ELECTRICITY MARKET REFORM:
Market Design and the Green Agenda
William W. Hogan
Mossavar-Rahmani Center for Business and Government
John F. Kennedy School of Government
Harvard University
Cambridge, Massachusetts 02138
Electricity Authority
New Zealand
Wellington, NZ
July 20, 2012
ELECTRICITY MARKET
Going Green
The focus on the electricity sector’s role in addressing climate change through improved
efficiency, development of renewable energy, and use of low carbon fuels creates expanded
demands for and of electricity restructuring.
The transformation envisioned is massive, long term, and affects every aspect of electricity production and
use.
 Uncertain conditions require a broad range of activities to integrate new technology and practices.
 Innovation requires promoting technologies and practices not yet identified or imagined. “Silver
buckshot rather than silver bullets.”
 Smart grids can facilitate smart decisions, but only if the electricity structure provides the right
information and incentives.
o Open access to expand entry and innovation.
o Smart pricing to support the smart grid technologies and information.
o Internalizing externalities, while exploiting the wisdom of crowds.
 Price on carbon emissions.
 Good market design with efficient prices.
 Compatible infrastructure expansion rules.
1
ELECTRICITY MARKET
Pricing and Smart Grids
Policies for smart grids emphasize better deployment of information and incentives. A major
challenge is to improve the information and rationalize the incentives deployed. According to the
White House plan:
“A smarter, modernized, and expanded grid will be pivotal to the United States’ world
leadership in a clean energy future. This policy framework focuses on the deployment of
information and communications technologies in the electricity sector. As they are developed
and deployed, these smart grid technologies and applications will bring new capabilities to
utilities and their customers. In tandem with the development and deployment of high-capacity
transmission lines, which is a topic beyond the scope of this report, smart grid technologies will
play an important role in supporting the increased use of clean energy.
…
This framework is premised on four pillars:
1.
2.
3.
4.
Enabling cost-effective smart grid investments
Unlocking the potential for innovation in the electric sector
Empowering consumers and enabling them to make informed decisions, and
Securing the grid.” 1
At least three of the four pillars imply a need for better pricing structures and signals.
1
Subcommittee on Smart Grid of the National Science and Technology Council, Committee on Technology, A POLICY FRAMEWORK FOR THE 21st
CENTURY GRID: Enabling Our Secure Energy Future, White House, June 13, 2011, p. v.
2
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.
o Physical and Financial Transactions.

Devilish Details.
o Market Power Mitigation.
o Coordination for Competition.
o Transmission Expansion.

Jurisdictional Disputes.
o US State vs. Federal Regulators.
o European Subsidiarity Principle.
3
ELECTRICITY MARKET
Energy Market Design
The US experience illustrates successful market design and remaining challenges for both theory
and implementation.
 Design Principle: Integrate Market Design
and System Operations
Competitive Wholesale Electricity Market Structure
Provide good short-run operating incentives.
long-run
Locational Marginal Prices (LMP)
granularity to match system operations.
with
 Design Implementation: Pricing Evolution
Genco ...
Genco
...
Genco
Genco ...
Genco
Regional Transmission Organization
Poolco
...
Gridco
Gridco
System Operator
Disco
Cust.
Disco
Cust.
...
...
Disco
...
Cust.
Disco
Cust.
Disco
...
Disco
Cust.
...
Cust.
Regulated
Financial Transmission Rights (FTRs).
Genco
Regulated
 Design Framework: Bid-Based, Security
Constrained Economic Dispatch
Generation
and
Transmission
markets
Distribution
Support forward
investments.
Market power mitigation, but better scarcity
pricing to support resource adequacy.
Unit commitment and lumpy decisions with coordination, bid guarantees and uplift payments.
 Design Challenge: Infrastructure Investment
Hybrid models to accommodate both market-based and regulated transmission investments.
Beneficiary-pays principle to support integration with rest of the market design.
4
NETWORK INTERACTIONS
Locational Spot Prices
RTOs operate spot markets with locational prices. For example, PJM updates prices and dispatch
every five minutes for over 8,000 locations. Locational spot prices for electricity exhibit substantial
dynamic variability and persistent long-term average differences.
Minnesota Hub: $131.21/MWh. First Energy Hub: $-1.57/MWh.
From MISO-PJM Joint and Common Market, http://www.jointandcommon.com/ for March 3, 2008, 9:55am. Projected 2011 annual average from 2006
Midwest ISO-PJM Coordinated System Plan.
5
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. 16.)
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
6
ELECTRICITY MARKET
Energy Market Transformation
Market design in RTOs/ISOs is well advanced but still incomplete and under constant stress.2
 Regional Markets Not Fully Deployed
 Reforms of Reforms
Market Power mitigation through offer caps.
California MRTU (April 1, 2009) and ERCOT
Texas Nodal (December 1, 2010) reforms.
 Market Defect: Scarcity Pricing, Extended LMP
Smarter
pricing
to
support
operations,
infrastructure investment and resource adequacy.
 Market Failure: Transmission Investment
- Regulatory mandates for lumpy transmission mixed with market-based investments.
- Design principles for cost allocation to support a mixed market (i.e., beneficiary pays).
 Market Challenge: Address Requirements for Climate Change Policy
2
William W. Hogan, “Electricity Market Structure and Infrastructure,” Conference on Acting in Time on Energy Policy, Harvard University, September
18-19, 2008. (available at www.whogan.com ).
7
ELECTRICITY MARKET
Market Defects and Market Failures
Market design defects and market failures present continuing challenges to long-run success of
restructured electricity markets. A sampling of some of the more important issues includes:
 Pricing Challenges
o Scarcity pricing and resource adequacy
o Fairness and dynamic pricing
 Market Manipulation
o Fraud and misrepresentation.
o Price index manipulation.
o Collusion among market participants.
o Capacity auctions in organized markets.
o Demand response mandates.
 Transmission Expansion
o Hybrid Models of market design
o Transmission cost allocation
8
ELECTRICITY MARKET
Pricing Challenges
Smarter pricing provides an opportunity for enhancing efficiency and the range of alternative
technologies.
 Smarter Pricing Challenges
o
o
o
o
Average energy prices: $50/MWh.
Canonical bid baps: $1,000/MWh.
MISO average value of lost load: $3,500/MWh.
Reliability standard VOLL: $500,000/MWh.
Newark Bay Real-Time LMP Feb. 2010
 Real Time Pricing
200
o There is substantial
geographic and
temporal variability of
real-time prices.
180
160
140
Price ($/MWh)
o Time of Use (TOU)
approximations do not
track real-time prices:
RTP >> CPP > CPR >>
PP >> FR.
120
100
80
60
40
20
0
-20 0
5
10
15
20
25
-40
-60
Hour
9
ELECTRICITY MARKET
Pricing and Demand Response
Early market designs presumed a significant demand response. Absent this demand participation
most markets implemented inadequate pricing rules equating prices to marginal costs even when
capacity is constrained. This produces a “missing money” problem.
SHORT-RUN ELECTRICITY MARKET
Energy
Price
(¢/kWh)
MISO "Unmanagebale" Congestion Pricing
Short-Run
Marginal
Cost
}
Mitigated Price at
Missing
Money
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
Source: David Patton, 2010 State of the Market Report, Midwest ISO, Potomac Economics, May 2011, p. 171.
10
ELECTRICITY MARKET
Pricing and the Missing Money
The “missing money” problem is material and has a significant impact on investment incentives.
Major efforts have been focused on defining new products and better pricing methods to address
the incentives, ensure resource adequacy, and improve efficiency.
 PJM, Missing Money, Combustion
Turbine (1999-2010, per MW-Year).
Payments for CT Peaker
PJM Economic Dispatch
PJM CT 20-year Levelized Fixed Costs
and Net Energy Revenues
Average Net Energy Revenue = $40,943
$140,000
Average Levelized Fixed Cost = $88,317
 Capacity Markets.
PJM, SWIS.
ISONE, NYISO,
 Scarcity Pricing. Operating Reserve
Demand Curve in MISO, NYISO,
ISONE. (MISO FERC Electric Tariff, Volume No. 1,
Paymenst ($/MW-yr)
(PJM, State of Market Report, 2010, Vol. 2, p. 176)
$120,000
$100,000
$80,000
$60,000
$40,000
$20,000
$0
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Year
FC
Energy Revenues
Source: Monitoring Analytics, State of the Market Report, 2010, Table 3-21, Vol. 2, p. 171.
Schedule 28, January 22, 2009.)3
3
“For each cleared Operating Reserve level less than the Market-Wide Operating Reserve Requirement, the Market-Wide Operating Reserve Demand
Curve price shall be equal to the product of (i) the Value of Lost Load (“VOLL”) and (ii) the estimated conditional probability of a loss of load given that a
single forced Resource outage of 100 MW or greater will occur at the cleared Market-Wide Operating Reserve level for which the price is being determined. …
The VOLL shall be equal to $3,500 per MWh.” MISO, FERC Electric Tariff, Volume No. 1, Schedule 28, January 22, 2009, Sheet 2226.
11
ELECTRICITY MARKET
Generation Resource Adequacy
A variety of market rules for spot markets interact to create de jure or de facto price caps. The
resulting “missing money” reduces payments to all types of generation.
A Market Price Duration Curve
P($/MWh)
A Price Cap Results in "Missing Money"
P($/MWh)
Missing Money
Returns for Peak Generator
Returns for Mid-Range Generator
Price Cap
A
A
Returns for Base Load Generator
$85
$85
B
$35
B
$35
C
$15
$15
8760 (Hours)
C
8760 (Hours)
Missing money reduces the payments to all types of generation.
If market prices do not provide adequate incentives for generation investment, the result is a
market failure. The market design defect creates the pressure for regulators to intervene to
mandate generation investment.
12
ELECTRICITY MARKET
Missing Money
Regulated investment and capacity markets make central planners and regulators the decision
makers. High bid caps present a solution that will create more unintended consequences. How
can we think about an “energy only” market alternative?

