Download SSR2006_ Effects of Climate Change_Toole

Effects of Climate Change on California Energy Security1
L. Toole, S. Flaim, S. Fernandez, and J. Bossert Los Alamos National Laboratory, NM US
B. Bush, National Center for Atmospheric Research, CO US
B. Neenan, UtiliPoint Inc., NY US
Abstract
Sound energy planning requires an understanding of the primary external drivers that will impact
national futures over the next 25 years. One of the principal impacts may be from climate
variability – induced by both natural cycles and anthropogenic forcing. The Southwestern United
States is a case in point. This semi-arid region has seen its water and landscape resources
threatened by extended drought, and it will remain in a precarious position – projected to
increase its population by 50% over the next 25 years and highly susceptible to the vagaries of
climate change. This study, performed at Los Alamos National Laboratory, focused on climate
change impacts that may occur within the regional surrounding California prior to 2035. Results
from the Hadley CM-3 climate model were used as drivers for a comprehensive electric energy
model of the California regional network. Approximately 57 Gigawatts (GWe) of new generation
capacity will be required starting in 2022 due only to population growth and economic
expansion. Additional generation capacity will be required starting in 2015 due to climate change
to meet higher electricity demand. To pass through or mitigate such effects to the consumer,
Federal and state government will require new regulatory and pricing policies. This paper
discusses the adaptive changes required to address regulatory, social and physical security issues
related to climate change. 1Work supported by The U.S. Dept. of Energy.
Conclusions
Figure 1 summarizes projected drag on the California Gross State Product (GSP). Units shown as
“Cumulative $Millions” are US Dollars, valued in the year 2000.
Cumulative $Millions
FIGURE 1. DRAG ON CALIFORNIA GSP DUE
CLIMATE CHANGE.
400,000
300,000
200,000
100,000
0
2010
2015
2020
2025
2030
2035
Year
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Cumulative costs of climate change due to increased electric demand, construction and operation
of new generating capacity plus consumer expenditure impacts may rise to $400 billion (US
dollars) by 2035. For comparison, California’s GSP is estimated to be $3.4 trillion (US dollars)
in 2035 [1]. As a net economic effect, climate change has the potential to suppress state GSP by
0.5 to 2% per year.
11.2 GWe of additional generation capacity costing $80 ($US Dollars) billion per year (including
fuel costs) will be required starting in 2015 to meet higher demand due to climate change.
Electricity prices are projected to increase 12% in real terms or $122 (US dollars) per megawatthour in 2035 without implementation of mitigating strategies. Table 1 outlines possible
interactions of major stakeholder groups who can influence the outcome of such strategies in
California and their impact bound.
TABLE 1. ADAPTATION STRATEGY, STAKEHOLDER
PARTICIPANT AND IMPACT BOUND.
Due to the disproportionate effect of each strategy’s mix of capacity and costs, consumer rates
may be affected more or less favorably. “$/MWh” values shown in Table 1 are intended to be
illustrative only and refer to average bulk power rates calculated for California in 2035. To
simplify these comparison, each strategy is assumed to be implemented as a standalone program,
not in combination with others listed. This paper discusses each strategy, the likely factors
needed for successful mitigation and bounding estimates of their impact.
Assumptions and Method
Analytical models employed to examine the effects of climate change are usually macroeconomic “top-down” and technology-based “bottom-up” approaches. Each technique has its
benefits and limitations. “Top-down” models, for example, are unable to effectively reflect the
“no-regret” potential of technology-related measures. Conversely, “bottom-up” approaches
usually fail to reflect the full effects of more general parameters, such as the influence of markets
and organizational measures, or of learning. These differences can produce substantially different
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results, with “bottom-up” models generally leading to lower costs than “top-down” models. The
value of combining the two approaches is increasingly being accepted – although it is still rarely
applied. This study includes hybrid techniques of both approaches.
