HomeMy WebLinkAboutAgenda Report - March 18, 2009 K-02AGENDA ITEM L=0 zW
CITY OF LODI
COUNCIL COMMUNICATION
iM
AGENDA TITLE: Discuss and Consider Several Items Related to Electric Utility Matters: (1)
Adopt Resolution to Sell Surplus California Independent System Operator
(CAISO) "Congestion Revenue Rights" for Lodi Electric Utility's Benefit and
(2) Receive report Regarding Status of Market Redesign and Technology
Upgrade (EUD)
MEETING DATE: March 18,2009
PREPARED BY: Electric Utility Director
RECOMMENDED ACTION: Discuss and consider several items related to Electric Utility
matters: (1)Adopt Resolution to sell surplus California Independent
System Operator (CAISO) "Congestion Revenue Rights" for Lodi
Electric Utility's benefit and (2) Receive report regarding status of
Market Redesign and Technology Upgrade
BACKGROUND INFORMATION: The CAISO is currently scheduled to begin operation under its
Market Redesign and Technology Upgrade (MRTU) on March 31,
2009. The following is a discussion of several relevant items related
to MRTU.
1. Conaestion Revenue Riahts
The Federal Energy Regulatory Commission in 2002 proposed new rules aimed at making the nation's
electricity industry more efficient. One of those strategies included the creation of "Congestion Revenue
Rights."CRRs are property rights that can be traded through an open market with the holders having the
right to move electricity along a portion of the transmission system when demand for power is high,
crowding available pathways.
In California, this market-based system of securing transmission rights goes into effect on March 31,
2009. Because the price of transmitting energy between designated points is determined through an
Internet auction and uncertain, the CAISO is allocating Congestion Revenue Rightsto utilities serving
retail customers, such as the Lodi Electric Utility. For EUD's benefit, the Northern California Power
Agency holds E UD's allocation of CRRs — some of which will be used to hedge physical transmission
paths used by EUD to import power into Lodi and some of which are not needed for physical
transmission of power but will have financial value instead. (This agency relationship between NCPA and
EUD on CRR matterswas approved City Council Resolution 2007-103 on June 6,2007.)
On behalf of EUD and other NCPA Pool members, NCPAwill be strategically marketing surplus CRRs.
They are expected to have significant value in the forward market. If held until "real time," however, there
is a small risk these surplus CRRs can become a financial liability. To eliminate the risk of such a liability
APPROVED:
Discuss and Consider Several Items Relatedto Electric Utility Matters: (/)Adopt Resolutionto Sell Surplus California
Independent System Operator (CAISO) "Congestion Revenue Rights" for Lodi Electric Utility's Benefit and (2) Receive
Report Regarding Status of Market Redesipn and Technology UQ.Drade(EUD)
March 18, 2009
Page 2 of 3
or cost, NCPA plans to sell surplus CRRs in advance of real-time through an auction to be held by the
CAISO.
As noted earlier, the City Council has previously approved NCPA as EUD's agent for CRR transactions
with the CAISO. NCPA's General Counsel, however, has requested that this authority be explicitly
extended to the marketing/sale of surplus CRRs in the forward market. Therefore it is recommended the
Council approve the attached resolution to clearly authorize NCPAto offer and sell surplus CRRs on
behalf of EUD.
2. Market Redesign and Technoloav Upgrade (MRTU
As noted earlier, the CAISO is planning to "go live" with its new MRTU program on March 31, 2009,
although some delay is possible.
Under MRTU, CAISO is creating and managing Day Ahead and Real-time "energy markets." The basic
design of MRTU was approved in September 2006 by the Federal Energy Regulatory Commission, which
has oversight responsibility for regional transmission organizations (RTOs) such as CAISO. For the
CAISO, this has been a multi-year project to develop an extremely complex software model with the goal
of efficiently managing limited transmission by using market forces to deal with congestion on the
California transmission grid. During this time other market participants have also been required to
develop software to interfacewith the planned MRTU market. NCPA manages the CAISO interfacefor
NCPA Pool members such as Lodi.
There area number of major issues with MRTU such as:
• Will the CAISO's software/hardware be ready for "go -live"?
• Will market participants, including NCPA and Lodi's energy suppliers, be ready to interfacewith
CAISO?
• Will the overall MRTU program perform as advertised?
• Will there be significant economic/cost impacts of the new MRTU market system?
• Can CAISO handle the massive settlements process since all electricity transactions flow through
them for settlement?
MRTU, and the so-called Standard Market Design it implements, is enormously complex and
controversial. Public power electric utilities in California fought implementation of MRTU for many years
in the legal and regulatory arenas until it was eventually approved by FERC. Since that time, public
power agencies have worked hard to ensure that the details of MRTU were set up fairly for all market
participants and for the consumers of the State. The American Public Power Association has been a
significant ally for public utilities in questioning the value of MRTU and similar RTO markets (there are 5
other RTOs that operate markets in the United States).
We question the value, too, out of fear it may lead to significant unexpected costs that must be passed on
to our ratepayers. California's previous experiment with open power markets had disastrous
consequences because of illegal market manipulation and we have no assurances that will not be
repeated.
Discuss and ConsiderSeveral Items Related to Electric Utility Matters: (I) Adopt Resolution to Sell Surplus California
Independent System Operator (CAISO) "Congestion Revenue Rights" for Lodi Electric Utility's Benefit and (2) Receive
Report Regarding Status of Market Redesign and Technology Upgrade (EUD)
March 18,2009
Page 2 of 3
Attached to this Council Communication are several documents to provide background on the
implementation of MRTU specifically and RTO -run markets in general:
1. MRTU Update, written by NCPA, March 2,2009 (1 page)
2. MRTU FACT Sheet and timeline, prepared by CAISO (1 page)
3. Series of One Page MRTU-related Summaries, prepared by CAISO (8 pages)
4. FrequentlyAsked Questions about MRTU, prepared by CAISO (5 pages)
5. FERC Press Release (Fact Sheet) on MRTU Approval, September 21,2006 (5 pages)
6. Fact Sheet titled "Wholesale Electricity Markets, by APPA, February 2009 (4 pages)
7. Report titled "Consumers in Peril —Why RTO -Run Markets Fail to Produce Just and Reasonable
Rates", prepared by APPA, February 2008 (35+ pages)
FISCAL IMPACT: Revenue from the sale of CRR's would accrue to EUD's benefit hence lowering net
power costs. The impact of MRTU on Lodi Electric Utility is unknown.
FUNDING: Not applicable.
George F. Morrow
Electric Utility Director
MRTU Update
The California Independent System Operator (CASIO) has made a readiness certification filing with the
Federal Energy Regulatory Commission (FERC) indicating that they will implement a new market design
within California on March 31,2009. The CAISO is the organization that operates the vast majority of the
electrical grid in California, and through its tariff, specifies the rules under which electricity will be
purchased, sold and delivered for over 80% of the states residences and businesses, including NCPA
members.
The new market design known as Market Redesign and Technology Upgrade or MRTU has been in
development for approximately seven years and will dramatically change the way that utilities arrange
to procure and pay for electricity that is ultimately delivered to their customers.
The CAISO has retained three independent experts to attest to CAISO's readiness to implement MRTU,
and who either have, or will certify that:
• Market design software calculates Day Ahead and Real Time electricity prices accurately and
consistent with the MRTU tariff
• Settlement software correctly calculates invoices in accordance with the MRTU tariff
• Applications and systems that constitute MRTU were developed, built and tested in accordance
with the MRTU tariff
CAISO is also endeavoring to put in place mechanisms that will allow itto respond to unforeseen events
such as unexpectedly high prices or defects in the overall design that might force either corrections to
invoices or a complete rollback to the existing electric market design.
Despite all of the assurances of readiness offered by the CAISO and its experts, market participants such
as NCPA, municipal utilities in southern California and large investor owned utilities such as Pacific Gas &
Electric and Southern California Edison all remain concerned that critical MRTU systems are not
performing as expected, and as a result, that the CAISO is not as ready to implement the new market
design as claimed. Included in the concerns of these market participants are:
• The inability of the CAISO to produce one clean/accurate invoice during simulation exercises
• High unexplained prices occurring during simulation
• Inaccurate dispatch instructions to generators which could affect grid reliability
• Incomplete descriptions of safety net processesto protect against inordinately high electricity
prices
To address these ongoing concerns, NCPA, on behalf of its member municipal utilities in northern
California will continue to work with the CAISO and other market participants to attempt to resolve all
remaining outstanding issues prior to the proposed "go live" date of March 31St. In the event remaining
outstanding issues cannot be resolved, NCPA will also work with all appropriate regulatory and
legislative bodies to defer or delay MRTU should further delays to implementation be warranted to
protect the financial stability of NCPA members or the reliability of the electric grid.
March 2,2009
Northern California Power Agency
Calffbmia ISO
Yaw UWA ft ft%w
Fact Sheet
Market Redesign and Technology Upgrade (MRTU)
MR7 esitsroots
back to initiatives introduced in 1998.
The current work began in earnest Sept.
21,2006, when the Federal Energy
Regulatory Commission, the ISO lead
regulator, accepted the most recent
design proposal.
The new market further ensures power
suppliershave fair and open access to
the transmission system within the ISO
control area, resulting in the delivery of
the least cost electricity to consumers.
'The redesign introduces a day -ahead
:market for energy (electricity produced
for resale) that helps flan up next day
production and delivery schedules as
well as enable grid operators to manage
transmission boitlenecks efficiently so
that electricity flows without
interruption.
MRTU is actually two projects. One
creates the software needed to manage
,ail aspects of the market from power
;generators, to the transmission grid and
,eventually to the companies that deliver
electricity. The other upgrades ISO
,computer hardware with technologies
capable of running the sophisticated
:market so ftware,
'The several different elements of the
inew market redesign, working in
concert, manage the state's electricity
transmission system more efficiently
;and at less cost.
In addition, simultaneously
;managing of energy and
transmission resources eases the
time/price differential of today's
market and reduces the opportunities
for gaming the system.
'[999
New Features
• Integrated Fonvard Market—is
comprised of the day -ahead
1porket, ancillary services
(pleetrioity reserves) and
ft*Mimission management.
..Managing these resources at the
same time is much more efficient
and reduces the opportunity for
market manipulation.
Day ahead market -allows buyers
and sellersto trade energy a day
before it is needed.
]Locational Marginal Pricing —when
filly implemented sets wholesale
electricity prices at 3,000 different
system points (nodes) that reflect
local generation and delivery
costs. Grid users see higher costs
nodes and avoid them, which also
lowers costs.
■ Full Network Model —this is a
sophisticated computer model that
enablesthe ISO to analyze the
state transmission networkto see
how power is flowing and then to
'better manage energy schedules,
thus avoiding bottlenecks and
saves the expense of rerouting
electricity.
• Congestion Revenue Riots —this
;is an auction system for reserving
and allocating space on the
ttafs m issio n wires that helps
power companies manage their
delivery costs and avoiding
surprise expenses to re ro ute
electricity around bottlenecks.
Additional MRTU information is
availableon the California ISO
website at www.caiso.com
MRTU Histoiry Market Design 2002
Composed of Congestion
FE RC Orders the ISO - Management Redesign and
January 2000 to Redesign Day Ahead Market Started
T Congestion Management July 2002
Plan FERrders the ISO In
T Dec. 2416cl
to design a day
market.
2002 200$
1 EnergyGf rlsis Begins May I MD02 E)
i 2000 1 Energy Cris Is Ends Sept. 1 (includes
ISO Launched March 1998 2001
(incorporated May 1997)
ISO Completes Congestion
- MarraUwnwftRedeskjnJan.
2001
Benefits
The Integrated Forward Market links
the day -ahead market for energy and
ancillary services (electricity
reserves) with the real-time market,
which balances load on the grid on
short notice. The software analyzes
the best use of the grid and helps
create pricing consistency between
what generators have scheduled
day in advance and what the ISO
needs in real-time to meet demand.
Having a day -ahead market ensures
generators deliver power in real-time
as promised. This also helps grid
operators avoid having to call upon
standby generators at the last minute
to fill supply gaps, which charge
higher prices to respond quickly to
180 orders.
Locational marginal pricing reflects
the cost of generating electricity as
well as the cost oftransporting the
power (currently only the cost of
generating is transparent). LMP also
provides a signal for where new
wires or power plants will reduce
consumer prices as well as assure
developers a return on investment.
• The Full Network Model computer
simulation saves money by enabling
grid operators to see bottlenecks and
then reroute power to avoid the
congested higher -priced areas.
• Congestion revenue rights are like
insurance that protects rights holders,
often utilities, from the cost of
untangling transmission bottlenecks.
It also ensures price certainty for
transmission customers, letting them
avoid any surprise expenses to
reroute electricity around
bottlenecks.
ISO Board of Governors
7 OKs Basic MRTU Design
Oct. 2005
FERC Accepts MRTU
Design Proposal Sept. 2006
2008 2007 2008
Into MRTU MRTU Goes Live
5nal pricing
ISO. Stakeholders Work on
Market Rules. 2004-2006
Clear, consistent market redesign is the sturdy
framework for a fair and open power system. A
healthy energy marketplace leads to innovationand
impartiality. It is the heart ofthis hub for electricity
the California Independent System Operator
(California ISO).
who Is the COHNIlle U?
The California ISO is a not-for-profit public benefit
corporation established in 1996. It began operating the
bulkofhigh-voltage, long-distance transmission lines in
California in March 1998. The ISO is dedicated to:
■ Managing the safe and reliable flow of
electricity on California's high-voltage power
grid.
■ Ensuring fair and open access to the
transmission grid for all qualified users.
• Providing market and grid information with
integrity and impartiality.
Yew 10e8 the CRED1118 In Be Re M?
As guardian of open access to the grid, the California
ISO acts as the impartial link between power plants and
the utilities that provide electricity to customers. This
provides a fair and level playing field for energy
companies that want to use the 25,000 -circuit mile
wholesaletransmissionnetwork. The Californial SO is
the gatekeeper to more than two -dozen pathways of
power connecting California with neighboring states
as well as Mexico and British Columbia. Charged
with ensuring safe and reliable operationof the grid or
"keepingthe lightson," the California ISO isatraftic
controllerof sorts, managing bottlenecksthat could
overload key components and stop the flow of
electricity.
The ISO also matches the demand for electricity the
instant it is needed with just the right amount of
megawatts. Because electricity cannot be stored, the ISO
forecasts how much power customers will need at any
given time and makes sure that standby power plants are
available in case something goes awry.
What is more important; generation or transmission?
Both are critical, as evidenced during the energy crisis
of 200012001, Essentially, you can't have one without
the other. More than 10,000megawattsof new power
plants were built in Californiabetween 2000-2003, but
the power lines that make up the grid are often
overcrowded, limitingwhere power generation can come
from and where it can go. (For context, one megawatt is
enough electricityto power approximately750 homes).
ON Amoss
The ISO addresses crowdedpower lines via an electronic
transmission market that allocates limited space for
transmitting electricity. This market is conducted a day
before and an hour before the electricity is due to be
delivered. Energy suppliersparticipate in the transmission
market by offering to reduce their usage of an
overcrowded line or by offering to increase deliveries
on another line that can feed the same zone without
adding to the congestion. However, sometimes the
financial solution ofthe auction doesn't completelymeet
the needs of the physical reality of grid reliability. The
ISO provides the grease in the gearbox that safely and
reliably smoothes over any discrepancies between the
auction system that determines which entity gets access
to an overbookedpower line and the physical world of
power -flow engineering.
Redeslllll for Relic my
Energizing the electricity market in California are two
parallel programs: 1) Reliability and Market
Improvementsto assure grid reliability and 2) Technology
and Infrastructure Upgrades to strengthen the computer
systems that run the ISO power grid. These programs
have been merged into one initiative called Market
Redesign & Technology Upgrade (MRTU). The benefits
of MRTU include:
• Reduced dependency on the ISO Real -Time
Market; stabilizing costs and enhancing reliability.
■ Elimination of certain opportunities for
market manipulation and gaming.
• Updated control room computer systems that
replace aging infrastructure andtake advantageof
technological advances made in past five years.
■ Efticient and least -cost approaches in the
operation of the transmission system.
Wholesale price signals to help guide appropriate
investment in California's electricity supply.
V Ca1if6=&?.1S0
1
The original ISO market design has been improved
upon, but still contains inefficiencies that can make
the electricitymarket vulnerable to manipulation. The
energy crisis of 2000/2001 broughtsomeof these, flaws
to the surface. The Market Redesign and Technology
Upgrade (MRTU) is centralto providingthe framework
for reliable operations of the grid in the long run. It
provides ISO operators with the tools necessary to plan
for known bottlenecks in the power grid in advance
of real-time— allowing hours, rather than minutes, to
consider options for schedulingelectricity in a manner
that will meet the needs of California consumers. It
also replaces the "missing market" for electricitybought
and sold a day ahead of time. That market disappeared
when the California Power Exchange shut down
operations in 2001. The new market design will also
take into account long-term contracts for power signed
during the energy crisis —pinpointing any delivery
problems before the electricity actually flows on the
system.
MM vs. Zonal: Key to Addressing
Overcrowded Meas of the GM
The original ISO market design was a "zonal" system,
as opposed to a "nodal" one that allows a more detailed
view ofthe transmission system. The zonal system
divides California into three large zones that provide
limited information about how day -ahead energy
schedules will interact on the grid in real-time. It was
assumed that transmission lines connecting one zone
to another might become overcrowded, and the ISO
developed a system to deal with that "inter -zonal
congestion". It was also assumed that congestionwithin
the same zone (intra -zonal) would be minimal in scope
and cost. That turned out not to be the case. Dealing
with intra -zonal congestion within the current market
design can add $5-10 million a month to the cost of
delivering electricity to California consumers. It is a
significant problem with the addition of new power
plants in the CalifornialSO Control Area. The new
generation is welcome, however some of the newly
constructed power plants are connected to log jammed
sections of the power grid. As many as 1,700
megawatts of electricity can be "stranded" at the power
plant due to inaccessibility to the grid.
The solution to intra -zonal congestionis anodal system
that dividesthe state into hundreds of separate "nodes"
that represent generation and load points on the
transmission grid. A nodal system, coupled with the
use of a detailed computermodel ofthe grid, will make
it possible to determine if requests for transmissionuse
can be accommodated as early as the day before
electricity actually flows. Currently, scheduling
conflicts within one of the three big zones are
invisible until real-time, compromisingthe ISO's
ability to operatethe grid reliably. Our new market
design will allow us to see all potential transmission
line trafficj ams a day ahead of time, instead of five
minutes before the electron traffic has to be rerouted.
Missleg Market
The only energy market that the ISO operates currently
is the Real -Time Market for energy, which is needed to
balance supply and demand. Under restructuring,
most of the trading of electricity via a day -ahead
wholesale energy market was performed at the
California Power Exchange (PX), created at the same
time as the ISO. The bulk of next day energy needs
were traded at the PX, which submitted schedules
from its day -ahead energy market to the ISO. As
the independent transmission operator, the ISO
determined whether the submitted schedules could
be delivered as planned. However, inthe wake ofthe
energy crisis, the PX shut its doors and ultimately filed
for bankruptcy.
Utilities now rely on long-term contracts and their
own generating units to supply most of their custom-
ers' power needs, but there is no organized market held
24 -hours ahead of time to meet the changing demand
for energy. The hole left when the PX shut its doors
can leave too much reliance on the ISO Real -Time
Market. Just as buying an airl ine ticket at the last
minute can be costly, so too can purchasing
megawatts right before you need them in the Real -
Time Market. That's why the California ISO market
redesign includes a Day -Ahead Market for energy.
� j Califor.-MaSU
07 June 24,2004, the ISO Board of Governors approved
two parallel programs, managed as one ISO initiative in
order to gain economic and technical efficiencies:
• Market improvements to assure grid reliability and
more efficient and cost effective use of resources.
• Technology upgrades to strengthen the entire ISO
computer backbone.
M8aet Redomp
■Allows the ISO to conduct a Day -Ahead Market
that combines three services; energy, ancillary
services (operating reserves) and congestion
management to better match what really happens
when the electricity flows. The forward or Day -
Ahead Market determinesthe best use of resources
available, while finding the least cost method of
procuring required components. With the
bankruptcy of the Power Exchange in 2001, there
is currently no centrally organized day -ahead
energy market inCalifomia. By startingthis process in
the day -ahead time frame, there is less reliance on
the more volatile Hour -Ahead and Real -Time
Markets.
• Provides a more precise model of the grid using the
latest computer technology to allow the ISO to
better predict how energy scheduled a day ahead of
time will flow in real-time. The ISO will be able to
see ALL potential transmission line crowding a day
ahead of time, ratherthan waiting until real-time. Once
power is flowing, options for making adjust-
ments are limited and potentially more expensive,
and such adjustmentspresent challenges to reliability.
■Introduces new market rules and penalties that
prevent Enron -like gaming and manipulation. The
ISO is charged with keeping the grid reliable. It
does so by issuing dispatch orders to energy
suppliers to increase or decrease the amount of
energy they have successfully bid into the market.
