financial Bilateral Transactions, there are two counterparties: Buyer (Sink)
and Seller (Source). In addition, there is a delivery point somewhere between
the Source and Sink Nodes.
The Energy charge is settled between the counterparties outside of MISO.
Financial Bilateral Transactions are subject to Congestion and Losses in
MISO
•The Seller pays Congestion and Losses from Source to Delivery Point
•The Buyer pays Congestion and Losses from Delivery Point to Sink
FBT Concept
143
Financial Bilateral Transactions
Overview
Delivery Point
Node
Seller
Source
Node
Sink
Node
Buyer
The Source and Delivery Point Nodes could be the same, making
the Buyer financially responsible for all congestion and loss charges
Delivery Point
Node
Seller
Source
Node
Sink
Node
Buyer
If the Sink and Delivery Point Nodes are the same, the Seller is
financially responsible for all congestion and loss charges
FBT Concept
144
Bilateral Transaction
Example
Indianapolis Juice Incorporated wants to buy Oranges Juice
for its production.
Option 1. Buy them from the Local Wholesaler
Option 2. Buy them from a different Wholesaler in
different city and ship to Indianapolis
a
Option 3. Buy them from a Farmer in Florida and
ship them to Indianapolis and determine who
pays for the shipping cost
FBT Concept
145
Orange Juice
• The Orange Juice price is set at the FCOJ contract is
available for trade on the New York Board of Trade
(NYBOT). The Price of OJ is the same everywhere.
Transportation cost is based on the gasoline price and the
distance travel.
• The energy price component at MISO is same at any one
time for any location within MISO. The congestion and loss
component will determine the price difference between the
source and sink ( transmission cost).
FBT Concept
146
Option 1
Buy from the Local Wholesaler
The Local Wholesaler price reflects the Market
price for OJ and the delivery cost of the Oranges.
The Load within the MISO could buy Energy
from its Wholesaler ( MISO) at the LMP –
Locational Marginal Price
FBT Concept
147
Option 2
• Buy from a different Wholesaler in
a different city
(example Cincinnati) and ship the OJ to Indy.
• No advantage to buy from the same wholesaler and pay the
same ship cost, because the total cost would be the same.
• If you can buy the OJ from another wholesaler below market
price and ship it to Indianapolis, why would other wholesaler
be willing to sell below market price? The wholesaler is not
the final user and would have too much OJ.
148
FBT Concept
Option 2
• Delivery point not at the source.
• Since oranges are not grown in Cincinnati, the
wholesaler has to move them there.
Source - Florida
Delivery Point Cincinnati
Sink - Indianapolis
FBT Concept
149
Option 2
• This is true for a Load within the MISO
• There is NO advantage to buying from the MISO and paying
for Congestion and Losses to move the energy to Indy,
because the total cost would be the same.
• But if you could buy the Energy from a Marketer or generator
below forecasted market price at CIN HUB and ship it to
Indianapolis, then it would be beneficial.
•
Why would a marketer be willing to sell below the market
price? The marketer is not the final user and may have too
much energy, perhaps due to long term contracts where he
bought it cheaper and to lock in the price.
150
FBT Concept
Option 2
Delivery Point Node
– CIN Hub
Seller
Source
Node
Sink
Node
Buyer - Indy
In Financial Bilateral Transactions, there are two counterparties: Buyer (Sink)
and Seller (Source). In addition, there is a delivery point somewhere between
the Source and Sink Nodes.
The Energy charge is settled between the counterparties outside of MISO.
Financial Bilateral Transactions are subject to Congestion and Losses in
MISO
•The Seller pays Congestion and Losses from Source to Delivery Point
•The Buyer pays Congestion and Losses from Delivery Point to Sink
FBT Concept
151
Option 3
• Buy from an Orange Juice Cooperative in Florida
and ship them to Indianapolis.
• No advantage buying from the Indy wholesaler and paying
the same shipping cost, because the total cost would be
the same if he bought in Indy.
• If you could buy the Orange Juice from a Florida Orange
Juice Cooperative below market price and ship it to
Indianapolis, that would also be beneficial.
• Why would the OJ Co-op be willing to sell below market
price? The OJ Co-op is not the final user and may be
willing to get a little less for price certainty.
FBT Concept
152
Option 3
• Orange Juice Cooperative could sell the OJ in Florida and
Indianapolis Juice Inc. would pay for the shipping. Or
• Orange Juice Cooperative could sell the OJ in Florida and
also pays for the shipping to Indy .
Source - Florida
Sink - Indianapolis
Delivery Point
Delivery Point –
Florida
Indianapolis
FBT Concept
153
Option 3
• Buy from an Orange Juice Cooperative in Florida
and ship to Indianapolis.
• Although the transportation company charges the same
rate regardless of who pays for the shipping. The shipping
cost can change from day to day due to changes in the
gasoline price.
Either the Buyer or the Seller has to take the price risk
of the transportation cost.
FBT Concept
154
Energy Financial Bilateral
Transactions
Delivery Point
Node
Seller
Source
Node
Sink
Node
Buyer
The Source and Delivery Point Nodes could be the same, making
the Buyer financially responsible for all congestion and loss charges
Delivery Point
Node
Seller
Source
Node
Sink
Node
Buyer
If the Sink and Delivery Point Nodes are the same, the Seller is
financially responsible for all congestion and loss charges
FBT Concept
155
Energy Financial Bilateral
Transactions
• The price for the Congestion charge is determined by the
difference between the Marginal Congestion Component (MCC)
(of the LMP) between the source and sink nodes
• The price for the Loss charge is determined by the difference
between the Marginal Loss Component (MLC) (of the LMP)
between the source and sink nodes
• These can be positive or negative.
• Financial Bilateral Transaction Congestion and Loss charges are
settled in the Day-Ahead Market as well as in the Real-Time
Market
FBT Concept
156
Energy Financial Bilateral
Transactions Summary
• MISO is like the local
transportation company.
wholesaler
and
• The cost of the energy could be settled outside
of the market but the congestion and losses are
settled in the market and either the buyer or the
seller has to pay for them.
FBT Concept
157
Financial Bilateral Transactions
Summary
The Day-Ahead Market congestion component of the
cost could be hedged by buying a Financial
Transmission Right between the source and sink.
The FTR is like a long-term contract with the
transportation company for scheduled delivery and
pick up for a fixed amount. It does not cover last
minute pick-up and delivery just like an FTR does
cover Real-Time Congestion costs.
FBT Concept
158
Questions ?
FBT Concept
159
Financial Bilateral Transactions
Overview
Internal Bilateral Transactions
External Bilateral Transaction (EBT)
• Transactions that transfer physical energy
• Classified as Import, Export, Through, or
Grandfathered Agreement (GFA) Schedules
Internal Bilateral Transaction (IBT)
• Transactions that transfer financial responsibility
for energy within and across market footprint
• Must specify delivery point, source and sink
points, MW quantity, and time period
FBT Overview
161
Internal Bilateral Transactions
Two different systems used to capture Internal
Bilateral Transactions:
 Financial Scheduling System (FSS)
 Physical Scheduling System (PSS)
FBT Overview
162
FBT Overview
163
Financial Bilateral Transactions
Overview
• Financial Bilateral Transactions are created in the
Market Portal. They are comprised of two parts:
I. Financial Contract
II. Financial Schedule
FBT Overview
164
Financial Bilateral Transactions
Overview
• A Financial Contract is the agreement between
a buyer and a seller stating the duration of the
contract and the responsible party for the
congestion and loss between the source, sink or
the delivery point.
• Financial Schedules state the volume of each
hour for a specific date.
FBT Overview
165
Financial Bilateral Transactions
Overview
Asset Owners that are selling Financial Bilateral
Transactions must determine how to meet the financial
obligation of the Financial Bilateral Transactions by
either:
• Generating the MWh’s
• Purchasing from the Market
• Tying it to an Internal Bilateral Transactions
(Financial schedule) or an External Bilateral
Transaction ( Physical Schedule) purchase
FBT Overview
166
Financial Bilateral
Transactions Overview
Asset Owners that are buying Financial Bilateral
Transactions must determine how to meet the financial
obligation of the Financial Bilateral Transaction
(Financial Schedule) by either:
• Consuming the MWh’s
• Selling to the Market
• Tying it to a Financial Bilateral Transaction sale or a
Physical schedule export
FBT Overview
167
Financial Schedules
Day-Ahead
Day-Ahead
(Day 1)
(Day 2)
Real-Time
Real-Time
(Day 1)
(Day 2)
•
Day-Ahead FBTs (Financial Schedules) do not automatically become Real-Time FBTs (Financial
Schedules) or subsequent Day-Ahead schedules
•
Real Time FBTs (Financial Schedules) do not automatically become subsequent Real-Time or
Subsequent Day-Ahead FBTs (Financial Schedules)
FBT Overview
168
Financial Bilateral Transactions
Overview
FBT Overview
169
Financial Scheduling System
• Financial Scheduling System
1)
2)
3)
4)
Manage Contract – Create or Update
Manage Schedule
Confirm Financial Schedule
Query Schedules Requiring Confirmations
FBT Overview
170
Financial Scheduling System
FBT Overview
171
Financial Scheduling System
DIR
DIR
FBT Overview
172
Financial Bilateral Transactions
Overview
• Financial Contract
ABC: LGT(WEC.PLO123) BP DA
ABC
LGT
WEC.PLO123
Either Delivery Point or the
Congestion/ Losses must be
provided in order to determine
whether the buyer or seller is
responsible for Congestion and
Losses.