A primary source of publicly available information is the California Energy Commission’s
(CEC) long-term planning report issued in 2004 [2]. Assumptions regarding forecasted statewide
electric demand projected to 2035 were utilized. CEC’s nominal demand case was chosen for
this study, since it offers moderate increases consistent with recent trends. It is driven only by
population and economic expansion. This report also provides key information regarding
installed and retired electric generation capacity and system reserve margin.
Reserve margin is an important study assumption. It is defined as the amount of excess
generation capacity available above peak demand, irrespective of unplanned outages. Traditional
utility planning margins are 20-25% but a simple linear projection of California’s reserve
suggests margins falling below 10% after 2025. In this study reserve was assumed to be
stabilized at 10% after 2025. This could be achieved through a number of measures such as
active conservation and judicious use of imported power.
Two cases were created for this study: Case A and B. Case A corresponds to the expected utility
plan without climate change. Case B describes an “incremental” utility plan with climate change.
Formulation of Case B was accomplished as follows. Temperature-electric demand correlations
for six climate zones were performed using 2000 data series obtained from various sources. The
cities of San Diego, Sacramento, Redding, Glendale and Modesto were included in this sample.
Figure 2 illustrates a sample correlation obtained for Sacramento.
FIGURE 2. CORRELATION OF TEMPERATUREDEMAND FOR SACRAMENTO, CA.
Sacramento Demand Versus Temperature
3000
3.5% per
71 MW/degree
degree F
Excess Demand (MW)
2500
2000
Raw
1500
Normalized
Poly. (Normalized)
1000
2
y = 0.6385x + 21.383x + 227.3
R2 = 0.9244
500
0
0
20
40
60
80
100
120
Excess Temperature (F)
Figure 2 indicates that Sacramento exhibits a 3.5% rise in demand per 71 Megawatt (MWe). In
addition, the correlation is relatively linear. “Excess temperature” is defined as samples above 65
degrees Fahrenheit. “Excess demand” is defined as samples above 770 MWe. Average summer
temperatures in California are projected to increase between now and 2035 by 3 degrees
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Fahrenheit with an increasing frequency of annual heat wave days (100 vs. 140), as forecasted by
the Hadley CM-3 A1 scenario. The CM3 model is driven with a moderate 1% annual increase in
greenhouse gas concentrationBest average fit for all climate zones was found to be 3% change or
100 MW per degree rise.
The CEC report identified gas fired HSRG1 generating units as preferred base-to-intermediate
load additions. In both Case A and B, multiple units of this type are assumed to be added, 540
MWe rating. To maintain near-optimal capacity mix, a small fraction of gas-fired combustion
turbine (CT) units are also assumed to be added, 110 MWe rating. Table 2 summarizes
incremental capacity additions for Case B reported at 5-year intervals. The total capacity added is
11.2 GWe.
TABLE 2. SUMMARY OF CASE B CAPACITY (UNITS
ADDED AT 5TH YEAR INTERVALS).
All new generating units are assumed to be located at existing sites i.e. not “green field” sites. In
addition a fraction (5 of 15 HSRG generating units) are assumed to be located outside California
at existing sites. Upgrades to high-voltage transmission lines and natural gas pipelines serving
these sites would be required. This approach is preferred because it minimizes environmental
impacts due to new construction.
Table 3 summarizes the results of this analysis. All price factors are referenced to US dollars,
valued in the year 2000.
TABLE 3. SUMMARY OF CASE B ELECTRICITY PRICE
FACTORS ($PER MWH, US DOLLARS).
Capital, O&M (operations & maintenance) and fuel costs were accumulated for each 5th year
interval from 2015 to 2035. Capital costs are attributable to construction of in state and out-state
generating units, transmission lines and pipelines. O&M costs are attributable to maintenance
1
Heat recovery steam generator (combined cycle)
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and non-consumable items for generating units. Fuel costs are attributable to consumption of
natural gas by HSRG and CT units.
As shown in Table 3, the weighted price in 2015 of electricity is approximately $70.1 (US
dollars) per megawatt-hour2. A fraction of this price will be maintained by generating units,
which operate throughout the study period. Another fraction of this price will be affected by
generating units, which are retired. A third fraction of this price is determined by new generating
units. Values shown in the last row correspond to weighted prices, which includes costs
attributable to generating units maintained in stock, retired or added.
