Cost Allocation
Cost Allocation
Cost Allocation
Governor
TRANSMISSION BENEFIT
QUANTIFICATION, COST ALLOCATION
AND COST RECOVERY
Prepared For:
California Energy Commission
Public Interest Energy Research Program
Prepared By:
Lawrence Berkeley National Laboratory
Prepared By:
Vikram Budhraja, John Ballance, Jim Dyer, and Fred Mobasheri
Electric Power Group, LLC
Pasadena, California
Prepared For:
Public Interest Energy Research (PIER)
California Energy Commission
Jamie Patterson
Contract Manager
Mike Gravely
Program Area Lead
ENERGY SYSTEMS INTEGRATION
Mike Gravely
Office Manager
ENERGY SYSTEMS RESEARCH
Melissa Jones
Executive Director
DISCLAIMER
This report was prepared as the result of work sponsored by the California Energy Commission. It does not necessarily represent the views of the
Energy Commission, its employees or the State of California. The Energy Commission, the State of California, its employees, contractors and
subcontractors make no warrant, express or implied, and assume no legal liability for the information in this report; nor does any party represent
that the uses of this information will not infringe upon privately owned rights. This report has not been approved or disapproved by the California
Energy Commission nor has the California Energy Commission passed upon the accuracy or adequacy of the information in this report.
ACKNOWLEDGMENTS
The PIER Research Manager for this project was Virgil Rose. A Technical Advisory
Committee (TAC) was established to review research results and offer guidance to the
research team. Two in-person TAC meetings were held along with other written and
oral communications as needed and appropriate. The Technical Advisory Committee
consisted of:
o Dede Hapner, Vice President, FERC and ISO Relations, Pacific Gas & Electric.
o Les Starck, Director of T & D Business Unit, Southern California Edison.
o Caroline Winn, Director of T&D Asset Management, San Diego Gas & Electric.
o Sean Gallagher, Director of Energy Division, California Public Utilities
Commission.
o Steve Ellenbecker, Energy Advisor to Wyoming Governor Freudenthal.
o Jim Bushnell, Research Director, UC Energy Institute.
The research team and key areas of research responsibilities were as follows:
o Project Management and Outreach – Joe Eto and Vikram Budhraja.
o Review of Technologies – John Ballance, Jim Dyer, and Jim Terpening.
o Industry and Regulatory Changes – Vikram Budhraja, John Ballance and Jim
Dyer.
o Review of other Regions and Industries – Alison Silverstein.
o CA ISO Transmission Planning Process and Comparison of ISO’s -- John Ballance
and Jim Dyer.
o Benefit Quantification, Cost Allocation, Cost Recovery – Vikram Budhraja and
Fereidoun (Fred) Mobasheri.
The research team wishes to thank the Virgil Rose, PIER Project Manager for his guidance,
support and encouragement throughout the project and the TAC members for their useful
insights to sharpen the research focus.
Budhraja, Vikram, John Ballance, Jim Dyer, and Fred Mobasheri, (Electric Power Group, LLC), 2008.
Transmission Benefit Quantification, Cost Allocation and Cost Recovery. California Energy Commission,
PIER Energy-Related Environmental Research Program. CEC-xxx-xxxx-xxx
Preface
The Public Interest Energy Research (PIER) Program supports public interest energy
research and development that will help improve the quality of life in California by
binging environmentally safe, affordable, and reliable energy services and products to
the marketplace.
The PIER Program, managed by the California Energy Commission (Energy Commission),
conducts public interest research, development, and demonstration (RD&D) projects to
benefit California.
The PIER Program strives to conduct the most promising public interest energy research
by partnering with RD&D entities, including individuals, businesses, utilities, and public
or private research institutions.
PIER funding efforts are focused on the following RD&D program areas:
Benefit Quantification and Cost Allocation/Recovery Research Project for Transmission is the
final report for the Cost Allocation Research project Contract Number 500-05-001, work
authorization number MR0606/MR-051 conducted by Consortium for Electric Reliability
Technology Solutions/Electric Power Group, LLC. The information from this project contributes
to PIER’s Energy Systems Integration Program.
For more information about the PIER Program, please visit the Energy Commission’s
website at www.energy.ca.gov/pier or contact the Energy Commission at 916‐654‐5164.