But the ISO had limited authority to compel
suppliers to respond to dispatch instructions. The
ISO has been granted new authority by the Federal
Energy Regulatory Commission (FERC) to assess
financial penalties on market participants that do
not comply with instructions from the ISO control
room. The new market design also determines the
deliverability of all schedules, rejecting requests
that are physically impossible.
• 'Joduces local prices that eliminate the distinction
between inter- and intra -zonal congestion.
Locational Marginal Pricing (LMP) essentially
shows the cost ofproducing power as well as the
cost of delivery. This gives the ISO and
market participants a clearer picture of the true
cost of getting power to areas that may not have
enough local generation or where transmission
capacity is lacking. It will find and block
infeasibleday-aheadschedules—those that cannot
fit on the grid.
Tedoftly upgrade
' Prior to the market redesign effort in 2001, the
ISO began assessing its future systems and
infrastructure needs as the computers originally
installed at start-up began to approach the end of
their useful lives. A "fence and reinvest"
strategy was initiated, with the ISO seeking to
minimize maintenance costs and further
investmentin outdated systemswhile developing
new systems based on a more open architecture
that offers greater flexibility and allows for more
cost-effective changes down the line.
■Because power grids depend on the latest
computer technology to help manage loads and
resources, their reliability drives the reliability of
the grid. New computer systems are designed to
minimize downtime and the possibility for
interruption, enabling grid operators to managethe
transmission system more effectively and giving
them a better forecasting tool to spot potential
bottlenecks on power lines before electricity
actually flows in real-time.
Just as home computers become outdated overtime,
the ISO computers are in need of updating after seven
years of operation. New computer systems will
replace the existing systems that have been "patched"
more than 400times over the years. Replacing the
aging infrastructure also takes advantage oftechno-
logical advancements in the past five years.
*W Calif a.a? J
SdOdMM Foamy WWW a Now Pwadipm
Utilities or energy service providers cannot always cover
100 percent oftheir customers' electricity needs.
Even those that can always look for opportunities
to meet the requirementsas cheaply aspossible, and
they will skip using one oftheir power plants if they can
buy reliably on the open market for less. In part,
facilitating purchases and sales is one elementofthe
market redesign. Even if utilities lineup alltheir
customers' power needs aheadof time, the ISO must
match supply and demand to assure that power flows
on the grid reliably in real-time.
To make that assessment, every day and every hour,
wholesale energy suppliers and the utilities that serve
end users submit schedules to the ISO that detail which
power plants will supply power at what level, atwhat
time, and at which point on the grid. These schedules
are analogous to "flight plans" for electrons. The
ISO makes sure that thousands ofday- ah4 andhour-
ahead schedules, and any adjustmentsmade to them, will
all "fit" on the grid without overloading sensitive
equipment or exceeding reliability rules, Sometimes
that means adjusting schedules to avoid overloads that
can be predicted ahead of time. However, current
systems cannot "see" all the potential overloads from the
day -ahead scheduling process. It's like an air-traffic
controller who cannot tell ahead of time if a pilot's
flight plan will conflict with other pilots' flight plans.
Under its new market design, through the use of the
Full Network Model and the Integrated Forward Market
system, the ISO, which acts like atraffic controller for
electricity, will have the ability to electronically evaluate
the routes chosen before clearing energy schedules for
"takeoff.
The ISO can operate the grid more reliably when it
can "see" all the congestion from the day -ahead
schedules in advance, allowing it to make other
arrangements. That's why, as part of its market
redesign, the California ISO is developing a Full
Network Model of the grid and a computerized
simulator that can analyze the schedules submitted
today to make sure the energy can actually flow safely
and reliably tomorrow. If the system detects
bottlenecks, the Integrated Forward Market, also partof
the redesign, will allow the ISO to adjust day -
ahead schedulesto addressthe bottlenecks. Locational
Marginal Pricing, another part of the new market
design, makes it easier for the ISO and others to see
the least -cost option for adjusting those schedules.
The market redesign is a complex set of changes, but
it can be boiled down to three main elements:
• ThelntegraledForwardMarket (aDay-
Ahead Market)
■ The Full Network Model
■ Locational Marginal Pricing
The Integrated Forward Market (IFM) is a one-
stop shop for all three ofthe main servicesthe ISO uses
to operatethe grid; Energy, Ancillary Services (operating
reserves) and Transmission Management. Beginning in
the day-aheadtime frame, the IFM will determine the
best use of the resources (mostly generation and
imports) made available to meet the scheduled
energy requirement and provide necessary reserves.
This will be done in a mannerthat can be transmitted on
the grid without creating bottlenecks based on the
expected grid conditions. Currently, the ISO does not
have the tools or procedures in place to operate an
organized day -ahead energy market, making this kind
of one-stop shopping impossible. Furthermore, if the
scheduled energy requirement is less than the ISO next
day load forecast, any leftover resources can he made
available in the Real -Time Market. Finally, the ISO
will continue to fine-tune the grid, using the IFM
system to make adjustments in real-time based on
changing conditions. Making those adjustments with
IFM builds on the forward market schedules and
provides pricing consistency between the two time
frames, something lacking in the original design.
The Full Network Model (FNM) refers to anew
computer program that "models" the entire ISO -
operated grid, taking into account all known limitations
and predicting how power will actually flow. It's like
a simulator for pilot training. The ISO will use this
accurate and detailed computer simulation of the grid
to determine if the energy schedules submitted by
various entities will actually be able to flow on the
grid. The less sophisticated model currently used by
the ISO to analyze schedules is not programmed to
recognize all the possible problems. In simpler terms,
the ISO will be trading up from a magnifying glass to a
microscope to preview the grid. The Full Network
Model will allow the ISO to analyze forward schedules
and "see" all the potential power line crowdingbefore it
actually occurs, allowing ISO operators to plan
accordingly.
V Califomia ISO
Read About LMP »»
One of the biggest flaws in the ISO market structure is
the difference in the way two types of gridlock are
currently handled:
■Inter -Zonal Congestion: The ISO -controlled
grid is divided into three main "zones" that
roughly correlate to northern, southern and
central California. Overcrowding on power lines
that connect one zone to another is called "inter-
zonal congestion." When this type of bottleneck
occurs, the ISO computer systems currently can
rearrange the schedules automatically in the day -
ahead time frame to prevent an overload in real-
time, provided that the rearranged schedules
operate as planned and that grid conditions don't
change significantly.
■ Intra -Zonal Congestion: Many high-voltage
power lines are fully contained within one of the
current zones. These lines can be overbooked,
too, creating "intra -zonal congestion." The ISO
computer systems were not designed to look at
intra -zonal congestion from the day -ahead
schedules, so any overbooking is allowed to stand
until real-time. This is an inherent flaw that
continues to create operational difficulty and add
to costs. ISO control room staff are forced to
rearrange schedules in real-time to compensate
for the day -ahead schedulesthat can't all actually
tit on the grid. It can be more costly and creates
unnecessary reliability risks.
A Simple Example of
New Congestion managmllent Works Noor
Imagine a straight line marked with points A, B, C
and D. There are generators at points A, B, and D and
"load" ` or an energy consumer at point C. Generator A
has a contractto send 100 megawatts of power to the
load at point C.
But on summer afternoons, the demand for energy at
point C rises to 150 megawatts. The generator at
point B submits a day -ahead schedule to the ISO,
indicating it wants to send 50 megawatts to point C.
But, the line between A and C is limited to 100
megawatts. This overbooked line, or "intra -zonal
congestion", is invisible to the IS0 until real-time.
The ISO cannot arbitrarily decidewhich generator
should get access to the overloaded line and which
one should reduce its schedule, but one or both
generators at A and B must decrease or (DEC) their
output by a total of 50 megawatts to keep the A -to -C
line from overloading. The consumer at C still needs
50 megawatts of power to make up for that which
can't be delivered by A or B. The ISO calls on the
generator at point D to increase or (INC) its output
by 50 megawatts. Because of its location, it is not
affectedby the 100-megawattlimitation at what
would be the inter -zonal boundary. But the current
system doesn't check for any lower level bottleneck
between D and C, or at the intra -zonal level. So even
if the inter -zonal bottleneck is resolved, it is possible
to create another intra -zonal bottleneck with the
solution, somethingthat the new system will take into
consideration.
That is "congestion management" in its most
simplistic form. Multiply this by thousands of miles
of transmission lines, hundreds of generators, and an
ever-fluctuatingdemand for power, and yon will see
that managing congestion can quickly become a very
complex endeavor.
ON -California ISO
Murslam AIst Valera Mr4utba Costs
Congestion on the grid occurs when the total desired
Under the new market design, the ISO will allocate
energy flows scheduled by buyers and sellers of
CRRs, free of charge, to end-use customers located
power cannot fit on the power lines. This is when the
within the ISO transmission grid. The objective is to
ISO steps in and reschedules the electricity deliveries.
provide, as accurately as possible, the correct quantity
Buyers and sellers whose power is reshuffled will be
of CRR coupons to offset fully the annual congestion
assessed congestion charges that reflect the cost of
charges the customers will be assessed. In practice, the
rearranging the desired schedules to fit the grid. These
CRRs will actually he allocated to the utilities or retail
congestion charges will vary from season to season,
energy service providers responsible for serving the
from day to day, and from hour to hour within the day,
customers, not directly to the customers.
and they can he very hard to predict. The ISO offers a
kind of insurance against these unpredictable charges.
The ISO will also allocate CRRs to companies that
Called Congestion Revenue Rights (CRRs), these
invest in building new transmission facilities (that do
insurance "coupons" entitle the holder to a payback of
not get paid back for this investment through any kind
hourly congestion charges to offset amajor portion,
of customer surcharge). The objective in this second
perhaps even the full amount, of the congestion
type of allocation is to enable the investor to earn the
charges they have to pay for using the grid.
congestion charges that are paid by other parties who
use the new facilities added by the investor. After
conducting these allocations on an annual and monthly
basis, the ISO will hold annual and monthly auctions
for CRRs in which any qualified parties may bid to
buy and sell CRRs. This will enable parties that are
not eligible for free allocations of CRRs to invest in
CRRs as a way of smoothing out or "hedging" the
unpredictable hourly congestion charges they will he
exposed to under the new market design.
W CalifomiaaSO
Locational Marginal Pricing (IMP)divides
California into thousands of points or "nodes" on the
transmission grid instead of three main "zones".
Distinctprices at the different nodes axe used to
determine the most cost-effective use of resources to
resolvetransmissionbottlenecks. Locational Marginal
Pricing (LMP) will provide more information about
the real cost of deliveringpower to customers.
Buyers and sellers can make informed decisions
about energy pricing based on the ability to produce
and deliver power to where it's needed and, over
time, help to determinethe best locations for new
generation. Wholesale prices for energy will vary,
dependingon the ability to produce or contract for
power that can be easily delivered to where it is
needed. LMP will not affect retail rates, so
residential and business customers should not see any
changes in their utility bills. The new pricing system
simply provides market participants the correct
signals, so they can make wise choices at the
wholesale level.
TheLMP pricing method is workingwell elsewhere
LMP is thepreferred methodfor dealing with
transmission traf ejams and determining the least cost
methodfor meeting electricity demand It bused by all
of the ISOs in the eastern and central United States, where
it is successfully reducingcosts and increasingreliability.
^ California ISQ
roar Lk* w Paws.
Putting a new market design in place while the ISO
continues to operate on a daily basis has been
compared to doing a major engine overhaul on your
car and changing all four tires, while you're traveling
down the highway at 60 miles per hour. So, the ISO is
implementing the plan in phases.
Phage Vk-- nber. 2092
Phase 1 A gave the ISO a new tool, the Automatic
Mitigation Procedure (AMP), to combat "market
power." Market power is the ability of a buyer or
seller to significantly change the price of electricity
through its behavior. The new automatic process
compares previous offers to sell energy to current
market conditions and to each generator's recent
bidding history. If the price of those offers is found to
be too high, AMP automatically lowers the bids to a
preset "reference level" based on the cost of produc-
ing power from that generator. Phase 1 A also contin-
ues the "must offer" rule, which requires generators to
offer their capacity into the real-time market. It also
establishes a $250 damage control price cap that acts
as a backstop to AMP. Together, these rules and
systems are designed to reduce, if not eliminate, the
opportunity and incentive to exercise market power.
Ph= U-40 2904
Phase IB of the Market Redesign &Technology
Upgrade (MRTU) program is a new set of rules and
tools developed for control room operators and
market participants to automate the routine activities
of the Real -Time Market. The program helps
generators respond to ISO dispatches more quickly
and accurately. The result is greater consistency and
efficiency in grid operations as well as the least
expensive power to meet customers' needs. Phase
1 B is a key step toward a more reliable and least -
cost electricity system for California. There are two
main components of Phase 1 B:
■ Economic Dispatch ensures the best resources
are selected to meet the demand for electricity.
In this case, "best" means most reliable and cost
effective, which is good for California consum-
e n who want dependable and affordable
electricity.
■ Uninstructed Deviation Penalties (UDPs)
ensure that once a generator's bid is accepted
and dispatched, the generator delivers the
megawattswhen and where they are needed. If
they fail to do so, the Federal Energy Regulatory
Commission (FERC) has authorized the ISO to
levy tines in order to ensure markets are fair.
What are the benefits for California? Phase 1 B and
the MRTU program together are key to the state's
electricity future. It's a win-win for everyone:
.California's utilities and consumers get what
they are seeking—reliableand cost-effective
electric service.
• Generation owners are better able to manage
their units because they are clear about how the
ISO system is operating and what is expected
from them.
Jogg California ISO
Your Lb* to Power
California ISO
Market Redesign and Technology Upgrade (MRTU)
Frequently Asked Questions
How will MRTU improve grid operations in California?
Most importantly, MRTU improves reliable management of California's
transmission grid by using an accurate model of the transmission system.
Today's rules permit a serious disconnect between expected power flows and the
real time impact on the transmission network, thus requiring ISO operators to
manage congestion and avoid overloads in real time. MRTU fixes these flaws by
creating rules for a "day ahead" market and scheduling process where:
a) power flows over the next 24 hours are scheduled and modeled according
to actual grid conditions and the laws of physics;
b) the risk of shortages is assessed and minimized in advance; and
c) the power flows in real time as grid operators expect from the network
models.
In addition, MRTU will provide clear, stable rules for buyers and sellers in
California's wholesale electricity markets as well as useful information for
investors in transmission lines and power plants. The transparent MRTU rules
will allow market prices to reflect actual costs based on the way electrons
physically flow on transmission lines.
2. Will MRTU encourage new investment in generation and transmission
and provide efficient use of resources in California and the West?
The primary drivers for investment, like today, will continue to be the State's
resource adequacy requirements and long-term procurement rules, as they apply
to load -serving entities. In addition, the CAISO will continue to proactively identify
and pursue needed transmission projects. MRTU will complement and enhance
these features of the California landscape by providing transparent locational
marginal prices (LMPs) that reflect the true costs of energy and transmission.
Locational prices reveal how new power plants will impact the grid, which greatly
helps investors to estimate the revenue streams they can expect to earn by siting
at potential locations. High prices will more easily identify areas with congested
transmission lines, so that profit -minded companies and regulated utilities can
build new lines, with the CAISO's coordination, to improve efficiency and
reliability.
ays/MPD 1 DeoaTber 1,2006
California ISO
3. What measures is the CAISO taking to ensure that locational prices will
not spike, thereby harming consumers?
First, it is important to clarify that under MRTU only suppliers will see locational
prices, not consumers. For consumers, their prices will continue to be averaged
over larger geographical areas representing their utility's service area. MRTU
rules include appropriate local market power mitigation measures as well as
"price caps" that limit how much generators can get paid. Perhaps most
importantly, as a result of requirements and incentives that promote forward
contracting, generators will no longer have an incentive to raise spot market
prices. Under this new framework, if load -serving entities have forward contracts,
it is the suppliers that have an incentive to keep prices low, since it they who will
have to buy out of the spot market if they are unable to keep their contractual
commitments to deliver power. However, if price spikes are caused by supply
shortages, especially during extreme weather conditions, then the price signal
will ultimately attract more generation to the area and will reduce the risk of high
wholesale prices.
By aligning reliability requirements with market rules, MRTU should create more
incentives for power plant developers to site in areas needed to best serve
consumers and promote grid reliability.
4. Because Locational Marginal Pricing calculates prices based on the
highest accepted bid (i.e., the bid of the "marginal" generating unit),
will all generating units in the control area be compensated at the
highest price?
No. Under LMP the prices are calculated at each of about 3000 locations within
the control area, and the highest accepted bid at each generator location sets the
price for that location but not for the entire control area or large load (consumer)
pricing zone. As noted above, prices charged to load -serving entities are
averaged over large load aggregation areas, so the impact on consumers of a
few high locational prices will be muted.
5. How does MRTU protect load -serving entities from excessive
congestion costs?
The CAISO's new market design will give load -serving entities a hedging
instrument called Congestion Revenue Rights or CRRs. These rights give the
ability to load to largely hedge the risk of congestion costs, thus providing
certainty in the costs of transmission service.
ays/MPD 2 December 1,2006
California ISO
6. Will load serving entities have an opportunity to evaluate in a concrete
way the likely impact of the MRTU market design on their procurement
plans and costs?
The CAISO has performed several LMP studies to provide insights on the impact
on the market of moving to an LMP -based congestion management system.
Additional monthly studies will be posted until MRTU start-up.
Details of these studies and reports on the outcome can be found at:
httn://www.caiso.com/docs/2004/01/29/2004012910361428 D6.html
In addition, the CAISO has conducted mock allocations and auctions of CRRs,
which give parties practical insights on the tools they can use to manage risk
associated with the congestion component of LMPs. Currently, the CAISO is
conducting its CRR Dry Run based on the allocation and auction rules that were
approved by FERC.
To provide parties with a full bid -to -bill knowledge and experience prior to start-
up, the CAISO has developed a series of market simulation activities that allow
participants to evaluate and learn to use the scheduling and market systems. The
CAISO has also worked with its stakeholders to release details of the full network
model that will allow participants to evaluate the impact of the market rules using
their own tools.
7. Given all the complexities and uncertainties associated with Locational
Marginal Prices, is itworth it?Why notstick with the current market?
First, the "simplicity" of the current market design is illusory and, as explained
above, is based on an inaccurate representation of the power system. This
forced simplicity creates reliability problems for our operators and results in huge
uplift costs to all customers as a result of the need to make last minute
adjustments to the power system. Moreover, this disconnect between the market
design and reality can allow others to manipulate the system. The current market
design is a belt and suspenders system sustained by burdensome regulatory
requirements on generators, heavy dependence on State contracts, extensive
manual operational procedures in real-time and high uplift costs (costs not
reflected in the market transaction price) that are being spread to all consumers
rather than allocated on cost causation principles. LMPs replace this current
system of unpredictable and sometimes substantial uplift costs with prices that
are based directly on cost -causation principles.
Moreover, congestion management based on LMPs using a full network model
provides a tried and tested structure to aid grid operators. LMP provides more
transparent processes for determining dispatch levels, enabling all parties to
observe and track the cost of redispatch due to congestion.
ays/MPD 3 December 1,2006
California ISO
8. How does MRTU affect on-going concerns with "seams" between the
CAISO markets and other markets in the Western region?
Seams issues between control areas have long existed. The CAISO believes that
MRTU will help alleviate some seams issues and is neutral on the rest. For
example, the start of a Day Ahead market will help resolve congestion earlier and
the improve flows that need to be managed in real-time between control areas.
Additionally, MRTU diminishes current differences between CAISO and the rest
of the west, by moving the intra -day scheduling deadline from 2.25 hours before
each operating hour (T-135) up to 1.25 hours (T-75). This change has been
widely sought by parties scheduling interchange transactions, and will facilitate
increased intra -day trading of power for import and export to and from the CAISO
control area.
The most beneficial aspect of MRTU with respect to seams is the fact that LMPs
will provide more transparent and predictable pricing. One existing problem at the
seams, and one that MRTU alone will not be able to resolve, is the chronic
problem of unscheduled loop flows in real time, which is a challenge to reliable
operations as well as yet another non -transparent cost that is spread to all grid
users.
Pursuant to a FERC's directive, the CAISO will be participating in a technical
conference and is working on further initiatives to address seams issues under
MRTU. The CAISO looks forward to working with its neighbors to address
unscheduled flows and other seams issues that are problematic features in the
industry throughout the West.
9. The Energy Policy Act of 2005 afforded the Pacific Northwest
protection of transmission contracts, preventing FERC from requiring
the conversion cf physical transmission rights financial rights. Will
MRTU impact transmission rights outside of California?
No. MRTU does not require utilities in neighboring control areas to convert their
firm transmission rights to financial rights.