173
FBT Overview
Financial Bilateral Transactions
Overview
ABC: LGT(WEC.PLO123) BP DA
ABC
LGT
Post April 1, 2011
WEC.PLO123
New Field – RSG Deviation Contract
True/False
174
FBT Overview
Financial Bilateral Transactions
Overview
ABC: LGT(WEC.PLO123) BP DA
ABC
LGT
WEC.PLO123
To reset the message.
Click on the Change Date
button.
175
FBT Overview
Financial Scheduling System
IBS Contract Validations
• Any MISO Asset Owner (AO) can create an IBS contract
between themselves or with any other MISO AO.
• All Financial Contracts must be confirmed by both the
Buyer and Seller before it can be scheduled
• The Effective Start and Stop of the contract can be any
date, so long as the Start is not after the Stop
FBT Overview
176
Financial Scheduling System
IBS Contract Validations
• The Source, Sink and Delivery Point must all be valid
MISO Commercial Pricing Nodes (CPNODE)
• A contract can either have a “Delivery Point” (DP) set or
the “Congestions Losses” field set
– If the “Congestion Losses” field is elected for use,
BuyerPays results in the DP being set to the Source
and SellerPays results in the DP being set to the Sink
FBT Overview
177
Financial Scheduling System
• IBS Approval.
•
The Schedule Approval is one of three values:
– BuyerAutoApproval – if the Buyer submits the schedule against the
contract the schedule is automatically approved
– SellerAutoApproval – if the Seller submits the schedule against the
contract the schedule is automatically approved
– CounterPartyApproval – whether the Buyer or Seller submits the
schedule against the contract , the counter party to the contract must
confirm the schedule in order for the schedule to be confirmed
– NOTE: Any IBS contract that is created with the Buyer and Seller the
same is automatically approved, and any schedule submitted against
it is also automatically approved.
FBT Overview
178
Financial Scheduling System
FBT Overview
179
Financial Scheduling System
FBT Overview
180
Financial Scheduling System
DIRS
DIRS
DIRS
DIRS
FBT Overview
181
Financial Scheduling System
Note:
1) 115 days after the termination of the contract,
they are removed.
2) Unconfirmed Finschedules are deleted after 115
days.
FBT Overview
182
Financial Schedules
• Every Financial Schedule specifies a Source, Sink, and
Delivery Point (Optional)
• The Energy component between parties is settled outside of
the MISO market
• Congestion and Losses are settled between the Source and
Sink, as related to the Delivery Point
FBT Overview
183
FBT Overview
184
Contract Types of Financial Bilateral
Transactions
PureFinancial – These Financial Schedules are for a fixed number of
MW and may be submitted in either the Day-Ahead or Real-Time Energy
and Operating Reserve Markets. These transactions do not roll over from
the Day-Ahead to the Real-Time Energy and Operating Reserve
Markets. There are special Real-Time Financial Schedules that can be
used for RSG volume netting, but must be approved four hours prior to
the start of the hour.
Pseudo tie– These Financial Schedules apply to the Real-Time Energy
and Operating Market. These are used to connect an internal asset to an
external control area . An asset in an external control area connecting to
Midwest ISO would not need a financial schedule.
.
FBT Overview
185
Contract Types of Financial Bilateral
Transactions
Grandfathered
Option B - These Financial Schedules apply to the Day-Ahead Energy
Market. Option B Grandfathered Agreement uses Financial Schedule to
capture GFA transactions. These schedules paid the congestion and
loss charge but received a full rebate on the congestion and half on the
loss paid.
Carve-out - Carve- out can be scheduled in the Day-Ahead Energy or
Real-Time Market .These schedules paid the congestion and loss
charge but received a full rebate on both the congestion and the loss
paid. The Carve-out schedules are done on the physical scheduling
system.
FBT Overview
186
Financial Bilateral Schedules Summary
Type of Financial
Bilateral Schedules
Day
Ahead
PureFinancial
Yes
PureFinancial NDL
No
Real
Time
MP
Both Party
Create Confirm
Contract /approval
Volume
validated
Buy/Sell from Rebate
DA/RT Deadline Market
Cong/Loss
RSG_DIST
Netting
Yes
Yes
No
OD + 6 days
Yes
No
No
No
4 hr prior to
Mkt. Hour
Yes
No
Yes
Yes
100%/
100%
No
No
100%/ 50% No
Yes
Yes
Yes
Yes
GFA Carve-out
Yes
Yes
Yes
No
Yes
11am DA/ .5
hr RT
GFA Option B
Yes
No
No
No
Yes
11am DA
Pseudo Tie
No
Yes
No
No
No
OD + 53 days No
No
FBT Overview
No
187
Financial Bilateral Transactions
Overview
• Each of these three contract types have some
differences among them, like difference in time in
updating the volume.
• The next three Sections, we’ll review the purpose
and uniqueness of each of these three contracts.
FBT Overview
188
Financial Bilateral Transactions
Overview
Questions ?
189
FBT Review
Question 1
True/ False - The source and sink CPnode must be
in MISO
True
FBT Review
190
FBT Review
Question 2
True/ False - All FBT energy is settled outside of
the market
True
FBT Review
191
FBT Review
Question 3
True/ False - Congestion Charges are displayed as
a separate Charge Type on MISO settlement
statements.
True
FBT Review
192
FBT Review
Question 4
Which FBT below is not from GFA?
a) Pseudo-Tie
b) Carve-out
c) Option B
d) None of the above
FBT Review
193
FBT Review
Question 5
True/ False - Asset Owner’s settlement statement
shows FBT Congestion and Loss Charge on its
Statement all the time.
False – Only when it is responsible.
FBT Review
194
FBT Overview
195
PureFinancial (Fixed)
PureFinancial
Purefinancial schedules are the most common
contract type of financial bilateral transactions.
Period from 01-2009 to 01- 2010
Day Ahead
IBS
655
Real Time
254
GFAOB
122
PSEUDO Total #
777
10
264
Purefinancial
197
PureFinancial Characteristics
• Energy settled outside of the market
• Buyer, Seller or Both are responsible for
the congestion and loss between Source
and Sink
• Financial schedule must be confirmed by
noon of the 6th day after the operating day
Purefinancial
198
PureFinancial Characteristics.
• Ability to buy the energy from MISO at Source to
meet its obligation
• Ability to sell to MISO at the Sink any additional
volume above its obligation
• Ability to net positive and negative deviations in
RT_RSG_ DIST1 charge if netting option is
selected and schedule is confirmed before the
Notification Deadline (4 hours before the start of
the hour)
Purefinancial
199
PureFinancial Set Up
• A financial contract is needed between the source
and sink.
• The financial contract needs to be confirmed by
both parties.
• A financial schedule is needed each day and may
require confirmation of the volume by both or one of
the contracted parties.
Pseudo-Tie
200
Benefits for a Buyer
• Buyer could be a Load Serving Entity or a Marketer
• Reduce market risk by paying a fixed price over a
period of time
• Hedge against unexpected price volatility
• Some financial uncertainty due to congestion and
losses depending on the delivery point or who is
paying for them
• Gives the load the ability to match fixed revenue
stream with a fixed energy cost
Purefinancial
201
Benefits for a Seller
• Seller could be a Generation Owner or a Marketer
• Reduce market risk by selling at a fixed price over a
period of time
• Hedge against unexpected price volatility
• Some financial uncertainty due to congestion and
losses depending on the delivery point or who is
paying for them
• Guarantee revenue stream matched against fixed
operation costs and finance charge
Purefinancial
202
Benefits for a Marketer
• A marketer could help to reduce market risk of its
customer by matching buyers and sellers.
• A marketer may buy a contract from a generator and
sell at the MISO market or export it to a neighboring
market depending on the price.
• A marketer could buy a contract from a different
generators, consolidate the energy and sell a new
contract to a load.
• A marketer could use the MISO process its purchase
and sell at any particular CPNode like a hub.
