On Standard Market Design
Harry Singh
IEEE Summer Meeting, July 23, 2002
Chicago, Illinois
PG&E National Energy Group and any other company referenced herein which uses the PG&E name or logo are not the
same company as Pacific Gas and Electric Company, the California utility. These companies are not regulated by the
California Public Utilities Commission, and customers do not have to buy products from these companies in order to continue
to receive quality regulated services from the utility. Views expressed her are not necessarily those of PG&E National Energy Group.
Outline
„
„
„
Structure and Scope of RTOs
Evolution of RTOs
Elements of Standard Market Design
2
Evolution of RTOs
„
„
Order 888
Order 2000
–
„
Outlined RTO characteristics and functions at a high level
Standard Market Design (SMD)
–
–
–
–
Eliminate Seams
Adopt best practices
Address RTO functions in greater detail
To be released by FERC on Jul 31, 2002
3
Standard Market Design
„
„
FERC’s proposal mirrors the PJM and NY ISO market designs
Key elements of SMD
– LMP based congestion management
– Financial Transmission Rights
– Financially binding day-ahead energy markets
– Real time balancing markets
– Capacity markets (initial reluctance, gradual acceptance)
– Market power mitigation
4
Congestion Management
„
„
„
Experiences with high uplift costs in California, ERCOT and New
England
Uplifts are difficult to hedge
Zone redefinition creates uncertainties
General acceptance of LMP and nodal pricing (albeit with appropriate
hub definition)
–
(Bill Hogan was right after all!)
NE Congestion Uplift
30
25
$(Millions)
„
20
15
10
5
0
Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan- Feb- Mar- Apr- May- Jun00
00
00
00
00
00
00
00
00
00
00
00
01
01
01
01
01
01
Source: ISO-NE
5
LMP components (NYISO LBMPs June 5, 2002)
LBMP ($/MW Hr)
Losses
Congestion
LBMP at Reference Bus
LBMP decomposition depends on choice of reference bus
90
80
70
60
50
40
30
20
10
0
-10
LB M P ($/M W Hr)
Los s es
Conges tion
)
(A
T
W
ES
PJ
M
H
O
N
PX
(D
)
R
TH
N
O
N
YC
(J
)
(H
)
LW
M
IL
M
H
K
G
VL
IL
D
(E
)
)
(K
)
H
U
D
LO
N
VL
(G
Q
H
(I)
G
EN
ES
E
(B
)
O
D
W
TR
NYC
D
U
N
C
C
EN
AP
IT
L
L
(C
(F
)
)
Hr 14
LB M P at Referenc e B us
70
60
LMP
components
–
–
–
Energy
Congestion
Losses
50
40
30
20
10
0
Source: NYISO
0
4
8
12
16
20
Hr
24 6
Financially Binding Day-ahead Markets
„
„
„
„
„
„
Not required in Order 2000 but a key element of SMD
Shifts risk of generator non-performance from loads to
generators
Encourages price signals for demand response
Enhances reliability through day-ahead commitments
Currently used in PJM and New York, New England
implementation in Dec 02, missing in ERCOT
Design choices
–
–
–
Centralized unit commitment with multi-part bids (PJM, NY)
Decentralized self-commitment with single part portfolio bids
(CalPX)
General willingness to accept a NY (or PJM) style design despite
complexity of centralized optimization
7
No Balanced Schedules
„
„
The thinking then
– Minimize RTO’s role by separating Power Exchange (PX)
– RTO requires balanced schedule, PX allows participants to
balance their schedules
The thinking now
– Little success with independent power exchanges
– Too many coordination problems in congestion management
– RTO required to operate day-ahead energy market
– No balanced schedules necessary
8
Real-Time Markets
„
„
„
„
Fundamental balancing function for an RTO
General acceptance of ex-post pricing that reflects actual
dispatch
Prices that reflect reflect actual dispatch do not need to use
penalties for uninstructed deviations
However, FERC straw proposal allows penalties when
necessary
9
Transmission Rights
„
Emerging consensus on financial rights over physical rights (although
FERC straw proposal on SMD does not use the term “financial rights”)
„
„
“At the start of Network Access Service, the transmission provider must
offer source-to-sink obligations”
“Upon the request of market participants, the transmission provider must
also offer source-to-sink options and flowgate rights as soon as it is
technically feasible”
„
Should historical customers get initial Transmission Rights?
–
–
„
Option 1: Existing customers receive rights based on historical usage
Option 2: All customers receive a share
If existing customers receive rights, should they be auctioned or allocated?