The CAISO does not anticipate that MRTU will alter transactions between the
CAISO control area and the rest of the West. Nevertheless, the CAISO
recognizes that there are differences in market rules that will require solutions to
ensure that barriers to trade between the control areas are minimized or
eliminated. The CAISO has launched a coordinated effort to consult with its
neighboring control areas to identify and address any seams issues that may
exist.
ays1MPD 4 December 1,2006
California ISO
10. How will capacity markets in California affect the Pacific Northwest?
At the start of MRTU, the CAISO will not have a centralized capacity market in
place. The State's current "Resource Adequacy" and "Long -Term Procurement"
rules should lead to more contracts with generating plants in California. The
CPUC is now starting a process to evaluate the need for capacity markets in
California, which could lead to further incentives for generation investment both
within and outside of California.
11. Does a municipal electric system or other entities have to buy or sell in
the CAISO's markets?
No. Parties in California must submit hourly energy schedules so the CAISO can
safely manage the grid, but there is no requirement to participate in CAISO
markets. Any entity can buy or sell directly with any other entity, with no CAISO
knowledge or involvement other than scheduling the transmission.
12. Will the ISO offer long-term firm transmission rights as directed by
FERC?
Yes. The CAISO is currently developing these long-term rights under MRTU, with
significant input from stakeholders.
13. How does the CAISO accommodate the business needs of municipal
electric systems?
Over the years, the CAISO has worked closely with the municipal community to
develop specific features that substantially enhances the functioning of municipal
utilities in the CAISO Control Area. One of these important features is the ability
for a municipal utility to be a metered subsystem (MSS) entity. Under today's
market, an MSS entity can choose to follow their load with their resources,
schedule resources within their MSS to serve their own load, and be exempt from
uplift charges. Under MRTU, MSSs can continue to function the same way.
In addition, MRTU guarantees that contracts for transmission service remain
effective, even if signed before the CAISO's creation. Finally, MRTU preserves
the primary jurisdictional roles bywhich municipalities are regulated and meet
necessary reserve margins.
14. Will the MRTU rules change if there is more competition for retail
electricity customers?
No, not necessarily. If California policy makers decide to change State law and
revive and promote "Direct Access" among electricity consumers, the MRTU
design structure is already set up to be compatible with retail choice.
ays/MPD 5 December 1,2006
FEDERALENERGY
REGULATORY COMMISSION
wasxwcrox, D.C. zoazs
FACT SHEET
Si.vrEMBER 21, 2006
CALIFORNIA INDEPENDENT SYSTEM OPERATOR
MARKET REDESIGN AND TECHNOLOGY UPGRADE (MRTU)
The following relevant facts provide a broad overview of the Federal Energy
Regulatory Commission's action today on the California independent System Operator's
(CAISO) proposed MRTU tariff:
• The changes represent important, but incremental improvements to the existing
market design. MRTU does not create organized markets in California. They
already exist, and MRTU actually makes reforms to ensure that they function
properly. Moreover, these reforms are based on an extensive record reflecting
input from numerous parties inside and outside of California.
• MRTU does not create seams with the bilateral markets in the West; those seams
already exist due to the differing market structures within the Western
Interconnection. Instead, MRTU is designed, in many ways, to mitigate the
seams and enhance trade between the differing regions within the West.
• The day -ahead energy market will allow more opportunities for imports and
exports to be scheduled ahead of real-time. Transparent locational marginal
prices in the day -ahead market will make it easier for suppliers located outside of
California to sell their excess power into California at a competitive price.
• MRTU adopts oiily limited, but crucial, changes in the area of congestion
management. MRTU adopts improved price signals for generators to allow for
more efficient generation dispatch, but it does so in a way that protects
customers. MRTU will offer monthly and annual transmission rights to protect
customers against a much larger portion of congestion charges than is currently
possible.
These reforms should lower costs by increasing the efficiency of the CAISO's
transmission and operations, and offer customers important protections from
congestion charges that do not exist today.
The following are the most important elements of MRTIJ that fix market design
flaws, enhance reliability, better protect wholesale customers from price volatility and
gaining, incorporate price -responsive demand in the markets, and encourage construction
of new resources:
• Eliminates infeasible schedules. Market participants currently submit
infeasible schedules for energy because there are no negative financial
consequences to their doing so. Also, under the current tariff, the CAISO must
accept infeasible day -ahead schedules that do not reflect actual transmission
bottlenecks and operating limitations of generators because its computer
software ignores these limitations. This is a serious problem that forces the
CAISO's transmission grid operators to scramble in real-time to correct
infeasible day -ahead schedules. MRIU will ensure that day -ahead schedules
are physically feasible because its new computer software will fully consider
all transmission bottlenecks and generator operating limitations. This will
make the CAISO's system more reliable.
• Uses a more comprehensive model of the transmission grid. The CAISO
currently decides which resources will be used for reserves (ancillary services)
in a manner that is independent from its energy dispatch decisions. This results
in less efficient use of generation capacity. Under MRTU, the CAISO will
consider at the same time which resources to use for energy and which
resources to use for reserves. This will create more efficient dispatch. Meeting
demand and reserve requirements from the lowest cost set of generators will
benefit customers by keeping prices down.
• Adds a financially binding day -ahead market. Existing market rules require
each Scheduling Coordinator to anticipate customer demand and to match that
demand with an equal amount of generation supply. This can create
inefficiencies because there is no systematic way to ensure selection of the least
cost set of generators to meet customers' needs. Under MRTU, this problem is
solved by the creation of the day -ahead energy and ancillary services market,
which is open to all creditworthy market participants on a non-discriminatory
basis. The day -ahead market will enable all suppliers and customers to submit
offers to buy and/or sell electricity in advance of real time. The CAISO will
consider the bids of all suppliers in the day -ahead market and select the lowest
cost unix of suppliers to serve customers' needs. The creation of a financially -
binding day -ahead market will make it easier for all market participants,
particularly smaller entities, to participate in the California market. A
transparent day -ahead price signal can also be useful in demand response
programs. The day -ahead market will provide market efficiencies that will help
keep wholesale electricity prices down and make it easier for the CAISO to
maintain reliability.
E
• Adopts locational marginal -pricingfor suppliers and for improved congestion
management: Under locational marginal pricing, or LMP, prices in wholesale
markets vary by location and time, based on the physical limitations of the
transmission grid, and reflect the incremental cost of meeting customer demand
at each location. Locational marginal pricing will communicate the true market
value of electricity at each location, as well as the cost of alleviating congestion
between any two locations. This will create financial incentives to dispatch the
lowest cost energy, when considering all transmission bottlenecks. In the long-
term, by making energy and congestion prices more transparent, locational
marginal pricing will help encourage transmission and generation investment at
appropriate locations, as well as demand response. It hears emphasis that the
CAISO's version of locational marginal pricing is aimed primarily at suppliers
who will be paid their location -specific price. Wholesale customers will be
insulated from the location -specific prices because they will continue to pay an
aggregated zonal price.
• Improves transmission rights: The CAISO already incorporates financial
transmission rights, but these are limited to rights to congestion revenues
associated with transmission service between adjacent zones and external
interconnection points. The existing financial transmission rights allow
customers to protect themselves from congestion charges occurring between
zones. Currently, however, most congestion occurs inside the existing zones
and there is no way for customers taking transmission service within each of
the CAISO's three zones to protect themselves from these costs, which again
means that some customers are forced to significantly subsidize the cost of
serving other customers. Wholesale customers must pay for the costs of
congestion within zones in the form of "uplift" payments, or billing surcharges,
which can he highly volatile and unpredictable. MRTU largely alleviates this
problem by ensuring that all congestion costs are reflected in market prices, and
by issuing a better form of financial transmission rights, called congestion
revenue rights, or CRRs. Congestion revenue rights will enable load serving
entities and others to protect themselves against the costs of congestion. Also,
customers under contracts that pre -date the existence of the CAISO will
continue to receive protection against congestion costs consistent with the
requirements of their contracts.
• Requires compliance with the Long -Term Firm Transmission Rights Final
Rule: Currently, the CAISO offers no financial transmission rights with a
duration of longer than one year. This has often been cited as an impediment to
the construction of new facilities necessary to serve the California market, and
a harrier for customers trying to access needed resources on a long-term basis.
This order addresses that problem by directing the CAISO to comply with the
3
Long -Term Firm Transmission Rights Final Rule. This should hasten the
creation and availability of long-term firm transmission rights, directly
addressing concerns raised by customers in California.
• Increases bid caps incrementally: Currently, suppliers' bids into the CAISO's
real-time markets are capped at $400/MWE It has long been recognized that,
if price caps are set too low, they can result in a reduction in needed supply that
will usually not be in the public interest. Therefore, in markets where bid caps
are used to help protect against the exercise of market power, it is imperative to
set the bid cap at an appropriate level in order to stimulate demand response,
provide incentives to enter into long-term contracts, and foster investment in
new infrastructure. If a bid cap is set too low, this could adversely affect
reliability by artificially suppressing resource prices when resources are scarce.
MRTU is slated to go into effect November 2007. At that time, the bid cap will
be increased first to $500/MWh, and thereafter incrementally increased over
the next two years until it reaches $1,000/MWh. This gradual increase will
give market participants time to adjust to both the new cap levels and other
mitigation features, while helping to ensure that needed supply is not driven
from the market by overly restrictive price caps.
• Improves local market power miti ag tion: Currently the CAISO's market power
mitigation lacks adequate measures to address the potential for generators
located in load pockets (areas surrounded by transmission bottlenecks) to
exercise market power. MRTU adopts local market power mitigation
techniques that identify generators with the potential to exercise local market
power, and limits those generators' bids to pre -established default levels.
These default energy bids are tailored to contribute to the recovery of the
generator's fixed costs, so the generator can afford to continue producing
energy. These local market power mitigation rules will help prevent market
manipulation and price volatility, while maintaining adequate generation
supply and reliability.
• Demand Response: MRTIJ provides loads with demand response capability —
the opportunity to participate in the CAISO day -ahead, real-time, and ancillary
services markets under comparable requirements as supply, and receive the
corresponding market value. Price -responsive demand moderates price
increases and price volatility for all customers (because some demand is willing
to be reduced rather than pay higher prices for energy from more expensive
units) and it also helps to check potential market power because it provides a
countervailing willingness to reduce demand in the face of high prices.
Further, demand response contributes to reliability by shaving peak demand
and providing reserves. We believe the continuing development of demand
response is an effective route to produce CAISO markets that are competitive
4
and that can be relied upon to produce rates that are just and reasonable for
customers. We therefore direct parties interested in further developing demand
response in the CAISO markets to provide proposals to the Commission that
detail new avenues for incorporating price -responsive demand within 60 days
of the date of this order.
• Builds upon resource adequacy: Resource adequacy is the availability of an
adequate supply of generation or demand responsive resources to support safe
and reliable operation ofthe transmission grid. Until June 2006, the CAISO
market did not require load -serving entities to procure sufficient generation
capacity to serve their customers. The lack of this requirement jeopardized
reliability and made it difficult to ensure that wholesale prices would remain
just and reasonable. Under MRTIJ, load -serving entities under the authority of
the California Public Utilities Commission will be required to obey its
requirement to maintain a level of capacity above load serving entities'
forecasted customer needs (currently 15-17 percent). They will also have to
demonstrate a year in advance that they have procured resources to cover 90
percent of their summer (May through September) peak period needs. Other
load -serving entities that are CAISO members and serve customers in the
CAISO control are required to comply with the planning reserve margin for
capacity that is set by their Local Regulatory Authority. If the Local
Regulatory Authority does not establish such a margin, the default margin will
be 15 percent. These resource adequacy requirements will help ensure
sufficient supply, enhance reliability, protect against price volatility, and reduce
the opportunities to game the market that exist when electricity supplies are
insufficient to meet customers' needs.
In order to further address commenter concerns and to build on further market
improvements, the Commission's order on MRTU directed that future technical
conferences be held on various aspects of MRTU. One ofthe technical conferences the
Commission directed will address commenter concerns about operational rules that differ
between the CAISO and other providers of transmission service in the West (so-called
"seams" issues). The Commission order also directed the CAISO and neighboring
transmission providers to meet to resolve these seams issues, and to jointly inform the
Commission on the progress of these efforts through the filing of quarterly status reports.
G
®American
Wholesale Electricity Markets
other authorities to ensure that FERC addresses the
problems in these markets, and adheres to its statutory
obligation under federal law to protect electricity con-
sumers.
Public Power
FACT E ruary 2009
},�Issociation
Summary
In response to continuing problems facing members of
the American Public Power Association (APPA) in re-
gional wholesale power markets, primarily in regions
with Regional Transmission Organizations (RTOs)/In-
dependent System Operators (ISOs) that are under fed-
eraljurisdiction, APPA instituted the Electric Market
Reform Initiative (EMRI) in March of 2006. EMRI was
established to first assess and then address the market
failures and other serious challenges facing public
power systems across the country.
The migration to RTOs in certain regions of the
country coincidedwith a push in the 1990s to deregu-
late state retail electricity markets. This push was cou-
pled with assertions by state policymakers and federal
regulators that lower prices and increased infrastruc-
ture investments would be the result. It has become in-
creasingly clear to APPA, however, that RTO -operated
markets are not benefiting electricity consumers, and
that prices have increased disproportionately to infla-
tion and other factors like rising fuel costs. In our view,
these markets are not competitive; and we believe con-
sumers are exposed to prices for electricity that fly in
the face of the standard of "just and reasonable" rates
required by the Federal Power Act.
This issue is important to APPA because almost all
public power utilities rely to some extent on purchases
from the wholesale markets for the energy they supply
to their customers, and many rely almost exclusively on
such purchases. APPA, and many other organizations,
asked the Federal Energy Regulatory Commission
(FERC) to investigate the problems in these markets
identified through the EMRI studies and to take correc-
tive action, but FERC denied that request. Thus, APPA
believes that Congress should exercise its oversight and
Background
Often termed "restructuring" or "deregulation," a
major transition has taken place in some of both the re-
tail and wholesale electricity markets over the past 15
years. These changes were based in part on the belief
that electric utilities should no longer be regulated mo-
nopolies and instead should be deregulated and face
competition, just as trucks, railroads and airlines did
during the 1980s. In the retail markets, which are
under state control, policy changes in the 1990s en-
couraged or required abandonment of the traditional
vertically -integrated utility company model in order to
disperse ownership of generation facilities and thus
spur competition. In most states that made such
changes, public power utilities were allowed to "opt
out" of the retail access programs, and almost all of
them did so. That means that public power utilities re-
tained their legal obligation to serve all customers in
their service territory and to plan for and acquire the
necessary resources, either through ownership or con-
tract.
In the states that "deregulated,"retail customers of
private utilities were given the right to purchase power
from non-utility providers. As mentioned above, the
private utilities were required to sell their generation
facilities, but in many cases those power plants were
simply sold to an unregulated affiliate of the same
holding company that also owns the distribution utility
that sold them. As a result, the private utilities were also
11']x.�k'salc° l�.lecu�it:i€�� A9ar!:ets
forced to purchase their power on the wholesale mar-
ket, often generated from the same plants they Used to
own, but at much higher prices. two agreements were
generally reached between utilities and carstomer repre-
sentatives as part of the new retail market regime. First,
consumers were often required to finance the unpaid
debt on the existing generating Facilities, known as
"stranded costs." Second, retail rates for residential cus-
tomcrs were frozen during what was thought to be a
"transition" period turtil all customers could participate
in the marlccts by choosing alternative suppliers.
Meanwhile, the federal agency that regulates whole-
sale power sales, the Federal Energy Regulatory Com-
mission (FERC), began to push for restructuring of the
wholesale markets and the creation of WFOs/ISOs to
oversee these markets. FERC abandoned the require-
ment that. electricity sold in the wholesale market
should reflect the cost of producing the power (plus a
reasonable profit)– the traditional approach to meet-
ing the just and reasonable standard in federal law
mentioned above. Instead, they nsed certain economic
tests t.o analyze various market cotaditions and deter-
mine whether the), were sufficiently "competitive" to set
prices, subject only to reporting and limited oversight
requirements. Thcse changes hi the ivbolesale and re-
tail markets were predicated on assertions by federal
and state officials and other RTO proponents that they
would promote competition, spin- efficiencies and inno-
vation, and lower rates for consumers –assertions that,
for the most part, have not come to fruition.
in response to FERC's encouragement, wholesale
markets in the Northeast., Mid -Atlantic, Midwest re-
gions and California are now operated by RT0s/IS0s.
"These organizations administer niarkcts where electric-
ity is bought and sold under highly complex arrange-
ments. RTO-rc.ut markets generally cover the same
regions in which the majority of the retail access states
are located. As a result, these states are [ionic to a large
fool of generation with prices that arc unregulated at
both the state and federal levels.
In most retail access states, competitive suppliers at
the retail leveL have not materialized for most residen-
tial acrd small business customcrs, and thus these cus-
tomers still purchase power from heir local utilities.
But. because these utilities no longer own generation (as
discussed above), they must procure such power on the
wholesale markets run by R YOs/ISOs through various
"auctions" and other procedures nsed to select the sup-
pliers of the power. Again, as discussed above, often the
suppliers winning these auctions arc the unregulated
owners of the generating plants formerly owned by af-
filiated utilities, and largely paid for by customers. Yet,
because the prices for electricity are no longer cost -
based, these new owners arc able to charge match more
than the), were paid prior to deregulation.
One core function of an Wl'O is to provide non-dis-
criminatory open access transmission service for elec-
tricity transactions. This requires that owners of
transniission lines do not give any preference or deny
the use of their transmission lines to other sellers and
purchasers of electricity. "Io carry out this responsibility,
XrOs have firnctiorral control, but riot ownership, of
the transmission system. RTOs also coordinate regional
planning for new transmission lines and eliminate rate
"partcaking" (charging multiple transmission ices for
One transaction). Most RTOs handle these functions
well and provide benefits to consumers.
A second core function of RTOs is to administer
niarkcts for various electricity services in their regions
including energy, capacity and ancillary services . RTO -
administered markets are intended to provide a cen-
tralized marketplace in which electricity can be bought
and sold at. pi -ices established by "competitive" forces.
WrOs do not own the power- plants that generate the
power bought and sold in the market, but: rather de-
velop the rules to administer the niarkcts, decide which
generators will run and at what levels, grant (or deny)
the transmission services needed for transactions to
occur, and run the billing systems for payments for
power. The problems that have developed st.cm frons
this second core function—the energy-related markets
operated by clic RZ10s—and are attributable to certain
fundamental features of the market design, the exercise
of market power by some generators, and lack of'suffi-
dent FERC oversight.
ale Electricity Markets
Congressional Action
The Energy Policy Act of 1992 opened wholesale mar-
kets to independent power producers, which in turn
underscored the need for open access by these new
market participants to the bulk transmission lines
largely owned by vertically -integrated investor owned
utilities. In April of 1996, FERC issued its landmark
Order Nos. 888 and 889. In Order No. 888, FERC di-
rected the electric utilities under itsjurisdiction (pri-
marily investor-owned utilities) to provide open and
nondiscriminatory access to their transmission lines in
order to help bring down the cost of electricity through
increased wholesale competition. FERC also encour-
aged the formation of RTOs/ISOs, and set out certain
functions they should perform. In Order No. 889,
FERC requiredjurisdictional utilities to establish
electronic bulletin boards, called "OpenAccess Same
Time Information Systems," to help manage the non-
discriminatory flow of electrons across transmission
systems.
As regional power markets began to develop, it be-
came clear that new transmission facilities were not
being built at the same rate as new generation (and al-
most all of that generation was non-utility owned and
natural gas-fired).Therefore, in December of 1999,
FERC encouraged all transmission owners to voluntar-
ily develop andjoin RTOs, Order No. 2000 was then is-
sued and required FERC jurisdictional transmission
owners to submit an RTO plan by October of 2000, and
targeted December of 2001, as the date by which all
RTOs would be operational. However, since Order No.
2000 did not contain a mandated obligation to join an
RTO, they did not form in a number of regions of the
country. In response to this situation, in 2002 FERC
pushed to standardize RTO functions and markets
across the nation and to requirejurisdictional utilities
to participate in them. This FERC initiative, called
"Standard Market Design" (or SMD) spawned signifi-
cant opposition in Congress and further stalled RTO
development in regions of the country that did not yet
have them —primarily the Pacific Northwest, the South
and the desert Southwest.
In early 2008, companion Senate and House legisla-
tion to provide cost accountability to Regional Trans-
mission Organizations (RTOs)/Independent System
Operators (ISOs) was introduced. The Consumer Pro-
tection and Cost Accountability Act (S. 2660 and H.R.
5547, respectively) was sponsored in the Senate by Sen-
ators Sanders (IVT) and Snowe (R-ME),and cospon-
sored by Senators Kerry (D -MA), Kennedy (D -MA),
Leahy (D -VT), Collins (R -ME) and Mikulski (D -MD);
while in the House it was sponsored by former Repre-
sentative Allen (D-ME)and cosponsored by Representa-
tives Delahunt (D -MA), McGovern (D -MA), Michaud
(D -ME), Welch (D -VT), and Tierney (D -MA). It is un-
clear as of this writing if this legislation will be reintro-
duced during the 111th Congress.
