Masters G.M. Renewable and Efficient Electric Power Systems

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158 THE ELECTRIC POWER INDUSTRY

U.S. Industrial Average Revenue per kWh is 5.04 Cents

4.48

4.21

6.56

3.71

3.53

3.43

4.48

9.81

11.68

5.24

7.61

5.45

6.54

3.98

4.46

3.76

4.55

4.29

4.43

4.39

4.18

IAL

4.92

4.3

4.11

3.04

4.72

3.8

4.28

3.88

5.89

5.51

7.89

9.11

8.62

3.74

4.17

4.37

4.52

5.09

5.31

5.58

5.33

4.4

4.12

10.13

9.79

7.62

8.27

5.08

4.41

4.81

Figure 3.41 Av erage industrial sector revenue per kWh, 2001. California was 6.6¢/kWh

in 1998, before restructuring. From EIA (2003).

In the mid-1990s, California’s retail price of electricity for the industrial sector

was among the highest in the nation, yet the on-peak, wholesale market price

was less than one-fourth of that amount. Excess capacity in nearby states, along

with plenty of hydroelectric power, kept the wholesale marginal cost of electric-

ity low. The gap between wholesale and retail prices suggested that if utilities

could just rid themselves of their QF obligations and quickly pay down their

expensive existing generators, they would be able to dramatically lower prices

by simply purchasing their power in the wholesale market. Worried about losing

large industrial customers to other states with cheaper electric rates, the California

public utility commission (CPUC) in 1994 issued a proposed rule to restructure

the power industry with the goal of reducing the state’s high price of electricity.

The restructuring was unfortunately misnamed “deregulation,” and that became

the term that was used throughout the ensuing years of turmoil.

California’s AB 1890 Barely two years after the CPUC proposed to restruc-

ture the electric power industry, in 1996 the California Legislature responded

by enacting Assembly Bill 1890 (AB 1890). AB 1890 included the following

major provisions:

The wholesale market was opened to competition, and all customers would

have a choice of electricity suppliers.

Residential and small commercial customers would be given an immediate

4-year, 10% rate reduction to be funded by issuing bonds that would be

THE EMERGENCE OF COMPETITIVE MARKETS 159

repaid after the 4-year period ended. Larger customers who stayed with

their IOUs would have rates frozen at 1996 levels.

Utilities would be given the opportunity to recover their stranded costs

(especially nuclear and QF obligations) during that 4-year rate-freeze period.

The assumption was that utilities would collect more revenue at the frozen,

retail rates than would be needed to purchase power in the wholesale market,

cover transmission and distribution costs, and make payments on their rate-

reduction bonds. The difference between retail price and those various costs,

called the competition transition charge (CTC), would be used to pay down

stranded assets over the 4-year rate-freeze period.

A public goods charge would be levied to continue support for programs

focused on renewable energy, customer energy efﬁciency, and rate subsidies

for low-income consumers.

Utilities were to sell off much of their generating capacity to create new

players in the market who would then compete to sell their power, thereby

lowering prices.

After the initial 4 years—that is, by 2002—rates would be unfrozen and the

beneﬁts associated with the free market would be realized. The rate freeze

would end sooner for any utility that paid off its stranded assets in less than

4 years.

AB 1890 applied to the state’s three major IOUs, Paciﬁc Gas and Electric

(PG&E), Southern California Edison (SCE), and San Diego Gas and Electric

(SDG&E), which deliver roughly three-fourths of the electricity in California.

The remaining one-fourth is mostly made up of municipal utilities, which were

encouraged, but not required, to participate in the restructuring.

Following FERC’s Order 888, California established a not-for-proﬁt indepen-

dent system operator (ISO) to operate and manage the state’s transmission grid.

The ISO was meant to assure access to the transmission system so that buyers

could purchase electricity from any sellers that they may choose. In addition,

the California Power Exchange (CalPX) was set up to match supply to demand

using daily auctions. It accepted price and quantity bids from participants in both

“Day-Ahead” and “Day-Of” markets from which the market clearing price at

which energy was bought and sold was determined.

One of the beneﬁts of the restructuring was that customers could choose their

supplier of electricity. Competition was facilitated by energy service providers,

or power marketers, who offered a range of generation combinations, including

options for various fractions of renewables. To help make comparisons, utilities

and power marketers provided power content labels specifying the fraction of

their generation that was from renewables, coal, large hydroelectric, natural gas,

and nuclear.

The basic structure of California’s intended, restructured electricity system is

diagrammed in Fig. 3.42.

160 THE ELECTRIC POWER INDUSTRY

Generator Generator

Power Exchange

(CalPX)

Energy

Service

Providers

Independent System Operator (ISO)

Distribution Utilities

Utility

Customers

Direct Access

Customers

Figure 3.42 California’s initial electric industry restructuring.

