electricity market design: financial transmission rights

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electricity market design: financial transmission rights
ELECTRICITY MARKET DESIGN:
FINANCIAL TRANSMISSION RIGHTS
William W. Hogan
Mossavar-Rahmani Center for Business and Government
John F. Kennedy School of Government
Harvard University
Cambridge, Massachusetts 02138
Launching Conference of the CIDE Electricity Policy Group (CEPG)
The Foundations of the New Mexican Electricity Market
Mexico
April 14, 2016
ELECTRICITY MARKET
Electricity Restructuring
The case of electricity restructuring presents examples of fundamental problems that challenge
regulation of markets.

Marriage of Engineering and Economics.
o Loop Flow.
o Reliability Requirements.
o Incentives and Equilibrium.

Devilish Details.
o Market Power Mitigation.
o Coordination for Competition.

Jurisdictional Disputes.
o US State vs. Federal Regulators.
o European Subsidiarity Principle.
1
ELECTRICITY MARKET
Order 888 and Open Access
Order 888, 1996: “Promoting Wholesale Competition Through Open Access Non-discriminatory
Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities
and Transmitting Utilities.” The Order followed from a lengthy debate about the many details of
electricity markets.
“Today the Commission issues three final, interrelated rules designed to remove impediments to
competition in the wholesale bulk power marketplace … . The legal and policy cornerstone of these
rules is to remedy undue discrimination in access to the monopoly owned transmission wires that
control whether and to whom electricity can be transported in interstate commerce.” (FERC, Order 888,
April 24, 1996, p. 1.)
 What did Order 888 anticipate for the development of electricity market design?
 What other electricity market design options are available to achieve the objectives of open
access and Order 888?
 Is it possible to reform Order 888 to achieve the open access objective to remove
impediments to competition?
Can open access not be about market design?
2
ELECTRICITY MARKET
Order 888 and the Contract Path
Under Order 888 the FERC made a crucial choice regarding a central complication of the electricity
system.
“A contract path is simply a path that can be designated to form a single continuous electrical path
between the parties to an agreement. Because of the laws of physics, it is unlikely that the actual
power flow will follow that contract path. … Flow-based pricing or contracting would be designed to
account for the actual power flows on a transmission system. It would take into account the
"unscheduled flows" that occur under a contract path regime.” (FERC, Order 888, April 24, 1996, footnotes 184185, p. 93.)
Why is this important?
3
NETWORK INTERACTIONS
Loop Flow
Electric transmission network interactions can be large and important.

Conventional definitions of network "Interface" transfer capacity depend on the assumed
load conditions.

Transfer capacity cannot be defined or guaranteed over any reasonable horizon.
POWER TRANSFER CAPACITY VARIES WITH LOAD
(WITH IDENTICAL LINKS, TRUE CONSTRAINT ON LINE FROM OLDGEN TO BIGTOWN)
Is The "Interface" Transfer Capacity
900 MW?
Or
OLDGEN
NEWGEN
0 MW
900 MW
0
30 W
M
600
=m
ax
600 MW
600
=m
ax
BIGTOWN
1800 MW
INTERFACE
0 MW
OLDGEN
INTERFACE
300 MW
900 MW
1800 MW?
M
00
12
1800 MW
W
BIGTOWN
NEWGEN
4
NETWORK INTERACTIONS
Loop Flow
There is a fatal flaw in the old "contract path" model of power moving between locations along a
designated path. The network effects are strong. Power flows across one "interface" can have a
dramatic effect on the capacity of other, distant interfaces.
Transmission Impacts Vary Across the Eastern System
Transfer Interface Impact (1000 MW)
Transfer Capability Impacts
1000 MW from VACAR to BG&E/PEPCO
0.2
Contract Path
Assumption
(Impact = 0)
0.0
-0.2
-0.4
-0.6
-0.8
-1.0
-1.2
-1.4
-1.6
-1.8
-2.0
-2.2
-2.4
-2.6
EC
A
R
to
M
EC
AR
AA
to
VP
C
DU
TV
MA
A
KE
EC
W
N
to
AC
/C
.E
DU YPP
AR
P&
CA
to
KE
to
to
VP
Lt
R
M
DU
/C
oV
to
P& AA
OH
KE
P
C
L
/C
P&
L
Interface in Eastern Interconnected System
Source: VEM, Winter Operating Study, December 1993.