Also in 2008, the Government Accountability Office
issued a report on wholesale electricity markets as re-
quested by Senators Lieberman (I -CT) and Collins (R -
ME) which urged FERC to investigate these markets to
ensure that rates are just and reasonable.
APPA and other like-minded organizations continue
to encourage leadership in both the Senate Energy and
Natural Resources Committee and the House Energy
and Commerce Committee to hold investigative hear-
ings into the functionality of these RTO/ISO-run elec-
tricity markets and to urge FERC to undertake an
investigation of these markets as recommended by the
GAO.
APPA Position
APPA members in RTO regions report substantial prob-
lems that impair their ability to provide reasonably
priced and reliable long-term service to their own elec-
tric customers because of RTO -run markets. Studies un-
dertaken by APPRs Electric Market Reform Initiative
have shown that there is substantial evidence that
prices in these regions are "unjust and unreasonable."
FERC has the ability to use its existing and new author-
ities (provided in the Energy Policy Act of 2005) to rem-
edy this situation.
In December of 2007, APPA joined 40 other con-
sumer, business and public interest groups in asking
FERC to conduct abroad investigation of fundamental
RTO -run market problems and to take the necessary
steps to protect consumers as required by law. In a final
rulemaking issued by FERC in late 2008, this request
was denied. APPA has also spearheaded a new coalition
of industry and consumer groups called the Campaign
for Fair Electric Rates. This group is asking Congress to
1L'11r31cs;3ic Ellcctriciw M;irk(cis
PUL pressure on FERC, either through oversight hear-
ings or legislation, to fulfill its obligation of ensuring
just and reasonable rates Tor electric consumers,
In addition, APPA has developed detailed proposals
for both short- and long-term solutions to the problems
in RTO markets. The most recent of these is APPYVs
Competitive Market Plan released in February of 2000,
and available oar APP.A.'s website at www.appanet.org. In
sump ary, the plan proposes to retail, the wro func-
tions that are working well—principally those associ-
ated with planning for and operating the regional
transmission grid—acrd replacing those (Unctions that
are not beriefiting consumers, mainly the design and
operation of the energy and capacity markets. The
Competitive Market flan focuses on moving market
participants away horn short-t.erm, high-priced spot.
markets, and into long-term bilateral contractual
arrangements that will stabilize electricity prices and
provide the fina3lcial certainty necessary for invest-
nuents ill arcw generation and transmission infrastruc-
ture necessary to meet future reliability requirements.
APe"NAssociation
American
Public Power
V --.q ■
E1
Consumers
N
n Peril
Why RTO -Run Electricity Markets Fail to Produce
Just and Reasonable Electric Rates
Consumers
N
n Peril
Why RTO -Run Electricity Markets Fail to
Produce Just and Reasonable Electric Rates
February 2008
American
Public Power
Association
APIPOW"""1441"
1875 Connecticut Avenue. NW
Suite 1200
Washincglon, DC 20009-5715
P h 202.407.2900
Fax: 202.467.2914
www.APPAnet.org
Table of Contents
ExecutiveSummary ........................................ —............ .........V
I.
Introduction........................................................................
1
II.
Public Power's Perspective .................................................
5
Ill.
Competition and Wholesale Electric Power Markets ...........6
IV.
Failures of Centralized RTO -Run Wholesale
Electricity Markets.............................................................
12
V.
Fundamental Market Reform is Necessary
to Protect Consumers........................................................
25
VI.
Recommended Solutions to Specific, More Discrete
MarketProblems...............................................................
30
VII.
Conclusion .............._........ _ ............................. .............35
Executive Summary
0his white paper, prepared by the American Public Power Association,
comes at a time of increasing peril for electricity consumers–both in
present costs and future reliable service. Over the past 15years,
federal and state policymakers have fundamentally restructured wholesale
electricity markets and retail electric service in many parts of the country. These
changes were predicated on the promise that increased "competition" would spur
efficiencies, promote innovation, ensure an adequate infrastructure and, most
importantly, result in lower rates for consumers. But the opposite has occurred ----
restructured markets are producing higher prices (and higher profits) than one
would expect in a competitive market. Nor is new infrastructure being constructed.
And the only "innovation" many consumers have seen is in the new and complex
market mechanisms developed to extract more dollars from them for the same basic
product —retail electric service.
During this time, the Federal Energy Regulatory Commission changed its policy
emphasis from ensuring non-discriminatory open access transmission service to
implementing centralized wholesale electric markets run by regional transmission
organizations (RTOs). The commission has limited its regulation of electric markets
and allowed electricity generators to charge market-based rates. Many states in
regions with RTOs implemented some form of retail electric utility restructuring, to
allow retail consumers to choose their own power supplier. As part of the transition
to these new retail restructuring regimes, many state -regulated incumbent electric
utilities sold off their existing generation assets to unregulated third parties,
including their own unregulated affiliates. All of these policy changes were made on
the assumption that competition in wholesale and retail electric markets would
develop, But, as this white paper explains, the structural features of the electric
utility industry (high capital costs, high barriers to entry, control by incumbents of
generation sites, etc.) make it difficult for true competition to develop or flourish.
RTO Market Failures
The centerpiece of FERC's new wholesale electric regulatory policy --development
of RTOs and their operation of centralized markets for wholesale power supply,
capacity, and ancillary services—has been especially problematic. RTOs do provide
services that have substantial value, which should not be overlooked. These services
include administration of regional open access transmission tariffs (OATTs) on a
non-discriminatory basis, elimination of "pancaked (utility -by -utility) transmission
rates and development of more coordinated regional transmission planning
processes. But these substantial accomplishments have been overshadowed by the
high costs and dysfunctional nature of RTO -run centralized markets. Dysfunctional
features of these markets include:
Offers to sell power are not connected to the sellers' actual costs of generating
power (average, marginal or otherwise), as FERC would have required under a
traditional cost-of-serviceratemaking regime and as a more competitive market
would have produced. Lower-cost generators are paid the same price as those
with higher operating costs, but these additional dollars have not spurred the
w.APPAnet.org Consumers in Peril V
entry of now competitors or induced .substantial investment in new generation
facilities.
• Prices for power sold tinder bilateral contracts (individual contracts between a
buyer and a seller) have been substantially influenced by the high prices sellers
can obtain in the RTOs' centralized markets. It is uncomnnon to see bilateral
power supply contracts in RTO regions for terms longer than one to five years, or
that are backed by specific electric generation units. Longterm bilateral contracts
are increasingly difficult for purchasers to obtain under reasonable terms and
conditions.
• RTO -run bid -based markets create incentives for generators to withhold capacity
(to create artificial shortages that increase prices) and to refrain from building
otherwise -needed new generation capacity (which could reduce prevailing market
prices, thus reducing profits).
• In contrast to its theoretical basis, there is no evidence of any relationship
between locational marginal pricing (LMP) signals and the construction of new,
generation and transmission facilities.
• F.loctric consumers are paying billions in additional charges required by new
RTO -run locational capacity markets, but it is highly uncertain, at best, whether
these markets will support future development of enough new generation
facilities to meet demand.
• Regional high-voltage transmission facilities are essential to support wholesale
power supply transactions. However, transmission capacity is often insufficient to
meet demand and the associated transmission rates are therefore uncertain, due
to substantial congestion charges imposed by the RTO.
• In RTOs, new markets are continually developed to price previously cost -
regulated products, e.g., ancillary services, without any rigorous cost -benefit
analysis. The administrative and software costs associated with these new markets
are very high, with little evident benefit to consumers.
Fundamental Market Reform is Necessary to Protect
Consumers
It is time to acknowledge that market forces alone are not sufficient to discipline
prices and ensure adequate service in the electric utility industry. There is a
significant amount of evidence of problems in RTO -run markets presented in the
studies that APPA sponsored during the initial phase of its Electric Market Reform
Initiative. APPA summarizes that evidence in this white paper. The EMRi studies—
along with the multitude of materials filed by other load -side interests, in FERC's
Advanced Notice of Proposed Rulemaking (ANOPR) in Docket Nos. RM07-19-000
and AD07-7-000, Wholesale Conipeti[ion in Regions with Organized L:Iectric
Markets—strongly suggest that RTO -run centralized wholesale electricity markets are
not producing just and reasonable rates. In the face of this evidence, FERC has an
affirmative obligation—expressly set forth in the Federal Power Act—to investigate
whether rates subject to its jurisdiction are unjust and unreasonable and to take
remedial steps if it finds they are.
VI Consumers in Peril www.APPAnet.org
To avoid further harm to consumers while FERC is carrying outthis investigation,
APPA recommends that FERC quickly place a moratorium on both the establishment
of new RTO -nm centralized markets, as well as the implementation of new markets
for additional products and services in existing R'FOs, unless such markets are
supported by all classes of stakeholders and accompanied by a valid cost/benefit
analysis.
APPA Recommends Restructuring RTOs as Day 1 RTOs
Based on recent indications, APPA is concerned that. FERC will not initiate an
investigation into the justncss and reasonableness of rates in RTO -run centralized
markets without firsthaving received specific proposals for RTO market reforms. While a
number of RTO market reform proposals have been offered, APPA in this white paper
offers its own suggested reform proposal—to restructure full "Day 2" RTOs (RTOs with
full centralized power supply markets) into more streamlined "Day I" RTOs. This
proposal is designed to keep what is working relatively well in RfOs, namely the "Day I"
transmission -related functions, but to streamline and ultimately replace those functions
and features—mostly associated with R1'O-nun centralized power supply, ancillary service
and locational capacity markets—that have failed to produce sufficient benefits for
consumers. Such a regime would de-emphasize participation in RTO -run centralized
power supply markets by both buyers and sellers, and foster longer-term bilateral power
supply contracting.
The functions that such a Day 1 RTO would cant' out are as follows:
• Ensure non-discriminatory access to the grid through independent administration
of a regional OATT and provision of transmission service, including needed
ancillary services.
• Develop and administer a regional transmission rate design that eliminates rate
pancaking and assures the recovery of the cost of transmission facilities for all
u-ansmission facility owners that wish to participate in the FX0, regardless of their
form of ownership.
• Operate a single regional open access stmc-time information system (OASIS) and
independently calculate available transmission capacity (ATC).
• Conduct independent and collaborative regional transmission and generation
interconnection facilities planning, with the full inclusion of affected stakeholders.
• Carry out wide -area system security and ichability-related activities, ensuring that
transmission facilities are operated in compliance with relevant North American
Electric Reliability Corp. and regional reliability entity criteria.
• Operate an energy imbalance market to enable transmission customers to manage
their imbalances and to allow generators (including intermittent renewable
generators) to sell excess generation not committed under bilateral contract
arrangements.
• Ensure adequate generation reserves through implementation of appropriate
regional resource adequacy requirements.
APPA intends to produce a more detailed description of this proposal in a separate
www.APPAnetorg Consumers in Peril VII
document, which will be published later in 2008.
Until this proposal or similar Fundamental IUO market reforms are implenicnted, there
arc a number of discrete KFO-related problems that could be addressed more quickly, to
provide electric consumers with some; interim relief:
• Require c:ost-benefit studies and proof of broad stakeholder support to accompany
any RTO filings to implement ncty markets and programs or changes to existing
markets or programs;
• Revise RTO mission statements and strategic plans to include an explicit goal of'
reducing CICCtriC polver Costs to custom 'rs;
• Improve RTO governance to be more, respotAve to stake h olclens;
• Ensure that market monitors arc tnrly independent and have all of the resources
necessary to perform thein functions; and
• Improve data Van.5parency by providing public access to generator bid data on a
next -clay basis, with open identification of generators, as well as generator cost and
oporating data.
Conclusion
111'1A wants this white paper and the proposals it contains to contribute to a constructive
dialogue to develop sorely needed reforms to RTO -run centralized wholesale electricity
markets. The debate should no longer he about who can best massage the statistics on
prices or ivhetbcr' it is more virtuous to support "competition„ or "regul-Mion." Instead,
all industry participants need to work together to design a regulatory system for
clectrich), maAels that truly benelits coaastime s, businesses and the environment.
VIII consuiners io Peril wmY.APPAnet.org
Introduction
0emholesale electricity markets have changed fundamentally over the past 15
years, The Federal Energy Regulatory Commission changed its policy
emphasis from ensuring nondiscriminatory open access transmission
service to implementing centralized wholesale electricitymarkets run by regional
transmission organizations (RTOs),with limited regulation. Meanwhile, many states
implemented programs to provide retail consumers with a choice of electricityproviders.
In many of these states, shareholder -owned electric utilities sold offtheir generating plants
to third parties (in many cases, unregulated affiliates), who can sell their power at prices
that are no longer tied to the cost of production and arc subject only to limited RTO
"'market mitigation" rules.
These changes were predicated on the premise that the combination of open access
transmission service and these new centralized wholesale markets would promote
" competition" that would spur efficiencies and innovation, ensure adequate supplies and,
most importantly, lower rates for consumen. But evidence gathered in investigations of
the RTO -run wholesale markets and the real-world experience of consumers shows that
the opposite has occurred. These deregulated markets are producing both higher prices
and higher profits than one would expect in a competitive market. Prices exceed those
prevailing in the remaining regions that have not restructured and have retained cost-of-
service
ost-ofservice regulation.
This is not to say that RTOs provide no benefits. Properly structured, RTOs can provide
independent and nondiscriminatory transmission service under open access
transmission tariffs (OATTs), charge regional, non -pancaked transmission rates, and lead
regional collaborative transmission planning and construction processes. Such RTO
functions benefit consume yet FERC's policies in promoting centralizedRTO-run
markets have increasingly lost sight of these RTO functions, as market implementation
has taken center stage. It is the RTO -run centralized wholesale markets that are the
primary focus of this white paper.
On December 17,2007, a diverse group of 41 consumer advocacy, business and public
power organizations came together to ask the FERC to investigate whether restructured
wholesale electricity markets are producing unjust and unreasonable wholesale power
prices prices that are then passed along to retail customers in their monthly bills. Among
the serious problems flagged in that filingare the increasingly high electricity prices
consumers are paying, while certain sellers of electric generation are earning excessive
profits. Worse yet, these higher profits are not invested in new electric generation and
transmission facilities and, therefore, will not reduce prices over the longer term
A large body of evidence gained through various studies that the American Public Power
Association and others have commissioned supports these conclusions.' These studies
contain substantial evidence of market dysfunction, demonstrating that the portion of
the electricityindusuy operating under FERCjurisdictionat RTOs resembles more of a
1 A summary of the initial studies that APPA commissioned can be found at:
http://www.appanet.org/ftles/PDFs/EMR[Summarybooklet.pdf. For the full studies, go
to http://www.appanet.org/emri.cfm.
www.APPAnet.org consumers in Peri! 1
Supporters cf
concentrated oligopoly than a competitive market. (For example, financial analyst
restructuring continue
Edward Bodmer found that shareholders of five owners of unregulated generation assets
have earned as much as $70 billion more than investors in regulated electric utilities over
to promote market-
the past few years.)2 Analyses by London Economics and Synapse Energy Economics
suggest behaviors inconsistent with a competitive market and consistentwith the exercise
based rates, highly
of market power: large and fluctuating disparities between costs and prices, aberrational
rest icted access to
patterns of offers to sell power, and the absence of effective price signaling for the
construction of sorely needed new generation and transmission facilities?
relevant price and cost
data and other policies
These non-competitive outcomes are the result of specific policies applicable to
centralized RTO -run wholesale markets. For example, FERC allows generators to charge
that could work only in
"market-based rates," relying on a supposedly competitive market to discipline prices to
markets with robust
the 'just and reasonable" levels required by the Federal Power Act. Such a policy fails to
recognize that these markets are fundamentally different from markets for other goods
competition.
and services.AS the December 17filingnotes, "`thecommission'sratemaking
methodology in RTO -run organized markets is based on presumed conditions that are at
variance with reality. 114
These presumed conditions include: the absence of significant
market power; free entry and exit of competitors; an optimized generation resource mix;
the absence of significant structural and behavioral impediments to long-term
contracting; the presence of price -responsive demand; and the availability of short-term
substitution alternatives.
Despite the large body of evidence that these markets do not meet the preconditions for
effectivecompetition and in fact demonstrate outcomes indicative of the exercise of
market power, supporters of restructuring continue to call these markets "competitive."
They continue to promote market-based rates, highly restricted access to relevant price
and cost data and other policies that could work only in markets with robust
competition. Many of these restructuring supporters are entities with large portfolios of
generation facilities in RTO regions; they are the primary beneficiaries of the current
dysfiinction in centralized RTO -run wholesale electric markets.
Supporters of these markets try to frame the debate by characterizing critics as opposing
"markets"and "competition"and instead supporting "regulation."But it is becoming
increasingly apparent that leaving electricity pricing and supply up to these "markets'ls
an invitation to exercise market power. Because current wholesale regulatory policies
2 Affidavit of Edward Bodmer, Comments of the American Public Power Association FERC
Dockets R ML 07-19-000 and AD07-7.000, Wholesale Competition in Regions with
Organized Electric Markets, September 14,2007.
S A Comparative Analysis of Actual Locational Marginal Prices in the PJNI Market and IfUimaaw
Short -Run Marginal Costs: 2003-2006, prepared by Serkan Bahceci,Julia Frayer, Amr
Ibrahim and Sanela Pecenkovic, London Economics International, February 2007, and
LMPElectricity Markets, Market Operations, Market Power, and Value for Consumers, prepared
by Ezra Hausman, Robert Fagan, David white, Kenji Takahashi and Alice Napoleon,
Synapse Energy Economics, at http://mwappanet.org/emri.dm.
4 Request to Expand the Scope of the 206 Proceeding, Docket Nos. RM07-19-000 and AD07-
74)00, December 17,2007.
2 Consumers in Peri! www.APPAnet.org
ignore these problems, they are detrimental to consumers. Moreover, the problems arc
growing worse. 'I'liese policies are harming not just public power utilities and the
consumers (lie), serve, but also consumers alld bUsineSSCs throughout. the country.
Because many states that implemented retail access programs required their investor-
owned utilities to sell off their generation facilities to unregulated entities, these
generation facilities are now largely concentrated in the hands of owners that can charge
"market rates" for this power (often unregulated affiliates of the traditional utility
supplier). Most consumers in these states arc still purchasing retail electric service from
their traditional electric utility under "default" or "provider of last resort" service. As a
result, most residential customers are rcceivingr power from the same utility as before, but
that utility must now procure electricity ori the wholesale market, at substantially higher
"market" rates, in many cases From the same generation facilities that the utilities
themselves used to own. With retail rate caps now expiring in many states, consumers arc
finding themselves exposed to the lull brunt of the resulting higher wholesale power
prices for the first time.
In restructured states where customers arc now fully exposed to market prices, electricity
rates increased almost 40 percent since 2002, compared to 19 percent for states that
remain regulated.{' In July 2007, the average electricity price in states located within
RFOs was almost 11 cents per kilowatt-hour, about 2.4 cents greater than the rates paid
outside of R'I'O markets (about a 30 percent difference). 'This differential was
significantly greater than [lie I cent difference in January 2003, when, non -R'I'O states
had an average rate of about 6 cents.''
Not only are prices increasing at a faster rate in R'I'O-rutr markets, butt also wholesale
customers in these regions (load -serving electric utilities that procure power to serve
their crud-usc customers and large industrial customers that can purchase directly in
wholesale markets) are finding it difficult to obtain reasonably priced longer-term power
supply co.ntr-acts.7 "I'be lack of such long-term contracting makes it more difficult to
The 17111u1rl o%Cont judili.oa. ora Electricity Prices: Can 4t e Dimxrn a Pallem.?, IS,enneth Rose, Ph. D.,
Consultant and Senior bellow, 11IMiLOW of Public I7tihucs, prescirtatiou to the Harvard
Electricity Policy Croup, December 6, 2007, available at
lute://����cv.alapanet.org'/crnr-i.cfin.
The A4issi-ngBenclrnacark iva lsleclricily Denfguhzlion, by Robert. McCullough, Managing Partner,
and Ann Stewart, Research Analyst, McCullougli Research, December 2007, available at
htyr//ti�c,�v.appanc:t.org/enrri.cfirl.
See for example the following testimony provided to ISI;RC in Conferences on
Competition in Wholesale Power Markets, Docket No. AD07-7-000: Prcp<ucd Statement.
of Roy Thilly, President and CEO of Wisconsin Public Power Inc., February 27, 2007,
http://C,n,w.ferc.gov/EveratGale)iclai-/files/20070301133025-
'I'hilly,%20Wisconsin%201'ublic.%v201'otiver.pdf,'Iestiinony of MWI.er I;rockway— Manager
of' Regulatory Affairs — Energy for Alcoa, May 8, 2007,
burp://wvsv.ferc.gov/1?ventCalendar/k'iles/20070:�U8083948-Brockway,"%20AIcoa.pdf
Statement of Duane S. Dah1quist On Behalf of Blue Ridge Power Agency, May 8, 2007,
ltttp: //wanv. ferc.gov/Eve lxtCaltaid:ti-/Idles/200705091 > 1931-
Dahlyuist,%20Blue%20Ridge%201'o�tier.pdf
www.APPAnet.org Consumers it? Peril 3
finance needed new electric generation projects, including clean and innovative sources
of power. Moreover, in Ilse absence of regufato:i, measures to assure adequate supplies of
electricity to enforce a traditional service obligation by electric utilities to their retail
customers, generation owners and incumbent utilities have little incentive to invest in
new generation a n d transmission infrastructure.
