Carnegie Mellon University
Beyond Blind Faith: Rethinking
Electricity Restructuring
Seth Blumsack
Carnegie Mellon University
blumsack@cmu.edu
Electricity Industry Center
Carnegie Mellon University
Overview
Carnegie Mellon Electricity Industry Center (CEIC)
• One of 27 Sloan Centers of Excellence in different industries
• 17 Faculty and 22 Ph.D. students at CMU, 9 Ph.D.s granted so far.
• Probably the largest effort of its kind in the world focused on
interdisciplinary problems of the electricity industry.
• Close cooperation with all stakeholders: Industry, regulators,
government agencies, consumers, labor, national laboratories.
• Strategic focus on issues of middle and long-term importance
• Focus scientific knowledge to clarify the big picture issues and work
though individual projects on:
–Market Structure and Performance
–Distributed Energy Resources
–Advanced Generation and Transmission Technologies
–Environmental and Sustainability Issues
–Reliability and Security
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Overview
1. Deregulation or better regulation?
2. Why RTO markets may inherently raise costs
3. Retail competition has not lowered electricity prices
4. Investment: What can LMP tell us?
5. The good, the bad, and the ugly of LMP
6. Current RTO and market challenges
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Why Did We Need Deregulation
Restructuring To Do Something in the First
Place?
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U.S. Net Electric Generation
7000
6000
Billion kWh
5000
4000
3000
2000
70 B kWh / year
(10,000 MW/yr)
7¾ % / year
1000
1960
1970
1980
1990
2000
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Electricity Industry Center
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Why Not Reform Regulation?
• 1970s energy crises increased fuel costs, shifted
demand growth from exponential to linear
• Utility generation/transmission investments
became “white elephants”
• Regulators had no choice but to allow utilities to
pass costs on to consumers, increasing prices
• Consumer anger with utilities and regulators,
accusations of “gold-plating”
• Oil and gas deregulation followed by lower prices
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Effective regulation requires expertise
and information – even the best
regulators have less of both than the
companies they’re trying to regulate!
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Creating Competitive Electricity Markets
May Inherently Raise Costs
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Marginal and Average Cost Pricing
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Uniform Price Auctions
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Are Electricity Markets Competitive?
The usual market concentration metrics (HHI, etc.) do not translate
well into electricity markets.
A better notion is the pivotal supplier – a single supplier or group of
suppliers is pivotal if their capacity exceeds the spare capacity of
the system as a whole – buy from them or suffer blackouts!
Example of a “pivotal” monopolist
Suppose that:
• Total generation capacity is 100 MW;
• Firm M controls 18 MW;
• The ISO announces that it seeks to buy 90 MW;
Results:
• Firm M knows that it has monopoly power!
• If every other firm in the market had less than 1% of market
share, the conventional HHI would be 324.
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Should We Worry About Groups of Pivotal Suppliers?
Yes! Sarosh Talukdar has simulated markets that have 10 suppliers
or 10 demanders, each with 10% of capacity
Red: Inelastic
Demand
Blue: Elastic
Demand
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Pivotal Firms in CA, PJM, NYISO, 2000/2001
100%
CAISO
90%
PJM
80%
Duration (% of Hours)
NYISO
70%
60%
50%
40%
30%
20%
10%
0%
1
2
3
4
Number of Pivotal Firms
5
6
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Mitigating Pivotal Suppliers
• Have price caps & force generators to offer power
at variable cost when demand is high
• Build more generation
• Build more transmission
• Break up firms to keep them small
• Change structure: Eliminate hourly auctions
Each of these would work, but would involve substantial
costs – many would be more costly than the ~10%
efficiency improvements attributed to restructuring.
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Price Caps
Current FERC regulations:
• Price caps to keep price in control
• Require pivotal firms to offer electricity at
variable cost when demand is high
• Firms could never cover their fixed costs
and so no future investment
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Expand Generation Capacity
This will do the job, but the costs can be substantial – would
increase costs by at least 2 cts/kWh in any RTO.
Mitigation Cost ($ billion)
8
CAISO
PJM
NYISO
6
4
2
0
1
2
3
4
5
6
Number of Pivotal Firms
Assumptions: $600/kW capital cost, 10% discount rate (CAPM), all new generation is gas-fired with a 30-year
economic life, capacity is on standby during hours with pivotal suppliers.