5
TRANSMISSION CAPACITY
Definition
Electricity restructuring requires open access to the transmission essential facility. A fully
decentralized competitive market would benefit from tradable property rights in the transmission
grid. However, the industry has never been able to define workable transmission property rights:
"A primary purpose of the RIN is for users to learn what Available Transmission Capacity
(ATC) may be available for their use. Because of effects of ongoing and changing
transactions, changes in system conditions, loop flows, unforeseen outages, etc., ATC is
not capable of precise determination or definition. "
Comments of the Members of the PJM Interconnection, Request for Comments Regarding Real-Time Information Networks,
Docket No. RM95-9-000, FERC, July 5, 1995, p. 8.
The problems are not unique to the U. S. They same issue arises in any meshed network, as in
Europe and the regulations for European Transmission System Operators [ETSO]:
"Does the draft Regulation set the right objective when it requires TSOs to compute and
publish transfer capacities? ETSO says both yes and no …in many cases the (Net
transfer capacity or NTCs) may be a somewhat ambiguous information…The core of the
difficulty raised by transfer capacities lies in the fact that they do not obey usual
arithmetic: 'it makes no sense to add or subtract the NTC values…' Put it in other ways,
in order to compute the maximal use of the network, one needs to make assumptions on
the use of the network! This definition is restated and elaborated in ETSO (2001a) (p.
6)."
J. Boucher and Y. Smeers, "Towards a Common European Electricity Market--Paths in the Right Direction…Still Far From an
Effective Design," Belgium. September, 2001, pp. 30-31. (see HEPG web page, Harvard University)
6
ELECTRICITY MARKET
Order 888 and the Contract Path
Under Order 888 the FERC made a crucial choice regarding a central complication of the electricity
system.
“A contract path is simply a path that can be designated to form a single continuous electrical path
between the parties to an agreement. Because of the laws of physics, it is unlikely that the actual
power flow will follow that contract path. … Flow-based pricing or contracting would be designed to
account for the actual power flows on a transmission system. It would take into account the
"unscheduled flows" that occur under a contract path regime.” (FERC, Order 888, April 24, 1996, footnotes 184185, p. 93.)
“We will not, at this time, require that flow-based pricing and contracting be used in the electric
industry. In reaching this conclusion, we recognize that there may be difficulties in using a
traditional contract path approach in a non-discriminatory open access transmission environment,
as described by Hogan and others. At the same time, however, contract path pricing and
contracting is the longstanding approach used in the electric industry and it is the approach familiar
to all participants in the industry. To require now a dramatic overhaul of the traditional approach
such as a shift to some form of flow-based pricing and contracting could severely slow, if not derail
for some time, the move to open access and more competitive wholesale bulk power markets. In
addition, we believe it is premature for the Commission to impose generically a new pricing regime
without the benefit of any experience with such pricing. We welcome new and innovative proposals,
but we will not impose them in this Rule.” (FERC, Order 888, April 24, 1996, p. 96.)
Hence, although the fictional contract path approach would not work in theory, maintaining the
fiction would be less disruptive in moving quickly to open access and an expanded competitive
market!
7
ELECTRICITY MARKET
Transmission Management
Defining and managing transmission usage is a principal challenge in electricity markets.
Transmission Capacity Definitions
Contract Path
Contract Path Fiction
OASIS Schedules
and TLR
Flow-Based Paths
Point-to-Point
Parallel Flows
Flows Implicit
Flowgate Rights
FGRs
Financial Transmission
Rights
FTRs
8
ELECTRICITY MARKET
Pool Dispatch
An efficient short-run electricity market determines a market clearing price based on conditions of
supply and demand balanced in an economic dispatch. Everyone pays or is paid the same price.