Itis time to acknowledge that "market forces" alone are not sufficient to discipline prices
and ensure adequate service in the electric utility industry. The market failures described
above must be addressed before the lack of affordable electricity becomes even more of a
threat to the quality of life and the economy of much of the nation. As the electric utility
industr-1, implements carbon -reduction nwasures to address climate change, and as
needed new transmission and generation infrastntcuu•e addiiions come on line to meet
increasing demand, the financial burden on retail electric customers will increase. State
and federal policymakers owe it to these customers to make snre that rate increases are
not layered on top of already unjust and unreasonable rates engendered by
dysfunctional RTO markets.
The purpose of this white paper i s to present an overviow of the problems i n today's
resu-rrctured wholesale electric markets and to identify the steps needed to address these
problems. Section 11 provides a brief discussion of the public power business model and
our perspective on the industu�,. Section III then addresses the unique characteristics of
the wholesale electricity market that make competition difficult to achieve and the
statutory responsibility of FERC to ensure that rates arcj u st and reasonable. Section IV
details the specific problems that have arisen in the RTO -run wholesale markets. Section
V introduces APPA recommendations for longer-tenu reforms, and is followed by a
listing i n Section VI of proposed interim remedial actions that FERC should take i n the
near-term to protect consumers until more fundamental changes can be agrc_ed upon
and implemented.
4 Consumers in Peril Wt" APPAnet.org
11 Public Power's Perspective
0ublic power utilities were created by state or local governments to serve
the public interest. They are not-for-protit entities controlled locally by
the customers they serve. Their purpose is to provide reliable and low-cost
electric power to their retail and wholesale customers, consistentwith good
environmental stewardship, and to do so consistentlyyear after year. They have retained
their traditional utility obligation to serve all customers in their service areas; indeed,
they see this as their mission.
Some public power utilities, particularly the largest ones, are fully vertically integrated.
They own and operate all of the facilities -generation, transmission and distribution—
necessary to provide electric service to their retail customers, Large public power utilities
also provide transmission services to other eligible customers and partner with their
neighboring utilities tojointly plan transmission to meet regional needs. Other public
power utilities are "virtually" vertically integrated—they have contract and tariff
arrangements under which they buy wholesale transmission and power supply services
from others. Mwry havejoined together to form municipaljoint action agencies to own
or procure wholesale generation and transmission services. Nearly 1,OOOpublic power
utilities belong tojoint action agencies.
Still other public power utilities are distribution -only utilities that purchase the energy
and transmission services they need from larger utilities, including the Tennessee Valley
Authority, the Bonneville Power Administrationor neighboring investor-olyned or
cooperatively owned utilities. A significant number afpublic power utilities are located in
or near RTO regions and thus rely on RTO markets to meet a major portion of their
wholesale power supply and transmission needs.
www.APPAnet.org Consumers in Peril 5
III Competition and Wholesale
Electric Power Markets
What is Competition?
upporters of RTO -run centralizedwholesale electricity markets and state
retail restructuring regimes commonly use the term 'competitive" to
describe these markets and programs. Of course, calling a market
"'competitive" does not make it so, particularly when there is no basis to
believe these markets meet the basic criteria for effectivecompetition,
Notwithstanding this lack of analysis, RTO -run centralized Wholesale markets assume that
competitive forces would somehow keep prices at reasonable levels.
Advocates of these markets argue that wholesale electric power is essentially no different
from other industries and all that needs to be done is to improve market rules and
market oversight. But the threshold question—whether the economic and technical
characteristics of electric power production and transmission are compatiblewith truly
competitive markets—has never been thoroughly addressed. Even the economistAlfred
Kahn, a proponent of deregulating electricity markets, recognized that a deteimination
of whether market forces could sufficiently discipline prices and guide investment
decisions "would have to take into account the extraordinary and in some respects
literallyunique characteristicsof the industry."g
Addressing the question of whether true competition is achievable in elecuicitymarkets
first requires a common understanding of the term "competition."As simple as the
concept may seem, it is a major source of misunderstanding in the restructuring policy
debate. Economists disagree on a practical definition of competition, and many
policymakers apparently have not understood the implications and importance of this
disagreement.
The conventional textbook definition of competition requires numerous buyers and
sellers, no barrieis to entry, price flexibility in response to underlying cost changes,
perfect infoimation, and foresight by buyers and sellers. While the textbook definition of
competition might be too stiingent as a practical matter, the listed characteristics still
serve as a useful guide and, if too many of them are not present, policymakers should he
concerned. Columbia University economistJoseph Stiglitz, a Nobel laureate, provides
what he calls a simple "old-fashioned definition of competition: It is a "rivalry among
Firms to supply the needs of consumers and producers at the lowest price with the
highest qualities."9 If such rivalry is present, then sellers will be "price takers," not "pricc
setters," and consumers will benefit.
Kahn, Alfred. "The Deregulatory Tar Baby: The Precarious Balance Between Regulation
and Deregulation, 1970-2000 and Henceforward." Journal of ftulalo Economics. Vol. 21.
Issue 1 (2002), 46.
9 Stiglitz, Joseph. Whither Socialism? Cambridge (MA): The MPT Press, 1994,255.
6 ConsumersinPeril w.APPAnet.org
Structural Characteristics cf Electricity Markets
Price competition is especially important in electric power markets. In other industries,
lack of vigorous price competition may not be a major problem because firms can
compete by improving existingproducts or introducing new ones. But this is not so for
electricity Price is essentially the only dimension over which suppliers can compete and
if suppliers are not vigorously competing on the basis of price, then consumers will not
be better off. (One exception is the offering of "green power" whereby consumers can
purchase electricity generated by renewable energy facilities. But the "product" that is
consumed is still the same.)
A number of very important structural characteristics of the electric power industry raise
substantial barriers to entry and thus severelylimit competition. Most obvious, perhaps, is
the size of the capital investment needed to enter the industry.10 Other threshold
questions confronting a potential competitor are how much lead time it takes to enter
the market, where to build a new generation plant and, most importantly, whether there
will still be the same level of demand for electricity once the new plant is built and what
impact the addition of its new supplywill have on prices.
A new competitor might see a market opportunity where prices have been high for a
significantperiod of time and so might believe this would be the case for the next year
or two. But it takes a minimum of five years to build a large fossil fuel-firedplant and
even longer for a nuclear plant. Price forecastsbecome less reliable that far out and risks
increase correspondingly Without a long-term commitment by one or more buyers to
purchase the plant's output, financing becomes very problematic. Hence, the longer it
takes to enter the market, the less certain the amount of future revenues becomes. This
factor poses a significant barrier to entry, especially in the electric power indusy, where
the incumbents generally already control many of the best generation sites.
The control of most of the best locations for new generation sites provides a significant
absolute cost advantage to incumbent utility generators, These generators can add
capacity at existing sites by increasing the size of existing units, building new units in
their place or by adding new units to old ones at existing sites. In contrast, new entrants
face the challenge of finding sites not too far from high -population areas, transmission
lines, sources of water, rail lines, etc., depending on the type of unit theywish to build.
Consequently, new entrants often have to build plants at less desirable locations where
they may not have convenient access to other necessary infrastructure. If they do locate
plants closer to end users, land values are likely to be high, and siting and environmental
requirements more stringent and costly.
In Anew 500400 -megawatt, base -load coal plant costs about$800 million and anew comparably
sized nuclear facility cost? more than a billion dollars. Energy InformationAdministration,
Table 39. Cast and Performance Characteristics of New Central Station Electricity Generating
Technologies, http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/clectricitypdf#page=i3.
The control of most of
the best locations for
new generation sites
provides a significant
absolute cost
advantage to
incumbent utility
generators.
www.APPAnet.org consumers in Peril 7
Many of the generation
Advocates of R'I'O -run centralized markets have touted the entrance of "merchant
generators" into the marketplace as a sign that these markets are competitive. But many
units in their portfolios
of these companies are the deregulated generation affiliates of former vertically
are the same units that
integrated electric utility companies. Many of the generation units in their portfolios are
the same units that the vertically integrated utility built prior to restructuring to serve
the vertically
their retail customers. Thus, the generation portion of their business went from being a
integrated utility built
regulated monopoly to part of an unregulated oligopoly."
prior to restructuring
For example, the 6,000 megawatts of electric generation capacity that Baltimore Gas and
to serve their retail
Electric Co., a stateregulated transmission and distribution utility, once owned is now
owned by the company's unregulated affiliateswithin the Constellation Energy holding
customers. Thus, the
company.12 Constellation's "merchant" affiliates therefore do not face many of the high
barriers to entry -such as financing the plant and locating a site—that a true new
generation portion of
entrantwould. This head start enhances the market power of these merchant affiliatesof
their business went
traditional utilities. They can charge prices substantially above their own economic costs
of producing power (reapingvery handsome profits as they do so) and have little to fear
from being a regulated
from new entrants. As a result, there are only a limited number of generation
monopoly t O art of an
p y p
competitors in RTO markets, further undermining the ability of "competition" to bring
prices to reasonable levels.ls
unregulated ollgopaly.
Despite these and other impediments, advocates of RTO markets believe competition
can he "made to work," "designed" or "created. " This belief assumes that the basic
physical characteristics of the production and delivery of electric energy and the
economic characteristics of the industry matter little and that legal, structural and
institutional changes can make the industry competitive, in the process rendering price
regulation unnecessary, But this view is inconsistent with one of the cardinal elements of
competition: Competition itself restrains the behavior of market participants so there is
little or no need for government involvement. If wholesale electric power markets were
truly competitive, then the market itself would produce the correct levels of investment
in reliable and environmentallyresponsible electric service and assure that electricity is
produced and priced efficiently, Were the markets truly competitive, there would not be
a constant need for patchwork solutions to address concerns about reliability, excessive
prices and the adequacy of future generation capacity, as there are today
"A A market characterizedby such a small number of sellers such that each one can take
actions that affect the prices in the market.
12 Constellation Energy Group, 2006 Form 1 a -K p. 6.
18 For example, in peak hours in PJMin 2006, the Herfindahl-Hirschman Index (HHI),a
measure of market concentration, averaged 4,157, well above the cutoff of 1,800for a
"highly concentrated market." The average for intermediate houn was similarly high, at
2,664. (An HHI of 1,800 represents about five or six firms with equal market shares.)
2006 Stade of the Markel, PJM[nterconnection, LLC.
8 consumers in Peril www,APPAnet.org
Are Restructured Markets Synonymous with
Competition?
It is time to ask: Are continuing concerns about adequate capacity reliability and
generation market poaNer simply clue to the fact that we haven't yet been able to come up
with the correct "market design" or is it because the basic characteristics of electric
power markets ensure a large and tmacceptable level of market power that cannot simply
be "designed away!" Are the disconnects between how competitive markets should
theoretically perforin and what is actually happening in RTO wholesale power- markeu
due to faulty market design or, alternatively, do they reflect faulty assumptions regarding
what can realistically be clone: about the inherent lack of competitiveness of electric
power markcw?
APPA believes a detailed, unbiased study of the inherent economic conditions of the
electric power industry would raise serious questions about the competitiveness of RTO -
rim centralized markcw and their ability to discipline tvltolesale pi -ices to just and
reasonable levels. This does not mean that prices should not vary by time of use to reflect
varying costs of production in different hours a different levels of customer demand.
But variability in prices docs not mean, and should not serve as < pretext for, setting
prices far above costs, resulting in excessive returns to a limited sec of oligopolistic
generators. Nor should extreme price spikes be justified as promoting demand response,
when the actual result is "demand destruction" that can greatly harm consumers and
businesses.
There are significant natural and artificial impediments to competitive RTO -run
centralized wholesale markcw that policymaken cannot simply assume away. The views of
KFO-market proponents about the real or alleged failures of traditional regulation need
to be balanced with othervicws about the failures of electricity deregulation and RI`Q
markcw in particular. It is precisely those who must deal with these I(rO market
realities—consumers and the load -serving entities]`] responsible for meeting their
needs—who have expressed the most concerns, while it is the 1UOs themselves and the
generators tubo participate in these warkets ivho claim consurners are benefiting ii•otn
chem. This disconnect in itself should prompt policymakers to question whether these
markets benefit consumers or oligopoly generators.
How the Federal Power Act Addresses the Potential
for Anti -Competitive Behavior Through the Just and
Reasonable Rate Standard
During the early years of the electric utility industry, concerns about utilities exercising
market power to exploit consumers led to enactment of federal and state statutes
requiring that wholesale rates meet a' just and reasonable" standard. This standard still
14 A load -serving entity is a utility that has a responsibility to provide eleCLI-icity to retail cus-
totirers and purchases or generates electricity in order to satisfy that responsibility.
www.APPAnet.01'9 Consumers in Peril 9
exists in the Federal Power Act (FPA), which Congress has entrusted the FERC to
enforce.
The FERC's core responsibility under the FPA is to "guard the consumer from
r
exploitation by rtoa� cvmpctitiG�c electric pourer- cowpanies."1' Its prininq (but a)ot its
only) statutory tools to protect consumers arc FPA Sections 205 and 206.16 These
sections require commission -regulated "public ulilitics" to charge rates that arc' just and
reasonable." In reviewing public: utilities' rates under this standard, the commission must
balance competing interests: it must ensure that investors in the public utility receive a
Pair return on their investment while, at the same time, protecting consumers from
excessive rates.17
Although the statute docs not stipulate what method should be used to achievejust and
reasonable rates, the commission has until relatively recently used cost -of -service
regulation to make sure that rates were just and reasonable. The recent shift toward the
use of markets and supposed competitive forces to ensure fust and reasonable rates,
while not prohibited by the FPA as a method, is clearly not working to achieve the
required result.
Because the commission has decided to allow alleged competitive forces to discipline
wholesale power rates, it takes on the heavy bin•dcii of ensi ring that public utility sellers
in Pactstill charge onlyjust and reasonable Yaws? The U.S. Court of Appeals forthe
District of Columbia Circuit has found that while "contrasting or changing
chat actcristics" within the industry may justify "taking a new approach to the
detcrminat.ion ofjust and reasonable rates," FERC, may not abdicate "its statutory
responsibilities in favor of a method that guards against only grossly exploitative pricing
practices."1`1 Evidence from the restructured markets clearlyshows that market-based
rates and unregulated prices do not equate tojust and reasonable rates.
In an effectively competitive market, where neither buyers nor sellers have significant
market power, the commission can rationally assume that the terms of their voluntary
exchanges arc reasonable, and specifically infer that the sales prices arc close to niai,ginal
cost, so that a seller makes only a normal return on its investmcnt.211 (A normal return is
that which is sufficient to attract adequate levels of capital financing and not a level that
earns supra -normal profits.) But, as explained above, the structural features ofthe
Ir'
NAACP a, M'(:, 52{) F.2d 932, 4S8 (D.C. Cir. 1975), a%/i1, 425E .S. 662 (1976).
]ti 16 U.S.C. §§ 824d and Me,
17 Public 4)0ify Direr cl, No. I of,ynohoveisla C6,21W§=, 13ruh. v, P7,,Y?C, 471 F_'M 1053, 1055 (90, Or.
2(06).
18 Cal. ex rel Locky r v.. 1�7s'Rl;, 383 F.3d 1006 (9tl) Cir. 2004),
1�) Rlrme?a-Union Cent. Jaclr., Atr,�. v. I'7;1i(:, 734 F.2d 1486, 1503-04� (D.C. Ci€: 1984) ("1•ha•mes
20 Irjas Pwver v. 1T?RC, 908 G,2d (98, 1004 (1).C, Cir. 199{}).
10 Consumers in Peril wwvd.APPAnetarg
wholesale electric power industry, and the resultant marker power of generators, make it
vele difficult for competitive forces actually to discipline prices to just and reasonable
levels. Moreover, research conducted for APPA in the first phase of its E;lectl-ic Marker
Reform Initiative (undertaken in 2006) shots that wholesale power prices in RTO
tnarl,ets bear no relationship to sellers' marginal costs of production;" to the contrary,
certain owners of generation arc "earningsupra-competitive retIUDS that arc not
cO7nmensurate with returns w) investments in other enterprises having corresponding.
risks.""
These facts, taken together, lead APPA to conclude that wholesale rates in RTO -run
centralized markets arc notjust and reasonable. APPA believes the commission has the
statutory responsibility to investigate this situation, and to remedy i t if it fends rates to be
unjust and unreasonable. As FERC Chairman Joseph Kelliher himself has pointed out,
"1.0lie legal duty of the commission to prevent unjust and unreasonable rates a n d undue
discrimination or preference in the sale of wholesale power or interstate transmission by
jurisdictional sellers is absolute: the commission does not have the discretion] to ignore
theist."23
2t "A Comparative Analysis of Actual Locational Marginal Prices in the PIM Mallet and
Estimated Short -Run Marginal Costs," Prepared by Loudon Ecoctoniics Inlrrnational,
LI..C: (February 5, 2007) (LI:I:s analysis oi' ),Adding in PIM markets based on short -run
marginal costs sholved Ilaat offers to sell electricity into PJM's organized markets are o€ten
not tied to the seller's mar'g'inal cost of larodueing that electricity; for example, in PJM
Interconnection, during peak periods in recent years, as much ars 10 to 25 perccnt of the
price appears to he attributable to the difference between that price and the short -run
marginal costs of the generator whose bid cleared the market.).
22 Request to Expand OW Scope oI'the Section 206 Proceeding, Docket Nos. ILA407-19.000
and ADO'7-7-400, December 17, 2007 at 4.
2'3Joseph T. Kelliher, Markel Mrani.fuclalion, Marked Power; and lhrAulhcrrity rf the Erfleritd Enogy
Rrgidwoty Gomxpi. cion, 2G Energy T.J. 1, 3-4 (2005}.
www.APPAnet.org Consuiners in Peril 11
N. Failures of Centralized RTO -Run
Wholesale Electricity Markets
1%
entral to FERG's policies encouraging competition in the wholesale
electricity markets has been the promotion of RTOs and their operation
of centralized markets for wholesale electricity and ancillary services. These
markets, while operated without traditional cost -of -service regulation, are very complex,
entailing numerous market rules, large bureaucracies and expensive software packages.
The history of these RTO markets has been characterized by continued attempts to
address various issues through a series of market "fixes." However, because these
centralized markets were assumed to be competitive, the fact that continual "fines" have
been required calls into serious question the underlying assumption of competition.
Features of RTO Markels24
There are currently six FERC -regulated ISOs; ISO New England (ISO NE); the New York
ISO (NY ISO); the PJM Interconnection (PJM, which covers the Mid -Atlantic states and
some parts of the Midwest); the Midwest ISO (MISO, which covers other parts of the
Midwest); the CalifornlalSO (CAISO); and the Southwest Power Pool (SPP), which
covers parts of Texas, Louisiana, Arkansas, Missouri, Kansas and Oklahoma.25 The
concerns expressed in this paper focus specifically on the centralized RTO -run markets
that have come to dominate RTO operations. RTOs do provide services that have
substantial value and should not be eliminated. RTOs have implemented regional
OATTs, administered on a non-discriminatory basis, eliminated pancaked transmission
rates (allowing transacd ons to take place over a broader geographic area, provided that
the neeessaiy transmission infrastructure is available) and attempted to strengthen
regional transmission planning. Yet these substantial accomplishmentshave been
overshadowed by the costs and dysfunctional nature of RTO -run centralized markets.
RTOs generally opeiate centralized day -ahead and real-time spot markets for electricity,
as well as markets for ancillary services needed to use open access transmission service.
The prices for electric power in these markets are set at certain intervals (often every
hour) hased on the offers to sell power submitted by generation owners to the RTO.
These offers need not reflect the sellers' actual costs of geneiating power (average,
marginal or otherwise), as FERC would have required under a traditional cost -of --service
ratemaking regime. Rather, the sellers set their own price offers, unless the prices they
propose trigger preset "market mitigation" thresholds sethy the RTO. 26
-,rvc a I[1vi c uctailed descril,LIU],, see Understanding Electricity Markets An examination of how
electricity markets work—and how they don't, by Gary Newell and Ransom E. (Ted) Davis,
Thompson Coburn, for APPA, November 2006, athttp://nww.appanet.orq/aboutpub
lic/index.cfm?ltemi umber=17766.
25 The Electric Reliability Council of Texas ("ERCOT") is also an ISO, but since ERCOT
does not operate in interstate commerce, it is regulated by the Texas Public Utility
Commission.
26 For example, there are exemptions from mitigation granted to generators in PJM The
MarylandPublic Service Commission asserts in a complaint filed with FERC against PJM
in January 2008 that "a significantshare of generation resources in the PIM footprint
avoids mitigation even though they exercise market power," and that these exemptions
"'added $87.5 million to Maryland's 2006 real-time energy related charges."