Installed Capacity. Assuming it is impossible to provide adequate scarcity pricing, interventions
focus on regulation and installed capacity requirements.
o Emphasis on physical capacity and planning targets. This seems natural and innocuous, but
the physical perspective leads to a host of market design problems.
o Requirement for longer-term regulatory commitments and decisions. Substantial payments
must come through the regulatory decision, investment requires the commitment.
o Assumes there is some method for defining and ensuring transmission deliverability. If we
knew how to do this, everything would be easier. But the electricity network makes this difficult.
o Experience reveals unintended consequences and renews interest in better scarcity pricing.

High Bid Caps. Making the market safe for market power.
o Requires a relaxation of market power mitigation policies during times of scarcity.
o Requires regulators to deliver on promises not to intervene when the crisis occurs.

Scarcity Pricing. Suspending disbelief, consider better scarcity pricing through operating reserve
demand curves.
o An “energy only” market without an installed capacity requirement, but with alternative
regulatory requirements.
o Or “belts and suspenders” with better scarcity pricing that supports an installed capacity
system.
13
ELECTRICITY MARKET
Generation Resource Adequacy
A workable “energy only” market would eliminate the “missing money” problem and provide an
alternative to the growing prescriptions of installed capacity markets. The concept is not that there
should be no market interventions. But the interventions should not overturn the market.
An “Energy Only” Market Outline

Implicit demand for inflexible load would define the opportunity costs as the average value
of lost load (VOLL).
An Illustrative Demand for Electricity
Price
Responsive
Demand
Inflexible
Demand
Total
Demand
P ($/MWh)
P ($/MWh)
P ($/MWh)
$20,000
$20,000
$20,000
+
=
$10,000
$10,000
$10,000
$30
$30
30,000
Q (MW)
$30
15,000
Q(MW)
Demand
45,000
Q(MW)
Involuntary curtailment of inflexible demand has an opportunity cost at
the average value of lost load (VOLL).
14
ELECTRICITY MARKET
Generation Resource Adequacy
… An “Energy Only” Market Outline

Operating reserve demand curve would reflect capacity scarcity.
Illustrative Reserve Demand
P ($/MWh)
$20,000
Reserve
Demand
3%
$10,000
$30
Energy
Demand
7%
Q(MW)
There is a minimum level of operating reserve (e.g., 3%) to protect
against system-wide failure. Above the minimum reserve, reductions
below a nominal reserve target (e.g., 7%) are price senstive.
15
ELECTRICITY MARKET
Generation Resource Adequacy
Market clearing with integrated operating reserve demand curve reduces or eliminates the
“missing money.”
Normal "Energy Only" Market Clearing
P ($/MWh)
$20,000
$10,000
Scarcity "Energy Only" Market Clearing
P ($/MWh)
Generation
Supply
Energy +
Reserves
$30
$20,000
$10,000
$7,000
Generation
Supply
Energy +
Reserves
$30
Q(MW)
When demand is low and capacity available,
reserves hit nominal targets at a low price.
Q(MW)
When demand is high and reserve reductions apply,
there is a high price.
16
ELECTRICITY MARKET
Operating Reserve
The underlying models of operating reserve demand curves differ across RTOs. One need is for a
framework that develops operating reserve demand curves from first principles to provide a
benchmark for the comparison of different implementations.

Operating Reserve Demand Curve Components. The inputs to the operating reserve demand
curve construction can differ and a more general model would help specify the result.

Locational Differences and Interactions. The design of locational operating reserve demand
curves presents added complications in accounting for transmission constraints.