i
Table of Contents
ii
6.6. Delphi Method ................................................................................................................ 46
6.7. Resource Portfolio Analysis .......................................................................................... 47
6.8. Recommendation on Use of Research Results ........................................................... 49
6.9. Use of Improved Benefit Quantification Methods .................................................... 50
6.10. Recommendation on Additional Research ................................................................. 50
7.0 Cost Allocation And Cost Recovery ................................................................................. 53
7.1. Framework for Cost Allocation and Cost Recovery.................................................. 53
7.2. Cost Recovery ................................................................................................................. 54
7.3. Multiple Participants and Jurisdictions Project ......................................................... 54
7.4. Example of Auction Approach for Cost Allocation .................................................. 55
8.0 Framework For Incorporating Benefit Quantification Enhancements In
Transmission Planning ....................................................................................................... 59
9.0 Project Outreach and Briefings .......................................................................................... 61
10.0 Utilization of Research Results .......................................................................................... 63
11.0 Key Conclusions And Research Recommendations....................................................... 65
11.1. Recommendations for Benefit Quantification ............................................................ 65
11.2. Recommendations for Cost Allocation and Cost Recovery ..................................... 66
Glossary ............................................................................................................................................... 68
Bibliography ....................................................................................................................................... 69
Appendix A, Literature Search and References
Appendix B, Benefit Assessment Methodologies
Appendix C, Cost Allocation Methodologies and Cost Recovery
Appendix D, Technology Options and Implications and Their Impacts
Appendix E, Alternative Approaches Utilized for Transmisison Project Approvals—
Transmission Planning and Review of Industry and Regulatory Changes
Appendix F, Existing Process for Transmission Project Approvals and Case Histories
Appendix G, Fact Sheet—Benefit Quantification and Cost Allocation Research project
Appendix H, Comparison of Electric Transmission with Gas and Telecommunications
Industries
iii
List of Figures
Figure 8. Framework for Use of Benefit Quantification for Project Cost Effectiveness and Cost
Allocation ................................................................................................................................ 55
iv
Abstract
This project was commissioned to perform a scoping study to understand transmission benefit
quantification, cost allocation, cost recovery, and project approval processes with a particular
focus on recommending new methods for improved benefit quantification and cost allocation
that better fits the new electric industry structure and planning environment.
Use a social rate of discount to calculate the present worth of benefits of a new
major regional transmission projects rather than utility cost of capital to recognize
the public good and long life attributes of transmission.
Calculate explicitly the fuel diversity benefit from integration of large renewable
resources.
Utilize a stakeholder consensus approach, such as Delphi method, to assign value
to some of the strategic benefits such as risk mitigation against extreme reliability
and market volatility events.
Initiate research into (a) dynamic analysis to evaluate the impact on generation
expansion in exporting regions (b) resource portfolios analysis to assess
performance of different combination of demand response, renewables and fuel
based generation, transmission and energy conservation programs, and (c)
quantification of extreme event benefits (Insurance Value) in terms of reliability
and reduced market volatility to estimate the benefits from the low
probability/high impact events.
v
Executive Summary
This project was commissioned to perform a scoping study to understand transmission benefit
quantification, cost allocation, cost recovery and project approval processes with a particular
focus on recommending new methods for improved benefit quantification and cost allocation
that better fits the new electric industry structure and planning environment.
There is general policy consensus on the need for new transmission projects to advance the
policy objectives of renewables integration, reliability management, efficient market operations,
interconnect new load and generators, reduce transmission congestion and bottlenecks, and
expand access to regional power markets. Historically, major transmission projects were
sponsored and owned by utilities and generally proposed as part of new power plant
development by integrated utilities.
This landscape has changed with the separation of generation and transmission assets and
separation of transmission operations from ownership by shifting the responsibility of
transmission operations from utilities to Independent System Operators/Regional Transmission
Operators (ISOs/RTOs) such as California Independent System Operator (CA ISO). These
changes in industry structure, operations, and planning impact how new transmission projects
are planned, evaluated and approved. Approval of proposed major regional transmission
projects in this new environment has proved to be challenging, witness the difficulty in moving
forward with several California based projects such as the Palo-Verde Devers No.2 line,
Rainbow-Valley line and others. This difficulty has brought into focus the need for research on
benefit quantification and cost allocation methods to help with the approval of major regional
transmission projects.
Utility efforts to develop new transmission projects that are local in nature, address well
documented reliability needs, and are required for interconnecting new load or generation are
generally supported and have been gaining regulatory approvals and stakeholder support.
However, major regional transmission projects that involve multiple jurisdictions and utilities
and are needed for integrating remote resources, reducing costs, improving market operations,
providing long term strategic benefits and improving operating flexibility, don’t have a clear
path forward. For a major regional transmission project involving multiple jurisdictions and
utilities to go forward, there needs to be a consensus on benefits, costs, and allocation of benefits
and costs that can be embraced by stakeholders and policy makers.
The research focus was to identify different benefit streams, outline methodologies to quantify
benefits including strategic benefits that have in the past been handled qualitatively, and outline
approaches for assessment of benefits and assignment of benefits that could be factored into
project cost allocation and cost recovery decisions of major transmission projects that may
involve multiple utilities and regulatory jurisdictions. The research is not directed at seeking
consensus among stakeholders or recommending cost allocation methodology for any specific
project but to serve as an analytic framework that could be adapted for use for major
transmission projects.