Purefinancial
203
Purefinancial Summary
Option AO Relationship Location
1
2
3
4
5
Buyer = Seller
Buyer = Seller
Source = Del = Sink
Financial External
Impact
Contract Result
No
Serve no purpose
No
No
Moved energy from interface/
generator to load, for internal cost
accounting purpose
Acounting Impact
Source <> Del = Sink No
No
Yes
Buyer pays congestion and loss
from source to sink
Lock-In energy cost at
Source
Yes
Seller pays congestion and loss
from source to sink
Lock-In energy cost at
Sink
Yes
Seller pays congestion and loss
from source to Delivery Point
Lock-In energy cost at
Delivery Point
Source = Del<> Sink
Buyer <> Seller Source = Del<> Sink
Buyer <> Seller Source<> Del= Sink
No
Impact
Yes
Yes
Buyer <> Seller Source<> Del<> Sink Yes
Buyer pays congestion and loss
from Delivery point to Sink
6
Buyer <> Seller Source = Del = Sink
Yes
Yes
No Congestion and Loss,
Ownership of the energy changed
hands
Hedge Market
price/contract price
204
Purefinancial
PureFinancial
Pure Financial Related Day-Ahead Charges
Charge Type
Acronym
Type
Day-Ahead Asset Energy Amount
DA_ASSET_EN*
Energy
Day-Ahead Non-Asset Energy Amount
DA_NASSET_EN*
Energy
Day-Ahead Financial Bilateral Transaction
Congestion Amount
DA_FIN_CG
Schedule
Day-Ahead Financial Bilateral Transaction Loss
DA_FIN_LS
Amount
Schedule
Day-Ahead Market Administration Amount
DA_ADMIN*
Admin
Day-Ahead Schedule 24 Allocation Amount
DA_SCHD_24_ALC*
Admin
* Indirect Impact
Purefinancial
205
PureFinancial
Pure Financial Related Real-Time Charges
Charge Type
Acronym
Type
Real-Time Financial Bilateral Transaction
Congestion Amount
Real-Time Financial Bilateral Transaction
Loss Amount
RT_FIN_CG
Schedule
RT_FIN_LS
Schedule
Real-Time Market Administration Amount
RT_ADMIN*
Admin
Real-Time Schedule 24 Allocation Amount
RT_SCHD_24_ALC*
Admin
Real-Time Asset Amount
Non-Excessive Energy Amount
Real Time Non Asset Amount
Real-Time Revenue Sufficiency Guarantee
1st Pass Distribution
RT_ASSET_EN*
RT_NASSET_EN*
Energy
Energy
Energy
RT_RSG_DIST1*
Deviation
Real-Time Net Inadvertent Distribution
RT_NI_DIST*
Distribution
Real-Time Miscellaneous Amount
RT_MISC*
Distribution
RT_ASM_NXE*
*Indirect Impact
Purefinancial
206
PureFinancial
• Settlement Statement Example
207
PureFinancial
Questions?
208
FBT Overview
209
Financial Schedules –GFA
Option B
Grandfathered Agreements
• Grandfathered Agreements are only applicable to
agreements executed or committed to prior to September
16, 1998.
• Independent Transmission Company (ITC) Grandfathered
Agreements that are not subject to the specific terms and
conditions of the Energy Market Tariff (EMT) consistent
with the Commission’s policies.
• These agreements must have been previously identified
to the MISO and set forth in the EMT Attachment P.
Option B
211
Grandfathered Agreements
Option B
Option B is no longer available option
212
Financial Schedule - Option B
GFA Option B was one of the four options available
to Grandfathered Agreement of long term
transmission holders.
Financial Schedule System is used to record GFA
Option B schedule
Market Settlement System validated the GFA
Option B schedule
Option B
213
Option B Characteristics
1) Rebate the congestion and half of the loss
amount between the source and sink of the
schedule.
2) Option B must be scheduled before the close of
the Day Ahead Market only
3) Option B contract is created by MISO
Option B
214
Option B Characteristics
4) Option B schedule is registered in Attachment P
of the Tariff
5) Option B schedule is entitled to a fixed
predetermined volume defined in the Tariff
6) Option B Contract predefined the maximum
volume and is validated in DART.
Option B
215
Option B Schedule Location
• A generation source and a Load Zone,
• A generation source and an Interface
Commercial Pricing Node, or
• An Interface Commercial Pricing Node
and a Load Zone.
Option B
216
Option B Schedule
Validation:
• All GFAOB FBT hourly volumes are validated prior
to settlement.
• The validation process verifies the scheduled
volume of GFAOB FBTs do not exceed the
available generation supply and Load consumption.
• Validations are performed only once and one
transaction invalidation cannot then make another
transaction valid.
Market Settlements Calculation Guide MS-OP-029-r6 -GFAOB FBTs
Option B
217
Financial Schedule - Option B
Option B Schedule – Generation (Seller)
Validation:
If the generation volume is less than the total
GFAOB FBT volume being supplied, then all
the AO's GFAOB FBT volumes that are being
supplied by that generation source for that
Hour are reduced to zero
Market Settlements Calculation Guide MS-OP-029-r6 -GFAOB FBTs
Option B
218
Financial Schedule - Option B
Option B Schedule – Load (buyer) Validation:
If the Load Zone asset volume is less than
the total GFAOB volume, then all the AO's
GFAOB volume that is being provided to that
Load Zone asset for that Hour is reduced to
zero.
Market Settlements Calculation Guide MS-OP-029-r6 -GFAOB FBTs
Option B
219
Option B
25 MW
50 MW
Option B Schedule
50 MW
Seller
Source
Node
Sink
Node
Buyer
The Source volume is less than Option B schedule and the Sink,
The schedule will be not validated
50 MW
25 MW
Option B Schedule
50 MW
Seller
Source
Node
Sink
Node
Buyer
The Sink volume is less than Option B schedule and the Source,
The schedule will be not validated
FBT Concept
220
Option B
75 MW
50 MW
Option B Schedule
50 MW
Seller
Source
Node
Sink
Node
Buyer
The Source volume is greater than Option B schedule and the Sink,
The schedule will be validated
50 MW
75 MW
Option B Schedule
50 MW
Seller
Source
Node
Sink
Node
Buyer
The Sink volume is greater than Option B schedule and the Source,
The schedule will be validated
FBT Concept
221
Option B
50 MW
1) Option B
Schedule 50 MW
Seller
Source
Node
Sink
Node
100 MW
Buyer
40 MW
Seller
Source
Node
2) Option B Schedule
50 MW
Sink
Node
The Source volume is less than Sink, The schedule 2 will not be
validated
FBT Concept
222
Option B
50 MW
1) Option B
Schedule 50 MW
Seller
Source
Node
Sink
Node
90 MW
Buyer
40 MW
Seller
Source
Node
2) Option B Schedule
50 MW
Sink
Node
The Source and Sink volume is less than Option B schedule
volume. The schedule 1 & 2 will not be validated since
FBT Concept
223
Financial Schedule - Option B
Option B Settlement Charges
Option B Financial Related Day-Ahead Charges
Charge Type
Acronym
Type
Day-Ahead Asset Energy Amount
DA_ASSET_EN*
Energy
Day-Ahead Non-Asset Energy Amount
DA_NASSET_EN?
Energy
Day-Ahead Financial Bilateral Transaction Congestion
Amount
DA_FIN_CG
Schedule
Day-Ahead Financial Bilateral Transaction Loss Amount
DA_FIN_LS
Schedule
Day-Ahead Congestion Rebate on Option B Grandfathered
DA_GFAOB_RBT_CG
Agreements
Day-Ahead Losses Rebate on Option B Grandfathered
DA_GFAOB_RBT_LS
Agreements
Schedule
Schedule
Day-Ahead Market Administration Amount
DA_ADMIN*
Admin
Day-Ahead Schedule 24 Allocation Amount
DA_SCHD_24_ALC*
Admin
* Indirect Impact
Option B
224
Option B
• Settlement Statement Example
Option B
225
Option B
Questions?
226
FBT Overview
227
Financial Schedules –GFA
Carve-out
Grandfathered Agreements
Carve-Out
Option B is no longer available option
229
Financial Schedule – Carve-Out
• GFA Carve-Out was one of the four options
available to Grandfathered Agreement of long term
transmission holders.
• Physical Schedule System is used to record and
validate GFA Carve-Out schedule.
• Financial Scheduling System processes the GFA
Carve-out schedules like any other financial
schedule.
Carve-Out
230
Carve-Out Characteristics
•
Full rebate on the congestion and the loss amount
between the source and sink of the schedule.
• Carve-Out schedule is registered in Attachment P
of the Tariff
• Carve-Out schedule is entitled to a fixed schedule
volume
Carve-Out
231
Carve Out – Scheduling
•
Carve-Out schedules can be scheduled in both the
Day Ahead Market or Real-Time Market.
•
Physical Scheduling System ensures the Carve
Out schedule stays within its entitlement
•
Carve-out must be scheduled by 11:00 am for Day
Ahead and half an hour before the top of the hour
for Real-Time.
Carve-Out
232
Financial Schedule – Carve-Out
Carve-Out Schedule location:
• A generation source and a Load Zone,
• A generation source and an Interface Commercial
Pricing Node, or
• An Interface Commercial Pricing Node and a Load
Zone.
Carve-Out
233
Financial Schedule – Carve-Out
Carve-Out Settlements:
•
Charge for Congestion and Loss
•
100% Rebate of Congestion and Loss
•
Buy deficient energy at source from the Market
•
Sell surplus energy at sink to the Market
Carve-Out
234
Financial Schedule – Carve-Out
25 MW
50 MW
Carve Out
Schedule 50 MW
Seller
Source
Node
Sink
Node
Buyer
The Source volume is less than Carve out schedule and the Sink,.