–
–
–
–
Option 1: Allocation
Option 2: Auction
Option 3: Partial allocation
Option 4: Regional variation
10
RTO Congestion Costs
Congestion Costs
2000
2001
600
$ (million)
500
400
300
200
100
0
New York
PJM
NE
CAISO
CAISO data excludes intra-zonal congestion
New England data represents uplift costs
Source: Market monitor reports
11
PJM FTRs and Revenue Adequacy
P JM F T R P ayo u t
M onthly
A verage
120
100
80
%
60
40
20
0
Jan- Feb- M ar- A pr- M ay - Jun01
01
01
01
01
01
Jul- A ug- S ep- O c t- Nov- Dec 01
01
01
01
01
01
PJM Deficient/Excess Rents
15
$ (millions)
10
5
0
-5
Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec01
01
01
01
01 01
01
01
01
01
01
01
-10
-15
Source: PJM
12
CA FTR Auctions
CAISO FTR Auctions
Malin
90
80
Celilo (NOB)
Humboldt
$ (millions)
Delta (Cascade)Captain Jack
Summit
North Bay
NP15
Geysers
(230kV)
Silver Peak
San Francisco
Greater Bay Area
Fresno
19 paths
9,976 MW
2001
Owens (Inyo) (LADWP)
Mead
McCullough (LADWP)
2002
40,000
Four Corners
Moenkopi
Eldorado Merchant
Laughlin
SP15
ZP26
70
60
50
40
30
20
10
0
35,000
30,000
No FTRs on Path 15
LADWP
LA Orange County
Zone
Scheduling Point
Retained Node
Parker
AVE42
Coachella (Mirage)
ElCentro
Imp Val
IID
San Diego
Tijuanna
La Rosito
Blythe
Palo Verde
MW
25,000
Sylmar
Victorville
20,000
15,000
10,000
N.Gila (PV)
N.Gila (69kV)
5,000
0
FTRs
Source: CAISO
Total MW
13
ERCOT FTR Auctions
ERCOT
ERCOT TCR Auctions
80
Graham
$ (millions)
70
60
North
Parker
Temple
50
40
West
30
Houston
Dow
20
Sandow
10
0
Annual auction
South
Monthly auctions (Feb-Jun)
Stp
TCR Shift Factors
p = H 'µ
p= LMPs
µ= Shadow prices
H′= Shift factor matrix
H =
'
CM
Zone
W-N
Graham to
Parker
G to P
S-N
Sandow to
Temple
S to T
S-H
Stp to Dow
Stp to D
Houston
0.027650492
0.204409959
-0.169735742
North
0.004613148
0.004989182
-0.003475207
South
0.04591408
0.396734818
0.190336475
West
0.580664652
0.032884411
0.016168457
Source: ERCOT
14
Capacity Markets
„
Three distinct approaches
–
Energy only markets
„
–
Capacity payments
„
–
Difficult to guess “correct capacity price”
Capacity obligations for Load Serving Entities (LSE)
„
„
„
„
Price caps that disallow scarcity rents make this approach
difficult in the current political climate
RTO sets reserve margin and quantity obligation for each LSE
based on peak demand
Capacity price is determined by market
Markets must be forward looking (2- years) and long-term (e.g,
annual/seasonal) to make them meaningful
Other recent proposals
–
Call options (combines generation adequacy and price
insurance)
15
Market Power Mitigation
„
Market power mitigation, not price management
–
–
–
–
–
–
Encourage structural solutions, including divestiture
Should minimize refunds and ex-post price revisions
Damage control price caps a reality until a reasonable
demand response is available
Damage control price cap should be sufficiently high to allow
recovery of scarcity rents and elicit a demand response
Load pockets handled through RMR contracts
Parameters in price screens need to be selected carefully
„
„
„
Check for two conditions (1) impact test: prices jump suddenly
by predefined tolerance (2) conduct test: bidding behavior
changes suddenly (e.g., offer price exceeds 90 day-average by
X% or Y$)
If both conditions are true, mitigate offer price
Does not apply to small portfolios, hydro resources and if prices
fall below predefined threshold
16
RTO Consolidation
„
„
„
„
„
RTO consolidation motivated by desire to eliminate seams between
markets for increased efficiency and stable markets
Ultimate goal to create around five RTOs that cover the United States
Recent cost-benefit studies (PJM, Mirant, LECG, ICF) indicate clear
benefits to customers from a common market in the Northeast and
Midwest
Some regions will see lower prices (e.g. New York) while others may
see some increase in prices
NERTO common market
–
–
„
Common power market for ISO-NE and NYISO (Peak load 56,141 MW)
Possible participation by Canadian provinces
MISO-PJM-SPP common market (expected 2005)
–
–
More than 5000 generators
Will test the limits of large scale computation
„
Largest unit commitment tests to date have used around 3000 generators
17
RTO Structures
RTO
ITC/Transco
„
„
„
„
For-profit ITCs operating under a non-profit RTO can address
independence concerns
Is it possible to allow ITC to perform some RTO functions
without compromising efficiency?
What happens to ITC value proposition if RTO performs all
functions?
How should PBRs be established under an LMP regime?
18
Existing and Emerging RTOs
IMO
IMO
RTO West
MISO
Cal ISO
WestConnect
PJM
PJM-W
PJM-S
ISO-NE
NY/NE
NYISO
GridSouth (?)
SETrans
SPP
ERCOT
HQ
GridFlorida
MISO
PJM
Standard Market Design (SMD)
based largely on PJM, New York ISO
PJM, NYISO, ISO-NE, CAISO & ERCOT,
& MISO currently “operational” with varying
elements of SMD
19
Power Market Liquidity
Cinergy Into
MW Daily volumes (non RTO hubs)
Entergy Into
PV
Mid-C
30,000
25,000
MWh
20,000
15,000
10,000
5,000
NE
MW Daily volumes (RTO markets)
NY Zone G
PJM W
Jul-02
May-02
Mar-02
Jan-02
Nov-01
Sep-01
Jul-01
May-01
Mar-01
Jan-01
Nov-00
Sep-00
Jul-00
May-00
Mar-00
Jan-00
Nov-99
Sep-99
0
NP15
SP15
18,000
16,000
MWh
14,000
12,000
10,000
8,000
6,000
4,000
2,000
Source: MW Daily
Jul-02
Jun-02
May-02
Apr-02
Mar-02
Feb-02
Jan-02
Dec-01
Nov-01
Oct-01
Sep-01
Aug-01
Jul-01
Jun-01
May-01
Apr-01
Mar-01
Feb-01
Jan-01
Dec-00
Nov-00
0
20