For reference, the average bulk price of electricity reported by the CEC in 2000 was $104 (US
Dollars) per megawatt-hour. To calculate “incremental” effects for Case B, $38.0 (US Dollars)
per megawatt-hour was removed from the 2000 price to account for embedded transmission and
distribution (T&D) costs not attributable to climate change. The result, “Base price” is shown in
the fifth row. It represents the cost of generating plant existing prior to 2015. The “Weighted
price” shown in the sixth row contains T&D costs which can directly attributed to climate
change.
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Possible Adaptation by Utilities, Consumers and Government
Adaptation to climate change in California represents a microcosm of possible responses to the
global problem. For the purposes of this study such responses can be realized by the interaction
of three key stakeholder groups: utilities, regulatory agencies, and electric consumers. A map
outlining the potential interaction of these strategies is shown in Figure 3.
FIGURE 3. CLIMATE CHANGE ADAPTATION STRATEGIES3.
11.2 GWe IMPACT
REQUIRED
NO ACTION
EXCESSIVE
ENERGY PRICES
> $120/MWh
ACTIVE CONSERVATION
MODERATE
REDUCTION
LIKELY, PRICE
INCENTIVES
NEEDED
IMPORT OUT--STATE
GREENFIELD IN-STATE
ADVERSELY
AFFECTS POWER
AVAILABILITY
AND PRICE
PASSIVE
CONSERVATION,
ECONOMIC
DRAG
(SHORTFALL
)
SITES LIMITED
BY AIR QUALITY
AND
TRANSMISSION
CAPACITY
NON GREENFIELD,
PLANT EFFICIENCY
GAINS, OTHER
COSTLY
SUPPLY OPTIONS
(SHORTFALL
)
MODERATE
ENERGY PRICES
$100-115/MWh
(SHORTFALL)
Strategies shown in Figure 3 imply an expected order of implementation e.g. Active
Conservation may be attempted prior to Import Out-State. It is also likely that several strategies
will be implemented in parallel to reduce the risk of shortfall.
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Higher electrical demand will increase the likelihood that California utilities and regulators
would select a dual path approach: a) construction of additional generating capacity as early as
2015 and b) authorization to pass significant increases in real costs of electricity to the consumer.
Demand reductions achieved by conservation strategies may not be significant until after plant
construction is started. Therefore, utilities will probably choose an aggressive construction
program as their primary strategy.
Three sections, which follow, discuss adaptation issues related to 1. Conservation, 2. Technology
and 3. Regulatory Policy. There are significant overlaps in implementation among these
strategies. Therefore, it is difficult to estimate net impacts over the extended timeframe of this
study. The authors have attempted to provide impact bounds only for the purpose of examining
decision factors relevant to the climate change debate.
1.Conservation Strategies
Both passive and active electricity conservation is considered a viable response to climate
change. Conservation is defined as changes in the level and pattern of electricity usage, from
levels the customer typically or historically has consumed. This may occur in response to
incentives specifically design to accomplish that result (active) or by voluntary means (passive).
“Price elasticity” is a term often applied in the debate over conservation alternatives. It is defined
as the percentage change in quantity demanded in response to a percentage change in price.
Although the price elasticity of electricity in California has been the subject of rigorous debate,
Bernstein and Griffin [3] suggested that price elasticity exhibits both a near term value and a
long-term value. The recommended near term value of -0.2 represents a set of limited, voluntary
options to adjust to rapid “spikes” in the price of electricity. A long-term value of -0.7 reflects
wider conservation efforts as the population adjusts to the higher real cost of electricity.
Assuming a medium term elasticity of -0.4 for the time period of this study, up to 5% reductions
in demand in response to a 12% increase in the real cost of electricity by the year 2035 could
occur. Applying this reduction to the 88 GWe demand projected with climate change, a
reduction of less than 6 GWe through passive and active conservation efforts would occur.