Economic Dispatch. The derivation of the locational operating demand curves has implications for
the integration with economic dispatch models for simultaneous optimization of energy and
reserves.
A series of approximations to a probabilistic unit commitment and economic dispatch models
provides a framework for incorporating scarcity pricing and operating reserve demand curves. The
resulting model is a workable extension of existing unit commitment and economic dispatch
formulations.
17
ELECTRICITY MARKET
Smarter and Better Pricing
Improved pricing through an explicit operating reserve demand curve raises a number of issues.
Demand Response: Better pricing implemented through the operating reserve demand curve would provide an
important signal and incentive for flexible demand participation in spot markets.
Price Spikes: A higher price would be part of the solution. Furthermore, the contribution to the “missing money” from
better pricing would involve many more hours and smaller price increases.
Practical Implementation: The NYISO, ISONE and MISO implementations dispose of any argument that it would be
impractical to implement an operating reserve demand curve. The only issues are the level of the appropriate price and
the preferred model of locational reserves.
Operating Procedures: Implementing an operating reserve demand curve does not require changing the practices of
system operators. Reserve and energy prices would be determined simultaneously treating decisions by the operators as
being consistent with the adopted operating reserve demand curve.
Multiple Reserves: The demand curve would include different kinds of operating reserves, from spinning reserves to
standby reserves.
Reliability: Market operating incentives would be better aligned with reliability requirements.
Market Power: Better pricing would remove ambiguity from analyses of high prices and distinguish (inefficient) economic
withholding through high offers from (efficient) scarcity pricing derived from the operating reserve demand curve.
Hedging: The Basic Generation Service auction in New Jersey provides a prominent example that would yield an easy
means for hedging small customers with better pricing.
Increased Costs: The higher average energy costs from use of an operating reserve demand curve do not automatically
translate into higher costs for customers. In the aggregate, there is an argument that costs would be lower.
18
ELECTRICITY MARKET
Scarcity Pricing and Volatility
Inadequate scarcity pricing dampens real-time price volatility, and has a material impact on
incentives for innovation. Fixed rates, including pre-determined time-of-use rates, dampen
volatility. Levelized rates and socialized costs eliminate volatility. Accurate scarcity prices would
capture the marginal welfare effects of consumption and generation. Assuming cost recovery on
average, incomplete scarcity pricing implies various forms of inefficiency.
 Energy Efficiency and Distributed Generation. With levelized rates, passive energy efficiency
changes such as insulation are efficient only for customers with the average load profile. Customer
load profiles are heterogeneous, so there is too little or too much incentive for most. For distributed
generation and active load management, such as turning down air conditioning when away from
home, sees too little incentive when it is needed most during high periods of (implicit) scarcity prices.
 Load Management. Changing the load profile to arbitrage price differences over time depends on
exploiting price volatility. Suppressing and socializing scarcity prices dampens incentives for load
management.
o Load Shifting. Cycling equipment of moving consumption to “off-peak” hours receives too
little incentive.
o PHEV/EV. Managing the charging cycle for electric vehicles will affect the economics of both
cars and the electricity system. Inadequate scarcity pricing and rate smoothing dampen
incentives and raise costs.
o Batteries. The principal benefit of batteries, from high tech flow batteries to low tech ceramic
bricks, is profit from price arbitrage. Smooth prices undo the incentives for battery deployment.
19
ELECTRICITY MARKET
Fairness and Dynamic Pricing
Fairness issues of electricity market design focus on residential and small electricity customers;
industrial and large commercial customers are different and capable of hedging real-time prices.4
 The default choice (e.g., NJ Basic Generation Service (BGS) versus Dynamic Pricing) is
crucial.
 Transactions costs are not zero.
 Signaling through implicit endorsement.
 Behavioral biases. (see pension research and status quo bias)
 For large industrial and commercial customers, the default option would be dynamic pricing
and the market can provide alternative hedging instruments.
 For other customers, a default option could be like the New Jersey BGS, with dynamic pricing
and demand response.
 Customers could elect in advance to have a fixed load profile, and buy-and sell at real-time
prices for any surplus or deficit.
 Or customers could choose to have a full requirement contact and participate with efficient
pricing at real-time prices for demand response.
 For more vulnerable customers, means testing provides access to rate assistance payments.
 If there are large economies for comprehensive installation of AMI, then the joint cost allocation
would be according to a share in the benefits.
4
W. Hogan, :Fairness and Dynamic Pricing: Comment,” The Electricity Journal, Volume 23, Issue 6, July 2010, Pages 28-35
20
ELECTRICITY MARKET
Smarter Dynamic Pricing
Better scarcity pricing is an example of smarter pricing to reflect dynamic conditions in electricity
systems and better match prices and costs. The alternative includes regulatory mandates and
standards that create perverse incentives.

Mandates and Standards. Regulatory mandates often raise average costs but dampen apparent
price volatility. For example, capacity payments for the “missing money” induced by inadequate
scarcity pricing are typically recovered through socialized and levelized rates.

Supply Creates Demand for Mandates. Socialized costs produce inadequate signals and
incentives for distributed generation, variable energy resources, and demand response. The
pressure is for more mandates to overcome the poor incentives created by other mandates.

Efficient Market Design Competes with Regulatory Rent Seeking. The principles of workable
market design suffer from (constant) collateral attack in the give-and-take of regulatory rent seeking.
A challenge for regulators is to internalize and adhere to the principles of good market design.
This often requires making distinctions that are not natural.

Between Costs and Prices. Minimizing welfare costs is not the same as minimizing consumer
prices.

Between Short-Run and Long-Run. A familiar human challenge: “Penny wise and pound foolish.”

Between Local and Global Optimization. Seemingly attractive market design features can be
collectively inconsistent. Better design seeks consistency to minimize unintended consequences.
21
ELECTRICITY MARKET
Market Manipulation
Market manipulation covers a wide range of topics. The focus here is on virtual and physical
energy trading in organized markets. Set aside for now related but different problems of
manipulation, such as:
 Fraud and misrepresentation.
 Price index manipulation.
 Collusion among market participants.
 Capacity auctions in organized markets.
 Demand response mandates.
22
ELECTRICITY MARKET
Competitive Market
With attention to wholesale electricity markets, under what conditions can energy trading result in
price manipulation inconsistent with workably competitive markets?
Two attributes of perfectly competitive electricity markets:

Taking prices as fixed, transactions are profit maximizing.