SHORT-RUN ELECTRICITY MARKET
Energy Price
Short-Run
Marginal
Cost
(¢/kWh)
Price at
7-7:30 p.m.
Demand
7-7:30 p.m.
Price at
9-9:30 a.m.
Price at
2-2:30 a.m.
Demand
9-9:30 a.m.
Demand
2-2:30 a.m.
Q1
Q2
Qmax
MW
9
NETWORK INTERACTIONS
Locational Spot Prices
The natural extension of a single price electricity market is to operate a market with locational spot
prices.

It is a straightforward matter to compute "Schweppe" spot prices based on marginal costs
at each location. (Schweppe, Caramanis, Tabors, & Bohn, 1988)

Transmission spot prices arise as the difference in the locational prices.
LOCATIONAL SPOT PRICE OF "TRANSMISSION"
Energy Price
Short-Run
Marginal
Cost
(¢/kWh)
Price differential =
Demand
MW
A Pa = 51
Marginal losses
+ Constraint prices
Constraint
B
Energy Price
Pb = 66
C
(¢/kWh)
Short-Run
Marginal
Cost
Demand
Energy Price
Pc = 55
Short-Run
Marginal
Cost
(¢/kWh)
MW
Demand
MW
Price of "Transmission" from A to B = Pb - Pa = 15
Price of "Transmission" from C to A = Pa - Pc = -4
10
NETWORK INTERACTIONS
Locational Spot Prices
RTOs operate spot markets with locational prices. For example, PJM updates prices and dispatch
every five minutes for over 10,000 locations. Locational spot prices for electricity exhibit
substantial dynamic variability and persistent long-term average differences.
Illinois $529.71, North Dakota -$18.83
From MISO-PJM Joint and Common Market, http://www.jointandcommon.com/ for March 16, 2013, 3:05pm.
11
NETWORK INTERACTIONS
Financial Transmission Rights
A mechanism for hedging volatile transmission prices can be established by defining financial
transmission rights to collect the congestion rents inherent in efficient, short-run spot prices. (W.
W. Hogan, 2013)
NETWORK TRANSMISSION FINANCIAL RIGHTS
A Pa = 51
Constraint
B
Pb = 66
C
Pc = 55
Price of "Transmission" from A to B = Pb - Pa = 15
Price of "Transmission" from A to C = Pc - Pa = -4
DEFINE TRANSMISSION CONGESTION CONTRACTS BETWEEN LOCATIONS.
FOR SIMPLICITY, TREAT LOSSES AS OPERATING COSTS.
RECEIVE CONGESTION PAYMENTS FROM ACTUAL USERS; MAKE
CONGESTION PAYMENTS TO HOLDERS OF CONGESTION CONTRACTS.
TRANSMISSION CONGESTION CONTRACTS PROVIDE PROTECTION
AGAINST CHANGING LOCATIONAL DIFFERENCES.
12
ELECTRICITY MARKET
A Consistent Framework
The example of successful central coordination, CRT, Regional Transmission Organization (RTO)
Millennium Order (Order 2000) Standard Market Design (SMD) Notice of Proposed Rulemaking
(NOPR), “Successful Market Design” provides a workable market framework that is working in
places like New York, PJM in the Mid-Atlantic Region, New England, the Midwest, California, SPP,
and Texas. This efficient market design is under (constant) attack.
“Locational marginal pricing (LMP) is the electricity spot pricing model that serves as the
benchmark for market design – the textbook ideal that should be the target for policy makers. A
trading arrangement based on LMP takes all relevant generation and transmission costs
appropriately into account and hence supports optimal investments.”(International Energy Agency,
Tackling Investment Challenges in Power Generation in IEA Countries: Energy Market Experience, Paris, 2007, p. 116.)