12 Consumers in Petit w.APPAnet.org
The RTO takes all offers for a particular upcoming time interval in ascending price Price volatility in MO
order, stopping with the last offer needed to meet the power needs of loads during that
time interval. All sellers in that time interval, regardless of the amount of their own price energy markets has
offers, are paid the price based on the last and highest offer the RTO accepts to supply also resulted in
power to meet its regional demand—known as the bid that "clears the market." This
market design is known as a "single clearing price" market, and such markets are called irrational generating
"Day 2" markets.27 unit commitment and
Bid -based markets create well-known incentives for generators to withhold capacity (to
dispatch directives, as
create artificial shortages that increase prices) and to refrain from building othentiise
transitory RTO market
needed new generation capacity (which could reduce prevailing market prices, thus
reducing profits). This combination of complex market rules, incentives for short-term
price spikes cause
withholding, and depending on the "market" to assure adequate generation and
market participants to
transmission infrastructure can ultimatelyjeopardize reliable service to retail
customers, as witnessed by the load shedding that customers experienced in California
chase prices up and
during the 2000-2001 energy crisis. The complexityof the transition to using RTO
market's to operate a large multi -state power system may also have contributed to the
down in search of
August 14, 2003 Midwest/Northeast blackout, by distracting bulk power system facility
profit.
operators at the Midwest Independent Transmission System Operator and First Energy
from their respective obligations to comply with the North American Electric
Reliability Corp. reliability standards. Price volatility in RTO energy markets has also
resulted in irrational generating unit commitment and dispatch directives, as transitory
RTO market price spikes cause market participants to chase prices up and down in
search of profit.
Another central element of RTO -operated energymarkets is "locational marginal
pricing" (LMP) in which electricity is bought and sold at prices that vary by location
within the RTO area. LMP reflects the differences in the costs of delivering electric
power to different parts of the transmission grid due to transmission constraints (often
called "congestion"). Prices for power wry within the RTO's region during hours in
which transmission congestion (demand for use of specific transmission facilities that
exceeds those facilities' capacity to move power) makes it impossible for electricity to
reach every part of the RTO's system at the lowest overall economically efficient cost If a
customer happens to be located in a portion of the transmission system affected by such
a limitation (a "constrained zone"), the price the customer pays reflects the offer
submitted by the generator that is actually able to deliver electricity to the customer, even
if there are generators offeringlower prices elsewhere in the RTO. The difference
between the lowestprice and that charged in the constrained zone is referred to as the
"congestion charge."
Advocates of locational marginal pricing argue that the higher costs charged when
congestion occurs on the transmission system will give market participants an incentive
27 The California ISO does not yet use a full-fledged "Day 2" marker, bur intends to imple-
ment one in April 2008 (according to the California ISO Web sire). SPP has not to date
proposed a 'Day2' market, but does run an energy imbalance market
www.APPAnet.org consumers in Peril 13
Hedge funds,
investment banks and
other financial entities
have begun purchasing
FTRs through the
auctions, further
exposing transmission
customers to undue
risks. These entities
often have no stake in
the market except a
financial one and are
therefore bidding on
to pay for construction of new generation and transmission facilities.Altematively, the
higher costs might prompt electricity customers to reduce consumption or to use power
during periods of lower overall demand. However, there is no evidence that such pricing
signals have led to construction of generation or transmission.28 RTOs offer their
transmission customers an opportunity to limit the adverse impact of these congestion
charges by issuing financial transmission rights (FTRs), which generally give their holders
a right to receive a share of the congestion charges. Typically, RTOs allocate some
portion of these FTRs based on the amount and location of the generating resources
that each transmission customer has declared it will use to serve its retail loads. Some
RTOs also operate auctions and facilitate the secondary purchase and sale of FTRs
among customers.
But I oad-serving entities and large customers have faced difficulty obtaining sufficient
FTRs to hedge deliveries of power from their own electric generation sources 29 The
number offinancial rights an RTO issues is limited by the physical capability of the
network, which varies from time to time, depending on forecasted operating conditions.
Some load -serving entities have suffered sharp cuts in their financial rights allocations
when forecasted changes in operating conditions caused the RTO to impose reductions.
In addition, the amount of revenue FTRs provide is not guaranteed at any particular
level and can fluctuate due to a number of factors.
these F Ms purely for In another development, hedge funds, investmentbanks and other financial entities
speculative purposes. have begun purchasing FTRs through the auctions, further exposing transmission
customers to undue risks. These entities often have no stake in the market except a
financial one and are therefore bidding on these FTRs purely for speculative purposes.
Loadsewing entities, industrial customers and other wholesale power buyers must
purchase FTRs as a hedge against real congestion costs,
In December 2007, Mo hedge funds defaulted on $85 million in payments to PJM after
they suffered financial losses associated with FTRs they had purchased for speculative
purposes. The two funds had purchased "counterflowpositions" that historicallywould
have earned them money. When PJM-controiled transmission lines were shut down for
routine maintenance in New Jersey, the power flows on the system changed and these
FTRs lost money Both funds then defaulted on their financial obligations associatedwith
these FTRs, It appears that the remaining participants in PJM (and ultimately, retail
28 In LMP Electricity Markets: Market Operations, Market Power, and Value for Cmmzers, by
Synapse Energy Economics, February 2007, the authors found that "[t] here is simply no
evidence that the price signaling associatedwith LMP has been an effective spur to invest-
ment in generation, transmission or demand response initiatives, and some evidence to
the contrary"
299 In response to new legal requirements included in the Energy Policy Act of 2005 (incor-
porated in new Section 217 of the FPA), the commission has required Rios to develop
long term (e.g„ 10 -year) financial transmission rights. These rights, however, are not yet
fully available due to the time required for the commission to develop the relevant gener-
ic guidelines for these rights and to approve the subsequent compliance filings the vari-
ous RTOs have made to implement the guidelines.
14 Consumers in Peril www.APPAnet.org
customers in the PJM region) will he hilled for these losses.30
RTOs also administer markets for the sale and purchase of generation capacity, or the
ability to produce electric energy on an instantaneous basis as and when needed. Load -
serving entities with traditional service obligations have historically maintained an
adequate amount of capacity to meet their respective contributions to the region's
projected peak loads plus a reserve margin.
Because of concerns regarding the future adequacy of generation resources to meet
demand in RTO regions, three RTOs (ISO NE, PJM and the NYISO) have implemented
locational capacity markets, under which existing and new generators bid to receive
additional revenues (in addition to the centralized spot energy markets) from the RTO
and its load -serving customers in exchange for assuring the RTO that their generation
facilities can be called on in future periods to supply power. These markets have proven
to he very controversial, due to their high prices and questionable efficacy in supporting
the development of substantial new generation resources.
Buyers and sellers in Day 2 markets can attempt to avoid purchasing power in the RTO -
run spot markets by entering into individual contracts with generators (called "bilateral"
contracw). But the prices for power sold under those contracts are substantially
influenced by the prices the sellers can obtain in the RTOs' centralized markets. Very
substantialvolumes of power are sold through the centralized markets. It is uncommon
to see bilateral contracts in RTO regions for terms longer than five years and most such
contracts are only to supply electric power; they are not tied to specific electric
generating resources and therefore cannot be used to meet the buyer's locational
capacity market obligations. These contracts are often called "seller's choice
agreements," meaning the seller will determine exactly what generation sources the
power sold will come from at the time it is actually supplied. Moreover, bilateral contracts
do not insulate the customer from the payment of RTO congestion charges, which are
collected through an additional charge on top of the RTOs "base" transmission rate.
The generators' preference for selling into FZDnmcentralized power markets rather
than under bilateral contracw is illustrated by a presentation made by Public Service
Enterprise Group (PSEG) to the Edison Electric Institute in November 2007.31 One of
the slides in the presentation shows a decline in the percentage of coal and nuclear
output sold under bilateral contracw from 80 to 20 percent from 2008 to 2010,
Generation capacityunder bilateral contracw is projected to decline from about 90 to 50
percent in the same time period.
30 'TJM Completes Analysis of Recent Market Payment Default and Announces Steps to
Mitigate Future Risk Exposure," PJM Press Release, December 26, 2007,
http://www.pjm.coin/contributions/news-releases/2007/20071226-credit-default news-
release,pdf; Two companies default on payment of $85M in financial transmission rights,
says PJM Rblic Power Daily, January 4, 2008,
31 Presentation by the Public Service Enterprise Group at the 42nd EEI Financial
Conference, Lake Buena Vista, Fla., November 6,2007, http://Iibrary.corporate
ir.net/library/99/998/99807/items/268128/PSEG-�EEI.pdf
It is uncommon to see
bilateral contracts in
RTO regions for terms
longer than five Years.
www.APPAnet.org consumers in Peril 15
Bilateral markets in
APPA members in (or even near) RTO regions cannot avoid dealing with their RTOs
simply by consuucting their own generation resources or contracting with third -party
certain parts of the
suppliers. Under either arrangement, the APPA members would still be required to take
country (for example,
wholesale transmission service from their RTOs under FERC -regulated rates and tariffs.
Hence, they must obtain FTRs to hedge the transmission congestion costs associatedwith
the Desert Southwest
their power supply transactions. And they must still participate in their RTOs centralized
and Pacific Northwest)
day -ahead and real-time power supply markets, if only to resolve their hourly energy
imbalances. They are increasingly required to participate in RTO locational capacity
are very active, with
markets and ancillary services markets as well.
many wholesale sellers
Features of Bilateral Markets without RTOs
offering power on a
The absence of centralized RTO -run markets in some regions of the country does not
short— and Long -tem
necessarily equate to thin wholesale power markets in those regions. Bilateral markets in
basis, and many
certain parts of the country (for example, the Desert Southwest and Pacific Northwest)
are very active, with many wholesale sellers offering power on a short- and long-term
buyers seeking to
basis, and many buyers seeking to purchase such supplies. As would be expected, the
purchase such
strength of the wholesale electric power supply market in any particular region depends
on the same basic factors: the number of wholesale power buyers and sellers (and
supplies.
whether they have significant market power); the level of access to transmission service
needed to support transactions; long-term sufficiency of the underlying transmission and
generation infrastructure; and adequacy of information about differentpower supply
and transmission service options. This holds true in both RTO and non -RTO regions.
In regions without RTOs, bilateral contracts between power sellers and buyers are the
norm. They can be forvery short terms (e.g., one hour to 30 days) or very long terms
(e.g., 20 years). They are more often tied to sales of power (with or without associated
capacity) from specific generation resources or fleets of such resources, although seller's
choice -type energy-nnly agreements not tied to specific plants are also used in bilateral
regions. Because there is no centralized spot market run by one regional institution,
there are no regional "clearingprices" for any time interval. However, trade press
periodicals collect information on specific bilateral transactions and publish "index
prices" at certain key points on regional transmission systems, 32
In bilateral regions, individual transmission owners provide the associated transmission
services needed to support bilateral wholesale power supply deals under their own open
access transmission tariffs (OATTs) , which establish standard rates for the provision of
transmission service. Transmission providers generally offer transmission service under a
"physical rights" model, where they will only sign "firm" transmission service agreements
(under which transmission service is guaranteed unless curtailments are required to
maintain system reliability). The provider will offer these physical rights only if it has
sufficient available transfer capability (ATG) to support the specified transaction over the
32 For example, trade publications publish market index prices far the Southeast (into TVA,
into Entergy, into Southern, etc.) and the West (California -Oregon Border, Palo Verde,
Mead, etc.)
16 consumers in Per# w.APPAnet.org
proposed contract term. Hence, they do not ration access to their transmission systems
through the use of congestion pricing. While customers must obtain transmission service
from individual transmission providers instead of over a single RTO -managed grid, some
tools have been developed to support easier procurement of transmission, such as the
joint Wes=rans computer site, where market participants can obtain transmission
service from 24 Western transmission providers (both FFRC-regulated and non -
jurisdictional) using a common computer interface,33
One example of a non•RTO-based approach to transmission system management and
planning is the ColumbiaGrid in the Northwestern United Statess4 This is a nonprofit
membership corporation formed in 2006. ColumbiaGrid does not own transmission; its
members and the parties to its agreements own and operate an extensive network of
transmission facilities.While different models may he appropriate for different regions.
the ColumbiaGrid demonstrates that there are effective and consumer -friendly
alternatives to the use of pricing incentives to manage the power grid.
Public Power's Concerns with RTO -Run Wholesale
Markets
AFPAwas an early and strong supporter of ISO development. Many APPA members
hoped ISOs would eliminate "pancaked" [individual system-hy-system) transmission rates,
bring a more coordinated regional approach to planning and constructing transmission
facilities, and ensure nondiscriminatory transmission access. But as the commission
moved from encouraging initial ISO development to full-fledged RTOs, its policies
underwent a fundamental shift. The FERC's RTO policies morphed from promoting
open access to the transmission grid and a more coordinated approach to transmission
planning and construction into advancing centralized, RTO -run markets for day -ahead
and real-time energy capacity and ancillary services, and the use of LMP to price
transmission congestion. The use of market-based rates, combined with the single -price
auctions in these markets, often allowed generators to collect the higher of their own
units' specific costs (if they had higher cost units needed for reliability purposes,
regardless of costs) or the RTO -determined market price (if they had lower cost units).
Further, centralized bid -based auction markets have changed the incentive structures
faced by deregulated generators: measures that would reduce congestion or prevailing
market prices will reduce the profits of incumbent companies with large deregulated
generation portfolios. Incumbent generators have clear disincentives to make
investments that might reduce prevailing prices (and benefit consumers); new
competitors often find asset-based e n y diffrcultto impossible, unless such e n y is
supported by factors such as long-term contracts with load -serving entities (often public
38 www.wesnrans.net.
.34 http://www.col.udDiagrid.org. The corporation, with the participation and agreement of
its members, conduce transmission planning, including determinationof cost allocation
methodologies, analyzes long-term reliability proj ects, and a dmi n isters an Open -Access
Same -Time Information System (OASIS).
ColumbiaGrid does not
own transmission; its
members and the
parties to its
agreements own and
operate an extensive
network of
transmission facilities,
www.APPAnet.org Consumers in Peril 17
Incumbent generators
power utilities rather than investor-owned utilities which, in many cases, no longer have
have clear
an obligation to serve) or regulatory and tax policies (principallystate renewable
portfolio standards and federal production tac credits).
disincentives t® make
APPA first made its concerns about these RTO -run markets public in December 2004,
investments that might
when it issuedawhitepaperentitledRestructuringattheCiosmads;ILRCEkchicPoliry
reduce prevailing
Reconsidered.35 APPA there noted (at page 6): "APPAmembers located in RTO regions
report substantial, across-theboard problems with spiraling RTO costs, unaccountable
govemance,fack of understanding of transmission customer and end-user needs and
less -than -satisfactory service options. They see more and more RTO servicesbeing
provided through questionable market mechanisms, and RTO resistance to any
questioning of the economic theories underpinning these actions."APPA discussed the
problems its members were encountering in some detail, and suggested a number of
proposed "midcourse corrections," including development of long-term FI'Rs,
meaningful mechanisms to get additional transmission facilities constructed,
encouragement of joint ownership of transmission, more scnitiny of RTO administrative
costs, and more accountabilityof RTO managements to stakeholders.As APPA stated in
the conclusion of its white paper (at page 26), it sought to "reform the existing RTOs, so
that they operate to benefit electric consumers (rather than particular industry
participants), and employ market mechanisms only as a means to an end (serving
electric customers), and not an end in themselves."
There have been some improvements in the commission's RTO policies in the three
years since APPA issued that white paper. In part as a result of changes in the
membership of the commission, in 2005, the commission abandoned its insistence on
RTO formation in all regions, permitting more regional diversity. The commission also
revised its public utility accounting rules and reporting requirements to better
accommodate RTOs' administrative and operating cost categories. This will bring much-
needed cost accounting standardization, so the costs billed to market participants for the
administration and operation of each RTO can be better compared across RTOs. Finally,
the commission conducted the nilemaking required by EPAct 2005 to set guidelines for
long-term FfRs in RTO regions, which RTOs are now implementing.
Despite these improvements, the fundamental problem of an absence of effective
regulation and oversight in these wholesale markets has not been addressed. The
problems have indeed worsened since the release of Restructuring at the Crossroads, As a
result, the gap between regulated and unregulated prices has widened and profits of
owners of unregulated generation facilities have increased, while projected reserve
margins continue to shrink and many portions of the transmission system remain
congested. Because of the failure of RTO -run centralized spot markets and LMP -based
congestion pricing to support the construction of new generation and transmission
facilities, three RTOs have implemented separate locational capacity markets to try to fill
M'rhe paper is available at: http://www.appanct.org/files/PDFs/APPAWhitePaperRestructur-
ingatCrossroads1204,pdf.
18 Consumers in peal www,APPAnel.org
the void. It is unclear whether such markets are now, or will in the future, support
development of substantial new generation,36 but it is abundantly clear that electric
consumers in these three RTO regions are paying billions of dollars in additional
locational capacity charges?'
Prices in RTO -run centralized spot markets continue at ve ry high levels, while certain
utility -affiliated merchant generators holding fully depreciated, formerly utility -owned
generation assets are reaping extraordinary profits. The price expectations that sel lens
have formed from the high RTO spot market prices have bled over into bilateral markets
in RTO regions. In the experience of most APPA memhen, nearly all medium and long-
term contracts are indexed to natural gas prices and tend to pass through RTO
administrative costs, congestion charges and the exorbitant costs of RTO generation
capacity markets. Power marketers generally demand a substantial price/risk premium
above their costs, perhaps reflectinguncertainty about their Mn costs as well as the
foregone profits that might otherwise be made from sales into RTO spot, capacity and
ancillary services markets.
RTO "markets" are continuallyapplied to previously cost-regulatedproducts, e.g.,
ancillary services, without any rigorous cost -benefit analysis to ensure that end-use
customers are well served by such markets. Administrative costs associated with these new
markets are also very high, adding to the RTO costs that are passed directly on to the
customers who purchase power through these markets.
APPA filed comments on September 14,2007,with FERC on its "Advance Notice of
Proposed Rulemaking" (ANOPR) in Wholesale Competition in Regions with Organized
Wholesale Markets, FERC Docket Nos. AD07-7-000 and RM( 07-19-000.33 In those
comments, APPA delineated in great detail load -serving entities' substantial concerns
with RTO markets, casting significantdoubt on the commission's statement that RTO
markets "benefit consumers. " APPA also filed swom affidavits providing additional
evidence about the complex relationship between higher fuel prices and high RTO spot-
market
potmarket prices, and the extremely high profits enjoyed by certain merchant generaton in
RTO regions. Based on this evidence, together with the findings of its Electric Market
Reform Initiative studies, which were filed with the commission, APPA asked FERC to
investigate the prices charged in RTO markets, asserting that they are notjust and
reasonable, as Sections 205 and 206 of the Federal Power Act require. As of this writing,
86 At least one study. prepared for APPA. conclude, they will not. `Investment Performance in
Deregulated Markets for Electricity A Case Study o[New York .State, "prepared by Dr. Timothy
Mount of Cornell University. September 2007.
87 James F. Wilson, a principal at LECG I.1.C, found that although it is too soon to con-
clude that RPNI is uorking...the evidence to date suggests the contrary; that it is not
attracting new capacity where needed, and the bidding and price formation in the auc-
tions are not as mended and expected ..capacity prices for the first three RPM delivery
years reflect an approximately$ 15 billion increase in capacity value relative to the highest
rapacity price from the prior four years, adjusted fur Inflation.' Too Soon to Determine
Success of P11M s Reliability Pricing Model, Power Market 7bday, October 29.2007,
38 There commen Ls are available at http://www.appanet.org/files/PDFs/APPA_Cmts_iD07-
7 9-14.07%20%5Bas%20ftledclo5D.pdf.
Power marketers
generally demand a
substantial price/risk
premium above their
costs, perhaps
reflecting uncertainty
about their own costs
as well as the foregone
profits that might
otherwise be made
from sales into RTO
spot, capacity and
ancillary services
markets.
www.APPAnei org Consumers in Peril 19
the commission has not ,lard on APPA's request
The remainder of this section describes the growing body of evidence on the consumer
harms and absence of benefits from the current market structure and the importance of
FERC action in response.
Findings of EMRI Studies of Wholesale Markets
During the initial phase of its Electric Market Reform Initiative in 2006, APPA
commissioned a series of studies to gather more information about wholesale RFO
market operations and the associated impacts ori consumers. APPA in these studies
atteulpted to delve more deeply into assumptions and assertions often made in support
of the current markets.
The findings of these studies paint a very disturbing picture of RTO -run centralized
markets and the state of "competition" in them. There is real evidence of RFO market
failures that are harming consumers, and strong indications that the wholesale rates
these markets produce arc notjust and reasonable. 'The findings in these studies stand in
stark contrast to the contrary claims of the RPOs and the owners of unregulated
generation selling into those markets.