Prices clear the market, satisfying the no-arbitrage condition.
There is no perfect definition of “workably competitive.” Real transactions in real markets have some impact
on prices. Changes in prices have some impact on the profitability of transactions and related financial
contracts. Electrical network interactions and constraints have wide ranging effects. A workable definition
of “workably competitive” requires judgments about the acceptable degree of approximation of the attributes
of competitive markets.
“A market in which each supplier decides how much to supply at market prices that it cannot profitably affect
for long is said to be workably competitive.”5
5
Larry Ruff, Market Power Mitigation: Principles and Practice,” Charles River Associates, November 14, 2002, p. 3.
23
ELECTRICITY MARKET
Market Manipulation
A prior top ten list of issues and challenges in market power mitigation included:
…
3. “Scarcity pricing is good, withholding is bad. High prices may be politically unpopular, but
absent withholding of generation there is no exercise of monopoly power. Regulators who support
markets must face the periodic need for high prices during shortage conditions, at least in the realtime balancing market that sets the incentives for everything else through anticipation and
arbitrage.
4. Electricity markets make control of real time generation, transmission or load essential in
exercising market power. Derivative markets and long term contracts can change the incentives
to exercise market power, but at least in organized markets withholding in real time is required to
exercise market power. Otherwise, simple financial arbitrage would preclude any sustained
exercise of market power.
...
6. Monopsony is a problem as well as monopoly.
Compensating expensive generators for
running when cheaper alternatives are available produces prices that are too low and should be as
much a focus of policy concern as withholding to increase prices. Support of markets requires that
system operators run the system to reflect the bid-based costs, not to minimize price.” 6
6
William W. Hogan, “Local Market Power Mitigation,” Technical Conference on Compensation for Generating Units Subject to Local Market Power Mitigation
In Bid-Based Markets, PJM Interconnection, L.L.C., Docket Nos. PL04-2-000, EL03-236-000, Federal Energy Regulatory Commission, Washington, D.C.,
February 4, 2004.
24
ELECTRICITY MARKET
Market Manipulation
The Federal Energy Regulatory Commission policies confront decisions increasingly inconsistent
with basic market design principles.
“In the face of these diverging opinions, the Commission observes that, as the courts have
recognized, ‘issues of rate design are fairly technical and, insofar as they are not technical,
involve policy judgments that lie at the core of the regulatory mission.’ We also observe that,
in making such judgments, the Commission is not limited to textbook economic analysis of the
markets subject to our jurisdiction, but also may account for the practical realities of how those
markets operate. (FERC, “Demand Response Compensation in Organized Wholesale Energy Markets,” Order No. 745, ¶ 46,
March 15, 2011.)
This rejection of textbook economic analysis is a bad sign: “It won’t work in theory, but will it work in
practice?” The problem appears in policies to deal with or exploit market power.
Defining Market Power: Monopoly Withholding
P
Defining Market Power: Monopsony Withholding
P
Bids
MR
MC
MC
Bids
pm
pc
Max Capacity
pc
pm
Max Capacity
Demand
qm
qc
Seller Withholding
pm > pc = MC
Q
Demand
qm
qc
Q
Buyer Withholding
pm < pc = MC
25
ELECTRICITY MARKET
Buyer Cartels
Recent policy proposals organize buyer market power to reduce market clearing prices and count
the transfer from producers to consumers as a benefit captured through government mandates.
Demand Response Payments
“To address this billing unit effect, the Commission in this Final Rule requires the use of the net
benefits test described herein to ensure that the overall benefit of the reduced LMP that results
from dispatching demand response resources exceeds the cost of dispatching and paying LMP
to those resources.” (FERC, “Demand Response Compensation in Organized Wholesale Energy Markets,” Order No. 745, ¶
3, March 15, 2011.)
PJM Capacity Markets
“NJ Rate Counsel provided comments in the June 24, 2010 BPU Technical Conference
suggesting new, in-state generation could save NJ ratepayers approximately $465 million/year
in capacity payments. The analysis herein only considers the savings realized in the energy
market.” (LS Power, New In-State Generation LS Power Energy Savings Analysis, Nov. 2010)
“The Bill would require New Jersey to procure 1,000 MW of new capacity when it is not needed
for reliability, require the new capacity to clear in the auction through an offer price below its
costs and provide subsidies to the new capacity in the form of additional out of market revenue.
These features of the Bill are not consistent with the PJM market design. If implemented, the
market results would not be consistent with a competitive outcome. … The result of such a
subsidy by New Jersey ratepayers would be to artificially depress the Reliability Pricing Model
(RPM) auction prices below the competitive level, with the result that the revenues to
generators both inside and outside of New Jersey would be reduced as would the incentives to
customers to manage load and to invest in cost effective demand side management
technologies.” (PJM Market Monitor, “Impact of New Jersey Assembly Bill 3442 on the PJM Capacity Market,” January 6, 2011.)
26
ELECTRICITY MARKET
Mitigating Market Power
Offer caps and seller market power. Generators have an obligation to offer production at no more
than a predetermined offer cap. Actual production compensated at the market-clearing price.
 Distinguishes between
rents and scarcity rents.
monopoly
 Generator has an obligation to offer
at least the designated amount.
Offers for additional quantities are
unregulated.
 Provides the right incentives for
supply and demand, for entry and
operations.
 If high prices caused by withholding,
the offer cap will lower market
clearing price. If high prices caused
by scarcity, offer cap could produce
high prices.
Mitigating Market Power: Seller Offer Caps
P
MC
pc
Offer Cap
Max Capacity
Demand
qc
Q
pc > MC?
 The information burden is greater than for price caps but less than for cost-of-service regulation.
 Offer caps are generator specific and compatible with a workably competitive market.
27
ELECTRICITY MARKET
Market Interactions
Successful wholesale electricity market design depends on strong interactions between physical
energy trading, virtual trading and financial contracts.





Financial contracts interact with energy trading.
o
Financial transmission rights substitute for unavailable physical rights.
o
Contracts for differences integrate with organized spot markets.
Forward markets interact with real-time trading.
o
Financial transmission rights settle day-ahead.
o
Schedules and virtual transactions integrate day-ahead and real-time markets.
Market hedges are imperfect.
o
Imbalances for financial transmission contracts.
o
Portfolios for forward contracts integrated with virtual trading.
Barriers to entry differ in physical and financial markets.
o
Real-time physical markets have high short-run but lower long-run barriers.
o
Day-ahead financial markets with virtual trading have low barriers to entry.
Prices clear the market under economic dispatch with bids and offers.
28
ELECTRICITY MARKET
Market Interactions
Electricity markets are unlike other commodity markets. Real-time physical and forward financial
markets interact. But the lack of storability and the market-clearing process imply that market
power cannot be sustained in forward financial markets without manipulating real-time markets.
“Because of non-storability, manipulators of power markets must be producers of power, so speculative
corners are not possible. Moreover, a manipulator must have market power in generation.”7
Market Activities and Price Impacts
Real-Time Prices
Forward Prices
Real-Time Physical Issue: Monopoly and Monopsony, Forward contracts leverage incentives, but
Transactions
Energy Withholding.
real-time mitigation and easy entry in
markets
leave
workably
Policy: Mitigation with Offer Caps, forward
competitive conditions.
Must-Run Requirements.
Workably competitive.
Forward Financial Issue: Unit Commitment?
Transactions
Policy: Reliability Unit Commitment.
Negligible competitive effects?
7
Day-ahead price should approximate
expected real-time price, with transaction
costs and small possible risk premium.
Forward transactions do not create physical
real-time energy withholding; cannot
sustain manipulation of forward prices.
Workably competitive.
Craig Pirrong, “Manipulation of Power Markets,” Washington University, March 24, 2000, p. 1.
29
ELECTRICITY MARKET
Market Interactions
Interactions among physical energy trading, market-clearing prices, and financial contracts are
intended and necessary for successful electricity market design.
The mere fact that a physical transaction can affect prices to some degree, and thereby influence the
prices of related financial contracts, cannot be a per se definition of price manipulation.
Nearly every physical transaction can have some impact on prices.
economics.
This is basic supply and demand
If holding a financial contract that benefits from the price impact of a physical transaction were to be
deemed all that is required to establish price manipulation, then the entire foundation of successful
electricity market design would be destroyed with one stroke.
A FERC solution for distinguishing economic transactions from price manipulation is, has been,
and should be an application of a stand-alone profitability test.
“…HQ Energy did not use a combination of market power and trading activity to act against its economic
interest in one market in order to benefit its position in another market by artificially moving the market
price. There is no evidence that HQ Energy acted against its economic interest in any market. Rather,
the facts of this case show that HQ Energy made price-taker bids and used [Transmission Congestion
Contracts] to hedge congestion risk in a manner explicitly contemplated by the Commission.” 8
8
DC Energy, LLC v. H.Q. Energy Servs. (U.S.), Inc., 124 FERC ¶ 61,295 at 22 (2008) [footnote in original omitted]. Transmission
Congestion Contract is another term for Financial Transmission Right.
30
ELECTRICITY MARKET
Market Manipulation
A stand-alone profitability test does not require perfection, and is compatible with a workably
competitive market.
“…HQ Energy did not use a combination of market power and trading activity to act against its
economic interest in one market in order to benefit its position in another market by artificially moving
the market price. There is no evidence that HQ Energy acted against its economic interest in any
market. Rather, the facts of this case show that HQ Energy made price-taker bids and used
[Transmission Congestion Contracts] to hedge congestion risk in a manner explicitly contemplated by
the Commission.” [emphasis added]