The RTO NOPR Order SMD NOPR "Successful Market Design"
Contains a Consistent Framework
A Structure for Forward Market Scheduling,
Spot Market Dispatch & Settlements
Bilateral Schedules
Scheduling Transactions
Settlements
Locational
P, Q
¢
Coordinated
Spot Market
Bid-Based,
Security-Constrained,
Economic Dispatch
with Nodal Prices
Market-Driven Investment
License Plate Access Charges
at Difference in Nodal Prices
Start up Costs +
MW
Contract
$
T
Schedules
Reliability
Commitments
¢
Schedule Bids
kWh $
Balancing Bids
kWh $
07/05
07/02
12/99
5/99
¢
MW
Dispatch
Commitments
Q
Q
...
MW
Locational
p, q
Excess
Congestion
$
Financial
Transmission
Rights
T
Q
Generators
&
Customers
¢
MW
Financial Transmission Rights
(TCCs, FTRs, FCRs, CRRs, ...)
Scheduling
Settlements
P, Q, T
Excess
Congestion
$
Imbalance
$
Balancing
Settlements
p, q, Q
Balancing Transactions
13
FINANCIAL TRANSMISSION RIGHTS
Revenue Adequacy
The market equilibrium satisfies a “no arbitrage” condition implies that feasible financial
transmission rights must be revenue adequate.
1
Let y be any other feasible set of net loads, such that there is a u1 with:
 
K  y , u   0,
L y1 , u1   t y1  0,
1
1
u1  U .
Then, assuming concavity for the benefits function, we can show:


p t y*  y1  0.
1
If y corresponds the net loads implied by a set of simultaneously feasible financial transmission rights,
then the revenues from the current spot market congestion rents must be at least as large as the
obligations under the set of FTRs. This result holds for any economic dispatch and any configuration of
FTRs. This is unlike any set of physical transmission rights where “Because of effects of ongoing and
changing transactions, changes in system conditions, loop flows, unforeseen outages, etc., ATC is not
capable of precise determination or definition.”
14
TRANSMISSION INVESTMENT
FTR Allocation and Efficient Investment
Investment in the transmission grid should create new economic capacity. The allocation of FTRs
under a feasibility rule mitigates incentives for inefficient transmission investment. (Kristiansen &
Rosellón, 2006)(W. Hogan, Rosellon, & Vogelsang, 2010)
Feasibility Test: The aggregate of all financial transmission rights defines a set of net power
injections in the grid. The set of contracts is feasible if these injections and their
associated power flows satisfy all the system constraints.
Feasibility Rule: The grid expansion investor selects a set of new financial transmission rights
with the restriction that both the new and the old FTRs will be simultaneously
feasible after the system expansion.
 If the set of FTRs is feasible then the future payments required for the FTRs will never exceed the
congestion revenues collected through the spot market dispatch.
 Future investments in the grid cannot reduce the welfare of aggregate use according to the
existing FTRs. Hence, exposure to rent transfers is limited to the spot market.
 (Bushnell & Stoft, 1997). If PTP-FTR obligations initially match dispatch in the aggregate and new
FTRs are allocated under the feasibility rule, then the increase in social welfare will be at least as
large as the ex post value of new contracts.
 (Bushnell & Stoft, 1996). If PTP-FTR obligations match dispatch individually, then the allocation of
FTRs under the feasibility rule ensures that no one can benefit from a network investment that
reduces social welfare.
15
NETWORK PRICING EXAMPLES
Zones (cont.)
With loops in a network, market information could be transformed easily into a hub-and-spoke
framework with locational price differences on a spoke defining the cost of moving to and from the
local hub, and then between hubs. This simplifies without distorting the prices.
Contract Network Connects with Real Network
Determine Locational Prices for Real Network; Implement
Financial Transmission Rights and Trading on Contract Network
Contract Network
Local Bus
Zonal Hub
Real Network
16
NETWORK PRICING EXAMPLES
Transmission Congestion Contracts
The simultaneous set of transmission congestion contracts defines the "Available Transmission
Capacity." Consider the example network with two feasible sets of transmission congestion
contracts (TCC) for hub at "O".