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Expand Transmission Capacity
This will only work if cheap imports are readily available – could
be true in California, but probably not in the Eastern Interconnect
AZ
CA
NM
OR
WA
AZ
1
0.90
0.93
-0.10
-0.48
PJM
NYISO
ECAR
SERC
NEPOOL
CA
NM
OR
WA
1
0.80
-0.04
-0.41
1
0.10
-0.33
1
0.77
1
PJM
1
0.92
0.90
0.87
0.91
NYISO
ECAR
1
0.78
0.83
0.86
1
0.88
0.84
Demand correlation
matrix – Western States
SERC NEPOOL
1
0.74
Demand correlation
matrix – Eastern
Interconnect
1
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Force Large Generators to Divest
This would reduce market power but might also reduce operational
efficiency – there is evidence of this from the nuclear sector
100%
Mean Capacity Factor
80%
60%
40%
20%
Firms owning one plant
Firms owning two plants
Firms owning three plants
Firms owning > 3 plants
0%
1993
1997
2000
2002
Year
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Increased Risk in a Capital-Intensive Industry
• Merchant debt has
dropped to junk; IOU
debt below A grade
• Public power debt still
has A grade
Source: The Brattle Group
• For a new coal plant,
capital is at least 2/3 of
total cost. Investors
demanding 15% or
20% instead of 10%
can increase costs by 1
to 5 cts/kWh
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RTOs Are Costly Institutions
• Startup costs for California ISO estimated at $500 million to $1
billion, with operating costs of $200 million/year
• PJM has operating costs of $250 million/year
Source: Public Power Council
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Retail Competition Has Not Lowered
Industrial Electricity Prices
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Why Retail Competition?
Restructuring in the electric power industry was supposed to lower
costs, increase efficiency, and make markets more competitive.
How have we done?
“…more than $3 billion in savings in 2002 in the Mid-Atlantic
(PJM) region…approximately $28.5 billion in future
savings…additional macroeconomic benefits should double the
direct customer benefits…”
(Excerpts from Benefits of Competition in the Mid-Atlantic Region,
Center for the Advancement of Energy Markets)
Sounds Great!
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What is Really Going On?
To the extent that retail prices have fallen, it is because regulators
have mandated rate-cuts and freezes. Many of these expire soon…
Some Proposed Retail Rate Increases
Connecticut Light & Power: 22%
Delmarva Power: 56% to 117%
TXU Corp. (Texas): 80% (actual, not proposed)
NStar (Massachusetts): 60% to 80%
Baltimore Gas & Electric: 72% proposed, at least 15% actual
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We examine industrial sales and revenue
data from EIA forms 826 and 861
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Frequencies Present in Maryland Industrial Price Data
12 months
5
6 months
4 months
3 months
2.4 months
Power
4
3
2
1
0
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
Frequency (cycles per month)
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0.5
Carnegie Mellon University
Maryland Industrial
6.5
Cents per kWh
6
5.5
5
4.5
4
3.5
1990 91
92
93
94
95
96
97
98
99 2000 01
02
03
Electricity Industry Center
04
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Western Industrial
12
CA
AZ
NV
10
CA
OR
Cents per kWh
WA
8
NV
6
AZ
4
OR
WA
1990 91
92
93
94
95
96
97
98
99 2000 01
02
03
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04
Carnegie Mellon University
Southern Industrial
12
FL
GA
Cents per kWh
10
MS
AL
SC
8
6
4
1990 91
92
93
94
95
96
97
98
99 2000 01
02
03
Electricity Industry Center
04
Carnegie Mellon University
New England Industrial
12
RI
Cents per kWh
10
NH
MA
8
CT
VT
6
RI
MA
CT
4
NH
VT
1990 91
92
93
94
95
96
97
98
99 2000 01
02
03
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04
Carnegie Mellon University
10%
Annual Industrial Price Change
5%
0%
-5%
-10%
-15%
-20%
Before
After
-25%
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5%
Annual Industrial Price Change
2.5%
1.3%
1.0%
0.8%
0.3%
0%
0.0%
-0.6%
-0.7%
-1.3%
-0.8%
-0.8%
-0.7%
-1.3%
-1.8%
Before
After
-5%
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5%
Annual Industrial Price Change
2.1%
2.0%
1.8%
1.7%
0.9%
0.8%
0.4%
0.4%
0.5%
0.3%
0%
0.0%
-1.7%
Before
After
-5%
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Correlation of Restructuring with Industrial Price Changes
Regulated
Restructured
Annual Rate of Change After - Before
10%
5%
0%
-5%
-10%
-15%
-20%
-25%
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Large Customers Should Have Been the
Beneficiaries of Retail Competition
• They have the option to purchase power in bilateral
contracts through RFP / direct negotiation for block
purchases; they can become their own load-serving entity
and buy in the wholesale market. They are getting killed.