Conventional application with unique market-clearing price.
o
Taking the market price as given.
o
Not “against economic interest.” Profitable, or at least not loss making.
Generalized application with degenerate case of multiple market-clearing prices.
o
Taking market prices as given.
o
Not “against economic interest” for all prices in the degenerate range. In other words,
meets the stand-alone test for some price in the degenerate range. A symmetric rule
would apply for evaluating transactions not undertaken (i.e., withholding).
Passing the stand alone test would provide a safe harbor. Failing the stand-alone test would raise a
question of possible price-manipulation “to act against its economic interest in one market in order to
benefit its position in another market by artificially moving the market price.”
31
ELECTRICITY MARKET
Market Manipulation Summary
Electricity markets are unlike other commodity markets. Real-time physical and forward financial
markets interact. But the lack of storability and the market-clearing process imply that market
power cannot be sustained in forward financial markets without manipulating real-time markets.
Offer caps address the problem of generator market power mitigation for physical transactions and
real-time markets.
Interactions among physical energy trading, market-clearing prices, and financial contracts are
intended and necessary for successful electricity market design.
The mere fact that a physical transaction can affect prices to some degree, and thereby influence
the prices of related financial contracts, cannot be a per se definition of price manipulation.
A FERC solution for distinguishing economic transactions from price manipulation is, has been,
and should be an application of a stand-alone profitability test.
Passing an appropriate stand-alone profitability test should provide a safe harbor. Otherwise, the
entire foundation of successful electricity market design would be destroyed with one stroke.
32
ELECTRICITY MARKET
Market Failures
Transmission expansion for large scale investments confronts competitive market failures and
requires some form of mandates, through regulation or monopoly discretion.
 Transmission Expansion
o Hybrid models of market design
o Transmission cost allocation
33
ELECTRICITY MARKET
Transmission Investment
Transmission investment presents the most difficult challenges for an electricity market. In
practice and in theory, market failures can be significant. If regulatory intervention is required to
plan, coordinate and mandate transmission investment, how can the intervention reinforce the
larger market design? A focus on market failures provides a framework that might work in theory.
Comparison with the Argentine experience suggests the framework would work in practice. Getting
this right is important, with implications for the ultimate success of electricity restructuring.
 Level Playing Field. A fundamental assumption of electricity restructuring is that market incentives
and decentralized decisions would serve better than regulated decisions in determining investment
and allocating risk.
o Get the prices right.
o Allow the market to determine the balance among investment alternatives.
o Recognize that transmission is both a complement and a substitute for other investments.
 Slippery Slopes. Mandated investments not supported by market signals reveal or create
requirements for expanding the scope of central planning and regulatory rather than market
decisions.
o All investments change the economics of all other investments.
o Mandated investments tend to reinforce the distortions in price signals.
o The regulatory cure could be worse than the market disease.
34
TRANSMISSION INVESTMENT
Argentine Approach
An outline of the earlier Argentine experience bears directly on the debate in the United States and
elsewhere. (For details, see Stephen C. Littlechild and Carlos J. Skerk, ”Regulation of Transmission Expansion in Argentina Part I: State
Ownership, Reform and the Fourth Line,” CMI EP 61, 2004, pp. 27-28.)

Coordinated Spot Market. Organized under an Independent System Operator with Locational
Marginal Pricing.

Expansion of Transmission Capacity by Contract Between Parties.
transmission with voluntary participant funding.

Minor Expansions of Transmission Capacity (<$2M). Included regulated investment with
assignment of cost, either through negotiation or allocation to beneficiaries as determined by
regulator, with mandatory participant funding.

Major Expansions of Transmission by “Public Contest” Method. Overcame market failure
without overturning markets.
Allowed merchant
o Regulator applies the “Golden Rule” (the traditional Cost-Benefit Test).
o 30%-30% Rule. At least 30% of beneficiaries must be proponents. No more than 30% of
beneficiaries can be opponents.
o Assignment of costs to beneficiaries with mandatory participant funding under “area of
influence” methodology.
o No award of Financial Transmission Rights!
o Allocation of accumulated congestion rents to reduce cost of construction (“Salex” funds).
35
TRANSMISSION INVESTMENT
Argentine Approach
What impact did the Argentine approach have on transmission investment?
“To illustrate the change in emphasis on investment, over the period 1993 to 2003 the length of
transmission lines increased by 20 per cent, main transformers by 21 per cent, compensators by 27 per
cent and substations by 37 per cent, whereas series capacitors increased by 176 per cent. As a result,
transmission capacity limits increased by 105 per cent, more than sufficient to meet the increase in system
demand of over 50 per cent.” (Stephen C. Littlechild and Carlos J. Skerk, ”Regulation of Transmission Expansion in Argentina Part II:
State Ownership, Reform and the Fourth Line,” CMI EP 61, 2004, p. 56.)
Lessons

Transmission investment could be compatible with SMD incentives.

Beneficiaries could be defined.

Participant funding could support a market.

Award of FTRs or ARRs would be an obvious enhancement.
36
TRANSMISSION INVESTMENT
Hybrid Market Design
RTOs in the US are struggling with the development of an adequate infrastructure investment
policy. A major innovation appears in the New York ISO tariff that embraces the principles of the
Argentine model.
“The proposed cost allocation mechanism is based on a "beneficiaries pay" approach, consistent
with the Commission's longstanding cost causation principles. … Beneficiaries will be those
entities that economically benefit from the project, and the cost allocation among them will be
based upon their relative economic benefit. … The proposed cost allocation mechanism will
apply only if a super-majority of a project's beneficiaries agree that an economic project should
proceed. The super-majority required to proceed equals 80 percent of the weighted vote of the
beneficiaries associated with the project that are present at the time of the vote.”9

Beneficiaries pay.

Participant funded expansions included.

Regulated investment supported subject to super majority voting.