To begin to evaluate the results of restructnring, APPA decided to exarnnic a group of
studies often cited by lZFO market proponents, concerning the impacts of restructuring
ori consumers. Dr. John Kwoka, an economist at Northcastern University, reviewed these
studies and found that the methodologies used in them fell short of the standards
necessary for reliable ecoriornic research. As a result there "[ils no reliable and
convincing evidence that consumers are better off as a result of the restructuring of the
U.S. electric power industry," Dr. ICwoka said.
Given this dearth of reliable data and analyses, APPA decided to undertake a more
careful examination of the impacts of restructuring. One important indicator of whether
"'competition" is disciplining prices tojust and reasonable levels is the profitability of the
generators making sales into these markets. APPA therefore asked independent
consultant and financial analyst Ed Bodrner to look at the current and future profitability
of the five largest sellers of unregulated wholesale power hi PJK Using publicly available
data, Mr. Bodmer calculated the earnings 1)), shareholders iii these PJM companies to he
$32 billion and $40 billion greater than those for cost -regulated utility companies, for a
tlrr'ee- and 10 -year time period, respcctively.'s� Information these companies themsehcs
have prepared for investors and analysts contains predictions of additional substantial
profits upon expiration of state retail rate caps and full implerneatatiort of P'N's
locational capacity market, known as the "reliability pricing model," or RPM. Indeed, in a
The !?lerlric. 11ongjmi: The Profitability of De?wgufaleel Eleclric Genoalion Conillan.irs, by Edward
Bodiner, Pebruary 2007,
4o Affidavit of Edward Budnter, C:ommetus of tore. American Public Power Association, FERC
Dockets RM07-0-000 and AD07-7-000, 14, 2007.
20 Consuiners in Peril ww.APPAnei.org
September 2007 update of his study using 2006 data, Mr Bodmer found that these extra Synapse examined
investor earnings have now grown to between $44 billion and $67 billion.40
offer data from
Such excessive profit levels indicate that sellerswith lower costs do not face substantial generators in both
competitive pressures to pass on such savings to consumers. Another key question is the
extent to which there is a relationship in a deregulated market between power supply PJM and ISO New
prices and the costs of production. If a generator can successfully offer to sell power at a England and found that
price significantlyabove its actual cost to run its generation unit, then it is unlikely that
such a generator is facing any meaningful competition. Offers from the same
London Economics International, LLC (LEI) conducted a computer simulation for generating unit
APPA that asked what clearing prices would result if generator offers to sell power into
fluctuated by over
Pf M's spot markets were actually based on their short -run marginal costs. LEI then
calculated the difference between this simulated clearing price and the actual clearing
$100 per megawatt -
price and found that offers to sell electricity are often not tied to the marginal cost of
hour within one month.
producing that electricity. For example, during peak periods in PJM in recent years, as
much as 10 to 4 percent of the price is attributable to a markup above the short -run
These data indicate
marginal costs of the generator whose bid cleared the market. The LEI study also showed
that these sellers of
a high degree ofvariation in the markup, raising questions about PJMs publication of
only an average measure of the markup in its "State of the Market" reports. LEI also
electric power may
noted that PJMs markup index results are based on the production costs generators
have sufficient market
report to the market monitor, rather than independently verified cost data, and also
noted that much of the data that LEI needed to conduct its study was unavailable from
power to manipulate
PJn1I.41
prices.
A study for APPA by Synapse Energy Economics provides further evidence of the gap
between generators' offers and their actual production costs. Synapse examined offer
data from generators in both PJM and ISO New England and found that offers from the
same generating unit fluctuated by over $100per megawatt-hourwithin one month.. Yet,
generating units typically have only minimal day -today changes in their production costs.
These data indicate that these sellers of electric power may have sufficient market power
to manipulate prices, or at a minimum are pursuing a strategy of attempted
manipulation.
As data raising questions about the supposed price benefits from restructuring became
increasinglyprevalent, supporten of RTO markets have employed a new rhetorical
strategy They now acknowledge price increases, but claim such increases have been
driven by rising fuel costs, principally natural gas. Yet, Dr Ken Rose, a consultant and
senior fellow with the Institute of Public Utilities at Michigan State University, found in a
study APPA commissioned that fuel costs cannot fully explain the increase in wholesale
electricity prices. According to Dr. Rose, "attributing electricity price increases to only the
cost of fuels used to generate electricity is overly simplistic at best." In fact, recent trends
in PJM prices show that, rather than moving in lockstep, electricity prices and fuel costs
41 London Economics International. February 2007, p. 77.
www.APPAnet.org consumers in Pent 21
Areas where LMP can sometimes even move in opposite directions?* Dr, Rose's conclusionswere recently
confirmed by an analysishy Dr. Robert McCullough showing that when fuel costs are
prices are the highest, removed from prices, the differential between retail rates in RTO and non -RTO states
and thus transmission was 2.8 cents in July 2007, compared to 1.1 cents in January 2003. 43
facilities are the most Another critical measure of the success of a market structure is its ability to support
reliable electricity service, by ensuring that sufficientgeneration and transmission
congested, do not facilities are in place to meet projected future consumer needs. RTO -run centralized
correspond with the markets attempt to ensure future facilities adequacy largely through pricing incentives.
Synapse found, however, that the areas where LMP prices are the highest, and thus
areas where the transmission facilities are the most congested, do not correspond with the areas where
greatest investments the greatest investments in new generation and transmission have been made, 44
in new generation and Alarmed by the continuing lack of adequate investment, some RTOs are increasingly
relying on locational capacity payments to generators to encourage the needed
transmission have infrastructure investments. At APPA's request, Dr, Timothy Mount of Cornell University
been made. examined the effectiveness of the locational capacity market the NewYork ISO
administers. D r, Mount found that the main accomplishment of the hundreds of millions
of dollars consumers have paid to generators through the NewYork capacity markets has
been to increase the market value of generators' existing capacity. He concluded "the
evidence from NewYork shows that paying a large amount of additional money to
generaton in the [New York locational capacity] market does not guarantee that
investment in new generating capacitywill he made in a timely way."45
The findings from these vari= studies and the increased questions they raise about the
results from "competitive" RTO -run markets have led both the generation owners and
the RTOs themselves to step up their defense of the status quo. Yet additional claims of
benefits are now emerging. One of the most prominent is the claim that RTOs have
promoted the development of renewable generation resources. To fully investigate this
claim, Dr, Lester Lave and Kathleen Spees of the Cameg'se Mellon Electricity Industry
Center conducted a rigorous statistical analysis and found "no indication that RTOs have
facilitated the development of renewable resources." Rather, it appears that state policies
fostering renewahles are most effective, such as rebate programs, loan programs, net
metering, required green power offerings and renewable portfolio standards.
Supporters of restructured RTO markets also contend that restructuring promotes
improvements in operational efficiencies in generating plants. At the request of APPA
42 Thelmpact of Fuel Costs on Eleclric PowerP3ices, by Kenneth ROse,June 2007.
48 ftMining Benchmark in Eeclricily Uemegulation, by Robert McCullough, Managing Partner,
and Ann Stewart, Research Analyst, McCullough Research, December 2007.
44 LMP Eleclrieily Markets: Market Operations, Markel Powe; and Value for Consumers, by Ezra
Hausman, Robert Fagan, David White, Kenji Takahashi and Alice Napoleon, Synapse
Energy Economics, February 2007.
45 Investment Performance in Deregulated Markel.+for Eketricily: A Case Siudy of ,New York State, by
TimothyMount, PhD, Professor of Applied Economics and Management, Cornell
University, September2007.
22 consumers in Peril www.APPAnet.org
and the National Rural Electric CooperativeAssociation, Laurence a Kirsch and
Not only am consumers
Matthew J. Morey of Christensen Associates Energy Consulting reviewed a study b,/ Kr ra
in RTO regions bearing
Fabrizio, Nancy Rose and Catherine Wolfram on this topic. They also reviewed the
COMPETE Coalition'spress release publicizing this study. Kirsch and Morey found that
the brunt of power prices
in addition to several flaws in the study's methodology, the COMPETE Coalition's public
"further
higher than those in
statement that the study provides evidence that competitive forces in
restructured electricitymarkets drive efficiencies that benefit consumers by helping to
non -INTO regions but
drive down costs and reduce adverse environmental impacts" is misleading. They found
that the study itself provides no evidence of how competitive forces work in restructured
their electricity bills also
environment., or whether any cost reductions resulting from increased operational
include the coots RTOs
efficiencies were passed on to consumers. Nor does the study attempt to measure any
environmental impacts associatedwith this market model.46
charge simply to run their
Evaluations of RTO -run centralized markets are hampered by the dearth of adequate
centralized markets.
data to explain the extent to which the RTO -operated markets diverge from the
competitive model. Moreover, it is impossible to identify the degree to which participants
exert market power. At the request ofAPPA, William Dunn, a consultant with Sunset
Point LLC, analyzed available RTO electricity market data to determine what
information would be needed to allow adequate oversight of RTO markets. Mr, Dunn
recommends that generator offer data in RTO markets be made publicly available on the
next day with the specific generation owners identified, as is common practice in the
markets in England, Wales and Australia. He also recommends providing the operating
characteristics of the generation plants.47 The issue of data transparencyis discussed
further in Section V of this white paper.
Not only are consumers in RTO regions bearing the brunt ofpower prices higher than
those in non -RTO regions, but their electricity bills also include the costs RTOs charge
simply to run their centralized markets. In an analysis for APPA, the consulting firm GDS
Associates found that RTO participants in 2005 paid more than $1 billion in total
administrative and operational costs to RTOs.48 This figure did not include the RTO
customers' own increased internal administrative and other costs incurred to participate
in RTOs, These high costs, taken together with the highly problematic power prices in
RTO -run markets, point up the need for an unbiased analysis of the costs and benefits of
46 7heGomPele Coaliiion Oversells IndtPendent Study Findings, by Laurence D. Kirsch and
Mathew J. Morey of Christensen Energy Associates Energy Consulting, December 2007.
47 Concept Paper by William H.DunnJr.; Data Rerluired furAlarkel Oversaghl, Deeember2007
48 Analysis of (*eational and Administrative Cost of RTOs prepared by William M,
Bateman and Robert C. Smith, CDS Associates, February 2007.
w.APPAnet.org cmuffnem in Pea 23
These "markets" are
essentially
administratively
developed constructs
featuring centralized
repeated auctions, in
which oligopoly sellers
can quickly learn the
strategies of other
bidders and adjust
their own bids
accordingly.
these markets.
Regulators And Other Policymakers Must Take Action
Given the results of these studies, and the increasing turmoil in states with retail
restructuring regimes,49 federal and state energy regulators and legislators cannot allow
the current problems vath RTO -run centralizedwholesale markets to continue
unexamined or unaddressed. The RTOs themselves and the "merchant" generators
reaping extraordinary profits in RTO -run markets have bombarded the public with a
steady stream of public announcements asserting that electric consumers benefit from
"competition"and "freemarkets."But RTO -run markets are neither competitive nor
free. These "`markets'dre essentially administratively developed constructs featuring
centralized repeated auctions, in which oligopoly sellers can quickly learn the strategies
of other bidders and adjust their own bids accordingly According to the generators,
their offers are extensively mitigated, preventing full recovery of their costs, yet some
generators are clearly making profits far in excess of the "cost plus a reasonable return"
that they would earn in a regulated market. Moreover, few of these dollars are reinvested
in new generation and transmission facilities. Access to regional transmission facilities is
essential to support wholesale transactions, but capacity is often insufficient and the
associated transmission rates are uncertain, due to LMP congestion fees and limited
FTRs.
No amount of free market rhetoric or touting of environmental benefits can cover up
the increasing shortfall of new generation capacity required to ensure adequate
electricity supplies in future years, at the same time that billions of dollars are simply
leaving the market in the form of profits to shareholders of unregulated generators.
Failure to take appropriate corrective actions to fix these systemic problems will not only
leave consumers prey to unjust and unreasonable rates, but could also lead to inadequate
transmission and generation capacity that undermines the electrical reliability of entire
regions of the country.
The next two sections discuss steps that should he taken to address these market
problems, including both fundamental reforms and more discrete steps to deal with
immediate problems with RTO -run markets.
49 Examples inchide recent actions taken against Constellation by the Maryland Public
Service Commission,the current debate over GovernorSLrickland's legislation in the
Ohio House of Representatives, and recent attempts in Pennsylvania by the state legisla-
ture to extend the rate caps.
24 consumers in Peri! www.APPAnet.org
V. Fundamental Market Reform k
Necessary to Protect Consumers
Consumer, Business, Public Interest and Other Groups
Agree on the Need for Reform
0 h road range of load -side interest and advocacy groups share APPA's
:oncerns about problems in the RTO -run markets and agree that
undamental market reforms are needed.50 For example, in their
eptember 2007 comments on the FERC's advanced notice of proposed
rulemaking, the Electricity Consumers Resource Council (ELCON),
American : ron and Steel Institute (AISI) and American Chemistry Council (ACC)
(collectively Industrial Consumers) said the "Industrial Customers believe that, as
currently designed, the organized (e.g., RTO) markets are permanently structured as
sellers' markets." They further said ".,.fundamental changes in the Day 2 market
paradigm will be necessary to establish a robust forward market capable of delivering net
benefits to consumers."
In that same proceeding, the Portland Cement Association (PCA) said "It is the hope of
PCA that the commission will seriously consider the impacts of prior commission
decisions on electricity consumers and address some of the basic market design
deficiencies that currently exist and cause the current system to effectivelyimpose a tax
on electricity consumers for the benefit of the shareholders and management of
electricity generating companies."
As a first step toward such reforms, APPA joined with these organizations and awide
range of other groups representing consumers, large industrial users, businesses and the
public interest to file a petition in this proceeding requesting the FERC to "expand the
scope of the Section 206 proceeding beyond the four issues discussed in the ANOPR to
comprehensively investigate thejustness and reasonableness of wholesale power supply
prices in the centralized markets administered by regional transmission organizations." 51
50 Among the market participants filing comments o i making presentations in Docket No. AD07-7.000 expressing strong concerns about
the impacts of RTO -run centralized markets were the following: the National Rural Electric CooperativeAssociation; Golden Spread
Electric Cooperative; the Electricity Consumers Resource Council: the Steel ManufacturersAssociation;the PJM Industrial Customer
Coalition; Industrial Energy Users -Ohio; West Virginia Energy Users Group; NEPOOL Industrial Customer Coalition; Southwest
Industrial Customer Coalition; Coalition of Midwest Transmission Customers;American Transmission Co., LLC; Alcoa, Inc.; Office of the
Ohio Consumers' Counsel; and Eastman Chemical Co.
51 Request of AARP,American Antitrust Institute, American Chemistry Council, American Forest & Paper Association, American Iron and
Steel Institute, American Municipal Power—Ohio, Ainerican Public Power Association,Association of Businesses AdvocatingTariff Equity,
Citizen Power, Citizens Utility Board of Illinois, Coalition of Midwest Transmission Customers, Colorado Office of Consumer Counsel,
Consumer Federation of America, Council of Industrial Boiler Owners, Democracy and Regulation, Electricity Consumers Resource
Council, Florida Industrial Power Users Group, Illinois Industrial Energy Consumers, Illinois Public Interest Research Group, Industrial
Energy Consumers of America, Industrial Energy Consumers of Pennsylvania, Industrial Energy Users—Ohio, Louisiana Energy Users
Group, Maryland Office of the People's Counsel, Maryland Public Interest Research Group, Missouri Industrial Energy Consumers,
National Association of State Utility Consumer Advocates, NEPOOL Industrial Customer Coalition, Office of the People's Counsel of the
District of Columbia, Ohio Hospital Association, Ohio Manufacturers' Association, Ohio Partners for Affordable Energy, PJM Industrial
Customer Coalition, Portland Cement Association, Power in the Public Interest, Public Citizen, Inc., Public Utility Law Project of New
York, Inc., Steel ManufacturersAssociation, West Virginia Energy Users Group, Wisconsin Industrial Energy Group, Inc., and Wisconsin
Paper Council to Expand the Scope of the 206 Proceeding, Docket Nos. RM07-19-000 and AD07-7-000, December 17,2007.
www,APPAnet.org consumers in Perri 25
APPA suggests the FERC Must Lead the Effort to Protect Consumers
commission consider Neither APPA nor other interest groups, no matter how well-informed, have the means,
the legal authority, or the access to pertinent data necessary to investigate fully and
restructuring full "Day adequately the causes of dysfunction in RTO -run wholesale markets. However, based on
211 RTOs as more its research, APPA believes such a thorough examination would likely reveal a melange
of administrativelydetermined market rules, algorithms understandable only to a few, ad
streamlined "Day hoc patches, makeshift and incomplete mitigation, perverse incentives, and profit-taking
RTOs. Such an at the expense of consumers.
approach would
Even with limited access to data, APPA's Electric Market Reform Initiative studies have
maintain most of the
presented a significant amount of evidence of market problems. Moreover, the multitude
of materials filed in the ANOPR proceeding by other load -side interests provide ample
demonstrated
evidence that R'I'O -run centralized wholesale electricity markets are not producingjust
consumer and
and reasonable rates and do not, in fact, meet many of the basic criteria for competitive
markets. In the face of this evidence, FERC cannot simply claim that it has found the
economic ben e f i i of
"rightmix" of competition and regulation for RTO markets52 and decline to examine
RTOs, which are in the
the situation. FERC has an affirmative obligation -expressly set forth in the FPA
investigate whether rates subject to itsjurisdiction are unjust and unreasonable, and to
Day -1 transmission-
take appropriate remedial steps.
related functions.
APPA Recommends Restructuring RTOs as "Day V RTOs
APPA does not believe that RTO -run centralized markets producejust and reasonable
rates. APPA believes a thorough investigation by FERC, subject to appropriate
congressional oversight, would confirm this. FERC, however, has indicated that it would
not initiate such an investigation without first having received specific proposals for RTO
market reforms to assist it in that effort. While some affirmative RTO market reform
proposals have been offered,53 APPA has borne the brunt of considerable criticism from
regulators, generators and the RTOs themselves for not providing any affirmative reform
proposal.
To contribute another policy option to the ongoing debate about possible "solutions" for
RTO market problems, APPA suggests the commission consider restructuring full "`Day
2" RTOs as more streamlined `Day 1"RTOs. Such an approach would maintain most of
the demonstrated consumer and economic benefio of RTOs, which are in the Day 1
transmission -related functions. Thus, this proposal is designed to keep what is working
relatively well in RTOs and replace those functions and features, mostly associatedwith
52 ANOPR at Paragraph 6.
53 Deregulation/Reslrucluring — When, Should F*Go ,From Here?, Carnegie Mellon Electricity
Industry Center Working Paper 07-07 http://wpweb2.tepper.cmu.edu/test/papers/ceic-
07-07,asp; Comment of American Forest & Paper Association under RM07-19 and AD07-7,
September 14,2007, http://elibrary.ferc.gov/idmws/File—list.asp?document—id=13538931,
Comments of Portland Cement Association, Multiple Intervenors, PJM Industrial
Customer Coalition, et al under RM07-19-060, January 11,2008.
26 consumers in Peril www.APPAnet.org
RTO -run centralised energy, and rapacity markets, that have failed to produce sufficient
benefits to consumers. The functions that such a Day 1 KTO would carry out are
described in general terms below Severn Iquest.ions and concerns thatAPPA is explofing
arc listed next to these liuhc:tions.
Ensure non-discriminatory access to the grid through independent administration of
an open access transmission tariff and provision of transmission service, including
needed ancillary services. For services that require generation, an appropriate pricing
method would need to be developed (e -g., cost -based, price -capped, market-based,
MI-) If the RTO were to provide ancillan, services using market-based rates, strong
market power monitoring and mitigation tools would be necessary.
Develop and administer a regional transmission rate design that eliminates rate.
pancaking and assures the recovery of the cost of transmission facilities owned by all
transmission owners and providers thatuish to participate in the RTO, regardless of
their form of ownership.
Operate a single regional open access same -time information system (OASIS) and
independently calcuiate available transmission capacky (AW). A crucial question
here iswhether implementation ofa Day I RTO would require a return to a physical
transmission rights regime and, if so, how such a transition would be accomplished. It
may be difficult to provide non -pancaked non-discriminatory transmission service
under a physical transmission rights regime (at least without a substantial transition
period) given that Day 2 RTOs superseded such rights with financially based rights.
Physical rights may also be more difficult to administer, given the size of some
existing Ms.
Conduct independent and collaborative regional transmission and generation
interconnection facilities planning, with the inclusion ofaffectedstakcholdcn,
including state authorities, thus building t..., regional support required to get siting
authority for needed new transmission facilities and upgrades.
Carry out wide -area system security and reliability -related activities, ensuring that
transmission facilities arc operated in compliance with relevant North American
Electric Reliability Corp. (NI?RC) and regional reliability entity criteria. A minimalist
congestion regime is likely to be required, butwould need to be designed to avoid
the substantial problems that have developed under LMP -based congestion regimes.