Hourly Wholesale Electricity Prices in Beaver
12
10
Spot vs. long term
cents per kWh
8
6
4
2
5/18/2005
5/19/2005
0
0
6
12
Hour of the Day
18
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What Can LMP Tell Us About
Investment?
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Investment Issues Under Restructuring
Restructured markets have not had a stellar record encouraging
investment. What is going on here?
1. Merchant generation investment and the gas bubble
2. Capacity markets, price caps, and resource adequacy
3. Transmission
What is the role of LMP in all of this?
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Restructuring and Natural Gas
Monthly Natural Gas Citygate Price
and consumption of natural gas for electric power generation
16
7
14
6
Consumption for Electricity
12
$ per mcf
10
4
8
3
6
2
4
Natural Gas Price
1
2
1990
-
1992
1994
1996
1998
2000
2002
2004
2006
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TCF used for electricity
5
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Capacity Markets
Out-of-market purchases, Reliability pricing model, etc…
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Capacity Markets and LMP
• Uniform price auction used in RTO markets starves the peakers
and transfers these “rents” to baseload plants.
• LMPs are incredibly volatile, as are spot prices for every energy
commodity – short-run demand curve is highly inelastic, and
short-run supply curve is very steep near the capacity constraint.
• Capacity payments are a political “second-best” solution to get
peakers and newer generators into the market when the RTO uses
caps and other mechanisms to keep LMPs low.
• Does a depreciated 50-year old nuke with MC = 1.5 cts/kWh
actually need a capacity payment?
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The Transmission Grid is Under Stress
• TLRs increasing
• Average and total congestion costs
increasing in restructured systems
• Investment in high-voltage lines
declining
PJM Congestion Costs
3.50
Total Congestion Costs ($M)
3.00
Total
2,000
Average
2.50
1,500
2.00
1.50
1,000
1.00
500
Average Congestion Costs ($/MWh)
2,500
0.50
0
0.00
1999
2000
2001
2002
2003
2004
2005
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Whatever Happened to Merchant
Transmission?
“The real difference between the U.S. and France is that
American economists believe that markets work in theory but not
in practice, whereas French economists believe that markets work
in practice but not in theory.”
-- Ezra Beeman of CERA (Paris)
North American RTOs have been demonstrating a distinctly
Gallic flair. They are still trying to attract merchant AC
transmission investment, dangling FTRs as carrots.
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Merchant Transmission in Theory
• Locational marginal prices (LMP) are investment signals;
differences in LMPs tell investors where to upgrade existing lines
or where to build new lines
• Investors are given financial rights to the congestion revenue, in
the form of point-to-point rights (Financial Transmission Rights
or FTR)
• The holder of an M megawatt FTR, defined between nodes a and
b in the grid, at time t receives
FTR Revenue: M  (LMPa,t – LMPb,t)
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Merchant Transmission Critique #1
Bus 2
π2 = $46.96
FS12 = 55 MW
μS12 = $45.87
FS24 = 36.7 MW
μS24 = $0
FS23 = 18.3 MW
μS23 = $0
Bus 1
PG1 = 91.67 MW
π1 = $11.96
FS13 = 36.7 MW
μS13 = $0
FS34 = 55 MW
μS34 = $20.30
Bus 4
PL4 = 100 MW
PG4 = 8.33 MW
π4 = $51.67
Bus 3
π3 = $33.72
"From" Bus
2
4
3
"To" Bus
1
3
2
"From" Price
($/MWh)
46.96
51.67
33.72
"To" Price
($/MWh)
11.96
33.72
46.96
Difference
($/MWh)
35
17.95
-13.24
Size
(MW)
5
5
18.3
Total
Value
($/h)
175
89.75
-242.292
$22.46
I can profit from building a line that causes congestion!