Expansions awarded incremental FTRs.
9
New York Independent System Operator, Inc Docket No. OA08-13-000, “Order No. 890 Transmission Planning Compliance Filing,” Cover Letter
Submitted to Federal Energy Regulatory Commission, December 7, 2007, pp. 14-15.
37
TRANSMISSION INVESTMENT
Supporting Markets
How do the developing transmission investment frameworks integrate with markets?
 Texas ERCOT and Competitive Renewable Energy Zones
o Competitive Construction
o PUCT Procurement
o Socialized Cost
 California and Locationally Constrained Resource Interconnection Facilities
o CAISO Procurement
o Beneficiary Pays Ex Post
o Socialized Risk
 Wyoming-Colorado Intertie
o Market Decision
o Beneficiary Pays.
“As part of the Open Season process, the project sponsors had offered up to 850 megawatts of transmission capacity in a
public auction. This has resulted in 585 megawatts of capacity purchase commitments from credit-worthy parties. … The
project sponsors are optimistic that the remaining 265 megawatts of capacity will be sold. The project sponsors expect to
complete the siting, permitting, and construction of the line and begin operation by mid-2013.” (WAPA Press Release, August
26, 2008)
 NYISO Transmission Expansion Proposal
o Mixed Market and NYISO Decision. Supermajority vote (80%).
o Load Beneficiary Pays.
38
ELECTRICITY MARKET
Transmission Costs and Benefits
The court has affirmed a cost-benefit standard for transmission evaluation and cost allocation.
“FERC is not authorized to approve a pricing scheme that requires a group of utilities to pay for
facilities from which its members derive no benefits, or benefits that are trivial in relation to the
costs sought to be shifted to its members. … Rather desperately FERC’s lawyer, and the lawyer
for the eastern utilities that intervened in support of [FERC’s] ruling, reminded us at argument
that Commission has a great deal of experience with issues of reliability and network needs,
and they asked us therefore (in effect) to take the soundness of its decision on faith. But we
cannot do that because we are not authorized to uphold a regulatory decision that is not
supported by substantial evidence on the record as a whole, or to supply reasons for the
decision that did not occur to the regulators. … We do not suggest that the Commission has to
calculate benefits to the last penny, or for that matter to the last million or ten million or perhaps
hundred million dollars. … (“we have never required a ratemaking agency to allocate costs
with exacting precision”); … If it cannot quantify the benefits to the midwestern utilities from new
500 kV lines in the East, even though it does so for 345 kV lines, but it has an articulable and
plausible reason to believe that the benefits are at least roughly commensurate with those
utilities’ share of total electricity sales in PJM’s region, then fine; the Commission can approve
PJM’s proposed pricing scheme on that basis. For that matter it can presume that new
transmission lines benefit the entire network by reducing the likelihood or severity of outages. …
But it cannot use the presumption to avoid the duty of “comparing the costs assessed against a
party to the burdens imposed or benefits drawn by that party.” 10
10
Illinois Commerce Commission v. FERC, 576 F.3d 470, 476 (7th Cir., August 6, 2009, citations omitted).
39
TRANSMISSION INVESTMENT
Cost Allocation
A major obstacle for transmission investment is development of a stable framework for decision
making and cost allocation that supports infrastructure investment and is compatible with a hybrid
market design. The latest effort at FERC stakes out a strong position to implement a beneficiaries
pays system.
“The touchstone of today's proposal is the cost causation principle, ensuring that only those consumers
benefiting from transmission facilities are charged for associated costs.”11
Connecting cost allocation to benefits is a necessary condition for compatibility with an electricity
market with decentralized decisions for most investments.
But how can the principle be made operational?
11
Statement of Chairman Wellinghoff, “On Transmission Planning and Cost Allocation Notice of Proposed Rulemaking,” Docket No. RM10-23-000,
Statement: June 17, 2010.
40
ELECTRICITY MARKET
Transmission Expansion
A transmission infrastructure mandatory cost allocation framework requires a hybrid system that
is regional in scope and compatible with the larger market design. FERC Order 1000 proposed
principles that are compatible with a larger hybrid system. 12
The broader framework would
include:

Cost Benefit Framework
o Gold Standard: Net Benefits > Total Cost
o Cost Sharing: Commensurable with Benefits
o Compatible with Larger Market Design

Ex ante Estimation and Allocation

Net Benefits = Change in Expected Social Welfare
o Counterfactual without contracts
o Uncertainty and Expected Present Value

Approximations of Benefits
o Reliability
o Economic
o Public Policy

Benefit estimates commensurable across categories for projects
o Transmission lines affect all categories of benefits
o Transmission costs cannot be separated into distinct buckets
12
Federal Energy Regulatory Commission, “Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities,” Docket
No. RM10-23-000; Order No. 1000, Washington DC, July 21, 2011.
41
ELECTRICITY MARKET
Transmission Expansion
Efficient transmission infrastructure investment interacts with the costs and benefits of types and
locations of renewable energy investment.
RGOS Zone Scenario Generation and Transmission Cost Comparison13
13
Midwest ISO. Regional Generation Outlet Study, November 19, 2010, p. 3.
42
ELECTRICITY MARKET
Transmission Benefit Calculations
A simple model illustrates a basic framework for defining and classifying the impacts of
transmission expansion.
Transmission Between Regions
Export Region
Import Region
P
P
P
Supply
Supply
Demand
Exports
Demand
Imports
Q
Q
qc
Q
Illustrate benefits for this reduced model
43
ELECTRICITY MARKET
Transmission Benefit Calculations
Large scale transmission investments can change export and import volumes and have a material
effect on expected market prices.
Transmission Expansion Benefits
P
Base Case
Import Benefits=A
Export Benefits=E
Congstion Rents=B+C+D
A
B
C
D
E
Transmission
Capacity
Exports
F
Expansion Case
Import Benefits=A+B+F
Export Benefits=D+E+H
Congstion Rents=C+G
G
H
Imports
Net Benefits= F + G + H
Q
44
ELECTRICITY MARKET
Transmission Benefit Calculations
Different conditions can arise in parsing the distribution of benefits and the comparison with the
total cost of the transmission expansion.
Expansion Total Cost (TC) and Benefits
P
Gold Standard
F+G+H>TC
A
Exports
B
F
C
G
D
E
Transmission
Capacity
Business Stealing
B+F+G+D+H>TC> F + G + H
Core Coalition Case
B+F+G+D+H>F+G+H>TC
Strict Merchant Case
G>TC
H
Imports
Q
45
ELECTRICITY MARKET
Transmission Benefit Calculations
Past or continuing transmission infrastructure benefits include conflicting definitions that are
inconsistent with basic market principles and will create cost allocation problems.
Transmission Benefits
“The Energy Market Benefit component of the
Benefit/Cost Ratio is expressed as: Energy Market
Benefit = [.70] * [Change in Total Energy Production
Cost] + [.30] * [Change in Load Energy Payment].
… Reliability Pricing Benefit = [.70] * [Change in
Total System Capacity Cost] + [.30] * Change in
Load Capacity Payment].” (PJM, “PJM Region Transmission
Planning Process,” Revision: 16, Manual 14b, Effective Date: November
18, 2010, p. 75.)
“Market Congestion Benefit: 70% * Adjusted
Production Cost Savings + 30% * Load Cost
Savings.” (MISO, “2010 Transmission Expansion Plan,” Nov. 30,
Transmission Expansion Benefits
P
Base Case
Import Benefits=A
Export Benefits=E
Congstion Rents=B+C+D
A
Exports
B
F
C
G
D
E
Transmission
Capacity
Expansion Case
Import Benefits=A+B+F
Export Benefits=D+E+H
Congstion Rents=C+G
H
Imports
Net Benefits= F + G + H
Q
2010, p. 31.)
“Load Cost Savings where load cost represents the
annual load payments, measured by projections in hourly load weighted LMP: Load cost savings and
Adjusted Production Cost savings are essentially two alternative benefit measures to address a
single type of economic value and are not additive measures. Load cost savings were not used to
calculate the total value of the RGOS plans in MTEP10. … Value of transmission plan (per future) =
Sum of values of financially quantifiable measures = Adjusted Production Cost savings + Capacity
loss savings + Carbon emission reductions.” (MISO, “2010 Transmission Expansion Plan,” Nov. 30, 2010, p. 153-154.)
46
ELECTRICITY MARKET
Beneficiary Pays Cost Allocation
“The cost of transmission facilities must be allocated to those within the transmission planning
region that benefit from those facilities in a manner that is at least roughly commensurate with
estimated benefits. … Those that receive no benefit from transmission facilities, either at present or
in a likely future scenario, must not be involuntarily allocated any of the costs of those facilities.”
(FERC Order 1000, ¶ 622, 637 ) Cost benefit analysis of transmission expansion inherently provides
information about the distribution of benefits for use in cost allocation.14
Expansion Total Cost (TC) Allocation
P
Gold Standard
F+G+H>TC
A
B
F
C
G
D
E
Transmission
Capacity
Business Stealing
B+F+G+D+H>TC> F + G + H
Do not expand
Efficiency Constraints
Import Region < F
Exports
Export region < H
Trans. Rights < G
H
Imports
Q
14
Core Coalition Case
B+F+G+D+H>F+G+H>TC
Import Region %
= F/(F+G+H)
Export Region %
=H/(F+G+H)
Transmission Rights %
=G/(F+G+H)
Strict Merchant Case
Transmission Rights=100%
W. Hogan, “Transmission Benefits and Cost Allocation,” Harvard University, May 31, 2011. (www.whogan.com)
47
ELECTRICITY MARKET
Transmission Expansion Benefits
Efficient transmission infrastructure investment includes estimated reliability benefits.