The MP needs to buy 25 MW at the Source LMP.
50 MW
25 MW
Carve Out
Schedule 50 MW
Seller
Source
Node
Sink
Node
Buyer
The Sink volume is less than Carve-out schedule and the Source,
The MP needs to sell 25 MW at the sink LMP.
Carve-Out
235
Financial Schedule – Carve-Out
Carve Out Financial Related Day-Ahead Charges
Charge Type
Acronym
Type
Day-Ahead Asset Energy Amount
DA_ASSET_EN*
Energy
Day-Ahead Non-Asset Energy Amount
DA_NASSET_EN*
Energy
Day-Ahead Financial Bilateral Transaction Congestion Amount DA_FIN_CG
Schedule
Day-Ahead Financial Bilateral Transaction Loss Amount
Schedule
DA_FIN_LS
Day-Ahead Congestion Rebate on Carve-Out B Grandfathered
DA_GFACO_RBT_CG
Agreements
Schedule
Day-Ahead Losses Rebate on Carve-Out Grandfathered
Agreements
DA_GFACO_RBT_LS
Schedule
Day-Ahead Market Administration Amount
DA_ADMIN*
Admin
Day-Ahead Schedule 24 Allocation Amount
DA_SCHD_24_ALC*
Admin
* Indirect Impact
Carve-Out
236
Financial Schedule – Carve-Out
GFA Carve-Out Related Real-Time Charges
Charge Type
Acronym
Type
Real-Time Financial Bilateral Transaction Congestion
RT_FIN_CG
Amount
Schedule
Real-Time Financial Bilateral Transaction Loss
Amount
RT_FIN_LS
Schedule
Real -Time Congestion Rebate on Carve-Out
Grandfathered Agreements
RT_GFACO_RBT_CG
Schedule
Real -Time Congestion Rebate on Carve-Out
Grandfathered Agreements
RT_GFACO_RBT_LS
Schedule
Real-Time Market Administration Amount
RT_ADMIN*
Admin
Real-Time Schedule 24 Allocation Amount
RT_SCHD_24_ALC*
Admin
Real-Time Miscellaneous Amount
Real-Time Asset Amount
Non-Excessive Energy Amount
Real Time Non Asset Amount
RT_MISC*
Real-Time Net Inadvertent Distribution
RT_NI_DIST*
Distribution
Energy
Energy
Energy
Distribution
RT_ASSET_EN*
RT_ASM_NXE*
RT_NASSET_EN*
*Indirect Impact
Carve-Out
237
Carve Out
Questions?
238
FBT Overview
239
Financial Schedules –
Pseudo Tie
Pseudo-Tie
• Purpose of Pseudo-Tie
–
A Market Participant who wish to put their
generator or load into an external control area.
– The external control area will have the
operation control of the generator or the
responsibility to serve the load.
– The Market Participant will paid or paid by the
entities within the external control area.
Pseudo-Tie
241
Pseudo Tie
Pseudo Tie Out – ties generation or load to an external control area
DART will calculate and populate a schedule based on State Estimated
flows at internal source and sink and send to settlements
Pseudo-Tie
MISO
Gen.
PJM
Pseudo-Tie
242
Pseudo Tie
• In order to facilitate Pseudo Tie Out transaction,
financial schedule system is used to record this
transaction since it capture the Congestion and loss
at the CPNode and the interface point. MISO
creates a RT Financial Contract to represent the
pseudo tie out relationship.
Pseudo-Tie
243
Pseudo-Tie Set Up
• Pseudo -Tie Out schedule needs Firm transmission
• Registration of the node as a Pseudo-Tie, submit
Attachment B.
• Physically allow External Control Area to control the
unit.
• MISO creates a financial schedule to capture the
congestion and loss between the source and
interface point
Pseudo-Tie
244
Pseudo-Tie Characteristics
• Pseudo tied out load or generation is NOT in the
market;
• Pseudo tied RT finsched is mechanism to capture
TUC;
• A Pseudo tie Load Zone is created;
• A Pseudo Tie RT Finsched Contract is manually
created by MISO assigned to AO;
• The AO is the Buyer and Seller of the FinSched.
Pseudo-Tie
245
Pseudo-Tie Characteristic
• TUC is based on Congestion and Loss price
difference between Load zone and interface and
the MW injected or withdrawn at the Load zone
• MP have up to 53 days to update the schedule
volume
• DART provides an estimate schedule volume in
Real Time
• Pseudo Tie needs Transmission reservation to
cover the Generator capacity
Pseudo-Tie
246
Pseudo-Tie Benefits
• No Day Ahead and Real Time energy price
imbalance charge within MISO;
• Acts as a Real Time dynamic export schedule;
• Not subjected various Real Time deviation Charges
like RSG_DIST, RT Excessive Energy Charge or
Real Time uplift charge like Revenue Neutrality;
• Have full benefits of external BA rules and
conditions;
• Physical export/import schedule not required.
Pseudo-Tie
247
Pseudo-Tie
• Possible Pseudo-Tie Cost:
– Still responsible of the Real-Time Congestion
and Loss;
– Cannot sell directly to MISO Market at the
Pseudo Tie CPnode point.
– Pseudo Tie Out need a physical import schedule
to sell back into MISO
– Pseudo Tie Out cannot sell at Day-Ahead Market
in MISO
Pseudo-Tie
248
Pseudo Tie
What happen if an Asset is Pseudo Tie In to MISO?
• The Pseudo Tie-In Asset will have its own CPNode and its LMP
like any other MISO Asset. Although the asset is physically in
another control area, it is treated like any another asset in MISO.
Pseudo-Tie
249
Pseudo Tie
Pseudo Tie – Out Settlement Charges
Pseudo Tie Related Real-Time Charges
Charge Type
Acronym
Type
Real-Time Financial Bilateral
Transaction Congestion Amount
RT_FIN_CG
Schedule
Real-Time Financial Bilateral
Transaction Loss Amount
RT_FIN_LS
Schedule
Real-Time Market Administration
Amount
RT_ADMIN*
Admin
Real-Time Schedule 24 Allocation
RT_SCHD_24_ALC*
Amount
Admin
Real-Time Miscellaneous Amount RT_MISC*
Distribution
Real-Time Net Inadvertent
Distribution
Distribution
RT_NI_DIST*
*Indirect Impact
Pseudo-Tie
250
Pseudo-Tie
Real Time Settlement Example
Pseudo-Tie
251
PSEUDO-TIE
• PSEUDO -TIE schedule tie Format’
Generation Pseudo Tie-out schedule Format:
INJ_GEN_XXXX_XXXX_XXXX###########
ID – Injection GEN
Source CPNODE ID
Schedule ID Number
Pseudo-Tie
252
PSEUDO-TIE
• PSEUDO- TIE schedule tie Format
LOAD Pseudo Tie-out schedule Format:
WDRL_LOAD_XXXX_XXXX###########
ID – Withdrawal Load
Source CPNODE ID
Schedule ID Number
Pseudo-Tie
253
PSEUDO-TIE
Questions ?
254
FBT Review
Question 6
• How long do I have after an Operating day to
create a Day Ahead Financial Schedule?
Real Time Financial Schedule?
a)
b)
c)
d)
11:00 am before the OD
Noon on the 6th day after the OD
53 days after the OD
Noon on the 7th day past the OD
FBT Review
255
FBT Review
Question 7
• Which Financial Bilateral schedule(s) gets a
rebate on congestion?
a)
b)
c)
d)
Pure financial schedule
Carve-out financial schedule
Generation energy schedule
GFA Option B Financial schedule
FBT Review
256
FBT Review
Question 8
• What happen when I failed to confirm my
financial schedule before the deadline?
a)
b)
c)
d)
Phone MISO and ask for an extension
Phone MISO and ask for a confirmation override
Settle outside of the market for the difference
Create a new financial schedule
FBT Review
257
FBT Review
Question 9
• Which type of FBT gets 100% rebate on
congestion and losses?
a)
b)
c)
d)
Purefinancial Schedule
Option B
Pseudo-Tie
Carve-Out
FBT Review
258
FBT Review
Question 10
• True/ False There is a predefined maximum
set for purefinancial schedules?
• False.
FBT Review
259
BREAK
260
Financial Schedule
Charge Type Examples
Financial Bilateral Schedules
Example
• All Financial Bilateral Schedules impact Congestion
or Loss Charge Type either in the Day Ahead or
Real Time.
• The following Example will cover a Pure financial
and an Option B schedules.