3.12.3 Collapse of ‘‘Deregulation’’ in California

California ofﬁcially opened its wholesale electricity market to competition in

March 1998. For the ﬁrst two years, it worked quite well, with wholesale

prices hovering around $35/MWh (3.5¢/kWh) which was far less than the

frozen retail rates. Even after adding on the cost of transmission, distribution

and rate-reduction bonds, utilities were still netting around $35/MWh to pay

down stranded assets (Wolak, 2003). PG&E, SCE, and SDG&E had sold off

approximately 18,000 MW of generation capacity, or roughly 40% of California’s

generating capacity, to ﬁve new entrants into the California market: Duke,

Dynergy, Reliant, AES, and Mirant. Marketers of green power were beginning

to make inroads into the residential market.

Then in the summer of 2000, it all began to unravel (Fig. 3.43). The cost of

power on the wholesale market rose to unheard of levels. In August 2000, at an

average price of $170/MWh (17¢/kWh) it was ﬁve times higher than it had been

in the same month in 1999, and on one day it reached $800/MWh (80¢/kWh).

Under the ﬁxed retail-price constraints imposed by AB 1890, PG&E and SCE

were forced to purchase wholesale power at higher prices than they could sell it

for and began to rapidly acquire unsustainable levels of debt. SDG&E, however,

had already paid off its stranded assets and therefore was able to pass these

higher costs on to its customers, who, as a r esult, saw rates increase by as much

as 300%.

By the end of 2000, Californians had paid $33.5 billion for electricity, nearly

ﬁve times the $7.5 billion spent in 1999. Factors that contributed to the crisis

included higher-than-normal natural gas prices, a drought that reduced the avail-

ability of imported electricity, especially from the northwest, reduced efforts by

THE EMERGENCE OF COMPETITIVE MARKETS 161

California utilities to pursue customer efﬁciency programs in a deregulated envi-

ronment, and insufﬁcient new plant construction. Arguably, this construction was

not necessitated by growth in California’s electricity demand, which had been

modest, but rather it was the lack of construction in adjacent states that had tra-

ditionally exported power to California. Those states were not keeping up with

their own demands, which eroded the amounts usually available for California to

import. But the principal cause was the discovery by new generation companies

that they could make a lot more money manipulating the market than meeting

the needs of California with adequate supplies. In November 2000, even FERC

concluded that unjust and unreasonable summer wholesale prices resulted from

the exercise of market power by generators.

In January 2001, California experienced almost daily Stage 3 emergencies

and had several days with rolling blackouts. To have rolling blackouts in January

when peak power demands are one third-lower than they are in the summer

provided compelling evidence that generators had gamed the system by purposely

removing capacity from the grid in order to raise prices and increase proﬁts on the

facilities that they continued to operate. In fact, wholesale rates in January 2001

far exceeded those of the previous summer and at one point reached $1500/MWh

($1.50/kWh). California paid as much for electricity in the ﬁrst month and a half

of 2001 as it had paid in all of 1999.

As Fig. 3.43 shows, wholesale prices remained extraordinarily high through

the spring of 2001. By May, PG&E had declared bankruptcy and SCE was on

the edge, the CalPX had been shut down, and CalISO began to purchase power

as well as operate the grid. The crisis ﬁnally began to ease by the summer

of 2001 after FERC instituted price caps on wholesale power, the Governor

began to negotiate long-term power contracts, and the state’s aggressive energy-

conservation efforts began to pay off.

The true success story in relieving the anticipated summer 2001 meltdown

was California’s intensive and effective energy conservation program. Additional

funds were devoted to energy efﬁciency programs including a “20/20” program

that provided a 20% percent rate reduction to customers who cut energy use by

Jul 99 Jan 00 Jul 00 Jan 01 Jul 01 Jan 02 Jul 02

Wholesale Electricity Price

(Norminal Cents Per kWh)

Figure 3.43 California wholesale electricity prices during the crisis of 2000–2001.

From: Bachrach et al. (2003).

162 THE ELECTRIC POWER INDUSTRY

14%

12%

10%

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Percent Savings

2001

2002

Figure 3.44 California weather-adjusted monthly electricity reductions relative to 2000

(Bachrach, 2003). Efﬁciency programs saved the state from what could have been a

catastrophic 2001 summer.

20%—a target that over one-third of residential customers achieved. A number

of specialized programs were created to focus on reducing peak demand. Relative

to June 2000, energy use in June 2001, adjusted for weather, was down almost

14% and for the whole summer it was almost 8% lower. Those were gains

during a year in which the economy grew by 2.3%. The estimated cost of the

state’s conservation program was less than 3 cents per kWh saved, an order of

magnitude below the average wholesale price the previous winter and half the

cost of the long-term contracts the state signed in March 2001 (Bachrach, 2003).