A Tight Constraint from Bus O to Bus M Yields a Negative Price
150 MW
25 MW
200 MW
25 MW
New IPP
Green LDC
Orange LDC Red LDC
L
4
50 MW
70 MW
Blue LDC
C
7
W
5
12
3.5
5
10.75
7
Y
W
0M
18
30
M
W
W
M
3.5
P
W
M
N
X
"D-O"
180
160
"O-X"
180
160
"M-O"
30
10
"N-O"
30
70
Z
V
25 MW
3.25
W
M
0
10
TCC 2
(MW)
0
10
MW
70
90 MW
2
Old Nuke
5 MW
25 MW
50 MW
-0.75
90 MW
O
90 MW
B
M
15 MW
Tan LDC
W
M
15 M
W
D
30 MW
45
W
0M
10
90 MW
90 MW
TCC 1
(MW)
Old Gas
320 MW
30
25 MW
W
M
New Gas
A
From-To
Pink LDC
3
New Coal
Yellow LDC
3.25
New Gen.
Either set of TCCs would be feasible by itself in this network. However, subsets of the contracts
may not be feasible. Hence, the definition of available transmission capacity would be as a
simultaneously feasible set of contracts.
17
NETWORK PRICING EXAMPLES
Transmission Congestion Contracts
The congestion costs collected will always be sufficient to meet obligations under transmission
congestion contracts. Excess congestion rents, after paying TCC obligations, could be returned
under a sharing formula.
A Tight Constraint from Bus O to Bus M Yields a Negative Price
200 MW
25 MW
50 MW
70 MW
Pink LDC
New IPP
Green LDC
Orange LDC Red LDC
L
4
Blue LDC
C
7
W
5
12
3.5
Old Gas
320 MW
25 MW
30
7
Y
30
M
-0.75
2
0
10
Old Nuke
P
W
M
X
Z
V
N
25 MW
3.25
"D-O"
180
160
"O-X"
180
160
"M-O"
30
10
"N-O"
30
70
W
M
MW
70
90 MW
90 MW
D
B
5 MW
25 MW
W
M
50 MW
0
10
O
45
15 M
W
30 MW
15 MW
Tan LDC
90 MW
90 MW
90 MW
TCC 2
(MW)
W
0M
18
M
W
W
M
3.5
W
0M
10
TCC 1
(MW)
5
10.75
W
M
New Gas
A
From-To
150 MW
25 MW
3
New Coal
Yellow LDC
3.25
New Gen.
Load
at "L"
Bus Prices
¢/kWh
MW
"D"
"M"
"N"
Total
Rents $
"O"
TCC 1
TCC 2
"X"
0
3.50
3.75
3.25
3.50
7.00
6300
6300
5750
50
3.50
5.58
3.25
4.15
7.00
6300
6138
6084
150
3.50
10.75
3.25
-0.75
7.00
10950
1650
1650
18
TRANSMISSION CONGESTION CONTRACT
Auction
Transmission congestion contracts for the grid could be defined and awarded through an open
auction. The collective bids would define demand schedules for TCCs. The concurrent auction
would respect the transmission system constraints to assure simultaneous feasibility.
Concurrent Auction of Transmission Congestion Contracts
(WITH IDENTICAL LINKS, CONSTRAINT ON LINE 1-3)
P
6
TCC Bids
1-3
P
6
TCC Bids
2-3
3.6
1.8
480
1200
TCC
480 MW
840
1
600=max
3
1200
TCC
480+840 = 1320 MW
120 MW
720 MW
2
840 MW
TCCs from 1 -> 3 awarded for 480 MW at price 3.6
TCCs from 2 -> 3 awarded for 840 MW at price 1.8
19
TRANSMISSION CONGESTION CONTRACT
Revenue Adequacy
With spot locational prices, transmission congestion contracts provide price protection. Even with
changing load patterns, the congestion revenues collected by the system operator will be at least
enough to cover the obligations for all the TCCs.