262
Financial Bilateral Schedules
Example
Example Market Participant – City
For HE 4:
– CITY buy 25 MW for $28 from Gas Gen at the Source (Gen)
– CITY buy 5 MW for $32 from Coal Gen at the Sink (City)
– CITY buy 20 MW for $25 from a Marketer at Source(CIN Hub)
263
Financial Bilateral Example
Gas (50 MW)
25 MW FS
LMP = $45
MCC = $20
20 MW FS
55 MW Option B
CIN Hub
MCL = $ 5
LMP = $25
5 MW FS
Coal Plant
(100MW)
Load – City (75 MW)
MCC = $3
LMP = $30
MCL =$2
MCC = $7
20 MW Option B
MCL =$3
LMP = $37
MCC =$14.5
MCL = $2.5
264
PureFinancial Example
Did the CITY minimize its Cost for HE 4?
o What is difference between buying from the Market
or by these financial bilateral deals?
o What are the Settlement Charges for HE 4 for
CITY?
265
PureFinancial Example
• Energy Component
Load with No Financial Schedules
Location
Load-City
LMP
$
MW
30.00
Total Cost
75
$
2,250
Load with Financial Schedules
Location
Gas Plant
Cin Hub
Coal Plant
Load - City LMP
Total Cost
Contract Price
$
28.00
MW
25
Cost
$
700
$
$
25.00
32.00
20
5
$
$
500
160
$
30.00
25
75
$
$
750
2,110
266
PureFinancial Example
Congestion and Loss Cost:
Load with Financial Schedules
Location
Gas Plant
Cin Hub
Volume Source MCC - MCC-Sink
(MW) Del (MW) Source ($)
($)
25
25
20
7
20
20
3
7
Coal Plant
5
Load - City
LMP
25
Total
75
MLCSource MLCTotal
($) Sink ($) Total ($)
-325
5
3
-50
80
2
3
20
14.5
7
0
2.5
3
0
7
7
0
3
3
0
-
($245)
($30)
No Congestion
& Loss – Delivery
At Sink
267
PureFinancial Example
Load with Financial Schedules
Location
Price ($) MW
Cost ($) Congestion ($) Loss ($) Total ($)
Gas Plant
28
25
700
-325
-50
325
Cin Hub
25
20
500
80
20
600
Coal Plant
32
5
160
0
0
160
Load - City LMP
30
25
750
0
0
750
Total Cost
75
2110
-245
Location
Load-City
Load with No Financial Schedules
LMP
MW
$
30.00 75
-30 $
1,835
Total Cost
2,250
$
268
PureFinancial Example
• Looking at only the Energy Component, it is
insufficient to determine if the Financial Bilateral
schedule was economical.
• The Congestion and Loss component of the
transaction must be first taken into consideration.
269
Day-Ahead Energy
Charge Type
Day-Ahead Financial Schedule
Congestion Amount (DA_FIN_CG)
DA_FIN_CG - Purpose
• Day-Ahead Financial Schedule Congestion Amount
(DA_FIN_CG)
• Represents an AO’s total FBT congestion costs and Carve-Out
GFA Transaction congestion costs for an OD
• Charge or credit based on the difference between two CPNodes’
congestion costs multiplied by the transaction volume
• Calculated on FBTs (IBS and GFAOB transaction types) and
Carve-Out GFA Transactions
Who gets the
charge/credit?
• Sellers for congestion between the
source and Delivery Point CPNode
• Buyers for congestion between
Delivery Point and Sink CPNode
• GFAOB and GFACO Holders
Where does it go?
• Financial Transmission Rights
Holders (FTRs)
272
DA_FIN_CG - Hierarchy
*Note that the DA_GFAOB Buyer and Seller determinants must first be validated against
each other in order to ensure sufficient supply and load volume.
273
DA_FIN_CG - Formula
*DA_FIN_CG
(
=∑
DA_FIN_BUY_CG
H
+
DA_FIN_SELL_CG
+
DA_FIN_GFAOB_BUY_CG
+
DA_FIN_GFAOB_SELL_CG
DA_GFACO_BUY_CG
+
DA_GFACO_SELL_CG
+
)
Hourly Total Day-Ahead Buyer FBT Congestion Charge ($)
DA_FIN_BUY_CG
=
ΣTransactions [ (*DA_FINBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
Hourly Total Day-Ahead Seller FBT Congestion Charge ($)
DA_FIN_SELL_CG
=
ΣTransactions [ (*DA_FINSeller ) x (*DA_LMP_CGDP - *DA_LMP_CGSO ) ]
274
DA_FIN_CG - Formula
=
ΣH (DA_FIN_BUY_CG + DA_FIN_SELL_CG +
DA_FIN_GFAOB_BUY_CG + DA_FIN_GFAOB_SELL_CG +
DA_GFACO_BUY_CG + DA_GFACO_SELL_CG)
Hourly Total Day-Ahead Buyer Option B FBT Congestion Charge ($)
DA_FIN_GFAOB_BUY_CG
=
ΣTransactions [ (DA_GFAOBBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
Hourly Total Day-Ahead Seller Option B FBT Congestion Charge ($)
DA_FIN_GFAOB_SELL_CG
=
ΣTransactions [ (DA_GFAOBSeller ) x (*DA_LMP_CGDP - *DA_LMP_CGSO ) ]
Hourly Total Day-Ahead Buyer Carve-Out
GFA Transaction Congestion Charge ($)
DA_GFACO_BUY_CG
=
ΣTransactions [ (*DA_GFACOBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
Hourly Total Day-Ahead Seller Carve-Out
GFA Transaction Congestion Charge ($)
DA_GFACO_SELL_CG
=
ΣTransactions [ (*DA_GFACOSeller ) x (*DA_LMP_CGDP - *DA_LMP_CGSO ) ]
275
Financial Bilateral Example
Gas (50 MW)
25 MW FS
LMP = $45
MCC = $20
20 MW FS
CIN Hub
55 MW Option B
MCL = $ 5
LMP = $25
5 MW FS
Coal Plant
(100MW)
Load – City (75 MW)
MCC = $3
LMP = $30
MCL =$2
MCC = $7
20 MW Option B
MCL =$3
LMP = $37
MCC =$14.5
MCL = $2.5
276
DA_FIN_CG – FIN Example
Intermediate Calculations
Determinant
Formula
=ΣTransactions [ (*DA_FINBuyer ) x (*DA_LMP_CGSI -
DA_FIN_BUY_CGgas
-325
*DA_LMP_CGDP ) ]
=ΣTransactions [ (25) x (7 - 20 ) ]
=ΣTransactions [ (DA_FINBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
DA_FIN__BUY_CGcoal
0
=ΣTransactions [ (5) x (7 - 7) ]
=ΣTransactions [ (*DA_FINBuyer) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
DA_FIN_BUY_CGhub
80
=ΣTransactions [ (20) x (7 - 3 ) ]
277
Financial Bilateral Example
Gas (50 MW)
25 MW FS
LMP = $45
MCC = $20
20 MW FS
55 MW Option B
CIN Hub
MCL = $ 5
LMP = $25
5 MW FS
Coal Plant
(100MW)
Load – City (75 MW)
MCC = $3
LMP = $30
MCL =$2
MCC = $7
20 MW Option B
MCL =$3
LMP = $37
MCC =$14.5
MCL = $2.5
278
Option B Validation
• GFAOB FBT seller - If the generation volume is less
than the total GFAOB FBT volume being supplied, then all
the AO's GFAOB FBT volumes that are being supplied by
that generation source for that Hour are reduced to zero.
• GFAOB FBT buyer - If the Load Zone asset volume is
less than the total GFAOB FBT volume, then all the AO's
GFAOB FBT volume that is being provided to that Load
Zone asset for the that Hour is reduced to zero.
279
DA_FIN_CG –Example
Intermediate Calculations
Determinant
Formula
DA_FIN_GFAOB_BUY_CGgas
0
=ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
=ΣTransactions [ (0) x (7 - 20 ) ]
( Not Validated :Source < FSS Option B)
DA_FIN_GFAOB_BUY_CGCoal =ΣTransactions [ (DA_GFAOBBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
-150
DA_FIN_GFAOB_BUY_CGhub
0
=ΣTransactions [ (20) x (7 - 14.5 ) ]
=ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
=ΣTransactions [ (0) x (7 - 3 ) ]
280
DA_FIN_CG – Example
Charge Type Calculation
*DA_FIN_CG
=∑
H
(
+
DA_FIN_BUY_CG
DA_FIN_GFAOB_BUY_CG
DA_GFACO_BUY_CG
-$395
=∑
H
(
-$245
+
$0
DA_FIN_SELL_CG
+
+
+
+
DA_FIN_GFAOB_SELL_CG
DA_GFACO_SELL_CG
$-150
+
$0
+
+
)
$0
+
$0
)
Results in a $395 Credit for HE 4
281
DA_FIN_CG – Summary
• The Day-Ahead Financial Schedule Congestion
Amount is the product of the transaction volume
and the difference between two CPNodes’
congestion costs.
• IBS FBTs can exist at any CPNodes
Questions?