Moreover, as Fig. 3.44 shows, even after the crisis had passed, the conservation

gains showed every sign that they would persist.

In March 2003, the FERC issued a statement concluding that California elec-

tricity and natural gas prices were driven higher because of widespread manipu-

lation and misconduct by Enron and more than 30 other energy companies during

the 2000–2001 energy crisis.

While the momentum of the 1990s toward restructuring was shaken by the

California experience, the basic arguments in favor of a more competitive electric

power industry remain attractive. Analysis of the failure there has guided the

restructuring that continues to proceed in a number of other states. It is hoped

that they’ll do better.

REFERENCES

Bachrach, D., M. Ardema, and A. Leupp (2003). Energy Efﬁciency Leadership in Cali-

fornia: Preventing the Next Crisis, Natural Resources Defense Council, Silicon Valley

Manufacturing Group, April.

PROBLEMS 163

Bayliss, C. (1994). Less is More: Why Gas Turbines Will Transform Electric Utilities,

Public Utility Fortnightly, December 1, pp. 21–25.

Bosela, T. R. (1997). Introduction to Electrical Power System Technology, Prentice-Hall,

Englewood Cliffs, NJ.

Brown, R. E., and J. Koomey (2002). Electricity Use in California: Past Trends and

Present Usage Patterns, Lawrence Berkeley National Labs, LBL-47992, Berkeley, CA.

California Collaborative (1990). An Energy Efﬁciency Blueprint for California, January.

Culp, A. W., Jr. (1979). Principles of Energy Conversion, McGraw-Hill, New York.

Energy Information Administration (EIA, 2001). The Changing Structure of the Electric

Power Industry 2000: An Update, DOE/EIA-0562(00), Washington, DC.

Energy Information Administration (EIA, 2003). EIA Annual Energy Review 2001 ,

DOE/EIA-0348(2001), Washington, DC.

IPCC (1996). Climate Change 1995: Impacts, Adaptations and Mitigation of Climate

Change: Scientiﬁc-Technical Analyses, Intergovernmental Panel on Climate Change,

Cambridge University Press, New York.

Lovins, A. B., E. Datta, T. Feiler, K. Rabago, J. Swisher, A. Lehmann, and K. Wicker

(2002). Small is Proﬁtable: The Hidden Economic Beneﬁts of Making Electrical

Resources the Right Size, Rocky Mountain Institute, Snowmass, CO.

Masters, G. M. (1998). Introduction to Environmental Engineering and Science, 2nd ed.,

Prentice-Hall, Englewood Cliffs, NJ.

Penrose, J. E., Inventing Electrocution, Invention and Technology, Spring 1994, pp. 35–44.

Petchers, N. (2002). Combined Heating, Cooling & Power: Technologies & Applications,

The Fairmont Press, Lilburn, GA.

Sant, R. (1993). Competitive Generation is Here, The Electricity Journal, August/

September.

Union of Concerned Scientists (UCS, 1992). America’s Energy Choices: Investing in a

Strong Economy and a Clean Environment, Cambridge, MA.

Wolak, F. A. (2003). Lessons from the California Electricity Crisis, University of Cali-

fornia Energy Institute, Center for the Study of Energy Markets, CSEMWP110.

PROBLEMS

3.1 A Carnot heat engine receives 1000 kJ/s of heat from a high temperature

source at 600

◦

C and rejects heat to a cold temperature sink at 20

◦

a. What is the thermal efﬁciency of this engine?

b. What is the power delivered by the engine in watts?

c. At what rate is heat rejected to the cold temperature sink?

d. What is the entropy change of the sink?

3.2 A heat engine supposedly receives 500 kJ/s of heat from an 1100-K source

and rejects 300 kJ/s to a low-temperature sink at 300 K.

a. Is this possible or impossible?

b. What would be the net rate of change of entropy for this system?

164 THE ELECTRIC POWER INDUSTRY

3.3 A solar pond consists of a thin layer of fresh water ﬂoating on top of a

denser layer of salt water. When the salty layer absorbs sunlight it warms

up and much of that heat is held there by the insulating effect of the fresh

water above it (without the fresh water, the warm salt water would rise

to the surface and dissipate its heat to the atmosphere). A solar pond can

easily be 100

◦

C above the ambient temperature.

Salty layer

Freshwater

Figure P3.3

a. What is the maximum efﬁciency of a heat engine operating off of a

120

◦

C solar pond on a 20

◦

Cday?

b. If a real engine is able to achieve half the efﬁciency of a Carnot engine,

how many kilowatt hours of electricity could be generated per day from

a 100 m × 100 m pond that captures and stores 50% of the 7 kWh/m

solar radiation striking the surface?

c. For a house that requires 500 kWh per (30-day) month, what area of

pond would be needed?