Constraints with Out-Of-Merit Costs
System Operator Revenues
(WITH IDENTICAL LINKS, CONSTRAINT ON LINE 1-3)
Quantity
Price
$
Bus 2 generation cost goes above 2.3
Load and flows change; constraint binds
Bus 1
900
2
($1,800)
Bus 2
0
2.3
$0
Bus 3
2100
2.6
($5,460)
Bus 3
-3000
2.6
$7,800
TCC 1-3
480
0.6
($288)
TCC 2-3
840
0.3
($252)
Price includes congestion charge
900 MW
1
600=max
3
3000 MW
P=2.0 + 0.6 = 2.6
P=2
2100 MW
300 MW
300 MW
2
P = 2.0 + 0.3 = 2.3
0 MW
Net Total
$0
20
NETWORK INTERACTIONS
Locational Spot Prices
Combining contracts for differences between parties, and financial transmission rights offered by
the system operator, the electricity market can support efficient operations, open access, nondiscrimination and long term contracts.
Long-Term
Power Contracts
Generators
Customers
Long-Term
Transmission
Contracts
Short-Term
Power Sales
Short-Term
Power Purchases
Power Pool
Price
A
Pa =
Time
Price
B
Pb =
C
Price
Pc =
Time
Time
21
ELECTRICITY MARKET
Financial Transmission Rights
Financial Transmission Rights (FTRs), including Transmission Congestion Contracts (TCCs) and
Congestion Revenue Rights (CRRs), present a variety of issues.
 Definitions.
o Duration.
o Obligations vs. Options.
o Auction Revenue Rights.
o Sequential Markets.
o Expansion Rules.
 Revenue Adequacy.
o Theory: Simultaneous Feasibility Ensures Full Funding with Same Grid.
o Practice: Carve Outs, Outages and Loop Flow Forecasts can Affect Feasibility.
 Market Performance.
o Arbitrage and FTR Prices.
o Gaming and Credit Risks.
o Market Power Interactions.
 Investment and Trading.
o Grid Expansion.
o Continuous Trading: Nodal Exchange.
( http://www.nodalexchange.com/about_nodal/overview.php )
22
References
Bushnell, J. B., & Stoft, S. E. (1996). Electric grid investment under a contract network regime. Journal
of
Regulatory
Economics,
10(1),
61–79.
Retrieved
from
http://ezpprod1.hul.harvard.edu/login?url=http://search.ebscohost.com/login.aspx?direct=true&db=bth&AN=16
615451&site=ehost-live&scope=site
Bushnell, J. B., & Stoft, S. E. (1997). Improving private incentives for electric grid investment. Resource
and Energy Economics, 19(1-2), 85–108. doi:10.1016/S0928-7655(97)00003-1
Hogan, W., Rosellon, J., & Vogelsang, I. (2010). Toward a combined merchant-regulatory mechanism
for electricity transmission expansion. Journal of Regulatory Economics (Vol. 38).
doi:10.1007/s11149-010-9123-2
Hogan, W. W. (2013). Financial Transmission Rights: Point-to Point Formulations. In J. Rosellón & T.
Kristiansen (Eds.), Financial Transmission Rights (Vol. 7, pp. 1–48). Springer London.
doi:10.1007/978-1-4471-4787-9_1
Kristiansen, T., & Rosellón, J. (2006). A merchant mechanism for electricity transmission expansion.
Journal of Regulatory Economics, 29(2), 167–193. doi:10.1007/s11149-006-6034-3
Schweppe, F. C., Caramanis, M. C., Tabors, R. D., & Bohn, R. E. (1988). Spot pricing of electricity.
Kluwer
Academic
Publishers.