282
Day-Ahead Financial Schedule
Loss Amount (DA_FIN_LS)
DA_FIN_LS - Purpose
• Day-Ahead Financial Schedule Loss Amount
(DA_FIN_LS)
• Represents an AO’s total FBT loss costs and Carve-Out
GFA Transaction congestion costs for an Operating Day
• Charge or credit based on the difference between two
CPNodes’ LMP loss component multiplied by the
transaction volume
• Calculated on GFAOB, GFACO, and IBS FBTs
Who gets the
charge/credit?
Where does it go?
• Sellers - for losses between the
Source CPNode and Delivery Point
• Buyers - for losses between Delivery
Point and Sink CPNode
• GFAOB and GFACO Holders
• Load Zone AOs (RT_LOSS_DIST)
284
DA_FIN_LS - Hierarchy
*Note that the DA_GFAOB Buyer and Seller determinants must first be validated against
each other in order to ensure sufficient supply and load volume.
285
DA_FIN_LS - Formula
*DA_FIN_LS
(
=∑
DA_FIN_BUY_LS
H
DA_FIN_GFAOB_BUY_LS
DA_GFACO_BUY_LS
+
DA_FIN_SELL_LS
+
+
DA_FIN_GFAOB_SELL_LS
+
DA_GFACO_SELL_LS
+
)
Hourly Total Day-Ahead Buyer FBT Loss Charge ($)
DA_FIN_BUY_LS
=
ΣTransactions [ (*DA_FINBuyer ) x (*DA_LMP_LSSI - *DA_LMP_LSDP ) ]
Hourly Total Day-Ahead Seller FBT Loss Charge ($)
DA_FIN_SELL_LS
=
ΣTransactions [ (*DA_FINSeller ) x (*DA_LMP_LSDP - *DA_LMP_LSSO ) ]
286
DA_FIN_LS - Formula
=
ΣH (DA_FIN_BUY_LS + DA_FIN_SELL_LS +
DA_FIN_GFAOB_BUY_LS + DA_FIN_GFAOB_SELL_LS +
DA_GFACO_BUY_LS + DA_GFACO_SELL_LS)
Hourly Total Day-Ahead Buyer Option B FBT Loss Charge ($)
DA_FIN_GFAOB_BUY_LS
=
ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_LSSI - *DA_LMP_LSDP ) ]
Hourly Total Day-Ahead Seller Option B FBT Loss Charge ($)
DA_FIN_GFAOB_SELL_LS
=
ΣTransactions [ (*DA_GFAOBSeller ) x (*DA_LMP_LSDP - *DA_LMP_LSSO ) ]
Hourly Total Day-Ahead Buyer Carve-Out
GFA Transaction Loss Charge ($)
DA_GFACO_BUY_LS
=
ΣTransactions [ (*DA_GFACOBuyer ) x (*DA_LMP_LSSI - *DA_LMP_LSDP ) ]
Hourly Total Day-Ahead Seller Carve-Out
GFA Transaction Loss Charge ($)
DA_GFACO_SELL_LS
=
ΣTransactions [ (*DA_GFACOSeller ) x (*DA_LMP_LSDP - *DA_LMP_LSSO ) ]
287
DA_FIN_LS – FIN Example
Intermediate Calculations
Determinant
Formula
=ΣTransactions [ (DA_FINBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
DA_FIN_BUY_LSgas
-50
=ΣTransactions [ (25) x (3 - 5 ) ]
=ΣTransactions [ (DA_FINBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
DA_FIN_BUY_LScoal
0
=ΣTransactions [ (5 x (3 - 3 ) ]
=ΣTransactions [ (DA_FINBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
DA_FIN_BUY_LShub
20
=ΣTransactions [ (20) x (3 - 2 ) ]
288
DA_FIN_LS – Option B Example
Intermediate Calculations
Determinant
Formula
=ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_LSSI - *DA_LMP_LSDP ) ]
DA_FIN_GFAOB_BUY_LSgas
0
=ΣTransactions [ () x (3 - 5 ) ]
=ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_LSSI - *DA_LMP_LSDP ) ]
DA_FIN_GFAOB_BUY_LScoal
10
=ΣTransactions [ (20 x (3 - 2.5 ) ]
=ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_LSSI - *DA_LMP_LSDP ) ]
DA_FIN_GFAOB_BUY_LShub
0
=ΣTransactions [ (0) x (3 - 3 ) ]
289
DA_FIN_LS – Example
Charge Type Calculation
*DA_FIN_LS
=∑
H
(
+
DA_FIN_BUY_LS
DA_FIN_GFAOB_BUY_LS
DA_GFACO_BUY_LS
-$20.0
=∑
(
H
-$30
+
$0
+
DA_FIN_SELL_LS
+
+
$10
+
DA_FIN_GFAOB_SELL_LS
DA_GFACO_SELL_LS
+
$0
+
+
)
$0
+
$0
)
Results in a - $20 credit for HE 4
290
DA_FIN_LS – Summary
• The Day-Ahead Financial Schedule Loss Amount is the
product of the transaction volume and the difference
between two Commercial Pricing Nodes’ loss cost
components.
• The Delivery Point is defined as the financial location,
which can be either the source, sink or any other CPNode,
where responsibility for the cost of losses is transferred
from seller to buyer, or shared in the case of a Delivery
Point other than the source or sink.
•
•
Transaction sellers are responsible for losses between the Delivery
Point and the source CPNode.
Transaction buyers are responsible for losses between the sink and
Delivery Point CPNode.
Questions?
291
Day-Ahead Congestion Rebate on
Option B Grandfathered
Agreements
(DA_GFAOB_RBT_CG)
DA_GFAOB_RBT_CG - Purpose
•
Day-Ahead Congestion Rebate on Option B
(DA_GFAOB_RBT_CG)
Grandfathered Agreements
• Represents an AO’s total Operating Day rebate, equal to all DayAhead FBT Congestion Amount charge type charges and credits
for Option B GFAs Transactions
• Similar to the Day-Ahead FBT Congestion Amount, the rebate
can be a charge or credit depending upon the CPNodes of the
transaction
• Calculated hourly by AO for every valid GFAOB Transaction
where it is buying and/or selling, and then is summed to a daily
total
Who gets the
charge/credit?
Where does it go?
• Asset Owners with valid Day-Ahead
Option B GFAs Transactions
• Uses funds collected for Congestion
through the DA_FIN_CG (GFAOB)
Charge Type
• If insufficient funds, the Revenue
Neutrality Uplift Amount is used
293
DA_GFAOB_RBT_CG Hierarchy
294
DA_GFAOB_RBT_CG - Formula
*DA_GFAOB_RBT_CG
(
=∑
H
DA_FIN_GFAOB_BUY_CG
+
DA_FIN_GFAOB_SELL_CG
) x(-1)
Hourly Total Day-Ahead Option B Buyer FBT Congestion Charge ($)
DA_FIN_GFAOB_BUY_CG
=
ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
Hourly Total Day-Ahead Option B Seller FBT Congestion Charge ($)
DA_FIN_GFAOB_SELL_CG
=
ΣTransactions [ (*DA_GFAOBSeller ) x (*DA_LMP_CGDP - *DA_LMP_CGSO ) ]
295
DA_GFAOB_RBT_CG – Load
Example
Intermediate Calculations
Determinant
Formula
=ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_CGSI - *DA_LMP_CGDP ) ]
DA_FIN_GFAOB_BUY_CG
-150
=ΣTransactions [ (20) x (7 - 14.5 ) ]
296
DA_GFAOB_RBT_CG – Load Example
Charge Type Calculation
*DA_GFAOB_RBT_CG
(
=∑
DA_FIN_GFAOB_BUY_CG
H
$150
(
=∑
H
-$150
+
+
DA_FIN_GFAOB_SELL_CG
$0
) x(-1)
) x (-1)
Results in a $150 charge for HE 4
297
DA_GFAOB_RBT_CG – Summary
• The Day-Ahead Congestion Rebate on Option B GFAs
Amount represents an AO’s total OD rebate of all
congestion charges and credits from the DA FBT
Congestion Amount charge type.
• Option B FBTs that did not pass validation in the Day-Ahead
Option B Financial Schedule Validation are not charged the
DA_FIN_CG charge type amount and as such are not
assessed any rebates in this charge type.
Questions?
298
Day-Ahead Losses Rebate on
Option B Grandfathered
Agreements (DA_GFAOB_RBT_LS)
DA_GFAOB_RBT_LS - Purpose
• Day-Ahead Losses Rebate on Option B Grandfathered
Agreements (DA_GFAOB_RBT_LS)
• Represents an AO’s total Operating Day rebate of the difference
between Marginal Losses and GFA Average Losses (50%) in the
Day-Ahead FBT Loss Amount charge type related to GFAOB FBTs
• The buying and selling MPs of GFAOBs are refunded a portion of
their loss charges (and credits) based on a refund rate that is fixed
in the Energy and Operating Reserve Markets Tariff
• Calculated hourly by AO for every valid GFAOB Transaction where
it is buying and/or selling and then is summed to a daily total
Who gets the
charge/credit?
Where does it go?