3.4 A combined-cycle, natural-gas, power plant has an efﬁciency of 52%. Nat-

ural gas has an energy density of 55,340 kJ/kg and about 77% of the fuel

is carbon.

a. What is the heat rate of this plant expressed as kJ/kWh and Btu/kWh?

b. Find the emission rate of carbon (kgC/kWh) and carbon dioxide

(kgCO

/kWh). Compare those with the average coal plant emission rates

found in Example 3.2.

3.5 A new coal-ﬁred power plant with a heat rate of 9000 Btu/kWh burns coal

with an energy content of 24,000 kJ/kg. The coal content includes 62-%

carbon, 2-% sulfur and 10-% unburnable minerals called ash.

a. What will be the carbon emission rate (g C/kWh)?

b. What will be the uncontrolled sulfur emission rate (g S/kWh)?

c. If 70% of the ash is released as particular matter from the stack (called ﬂy

ash), what would be the uncontrolled particulate emission rate (g/kWh)?

d. Since the Clean Air Act restricts SO

emissions to 130 g of sulfur per

kJ of heat into the plant, what removal efﬁciency does the scrubber

need to have for this plant?

PROBLEMS 165

e. What efﬁciency does the particulate removal equipment need to have to

meet the Clean Air Act standard of no more than 13 g of ﬂy ash per

kJ of heat input?

3.6 Using the representative capital costs of power plant and fuels given in

Table 3.3, compute the cost of electricity from the following power plants.

For each, assume a ﬁxed charge rate of 0.14/yr.

a. Pulverized coal steam plant with capacity factor CF = 0.7.

b. Advanced coal steam plant with CF = 0.8.

c. Oil/gas steam plant with CF = 0.5.

d. Combined cycle gas plant with CF = 0.5.

e. Gas-ﬁred combustion turbine with CF = 0.2.

f. SIGT gas turbine with CF = 0.4.

g. New hydroelectric plant with CF = 0.6.

h. Wind turbine costing $800/kW, CF = 0.37, O&M = 0.60¢/kWh

3.7 Consider the following very simpliﬁed load duration curve for a small utility:

9000800070006000500040003000200010000

100

200

300

400

500

600

700

800

900

1000

Hours/year

Demand (MW)

8760 hr/yr

Figure P3.7

a. How many hours per year is the load less than 200 MW?

b. How many hours per year is the load between 300 MW and 600 MW?

c. If the utility has 500 MW of base-load coal plants, what would their

average capacity factor be?

d. How many kWh would those coal plants deliver per year?

3.8 If the utility in Problem 3.7 has 400 MW of peaking power plants with the

following “revenue required” curve, what would be the cost of electricity

(¢/kWh) from these plants when operated as peakers?

166 THE ELECTRIC POWER INDUSTRY

1.00.90.80.70.60.50.40.30.20.10.0

100

150

200

250

300

350

400

450

500

Capacity Factor

$/YR-KW

Figure P3.8

3.9 Consider screening curves for gas turbines and coal-ﬁred power plants given

below along with a load duration curve for a hypothetical utility:

1.00.90.80.70.60.50.40.30.20.10.0

100

150

200

250

300

350

CAPACITY FACTOR

$/YR-KW

COAL

GAS

TURBINE

1009080706050403020100

% OF YEARLY HOURS

million kW

Figure P3.9

PROBLEMS 167

a. For a least-cost combination of power plants, how many MW of each

kind of power plant should the utility have?

b. What would the cost of electricity be ($/kWh) for the gas turbines sized

in (a)?

3.10 The following table gives capital costs and variable costs for a coal plant,

a natural gas combined-cycle plant, and a natural-gas-ﬁred gas turbine:

COAL NG CC NG GT

Capital Cost ($/kW) $ 1,500.00 $ 1,000.00 $ 500.00

Variable Cost (¢/kWh) 2.50 4.00 8.00

The utility uses a ﬁxed charge rate of 0.10/yr for capital costs. Its load duration

curveisshownasfollows.

800070006000500040003000200010000

1000

2000

3000

4000

5000

6000

7000

8000

HRS/YR

DEMAND (MW)

Figure P3.10

a. Draw the screening curves (Revenue Required $/yr-kW vs hr/yr) for each

of the three types of power plants.

b. For a least-cost combination of power plants, how many MW of each

kind of power plant should the utility have? If you plot this carefully, you

can do it graphically. Otherwise you may need to solve algebraically.

c. Estimate the average capacity factor for each type of power plant.

d. How many MWhr of electricity would each type of power plant generate

each year?