Traditional utility rates are not time-differentiated in a way that links consumer prices with the
actual cost of supply. They use an average representation of supply costs. These supply costs are
highly variable over the hours of the day, and seasons of the year. As a result, consumption
decisions do not reflect the marginal value to the customer of electricity. At times, the price is
below the marginal supply costs, and consumption is too high relative to its value to customers.
At other times the rate is higher than the supply costs, resulting in under consumption.
Advances in metering information technology have opened up new avenues for delivering to
customers up-to date prices which they can combine with real-time meter reads to implement
conservation strategies. The introduction of non-intrusive control devices and systems for their
remote operation offers new ways to bring demand under control. These new ways are potentially
cost-effective and offer minimal inconvenience to customers. California has already established a
goal of bringing 7% of electric load into an active conservation program by 2007. This quantity
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corresponds to about 3 GWe of reduction. If program participation can be doubled through
aggressive actions taken by all stakeholders, then active conservation could reduce rate impacts
attributable to climate change by 20%. It also can achieve additional economic and
environmental benefits not estimated in this study. This strategy yields average rates of
approximately $100 (US dollars) per megawatt hour in 2035.
2. Technology Strategies
Over the next 50–100 years, the entire energy supply system will be replaced at least twice.
Therefore, replacement of existing technology stock may be an important strategy. Promising
approaches to mitigate climate change impacts in California (not ordered according to priority)
include more efficient conversion of fossil fuels; switching to low-carbon fossil fuels (such as
natural gas); switching to nuclear energy; and switching to renewable sources of energy [4].
The theoretical potential for efficiency improvements is large and current energy systems are far
from the maximum theoretical (ideal) levels suggested by the second law of thermodynamics.
Inertia as well as social behavior, vintage structures, costs, lack of information and know-how,
and insufficient policy incentives must be overcome before a portion of this potential can be
realized. One study suggested the efficiency of electricity generation will increase from the
present world average of about 30% to more than 60% between 2020 and 2050 [5]. Presently, the
best available coal and natural gas plants achieve efficiencies of 45% and 52%, respectively [6].
While the costs of these efficiencies are influenced by many factors, advanced technologies exist
that are cost-effective.
If high-efficiency HSRG gas-fired turbines are assumed to be installed, using natural gas as their
primary fuel, such power plants have the highest conversion efficiencies of all fossil fuels—
presently 45% in the short term and 55% and more in the longer term. Combined cycle plants
have approximately 30% lower investment costs than a conventional gas steam counterpart,
although specific electricity costs will depend on the usually higher fuel costs of natural gas
compared to coal. On the other hand, combined cycle plants are more costly than less efficient
combustion turbines, although they have shorter installation times [7]. Unfortunately, efficiency
gains will offset costs of fuel but they may not offset the need to build plant capacity. Assume the
same rated stock of units must be built i.e. 11.2 GWe. A moderate efficiency gain may still occur,
say from 45% to 60%, therefore the fuel component of consumer rates can be expected to
decrease in rough proportion. This strategy yields average rates of approximately $115 (US
dollars) per megawatt hour in 2035.
Another Technology strategy of interest is importation of electricity from out-state sources. To
supply 25 percent of the peak demand not including climate change requires California to import
23 GWe [8]. The entire transmission capacity cannot be utilized simultaneously during the peak
hours. Assume at a minimum that 15 percent reserve transmission margin is required, California
must add about 8 GWe to the existing transmission interconnection capability over the next three
decades. This addition would be equivalent to increasing the current interconnection capability
by 50 percent over this period. The likelihood of such upgrades occurring in a timely manner is
relatively low, given conflicting environmental and policy constraints within the state.
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Additionally, California’s ability to import a significant fraction of the 11 GWe requirement
attributable to climate change is also uncertain4. A bounding estimate of 4 GWe imported to
serve additional demand due to climate change is optimistic, given comments above.