• Asset Owners with valid Day-Ahead
Option B GFAs Transactions
• Uses funds collected for Losses
through the DA_FIN_LS (GFAOB)
Charge Type
300
DA_GFAOB_RBT_LS Hierarchy
301
DA_GFAOB_RBT_LS - Formula
*DA_GFAOB_RBT_LS
(
=∑
DA_FIN_GFAOB_BUY_LS
H
[
1–
(
+
*GFA_AVG_LOSS_PCT
)x
/ 100) ] x (-1)
DA_FIN_GFAOB_SELL_LS
Hourly Total Day-Ahead Buyer GFAOB FBT Loss Charge ($)
DA_FIN_GFAOB_BUY_LS
=
ΣTransactions [ ( IF ( Pre 888 Loss Flag = “B”, THEN *DA_GFAOBBuyer , ELSE 0 )
x (*DA_LMP_LSSI - *DA_LMP_LSDP ) ]
Hourly Total Day-Ahead Seller GFAOB FBT Loss Charge ($)
DA_FIN_GFAOB_SELL_LS
*GFA_AVG_LOSS_PCT
=
=
ΣTransactions [ ( IF ( Pre 888 Loss Flag = “B”, THEN *DA_GFAOBSeller , ELSE 0 )
x (*DA_LMP_LSDP - *DA_LMP_LSSO ) ]
GFA Average Loss Rate Percentage (%)
MISO System Average Loss Rate / MISO Average Marginal Loss Rate
(estimate … set to 50%)
302
DA_GFAOB_RBT_LS – Load Example
Intermediate Calculations
Determinant
Formula
Pre 888 Loss Flag = “B” , so
=ΣTransactions [ (*DA_GFAOBBuyer ) x (*DA_LMP_LSSI - *DA_LMP_LSDP ) ]
DA_FIN_GFAOB_BUY_LS
10
=ΣTransactions [ (20) x (3 - 2.5 ) ]
303
DA_GFAOB_RBT_LS – Load Example
Charge Type Calculation
*DA_GFAOB_RBT_LS
(
=∑
DA_FIN_GFAOB_BUY_LS
H
[
-$5.0
1–
(
(
=∑
[
1–
*GFA_AVG_LOSS_PCT
+
$10
H
(
+
50
)x
/ 100) ] x (-1)
DA_FIN_GFAOB_SELL_LS
)x
/ 100) ] x (-1)
$0
Results in a $5 credit for HE 4
304
DA_GFAOB_RBT_LS – Summary
• All valid GFAOB FBTs are assessed the full loss
charge or credit per the DA_FIN_LS amount and
receive a rebate of the difference between Marginal
Losses and System Average Losses.
Questions?
305
Financial Bilateral Schedule
Charges Summary
Day-Ahead Financial Bilateral Charges
Charge Type
Pure Financial Carve-Out
Option B
Pseudo Tie
Day-Ahead Asset Energy Amount
Possible
Possible
Possible
No
Day-Ahead Non-Asset Energy Amount
Day-Ahead Financial Bilateral Transaction
Congestion Amount
Day-Ahead Financial Bilateral Transaction
Loss Amount
Day-Ahead Congestion Rebate on Carve-Out
Grandfathered Agreements
Day-Ahead Losses Rebate on Carve-Out
Grandfathered Agreements
Day-Ahead Congestion Rebate on Option B
Grandfathered Agreements
Day-Ahead Losses Rebate on Option B
Grandfathered Agreements
Possible
Possible
Possible
No
Yes
Yes
Yes
No
Yes
Yes
Yes
No
No
Yes
No
No
No
Yes
No
No
No
No
Yes
No
No
No
Yes
No
Day-Ahead Market Administration Amount
Possible
Possible
Possible
No
Day-Ahead Schedule 24 Allocation Amount
Possible
Possible
Possible
No
* Indirect Impact
306
Real-Time
Charge Type
Financial Bilateral Schedule
Charges Summary
Real-Time Financial Bilateral Schedule Charges
Charge Type
Real-Time Financial Bilateral Transaction
Congestion Amount
Pure
Carve-Out Option B Pseudo
Financial
Tie
Yes
Real-Time Financial Bilateral Transaction Loss
Yes
Amount
Real -Time Congestion Rebate on Carve-Out
No
Grandfathered Agreements
Real -Time Congestion Rebate on Carve-Out
No
Grandfathered Agreements
Yes
No
Yes
Yes
No
Yes
Yes
No
No
Yes
No
No
Real-Time Market Administration Amount
Possible
Possible
No
Possible
Real-Time Schedule 24 Allocation Amount
Possible
Possible
No
Possible
Real-Time Miscellaneous Amount
Possible
Possible
Possible
No
Real-Time Asset Amount
Possible
Possible
No
No
Non-Excessive Energy Amount
Possible
Possible
No
No
Real Time Non Asset Amount
Possible
Possible
No
No
Real-Time Net Inadvertent Distribution
Possible
Possible
Possible
Possible
308
Real Time Charge– Summary
• The Real-Time Financial Bilateral Transaction Congestion
Amount and Real-Time Financial Bilateral Transaction
Loss Amount are identical to Day Ahead calculation.
• Real -Time Congestion Rebate on Carve-Out
Grandfathered Agreements and Real –Time Loss Rebate
on Carve-Out Grandfathered Agreements are also
calculated same as the Day Ahead example.
Questions?
309
RT RSG Financial Bilateral
Example
Assumptions:
1) No Day Ahead Schedules
3) FSS Del at Source
2) FSS is done before NDL
What is the RSG Impact at the load?
Gas (50 MW) NDL
Load – City (75 MW) NDL
25 MW FS
( 85 MW) RT
LMP = $45
LMP = $30
MCC = $20
MCC = $7
MCL = $ 5
MCL =$3
CCF = -.5
CCF =.3
310
RT RSG Financial Bilateral
Example
1) What is the RSG_Dist Charge at the load without NDL FSS ?
2) What is the RSG_Dist Charge at the load with NDL FSS ?
Gas (50 MW) NDL
Load – City (75 MW) NDL
25 MW FS
( 85 MW) RT
LMP = $45
LMP = $30
MCC = $20
MCC = $7
MCL = $ 5
MCL =$3
CCF = -.5
CCF =.3
311
Real-Time Revenue Sufficiency
Guarantee First Pass Distribution Amount
(RT_RSG_DIST1)
Post April 2011
RT_RSG_DIST1 - Purpose
• Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount (RT_RSG_DIST1)
• This charge funds the RSG Make Whole Payments paid to the generation
Asset Owners
• Charges Asset Owner’s assets and schedules with an adverse impact on
a constraint based on the amount of deviation and the Constraint
Contribution Factor (CCF) for the Active Transmission Constraint
• Charges Asset Owner’s sum total of asset-related deviations and demand
changes which are deemed to be a cause for Real-Time RAC generation
commitments
Who gets the
charge/credit?
• Asset Owners with assets and
schedules which adversely impact
Constraints and deviations and
demand changes resulting in
commitments
Where does it go?
• Asset Owners with generation (via
Make Whole Payment)
313
RT_RSG_DIST1
Commonly Used Acronyms
AO
Asset Owner
ATC
Active Transmission Constraints
CCF
Constraint Contribution Factor
CMC
Constraint Management Charge
DDC
Day-Ahead Deviation & Headroom Charge
MP
Market Participant
NDL
Notification Deadline
RAC
Reliability Assessment Commitment
314
RT_RSG_DIST1 – Hierarchy
315
RT_RSG_DIST1 - Formula
*RT_RSG_DIST1
(
=∑
H
*RT_RSG_DIST1_HR
)
Hourly Real-Time RSG Distribution Amount
*RT_RSG_DIST1_HR
=
CMC_DIST + DDC_DIST
316
RT_RSG_DIST1 – Hierarchy
317
RT_RSG_DIST1
Constraint Management Charge Distribution Calculation (CMC_DIST)
• Funds Real-Time RSG MWP amount credits paid to units committed
in the RAC to manage Active Transmission Constraints (ATCs).
• AO’s assets and schedules with an adverse impact on a constraint
are charged based on the amount of deviation and the Constraint
Contribution Factor for the ATC.
• Calculates deviations from the Day-Ahead to the Notification
Deadline.
• Calculates deviations from the Notification Deadline to the RealTime.
318
RT _RSG_DIST1
1
CMC1
CMC2
DDC
CMC4
CMC3
1
FSS moving Dev volume from Constraint 1 to 2
2
FSS moving Dev volume within Constraint 3
2
319
RSG_DIST
CMC_DEV_VOL =
NDL Dev
RT DEL
DDC_DEV_VOL =
CMC_NDL VOL
DDC_NDL_ VOL
+
+
CMC_RT_VOL
DDC_ RT_VOL
320
RSG_DIST
• CMC_DEV_VOL =
NDL Dev
RT Dev
CMC_NDL_ VOL
Sum of All +/- Deviation X CCF
Net Positive Total is added to RT Dev.