Operate an enemy imbalance market to enable transmission customers to manage
their imbalances and to allow generators (including intermittent renewable
generators) to sell e ,cress generation not committed under bilateral contract
arrangements. As % th the ancillary ser0ces market, the pricing system used in (hr.
imbalance market would have to he carefully considered. A market-based system
should only be considered ifthe imbalance market. is limited to no more than 5
percent of the load and accompanied by strong market power monitoring and
mitigation tools.
Carty out additional functions (e.g., operation ofa power pool) ifall classes of
stakeholders in the region agree on the need for such functions and die RTO can
justify them as beneficial to ultimate consumers tlhrough thorough cost -bench t
analyses.
Ensure adequate generation reserves through implementation of resource adequacy
www.APPAnet.org Consumers in Peril 27
Supporting a more
requirements. Individual load -serving entities would meet these requirements
through development of appropriate power supply and capacityporifolios.
robust bilateral market
Such a Day 1 RTO would provide substantial consumer benefits from regional
and reducing reliance
transmission open access, elimination of rate-pancaking and capturing of short-term
on a bid -based spot
operational efficiencies in the imbalance market. Equally important, it would minimize
the market dysfunction problems that have plagued Day 2 RTOs. The RTO would
market would come at
operate an energy market only to balance loads. Thus the bulk of the energywould be
a time when several
sold under regulated retail rates, wholesale bilateral contracts (which would be at
market-based rates if the seller held the appropriate market-based rate authority), or
retail choice states are
retail supplier pass-through of wholesale power purchases.
already reevaluating
Such a regime would de-emphasize spot market participation by both buyers and sellers.
Meir retail access
APPA believes this is important to foster long-term power supply contracting, thus
providing the certainty needed for construction of new generation facilities. It would also
regimes and are
reduce the complexity and costs imposed on end-use consumers by Day 2 RMs,both
considering regimes
directly through their tariffs and administrative fees and indirectly through load -serving
entities' increased costs of internal operations. It would eliminate the mandatory RTO
that provide a greater
hid -based energy and capacity markets that magnify both the effects of generator market
role for their
power and the design flaws in RTO-administeredmarkets.
incumbent utilities in
Supporting a more robust bilateral market and reducing reliance on a bid -based spot
market would come at a time when several retail choice states are already reevaluating
the construction or
their retail access regimes and are considering regimes that provide a greater role for
procurement of
their incumbent utilities in the construction or procurement of generation. Examples
include steps to allow incumbent utilities to build generation facilities (as in
generation.
Connecticut) or to procure power through long-term contracts (as in Maryland.) 54
Power supply choices should he determined under rigorous review procedures to ensure
that retail customers are served by the most economic set of generation resources.
APPA presents its Day 1 recommendation here in broad outline to introduce it and allow
policymakers to consider it in the context of the issues discussed in this paper. APPA
intends to produce a more detailed version of this proposal in a separate document,
which will be published later in 2008.
APPA recognizes that implementation of such a Day 1 RTO regime would take time.
Many thorny transition issues would have to be resolved. Substantial institutional and
political obstacles exist as well. Moreover, differences among RTOs and the retail regimes
in the states they serve, as well as their different stages of development, likely requires
54 Interim Report tf the Public Service Commission cF Maryland to the Maryland General Assembly,
Part Z Ofitions For Re -Regulation and New Generation, December 3,2007, p. 34. Connecticut
enacted a law in July 2005 that allows the state's regulated utilities to build tap to 250
megawatts of peaking capacity. See "What Is Happening In State Retail Choice Programs?
August Update: A Focus on Obtaining Power Supply," APPA,
http://www,appanct.org/files/pdfs/stateupdateaugust2006.pdf.
2% consumers in Peri! www.APPAnet.org
custornimd application of this proposal in each RTO in it manner that recognizes and
accoininodates these differences. Ilence, APPA proffers this solution as a long-term one.
but one the industry should begin to move toward now. In the interim, there are several
more discrele RTO -related problems that FERC should address, which arc discussed in
the final section of this report.
FERC Should Do No Harm in the Interim
nAPPA's view, returning to just and reasonable rates requires FERC first to ensure that
there is no further development of RIO -run centralized wholesale markets. As discussed
above, one of the diff€Gullies in addressing the failure of these markets is the extent and
level of complexity to which flicy have already evolved and t1w continuing series of
patches that have been applied in attempts to remedy shortcomings in market design.
Adding further levels of complexity will only make the eventual return tojust and
reasonable rates more difficult.Thus, APPA recommends that rI?RC quickly place:
A moratorium oil the establishment of any new Day 2 RTOs; and
A moratorium on the establishment of new KPO-run markets for additional products
and serviceswithin existing RTOs, unless accompanied by the L) -pc of cost/Benefit
analysis discussed later its tlii.s paper.
wwiv.APPAnet.org Consumers in Peril 29
VI: Recommended Solutions to Specific,
More Discrete Market Problems
0rotection
of consumers' interests requires a return tojust and
reasonable rates as mandated by federal law. While the fundamental
long-term changes necessary to protect consumers are implemented, other
discrete market problems could be addressed more quickly These, especially in the
aggregate, could provide substantial consumer benefits. Following are some examples.
RTO Costs and Services
RTOs have unbundled their services into many separate markets, including day -ahead
and real-time energy, locational capacity and ancillary services. Since most of these
products are provided by the same generdtion base, pricing such services separately
makes it difficult to determine whether the generation owner is receiving revenue more
than once to cover the same claimed costs. As a result, such separation can result in costs
higher than what would be charged for an integrated product.
In addition, the proliferation of RTO -operated markets has resulted in more complexity,
requiring that participants, including load -sewing entities, conduct detailed monitoring
of billing procedures and extensive training of employeesto learn the technical aspects
of market participation. Stakeholders also incur administrative and legal costs to
participate in RTO system planning, stakeholder governance and other RTO processes.
Whether the benefits derived from participation in RTO markets outweigh the sum of
these costs remains an open question—butAPPA's Electric Market Refoim Initiative
studies imply this is unlikely To begin to provide a definitive answer, FERC should
require RTOs to obtain unbiased cost -benefit studies to accompany any filing of any new
markets and programs, as well as changes in existing markets and programs. No new
program or change should be put in place unless it is affirmatively shown to provide true
net benefits to end-use consumers in the form of lower costs and more reliable service.
Such assessments should be performed by neutral third parties (such as an independent
policy analysis group, academic department, outside market review committee or a
consulting firm engaged on a one-time basis) rather than for-profit consulting firms
beholden to the RTOs for continuing future business.
FERC should also develop clear criteria to measure the perfoimance of RTOs. Measures
could include: differentials between generator costs and prices charged in RTO -run
power markets; success in meeting RTO transmission expansion plans; responsiveness in
dealing with transmission service and interconnection requests; reductions or increases
in the level of transmission congestion costs over time; and benchmarking of
administrative and operating costs among RTOs.
RTO Mission Statements and Objectives
Judging by their mission statements, RTOs believe their core objective is to ensure
reliability and the effectiveoperation of wholesale electricity markets. While some RTO
mission statements include references to customers and to the public interest, the focus
on the end-use customer must be stronger, more explicit and in fact central to an RTO's
purpose. Thejustification for introducing competition into electricity markets was to
30 consumers in Peril www.APPAnet.org
increase economic efficiency and thereby provide lower prices and greater reliability to
Governance would also
electricity consumers. RTOs grew out of the competition experiment. Ultimately, to be
improve through better
costeffective and efficient, an RTO must make end-use customers better offthan they
would be without the RTO.
use of stakeholder
RTOs must be accountable for the cost impacts of their decisions. Their mission
advisory committees to
statements should include an explicit goal of reducing electric power costs to customers.
provide a b ro ad e r
This entails keeping costs—both from RTO operations and from the design of wholesale
markets—as low as reasonably possible. In addition, RTOs' strategic plans should he
range of input to RTO
developed in view of the central goal ofproviding tangible benefits to consumers.
boards.
RTO Governance
RTO boards must reflect a balance between independence from i n d u s y stakeholders
and accountability to the industry as a whole. Board decisions affect all aspects of RTO
market design and costs. It is therefore crucial that stakeholders have direct and effective
access to RTO hoards.
Current RTO governance structures include independent boards as well as processes for
developing stakeholder input. However, these processes do not always function well. In
particular, smallerload-serving entities, which include many public power utilities and
theirjoint action agencies, do not have the resources to participate in the numerous
RTO committees and working group. In addition, RTO boards often are not responsive
to stakeholder input even when it is provided. They have implemented significant
changes in spite of strong opposition from a large number of stakeholders.55
Hybrid RTO boards, composed of a majority of independent directors and a minority of
stakeholder directors, would ensure that stakeholder input is heard as part of all board
discussions. Since they have experience operating in an RTO, stakeholder board
members could provide practical advice on how RTO markets work and how potential
changes could affectvarious market participants. Stakeholder hoard members should he
elected by a supermajorityof the stakeholder sectors. This approach would ensure that
the stakeholder directors are well-respected and have the broad support of the
stakeholder community.
Governance would also improve through better use of stakeholder advisory committees
to provide a broader range of input to RTO boards. An advisory committee's interaction
ss A recent example is the January 30,2008filingmade by PJM in FERC Docket No. ER08-
516-000, in which PJM proposes to increase the "'Cost of New Entry" component of its
RPM framework (see http://www.pjm.com/documents/ferc/documents/2008/20080130-
er08-xxx-000.pdf). PJM notes in that filing (at 5) that it was unable to obtain the support
of the PVI Members Committee to proceed with the filing, since the sectorvote held in
the Members Committee was split between supply and load interests (93% of generation
owners voted in favor of the proposal, while only 9% of electric distributors and 0% of
end-use customers voted in favor of it.) The PJM Board subsequently voted to proceed
with the filing, notwithstanding the outcome of the vote in the Members' Committee.
www.APPAnet.org Consumers in Peril 31
WO management
with the board should not be limited to making formal presentations prior to the board's
vote on a topic. Rather, the process should allow the advisory committee to have early
should not be allowed
and unfiltered access to the board. This could occur through monthly teleconferences or
to direct market
quarterly meetings, with agendas set through nominations by the stakeholders.
monitor activities,
Market Monitoring
change market monitor
Given the important role that has fallen to market monitors, FERC must ensure that
reports or otherwise
market monitors are truly independent and have all of the resources necessary to
perform their functions. The structure of the market monitoring unit (MMU)—internal
interfere with a market
vs, external—and the specific tariffprovisions regarding the MMU are less important
monitor's activities.
than what happens in practice. In particular, RTO management should not be allowed to
direct market monitor activities, change market monitor reports or otherwise interfere
with a market monitor's activities. FERC should require the market monitor to report
directly to the RTO board or a board committee and FERC itselfshould be active in
enforcing the MMU tariff provisions.
The MMU should also have the full cooperation of market participants in data
gathering, including access to companyspecific financial information and generating
unit cost and operating data. The market monitor must have sufficient resources to carry
out its duties. This includes unrestricted access to RTO data and a budget that provides
for the necessary personnel, computer systems and training. If possible, the market
monitor should have an office and staff on site at the RTO, along with complete access to
RTO staff and RTO computer information systems.
A central part of the market monitor's mission is to protect wholesale and retail
customers from the exercise of market power and the payment of unjust and
unreasonable rates. Thus, the MMU must have the right to review bids submitted into
RTO markets and to take actions to prevent the exercise of market power or the
manipulation of RTO markets. & part of this mission, the MMU must also be
responsible for identifying adverse competitive consequences of RTO market rules. The
MMU should not participate in the initial development of rules, but should be allowed to
express in public forums its news on proposed rules. The RTO should also ask the MMU
for an independent assessment of the efficacyof a proposed rule, including the effect of
the rule on consumers and suppliers. Finally, the market monitor should have the right
to file in FERC dockets to make clear any concerns it bas with RTO proposals.
Information Transparency
RTOs publish a large volume of data on market operations, but currently keep the most
crucial information–generator bid data -confidential, releasing it only in masked form
after a delay of several months. Providing the public with access to this data on a nextday
basis and with open identification of generators would allow third parties to conduct
their own analysis of bidding behavior and price formation in RTO markets. (Note that
the release of bid data on a nextday basis is standard practice in international electricity
markets such as Australia, England and Wales.) This added transparencywould discipline
market behaviorbecause bidders would know that they were operating in full view of the
32 consumers in Petit w.APPAnet.org
public. It would also raise confidence in market operations because all market
participants and the public could independently validate how well markets were working.
They would be able to analyze bidding patterns, compare bids with cost factors, search
for indications of market power and, ultimately, advocate for better RTO market rules.
According to Frank Wolak, professor of economics at Stanford University, regulators
must have sufficient information to thoroughly analyze market operations and public
release of data is crucial:
The second crucial aspect of "smart sunshine regulation" is public
data release. Specifically, all data submitted to a real-time market and
produced by the system operator should be released to the public
immediately.The public data release should identifythe market
participant and specific generation unit associatedwith each bid,
generation schedule or output level. Masking the identity of the
market participants, as is done in all U.S. wholesale markets, limits the
discipliningvalue of public data release on market participant
The FERC should also consider requiring RTOs to report their "system lambdas" —the
variable cost of the last kilowatt produced over a set time period (e.g., each hour) from
the dispatchable generation units participating in each RTOs power supply markets.
This would allow observers to compare the prices set by these markets with the
underlying generation costs. 57 Similarly, non-utility generators should be required to
report annual cost and operating data to FERC and this information should be made
publicly available, as is currently the case with the generator cost data reported to FERC
by regulated public utilities. This information would allow FERC and the public to
determine whether rates in RTO -operated markets arejust and reasonable.
Generators cite two basic arguments againstmaking their cost and bid information
publicly available. First, they claim that revealing cost information would harm their
competitive position. Second, they assert that revealing bid data could facilitate collusion
among bidden. But, in fact, large generators already have substantial market information
because of their active roles—often with multiple plants—in both electricity and fuel
markets. In addition, generators can learn the bidding strategies of their competitors
through repeated interaction in an RTOs auction -based markets. large generators also
have access to more information resources, such as subscriptions to proprietary databases
of generation units and fuel market information that allow them to model market
behavior and analyze their competitors' costs and bidding patterns. Making cost and bid
data public would put the same information in the hands of smaller market players,
56 Frank A. Wolak, "Unilateral Market Power in Wholesale ElectricityMarkets," published in
GE.Sifo Bice Report' Journal for Imlidulional Comparisom, Ifo Institute. for Economic Research,
Vol. 4, No. 2, Summer 2006, p. 12.
57 This recommendation is contained in "The Missing Benchmark in Electricity
Deregulation," McCullough and Stewart.
The FERC should also
consider requiring
RTOs to report their
"system lambdad'—the
variable cost of the
last kilowatt produced
over a set time period
(e.g., each hour) from
the dispatchable
generation units
participating in each
RTQ's power supply
markets.
www.APPAnet.org Consumers in Peril 33
regulators, academics and the public, so it would not be available only to those with
superior mark(,[ positions or the financial resources to purchase it.
Finally, FERC and the public: should have greater access to financial information on
unreguia[ed generating companies. Some generating companies arc privately held and
[pus report little information. Others arc units of larger holding companies, so the
publicly available statistics arc on a holding coinpang-wide basis and provide (cw spc,c:ific
details on particular unrcgUlated atfiliatcs' genes-ation operations. Electric generation
companies should be required to File with FEKC basic financial information at the
individual company level, similar to file information regulated investor-owned public
utilities file in their RW, Form Is, including balance .shecas, operating income and
expenses, retained earnings and cash flows. FERC should require anmial reporting of
data specific to generation operations in detail sufficient to allow FFAC to develop basic
profit statistics. Data on prices, costs and profas are essential to dctc3•inine whether rates
are just and reasonable, whether they are set using cost -of sen=ice regulation or a market-
based regime.
34 Consumers it? Peril vvvm.APPMet.org
V11. Conclusion
0ishe electricity markets are in a time of crisis, with dire implications for
the economy, reliability and the general well-being of the population. It
our intention that this white paper and the proposals contained herein
will open a constructive dialogue to develop sorely needed reforms to the wholesale
electricity markets. The first step in achieving such a solution, however, will be for FERC
and other RTO market supporters to cease the rhetoric and acknowledge that these
markets are not competitive.
The debate should no longer be about who can best massage the statistics on prices or
whether it is more virtuous to speak of competition or regulation. But instead, we all
must work together to design a regulatory system for electricity markets that is truly in
the best interest of consumers, businesses and the environment
www.APPAnet.org consumers in Peri! 35
RESOLUTION NO. 2009-33
A RESOLUTION OF THE LODI CITY COUNCIL
AUTHORIZING NORTHERN CALIFORNIA POWER AGENCY
TO SELL SURPLUS CALIFORNIA INDEPENDENT SYSTEM
OPERATOR "CONGESTION REVENUE RIGHTS" ON
BEHALF OF THE CITY OF LODI
WHEREAS, by Resolution 2007-103 the City Council authorized the Northern
California Power Agency (NCPA) to participate on behalf of the City of Lodi Electric
Utility (EUD) in the California independent System Operator (CAISO) Congestion
Revenue Rights (CRRs) allocation process in order to stabilize and/or reduce the costs
of transmission in delivering energy from Lodi's power resources to load; and
WHEREAS, the CAISO has allocated CRRs to NCPA on behalf of EUD and may
do so again from time to time; and
WHEREAS, certain CRRs may be surplus to EUD's need to hedge transmission
costs; and
WHEREAS, NCPA's General Counsel believes it is unclear whether NCPA has
been granted the authority under Resolution 2007-103 to market and sell surplus CRRs
for the City of Lodi's account; and
WHEREAS, EUD staff, the NCPA Risk Oversight Committee, and the NCPA
Commission (NCPA Commission Resolution 09-08) have reviewed and approved limited
participation in CAISO auctions to reduce risk.
NOW, THEREFORE, BE IT RESOLVED that the Lodi City Council does hereby
authorize NCPA to offer and sell surplus CRRs in CAISO auctions on behalf of the City
of Lodi Electric Utility until such time that NCPA is notified otherwise in writing by the City
Manager or Electric Utility Director.
Dated: March 18, 2009
hereby certify that Resolution No. 2009-33 was passed and adopted by the Lodi
City Council in a regular meeting held March 18, 2009, by the following vote:
AYES: COUNCIL MEMBERS — Hitchcock, Katzakian, Mounce, and
Mayor Hansen
NOES: COUNCIL MEMBERS —Johnson
ABSENT: COUNCIL MEMBERS— None
ABSTAIN: COUNCIL MEMBERS —Non&JOHL
City Clerk
2009-33
Market Redesign &
Technology Upgrade 101
(MRTU)
City Council
March 18, 2009
CAISO
• California Independent System Operator
• Established by AB1 890 (Deregulation Bill) in
1996
• Began operation in 1998 as operator of much of
California's transmission network
• 500+ employees, $150M annual expenses
2
CAISO Operations Today
Uses a simplified 3 "Zonal" transmission model
of electric network
CAISO tasks:
— Preventing network overloads by adjusting power
schedules in real time
— Procuring "ancillary" services (reserves)
— Day ahead generating unit commitment
,* Limitations
— May accept infeasible day -ahead schedules
— Difficult to handle "intra -zonal" problems
— Lack of a forward or "day ahead" market
K
MRTU
• Approved by FERC in September 2006
• Planned "Go Live" date is.March 31
• For CAISO, resolves limitations of current
management of grid by:
— Use of a Full Network Model
— Establishment of an Integrated Forward
Market
— Use of Locational Marginal Prices (LMP's)
4
LMP's
• "Locational Marginal Price"
• Difference between energy prices for any
2 network nodes
• Composed of marginal prices for:
— energy
— congestion
— transmission losses
6i
Value of RTO/ISO's
• "Regional Transmission Organizations"
• Transmission access is non-discriminatory
• Administer "open access" tariffs
• Elimination of "pancaked" transmission
charges
• Regional transmission planning
coordination
C.1
MRTU Risks
• Software/hardware doesn't perform as
designed (CAISO and/or NCPA)
• New "Market" isn't competitive
— Seller's have market power
• "LMP's" are high and/or create major
winners & losers
• CRR's don't perform as expected
• Creates centralized market similar to
AB1890 (California deregulation law)
7
Video
CAISO Video on MRTU:
• The MRTU Program (10 minutes)
• The Heart of Market Redesign (15 minutes)
E:1
ISO Market "Problems"
All seller's receive "market clearing price"
Sellers become shorter term on pricing of power
Incentives for generators to withhold capacity
from market
• No evidence that high LIVIP's promote new
transmission and/or power plants
New costs to consumers for "capacity" and
CRR's
High ISO administrative costs
CRR's
0 "Congestion Revenue Rights"
Financial instrument to insure against
Congestion costs under MRTU
• Lodi granted authority to NCPA to procure
CRR's for Lodi (June 6, 2007)
NCPA desires members to clarify that NCPA has
authority to market and sell surplus CRR's also.
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Action
• Approve Resolution to clarify that NCPA
has the authority to market/sell CRR's for
the benefit of Lodi Electric Utility
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Questions/comments?
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