3. Regulatory Policy Strategies
The International Energy Agency, IEA, has documented more than 750 regulatory policies and
measures in effect around the world to reduce greenhouse gas emissions and to mitigate the
effects of climate change [9]. Although the inventory is comprehensive in scope, it contains only
a partial list since nuclear development programs, market deregulation; and broad pollution
control measures could have substantial climate impacts. The list is only a partial inventory
because it includes actions taken by national (federal) levels of government, not actions taken by
lower (state, regional, and local) levels of government.
Regulatory efforts are usually intended to establish an equitable, intermediate path between two
extremes i.e. allowing total pass through of capital and operating costs and stabilization of the
current real cost of electricity. Therefore, probable outcomes are:



A moderate rise in the real cost of electricity
A increase in conservation efforts that may reduce total
required capacity or
Continued regulatory tensions to allocate the costs of required
capacity
California’s projected population growth combined with increasingly restrictive environmental
covenants affecting power plant siting and operations will require a combination of regulatory
strategies to achieve the goal of stabilizing climate change impacts. Policy processes, (strategic
planning, disseminating information, and consultation), fiscal instruments (taxes, tax exemption
or credit, incentives, subsidies), regulatory instruments (mandates, standards and regulations)
may be implemented. The overall result is that resources are not used optimally, which economist
refer to as “deadweight losses”, an indication of inefficiency of resource utilization. More
poignantly, inefficient pricing results in the need to build generation and delivery capacity to
serve demands for only a few hours a year. Efficient pricing, e.g. active conservation would
reduce those peak needs, and reduce the amount of additional capacity required to cope with
climate change. Moreover, there would be cascading benefits in the form of lower electricity
prices and lower water and other resource uses that translate into improvements in state GSP, and
reduced environmental emissions.
The authors’ estimate for capacity reductions under these circumstances is on the order of 5%
or less than 5 GWe, given price elasticity assumptions outlined under conservation strategies.
The underlying assumption is that regulatory mechanisms, which accomplish such changes, are
The capacity of a single circuit 500-kilovolt transmission line is 2-3 GWe. With 15% reserve
margin , this provides on average, 2 GWe delivered capacity. Two or more circuits can be
installed in a common corridor to increase capacity.
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within acceptable consumer tolerance. This strategy may result in changes to the equity structure
of utility rate base, affecting the percentage contribution from each customer class. Supply (not
demand) is reduced, providing yet another price trajectory in terms of consumer rates. A
downside effect is the potential to reduce supply reliability below levels acceptable to many
consumers. This strategy yields average rates of approximately $115 (US dollars) per megawatt
hour in 2035.
Future Research
This study was performed to identify adaptive changes needing attention during the global debate
over climate change. Although California impacts are presented in terms of bounding estimates,
they provide an early indication of the decisions to be made in the areas of consumer response,
technology and regulatory policy. The methodology described is intended to approximate factors
that utility planners must face during episodic changes in climate. However, there are a myriad of
issues needing further study such as:




Likely availability of large quantities of natural gas for in state
generating units
Ability to overcome regional constraints on water for cooling
Ability to maintain existing north-south transmission
bottlenecks such as Path 15
Interaction of drought-induced constraints within adjacent
states especially imports and hydro production
Additional statistical analysis of historical relationships between energy demand and temperature
variations will aid more sophisticated modeling and analysis. Improved estimates will allow
stakeholders to begin the difficult process of planning with certainty for eventual impacts to
infrastructure systems esp. electric grids, which support basic social and economic activities.
References
[1] U.S. Department of Energy, Energy Information Administration, Office of Integrated
Analysis and Forecasting. Annual Energy Outlook 2003 With Projection to 2025. January 2003.
DOE/EIA-0383 (2003). Reference Case Forecast. [http://www.eia.doe.gov/]. Growth rates
documented here were used to extrapolate California’s 2005 GSP, $1.4 trillion (US Dollars).