Reliability modeling in a cost benefit framework.
o Reliability constraint and cost minimization.
o Change in value of expected curtailments at VOLL.
o PJM CETO/CETL method approximates expected curtailments.
Transmission Reliability Benefits
Reliability Test Area
P
After
Before
Capacity Supply Costs
VOLL
Local LOLP Requirement
Transmission
Expansion

Q
For example, this is not the same as a DFAX cost allocation
“Calculate the Distribution Factor (DFAX), where DFAX represents a
measure of the effect of each zone‘s load on the transmission constraint that requires the mitigating
upgrade, as determined by power flow analysis. The source used for the DFAX calculation is the
aggregate of all generation external to the study area and the sink is the peak zonal load for each
Transmission Owner within the study area. Multiply each DFAX by each zonal load to determine
the zone‘s MW impact on the facility that requires upgrading.” (PJM Manual 14B, p. 34)
48
ELECTRICITY MARKET
Transmission Expansion
Efficient transmission infrastructure investment includes benefits of meeting public policy
objectives or constraints.
 Environmental Constraints. With caps or prices on emissions, environmental costs would be
internalized with the cost of generation expansion and dispatch. Public policy objectives become part
of standard economic cost benefit analysis.
 Renewable Portfolio Standards.
The Midwest “RGOS Zone Scenario Generation and
Transmission
Cost
Comparison”
provides an example of including public
policy constraints. States established
the anticipated targets, including local
generation requirements. The scenarios
considered different mixes of generation
and transmission investment subject to
the constraint of meeting the RPS
mandates.
 Transmission Benefit Calculation.
The benefit of transmission expansion
does not include the benefit of the RPS
mandate. Evaluating the benefits of
public policy is different and more
difficult than evaluating the benefits of
transmission expansion in meeting
public policy objectives.
49
ELECTRICITY MARKET
Transmission Expansion Example
The simplest network to illustrate locational interactions has three lines and nodes. Consider a
lossless approximation with identical lines and one constraint.
The simple supply curves are flat up to the maximum quantity. Generators G1, G4 and G6 are renewable
sources. There is a renewable portfolio standard (RPS) of 50% of the load at location 3. The demand
curves are price sensitive at locations 1 and 2, but fixed at location 3. The transmission constraint applies
to the line between locations 1 and 3.
G1
G2
L1
P
50.00
40.00
75
Max
1000
500
300
600max
1 3
G3
G4
L2
P
50.00
60.00
60
Max
500
500
50
P
70.00
150.00
500
Max
500 G5
2000 G6
1800 L3
2 This network would support Financial Transmission Rights (FTRs) for 900 MW between locations 1 and 3.
50
ELECTRICITY MARKET
Transmission Expansion Example
The possible network expansion has identified an additional line between locations 1 and 3 to
double the capacity on this segment.
The same supply and demand conditions apply. The expanded grid could provide 1500 MW of FTRs
between locations 1 and 3.
G1
G2
L1
P
50.00
40.00
75
Max
1000
500
300
1200max
1 P
3
G3
G4
L2
P
50.00
60.00
60
Max
500
500
50
Max
70
150
500
500 G5
2000 G6
1800 L3
2 The expanded dispatch would change the patterns of costs and benefits. (Caution: This is a conceptual
illustration and does not represent any particular transmission expansion plan.)
51
ELECTRICITY MARKET
Transmission Expansion Example
The future is uncertain, and conditions differ across different scenarios. The use of two economic
scenarios, for peak and off peak conditions, illustrates the idea. A third low probability case
proxies for reliability standards.
The example ignores contingency constraints, but additional operating constraints would be incorporated
as done now in dispatch and planning models. The RPS standard is an expected value constraint across
all scenarios and produces a price for a renewable energy credit (REC). The prices and flows include:
Base Case
Off Peak
On Peak
0.75
REC
10.00
40.00
G1
G2
L1
270.44
439.56
300.00
G1
G2
L1
1 256.67
153.33
3
40.00
2 G3
G4
L2
0.00
0.00
50.00
40.00
0.24
40.00
0.00 G5
0.00 G6
360.00 L3
90.28
472.22
162.50
600max
1 600.00
‐200.00
3
70.00
103.33
2 G3
G4
L2
500.00
500.00
0.00
400.00 G5
0.00 G6
1800.00 L3
800.00
55.00
The off-peak case has no congestion. The on-peak case shows congestion and this limits access
to lower cost generation, including renewables. The REC price is assumed to be paid by RPS
load at location 3, and received by the various renewable generators.
52
ELECTRICITY MARKET
Transmission Expansion Example
The expansion case uses the same economic scenarios, probabilities and RPS requirements.
The increase in transmission capacity affects the dispatch, costs and benefits.
Transmission Expansion
Off Peak
On Peak
REC
2.30
47.70
G1
G2
L1
183.00
500.00
273.00
1 154.00
154.00
102.00
3
47.70
2 G3
G4
L2
0.00
0.00
50.00
47.70
G1
G2
L1
0.00 G5
0.00 G6
360.00 L3
785.50
500.00
85.50
1 600.00
600.00
0.00
3
67.70
52.00
47.70
1200max
2 G3
G4
L2
500.00
100.00
0.00
0.00 G5
0.00 G6
1800.00 L3
600.00
57.70
Prices change for all scenarios, including the REC price.
53
ELECTRICITY MARKET
Transmission Expansion Example
A comparison of the base case and expansion case provides the expected costs and benefits in
aggregate and for different loads, generators and FTR holders.
The details at each location amount to unpacking the “bid production” costs and revenues. These are the
individual consumer and producer surplus, and congestion, calculations.
Base Case
Off Peak
On Peak
0.75
REC
10.00
40.00
G1
G2
L1
270.44
439.56
300.00
G1
G2
L1
1 256.67
153.33
3
40.00
2 G3
G4
L2
0.00
0.00
50.00
0.24
40.00
0.00 G5
0.00 G6
360.00 L3
90.28
472.22
162.50
600max
1 600.00
‐200.00
103.33
2 G3
G4
L2
40.00
500.00
500.00
0.00
70.00
400.00 G5
0.00 G6
1800.00 L3
67.70
0.00 G5
0.00 G6
1800.00 L3
3
800.00
55.00
Transmission Expansion
Off Peak
On Peak
REC
2.30
47.70
G1
G2
L1
183.00
500.00
273.00
1 154.00
154.00
102.00
3
47.70