+
+
CMC_RT_VOL
Sum of all Positive (Deviation x CCF)
321
RSG_DIST
DDC_DEV_VOL
NDL Dev
Sum of All +/- Deviation
Net Positive Total is added to RT Dev
+
Sum of all MAX(NDL Deviation,0 ) or
RT Dev
ABS( RT Deviation)
DDC_NDL_ VOL
+
DDC_ RT_VOL
322
RSG_DIST with No Financial
Schedule
CMC_ DIST
CMC_NDL_LOAD_VOL
#
DA_SCHD
1
NDL_DMD_FCST
0
75
DEV
CCF
-75
0.3
CMC_DEV_VOL
-22.5
CMC_RT_LOAD_VOL
#
NDL_DMD_FCST
1
AEW
75
CMC_DEV_VOL (Net Positive Sum )
CMC Rate $
CMC_Dist $
DEV
85
CCF
-10
CMC_DEV_VOL
0.3
0
0
3.89
0
323
RSG_DIST with No Financial
Schedule
DDC_ DIST
DDC_NDL_LOAD_VOL
#
NDL_DMD_FCST
1
75
#
1
Net Positive Sum
DDC Rate $
DDC_Dist $
DA_SCHD
DDHC_DEV_VOL
0
75
DDC_RT_LOAD_VOL
AEW
NDL_DMD_FCST DDHC_DEV_VOL
75
85
10
85
1.56
132.6
324
RSG_DIST with Financial
Schedule
CMC_ DIST
#
DA_SCHD
1
CMC_NDL_LOAD_VOL
NDL_DMD_FCST
DEV
0
75
-75
CCF
0.3
CMC_DEV_VOL
-22.5
CCFDP
-0.5
CMC_DEV_VOL
-12.5
CMC_NDL_FIN_VOL
#
1
NDL_FINSeller
NDL_FINBuyer
DEV
25
25
CMC_RT_LOAD_VOL
#
NDL_DMD_FCST
1
75
CMC_DEV_VOL (Net Positive Sum )
CMC Rate $
CMC_Dist $
AEW
85
DEV
-10
CCF
0.3
CMC_DEV_VOL
0
0
3.89
0
325
RSG_DIST with Financial
Schedule
DCC_ DIST
#
#
#
1
DDC_NDL_LOAD_VOL
NDL_DMD_FCST
DA_SCHD
75
0
1
DDC_NDL_FIN_VOL
NDL_FINBuyer
NDL_FINSSeller
25
0
1
DDC_RT_LOAD_VOL
AEW
NDL_DMD_FCST
75
85
Net Postive Sum
DDC Rate $
DDC_Dist $
DDHC_DEV_VOL
75
DDHC_DEV_VOL
-25
DDHC_DEV_VOL
10
60
1.56
93.6
326
Load RSG_DIST Summary
CMC_NDL_VOL
CMC_RT_VOL
CMC_DEV_VOL
CMC_DIST
DDC_NDL_VOL
DDC_RT_VOL
DDC_DEV_VOL
DDC_DIST
RSG_DIST $
Difference $
Load RSG_DIST Summary
Without FSS
With FSS
-22.5
0
0
0
75
10
85
132.6
132.6
-35
0
0
0
50
10
60
93.6
93.6
39
327
Load Charges Summary
Load Charges Summary
Without FSS
Real Time Asset Energy
With FSS
2550
1800
Real Time Congestion Charge
-325
Real Time Loss Charge
-50
Real RSG_Dist Charge
132.6
Total
$
2,682.60
Difference
$
1,164.00
Difference In $/MW
$
46.56
93.6
$
1,518.60
328
Pre vs. Post April 11 FSS - RSG
Summary
Pre-April 2011
• Financial Schedule has no Impact in RSG_DIST
Post-April 2011
•
•
•
•
Netting of FSS Volume across Asset Owner CPnodes
before NDL,
Two RSG Allocation buckets - CMC and DCC,
FSS must be confirmed before NDL,
Financial Contract must be selected.
329
Financial Bilateral Transactions
Charges
Questions ?
330
FBT Review
Question 11
• A marketer offers to sell energy at $31MW/h to a
Load at the delivery point where the Generator
CPNodes average LMP is $35. This is a
Purefinancial schedule. Is this a good deal ?
a) Yes,
b) No,
c) Maybe, Why?
331
FBT Review
Question 12
I would like to sell my MISO’s Generator
energy to PJM with this type of financial
bilateral schedule. I could use a _________
Schedule.
a)
b)
c)
d)
Pseudo Tie
Physical
Pure financial
Internal Bilateral Schedule
332
FBT Review
Question 13
If GFA Option B schedule was confirmed
in the market portal, does it mean the
schedule has been validated?
a) No
b) Yes
333
FBT Review
Question 14
Which Day Ahead charge types are not directly
related to Financial Bilateral Schedules?
a)
b)
c)
d)
Day-Ahead FBT Congestion Amount
Day-Ahead FBT Loss Amount
Day-Ahead Market Administration Amount
Day- Ahead RSG MWP
334
FBT Review
Question 15
RT_RSG_DIST charge can have an impact on
which type of Financial Schedules?
a)
b)
c)
d)
Pseudo Tie
Physical
Pure financial
Carve-Our Schedules
335
FBT Review
Question 16
True/False: A Financial Contract with RSG
Deviation selected still has up to 6th day noon to
confirm the financial Schedule .
a) True
b) False
336
FBT Review
Question 17
True/False:
I have an option to update RSG
Deviation Contract option to any active Financial
Contracts before April 2011.
a) True
b) False
337
FBT Review
Question 18
Would it be beneficial to do a FS RSG Deviation
Contract with generator at the source if the Constraints
Contribution Factor is negative?
a)
Yes
b) No
c) Depends
If the generator is increasing supply then it is helping
but if it is decreasing supply, then it is hurting the constraint.
There is not enough information to say it is beneficial or not.
338
FBT Review
Question 19
NDL_FINSeller
CMC_DEV_VOL
10
5
0
0
What is the CMC_DIST amount?
NDL_FINBuyer
0
0
15
20
DEV
-10
-5
15
20
CCFDP
CMC_DEV_VOL
5
-2.5
9
-2
9.5
-0.5
0.5
0.6
-0.1
CMC Rate
$
10.00
CMC_DIST
$
95.00
a) $75
b) $60
c) $95
d) $100
339
FBT Review
Question 20
What Real Time charge deals with allocation of
RT_RSG_MWP cost?
a)
b)
c)
d)
CMC_DIST
RT_RSG_DIST1
DDC_DIST
RT_DEV
340
Helpful Resources
References
• Settlement related documentation
– Posted on the MISO website (www.misoenergy.org):
• Market Settlements Business Practices Manual 005
• Market Settlements Business Practices Manual 005 Attachment A
• https://www.misoenergy.org/Library/BusinessPracticesManuals/Pages/Busine
ssPracticesManuals.aspx
• Market Settlements helpful documents and files
• Frequently Asked Questions (FAQs)
– Documents | Market Settlements
• Market Settlements Working Group (MSWG) Meetings
– Conducted monthly, generally the first Tuesday of every month
342
Helpful Resources
• Where can I learn about the MISO Market?
– Websites
• www.misoenergy.org
• http://extranet.misoenergy.org
– Documentation
• On www.misoenergy.org
– Guiding documents – Business Practices, Draft Tariff
– Informational documents – Training presentations, Testing documentation, etc.
– Technical Infrastructure documents – Implementation documents
– Technical specifications
– Testing information
– Market Registration documents – Registration packet, public data
– Client Account Representative are assigned to each Market Participant
343
Reporting Issues and Submitting
Questions
• Client Relations
– Call - 866-296-6476, Option 1
– E-mail clientrelations@misoenergy.org
– E-mail marketquality@misoenergy.org
• Network Operations Center (NOC)
– Call - 866-296-6476, Option 2
• Report Portal, Dispatch and AGC Outages 24x7
• Report other items during MISO business hours
344
RSG_DIST1 Training
345
RSG_DIST1 Training
346
Virtual Quiz Answers
1. True
2. d
3. a
4. a
5. a
6. d
7. b
8. c
9. a
10. d
347
Financial Review Answers
1. True
2. True
3. True
4. a
5. False
6. b
7. b & d
8. c
9. d
10.False
11. a
12. a
13. a
14. d
15. c
16. b
17. b
18. c.
19. c
20. b
348
Market Settlement Training Series
Market Settlements Training Modules:
–
–
–
–
–
–
–
Overview O101
(Feb. 2011)
ARR/FTR AF201
(Mar. 2011)
Virtual and Financial Schedules VF201 (Apr. 2011)
Physical Schedules PS201
(May 2011)
Load L201
(Jul. 2011)
Generation G201
(Aug. 2011)
Overview O101
(Sep. 2011)
349
Course Outline
TOPICS
Introduction
Physical Bilateral Transactions Overview
Physical Bilateral Transactions Market Types and Time
Lines
Physical Bilateral Transactions Dispute Process and
Examples
Physical Bilateral Transactions Systems
Physical Bilateral Transactions Market Settlements
Physical Bilateral Transactions Charge Types
350