[2] CALIFORNIA’S ELECTRICITY GENERATION AND TRANSMISSION
INTERCONNECTION NEEDS UNDER ALTERNATIVE SCENARIOS, California Energy
Commission, March 2004 Report 700-04-003, pages 11-21. [http://www.energy.ca.gov/]
[3] Bernsein, M.A., and Griffin, J., “Regional Differences in the Price-Elasticity of Demand for
Energy”, Rand Corporation Technical Report for the National Renewable Energy Laboratory,
2005.[http://www.nrel.gov/index.html]
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[4] IPCC Second Assessment Report 1995- The Science of Climate Change.(including Summary
for Policymakers). Report of IPCC Working Group I, 1995. 4.1.3
[5] Ref 4, 4.1.3.1
[6] Climate Change 1995- The Economic and Social Dimensions of Climate Change. (including
Summary for Policymakers). Report of IPCC Working Group III, 1995. 19.2.1
[7] Ref 6, 19.2.1.1
[8] Ref. 2, pages 25-27.
[9] “Dealing with Climate Change: Policies and Measures in IEA Member Countries, 2002
Edition, IEA, 2002, OECD, 2, rue André-Pascal, 75775 Paris cedex 16, France
Biography
G. LOREN TOOLE serves as a Project Leader in the Infrastructure Assurance Program for Los
Alamos. Mr. Toole received his B.S. and M.S. degrees in Electrical Engineering from Georgia
Tech in 1976. He has authored or co-authored over 35 journal and other publications. His
industrial experience includes over 20 years in the promotion of utility-related projects notably
cogeneration and renewable power. His research interests include electric demand-supply
strategies and distributed generation.
SILVIO FLAIM received his PhD (1978) in Resource Economics, Quantitative Methods and
Tax Law from Cornell University in 1978. His dissertation research was funded by the US Senate
Special Subcommittee on Integrated Oil Operations. Dr. Flaim has twenty-five years experience
leading large economic and environmental assessments of the energy industries and energy
infrastructures. He has substantial experience providing testimony before judicial, regulatory and
administrative authorities in national and international forums including various state courts, US
Federal District Courts and the US Supreme Court. Presently, Dr. Flaim is team leader for
Economics and Social Network Theory.
STEVEN J. FERNANDEZ received a B.S. in Chemical Physics from Centre College of
Kentucky in 1975, M.S in Chemical Engineering from Washington State University in 1977, and
a Ph.D. in Chemistry from the University of Idaho in 1984. Fernandez leads the Energy and
Infrastructure Analysis Group at Los Alamos National Laboratory. Before joining the Los
Alamos National Laboratory, he held senior National Security management positions at the Idaho
National Engineering and Environmental Laboratory, most recently as the program manager of
the National SCADA Test Bed.
JAMES BOSSERT received his Ph.D. in the Atmospheric Sciences from Colorado State
University in 1990, and his B.S. in the Atmospheric Sciences from the University of California at
Davis in 1982. He has authored or co-authored over 50 journal and other publications. serves as
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Deputy Division Leader of the Earth and Environmental Sciences Division at Los Alamos
National Laboratory. His research interests include the measurement, analysis and modeling of
flow and dispersion in mountainous and urban terrain, regional climate simulation, and wildfire
behavior modeling.
BRIAN W. BUSH received a B.S. in physics at the California Institute of Technology in 1985
and a Ph.D. in theoretical physics at Yale University in 1990. He is currently a technical staff
member in the Energy and Infrastructure Analysis Group at Los Alamos National Laboratory.
His work there has focused on developing computer simulations for complex phenomena
such as interacting critical infrastructures. He has recently began efforts to connect simulations
of weather and climate to impact models for energy and infrastructure networks.
BERNARD NEENAN has spent the last 20 years studying and reconciling electricity markets
from the perspective of suppliers, regulators, policy makers, and consumers. His utility
experience includes administering a traditional, cost-based electric and gas rate book, developing
and evaluating demand-side management programs, and designing and testing innovative retail
pricing plans. He was recognized by EPRI’s Innovator’s Award program for his contributions to
improving retail electricity pricing.
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