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Merchant Transmission Critique #2
• LMP differences do not capture the system cost of congestion
• If the line is expanded, the LMP difference disappears. Why
would anyone invest in a system like this?
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Merchant Transmission Critique #3
Bus 2
π2 = $46.96
FS12 = 55 MW
μS12 = $45.87
FS24 = 36.7 MW
μS24 = $0
FS23 = 18.3 MW
μS23 = $0
Bus 1
PG1 = 91.67 MW
π1 = $11.96
FS13 = 36.7 MW
μS13 = $0
FS34 = 55 MW
μS34 = $20.30
Bus 4
PL4 = 100 MW
PG4 = 8.33 MW
π4 = $51.67
Bus 3
π3 = $33.72
• Building line (2,3) causes congestion, but may provide a
reliability benefit.
• Merchant transmission assumes that congestion and reliability
are independent.
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Policy Assumes Congestion and Reliability
are Separable and Independent
Congressional, FERC, and RTO policy divides transmission
investments into those which enhance reliability and those which
reduce congestion:
• Federal Power Act, Sec. 215(e): FERC has regulatory jurisdiction
over economic transmission matters (i.e., congestion), and the ERO
has jurisdiction over technical matters (i.e., reliability).
• Merchant AC transmission via transmission congestion contracts,
participant funding, congestion reduction, etc.
• Cost allocation for new lines based on a reliability or congestion
designation. Lines for reliability have their costs socialized, while
lines for congestion are paid for by designated “beneficiaries.”
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Congestion and Reliability are Almost
Never Independent
• Simple simulations on a 118-bus network to isolate the
contributions of individual lines to congestion and reliability.
• Those that cause congestion also tend to increase reliability.
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Is Merchant Transmission the Problem?
• Actually, no. The real problem is with using LMP to compensate
transmission investment.
• Merchant transmission has been the policy of FERC and RTOs
for several years – FTRs have not gotten a single merchant line
built!
• Long-term contracts have gotten lines built (e.g., Neptune line)
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Where to From Here?
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Summary: Which do you Want First, the
Bad News or the Bad News?
• Blind faith in restructuring and organized markets have not
brought down electricity costs. Prices have declined, but only by
edict from regulators.
• LMPs are naturally volatile and can/should spike to very high
levels during peak periods. RTOs have not permitted this.
• Price caps and other actions have required the development of
intricate and unnecessary capacity markets.
• Congestion and reliability are system attributes. AC transmission
investment is a systems problem that LMPs cannot solve.
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What is Wrong with LMP?
• LMP is a by-product of constrained economic dispatch. It tells
you some things about the system right now.
• In a competitive market, prices must send signals and convey
information.
• LMP does convey some information – such as whether there is
congestion – but it does not necessarily tell you the best corrective
action.
• LMPs as currently used represent incomplete information. LMPs
do not say anything about reactive power, reliability, admittance,
inertia, contingencies, marginal/aggregate losses (in some RTOs),
all of which are part of the electric “good” that customers purchase.
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Some Current Market Challenges
• Forward markets for energy: oil and natural gas prices are just as
volatile as electricity LMPs. But oil and gas have liquid forward
markets which allow for risk management. NYMEX has not been
effective for electricity.
• Compensating FACTS and other new technologies – what would it
mean to have an “LMP” for a phase-shifting transformer?
• Ancillary services markets have been uncompetitive. Should
ancillary services be procured jointly with energy in the spot
market? Would this capture enough value of ancillary services to
attract investment?
• Demand response – engaging consumers to be active market
participants. Is this an engineering or economic problem?
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Thank You!
Seth Blumsack
blumsack@cmu.edu
www.andrew.cmu.edu/~sblumsac
www.cmu.edu/electricity
Electricity Industry Center