Retrieved
from
http://books.google.com/books?id=Sg5zRPWrZ_gC&pg=PA265&lpg=PA265&dq=spot+pricing+of+el
ectricity+schweppe&source=bl&ots=1MIUfKBjBk&sig=FXe_GSyf_V_fcIuTmUtH7mKO_PM&hl=en&e
i=Ovg7Tt66DO2x0AH50aGNCg&sa=X&oi=book_result&ct=result&resnum=3&ved=0CDYQ6AEwAg
#v=onep
23
William W. Hogan is the Raymond Plank Professor of Global Energy Policy, John F. Kennedy School of Government, Harvard University. This
paper draws on research for the Harvard Electricity Policy Group and for the Harvard-Japan Project on Energy and the Environment. The author
is or has been a consultant on electric market reform and transmission issues for Allegheny Electric Global Market, American Electric Power,
American National Power, Aquila, Atlantic Wind Connection, Australian Gas Light Company, Avista Corporation, Avista Utilities, Avista Energy,
Barclays Bank PLC, Brazil Power Exchange Administrator (ASMAE), British National Grid Company, California Independent Energy Producers
Association, California Independent System Operator, California Suppliers Group, Calpine Corporation, CAM Energy, Canadian Imperial Bank of
Commerce, Centerpoint Energy, Central Maine Power Company, Chubu Electric Power Company, Citigroup, City Power Marketing LLC, Cobalt
Capital Management LLC, Comision Reguladora De Energia (CRE, Mexico), Commonwealth Edison Company, COMPETE Coalition, Conectiv,
Constellation Energy, Constellation Energy Commodities Group, Constellation Power Source, Coral Power, Credit First Suisse Boston, DC
Energy, Detroit Edison Company, Deutsche Bank, Deutsche Bank Energy Trading LLC, Duquesne Light Company, Dyon LLC, Dynegy, Edison
Electric Institute, Edison Mission Energy, Electricity Corporation of New Zealand, Electric Power Supply Association, El Paso Electric, Energy
Endeavors LP, Exelon, Financial Marketers Coalition, FirstEnergy Corporation, FTI Consulting, GenOn Energy, GPU Inc. (and the Supporting
Companies of PJM), GPU PowerNet Pty Ltd., GDF SUEZ Energy Resources NA, Great Bay Energy LLC, GWF Energy, Independent Energy
Producers Assn, ISO New England, Koch Energy Trading, Inc., JP Morgan, LECG LLC, Luz del Sur, Maine Public Advocate, Maine Public
Utilities Commission, Merrill Lynch, Midwest ISO, Mirant Corporation, MIT Grid Study, Monterey Enterprises LLC, MPS Merchant Services, Inc.
(f/k/a Aquila Power Corporation), JP Morgan Ventures Energy Corp., Morgan Stanley Capital Group, Morrison & Foerster LLP, National
Independent Energy Producers, New England Power Company, New York Independent System Operator, New York Power Pool, New York
Utilities Collaborative, Niagara Mohawk Corporation, NRG Energy, Inc., Ontario Attorney General, Ontario IMO, Ontario Ministries of Energy and
Infrastructure, Pepco, Pinpoint Power, PJM Office of Interconnection, PJM Power Provider (P3) Group, Powerex Corp., Powhatan Energy Fund
LLC, PPL Corporation, PPL Montana LLC, PPL EnergyPlus LLC, Public Service Company of Colorado, Public Service Electric & Gas Company,
Public Service New Mexico, PSEG Companies, Red Wolf Energy Trading, Reliant Energy, Rhode Island Public Utilities Commission, Round Rock
Energy LP, San Diego Gas & Electric Company, Secretaría de Energía (SENER, Mexico), Sempra Energy, SESCO LLC, Shell Energy North
America (U.S.) L.P., SPP, Texas Genco, Texas Utilities Co, Tokyo Electric Power Company, Toronto Dominion Bank, Transalta, TransAlta
Energy Marketing (California), TransAlta Energy Marketing (U.S.) Inc., Transcanada, TransCanada Energy LTD., TransÉnergie, Transpower of
New Zealand, Tucson Electric Power, Twin Cities Power LLC, Vitol Inc., Westbrook Power, Western Power Trading Forum, Williams Energy
Group, Wisconsin Electric Power Company, and XO Energy. The views presented here are not necessarily attributable to any of those
mentioned, and any remaining errors are solely the responsibility of the author. (Related papers can be found on the web at www.whogan.com ).
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