2 G3
G4
L2
0.00
0.00
50.00
47.70
G1
G2
L1
0.00 G5
0.00 G6
360.00 L3
785.50
500.00
85.50
1 600.00
600.00
0.00
52.00
47.70
1200max
3
2 G3
G4
L2
500.00
100.00
0.00
600.00
57.70
The details are tedious but straightforward.
54
ELECTRICITY MARKET
Transmission Expansion Example
The total change between cases identifies the total expected benefits. This includes economic
benefits, the cost of the RPS, and the cost of meeting the reliability standard. The single line
affects all categories of costs and benefits.
The total benefits would be
compared with the total cost
of the transmission line
expansion. The individual
benefit estimates include
transfer payments resulting
from the change in prices.
The
transmission
line
investment cost is not put in
buckets defined by type of
benefit.
The distribution of the total of
economic, reliability and
public policy benefits is not
uniform. The allocation of
the transmission expansion
costs could utilize this
distribution
of
expected
benefits.
55
ELECTRICITY MARKET
Transmission Expansion
Efficient transmission infrastructure investment inherently requires forecasts of conditions for
long-lived infrastructure. This presents challenges for cost benefit analysis and cost allocation.
 Defining the Horizon of Analysis. This is a standard problem in planning, but will be more
important to the extent it affects cost allocation.
 Representing Uncertianty. Scenarios and sensitivity analysis will be more important. And benefits
need to be aggregated as expected benefits, probability weighted across anticipated outcomes. This
is not new, but cost allocation will make this both more contentious and more necessary.
 Choosing the Counterfactual. This seems straightforward in a static one-shot framework.
becomes more difficult in the dynamic setting that includes future transmission investments.
It
 Harmoninzing Investment Decisions. The regional planning function for transmission is not the
same thing as integrated regional planning of old. Even if the plan mandates certain transmission
investments, the complementary decisions on generation and load will be decentralized.
 Eliciting Support of Beneficiaries. “The proposed cost allocation mechanism is based on a
‘beneficiaries pay’ approach, consistent with the Commission's longstanding cost causation
principles. … Beneficiaries will be those entities that economically benefit from the project, and the
cost allocation among them will be based upon their relative economic benefit. … The proposed cost
allocation mechanism will apply only if a super-majority of a project's beneficiaries agree that an
economic project should proceed. The super-majority required to proceed equals 80 percent of the
weighted vote of the beneficiaries associated with the project that are present at the time of the vote.”
(New York Independent System Operator, Inc Docket No. OA08-13-000, “Order No. 890 Transmission Planning Compliance Filing,” Cover
Letter Submitted to Federal Energy Regulatory Commission, December 7, 2007, pp. 14-15.)
 Other?
56
ELECTRICITY MARKET
Pricing for Smart Grids
Efficient pricing presents one of the important challenges for Regional Transmission Organizations
(RTOs) and electricity market design. Simple in principle, but more complicated in practice,
inadequate scarcity pricing is implicated in several problems associated with electricity markets.

Investment Incentives. Inadequate scarcity pricing contributes to the “missing money” needed to
support new generation investment. The policy response has been to create capacity markets.
Better scarcity pricing would reduce the challenges of operating good capacity markets.

Demand Response. Higher prices during critical periods would facilitate demand response and
distributed generation when it is most needed. The practice of socializing payments for capacity
investments compromises the incentives for demand response and distributed generation.

Renewable Energy. Intermittent energy sources such as solar and wind present complications in
providing a level playing field in pricing. Better scarcity pricing would reduce the size and importance
of capacity payments and improve incentives for renewable energy.

Transmission Pricing. Scarcity pricing interacts with transmission congestion. Better scarcity
pricing and transmission cost allocation would provide better signals for transmission investment.
Improved pricing would mitigate or substantially remove the problems in all these areas.15
Smart Grids Need Smart Prices.
15
FERC, Order 719, October 17, 2008.
57
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 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, Canadian Imperial Bank of Commerce, Centerpoint Energy, Central Maine
Power Company, Chubu Electric Power Company, Citigroup, 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, Dynegy, Edison Electric Institute, Edison Mission
Energy, Electricity Corporation of New Zealand, Electric Power Supply Association, El Paso Electric, Exelon, Financial
Marketers Coalition, FTI Consulting, GenOn Energy, GPU Inc. (and the Supporting Companies of PJM), GPU PowerNet Pty
Ltd., GWF Energy, Independent Energy Producers Assn, ISO New England, LECG LLC, Luz del Sur, Maine Public Advocate,
Maine Public Utilities Commission, Merrill Lynch, Midwest ISO, Mirant Corporation, MIT Grid Study, JP Morgan, Morgan
Stanley Capital Group, 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, Pepco, Pinpoint Power, PJM Office of Interconnection, PJM Power Provider (P3)
Group, PPL Corporation, Public Service Electric & Gas Company, Public Service New Mexico, PSEG Companies, Reliant
Energy, Rhode Island Public Utilities Commission, San Diego Gas & Electric Company, Sempra Energy, SPP, Texas Genco,
Texas Utilities Co, Tokyo Electric Power Company, Toronto Dominion Bank, Transalta, Transcanada, TransÉnergie,
Transpower of New Zealand, Tucson Electric Power, Westbrook Power, Western Power Trading Forum, Williams Energy
Group, and Wisconsin Electric Power Company. 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).
58