1
As part of the research, a review of other industries, planning methods, technology and
regulatory issues was also conducted. Key findings are summarized below:
2
o Models are data intensive—requiring assumptions about future generation mix,
fuel prices, and transmission network.
o Models are static with no feedback—they assume no change in investment for
new generation resulting in a zero sum benefit distribution game, for example,
Devers-Palo Verde No. 2.
o Extreme market volatility and multiple contingency system events which can be
very costly and risky to society are not captured in current models.
2001 California market dysfunction—$20–40 billion.
2003 Northeast Blackout—$5–10 billion.
2. CA ISO TEAM Methodology is Comprehensive and Incorporates Many Enhancements
to Traditional Production Simulation Analysis
o CA ISO developed the Transmission Economic Assessment Methodology
(TEAM) for benefit analysis of major transmission projects.
o In the TEAM approach, benefits are measured separately for consumers,
producers, and transmission owners in different regions.
o TEAM incorporates bid-cost markup in the analysis to reflect functioning of
markets
o Uncertainties are considered through a wide range of future system conditions—
dry and wet hydro, demand scenarios, gas price scenarios, generation addition
scenarios.
o Expected range of benefits is computed. Insurance and strategic value of
transmission is discussed.
o CA ISO TEAM methodology is recognized as progressive and path breaking.
3. Research identified several areas that are amenable to advancement in existing benefit
quantification methods as well as quantification of strategic benefits including:
o Use a social rate of discount to present worth benefits rather than utility cost of
capital.
o Quantifying fuel diversity benefit by taking into account the price elasticity of
natural gas.
o Application of Delphi or other stakeholder consensus generation methods to
quantify benefits of mitigating low probability high societal impact events such
as major blackouts and market dysfunctions.
o Application of dynamic analysis.
o Application of portfolio analysis methods commonly used in the financial
services industry.
o Developing model based techniques to quantify extreme event benefits.
3
4. With acceptance by regulators and policy makers, CAISO TEAM Method and other
methods in use could be augmented to recognize additional strategic benefits in the
following three areas
o Public Good
Use a social rate of discount to calculate the present value of benefits for the new
transmission project.
o Fuel Diversity
Include the benefit from a potential decrease of natural gas price due to the
construction of a new transmission project that integrates a significant amount of
new renewable resources which also reduces natural gas consumption and
emissions.
o Low Probability / High Impact Events
Add risk mitigation benefit to society for low probability/high impact extreme
market events and extreme system multiple contingency events—scenarios or
Delphi method for stakeholder consensus.
5. Supporting Additional Research on Benefit Quantification Methods in the Following
Areas:
o Dynamic Analysis to recognize the impact of new transmission projects on
construction of new generation capacity in exporting regions.
o Portfolio Analysis to assess performance of different combination of demand
response, renewables and fuel based generation, transmission and energy
conservation programs. Portfolio analysis methods are utilized in the financial
industry but research is needed to adapt these techniques to transmission
expansion planning.
o Quantification of Extreme Event Benefits (Insurance Value) in terms of reliability
and reduced market volatility. Quantification methods to be researched include
application of Value at Risk, Option Value, and insurance premium concept.
Reliability benefits can be measured in terms of reducing blackout footprint due
to extreme (N-n) events and societal value of reduced risk and exposure to run
away market prices.
4
1.0 Introduction
California’s more than 31,000 miles of electric transmission lines and 18,170 MW of
interconnection to neighboring states have been critical for efficiently meeting electricity needs
of California consumers with high degree of reliability.
There is general policy consensus that new transmission projects are needed to advance the
policy objectives of renewables integration, reliability management, efficient market operations,
interconnect new load and generators, reduce transmission congestion and bottlenecks, and
expand access to regional power markets. Historically, major transmission projects were
sponsored and owned by utilities and generally proposed as part of new power plant
development by integrated utilities.
This landscape has changed with the separation of generation and transmission assets and
separation of transmission operations from ownership by shifting the responsibility of
transmission operations from utilities to Independent System Operators/Regional Transmission
Operators (ISOs/RTOs) such as CA ISO. These changes in industry structure, operations, and
planning impact how new transmission projects are planned, evaluated, and approved.
Approval of proposed major regional transmission projects in this new environment has proved
to be challenging, witness the difficulty in moving forward with several California based
projects such as the Palo-Verde Devers No. 2 line, Sunrise, Rainbow -Valley, and others. This
difficulty has brought into focus the need for research on benefit quantification and cost
allocation methods to help with the approval of major regional transmission projects.
Utility efforts to develop new transmission projects that are local in nature, address well
documented reliability needs, required for interconnecting new load or generation are
generally supported and have been gaining regulatory approvals and stakeholder support.
However, major regional transmission projects that involve multiple jurisdictions and utilities
and are needed for integrating remote resources, reducing costs, improving market operations,
providing long term strategic benefits and improving operating flexibility, don’t have a clear
path forward. Projects cannot go forward without cost recovery certainty. Cost recovery
certainty requires allocation of costs through tariffs or contracts. For a major regional
transmission project involving multiple jurisdictions and utilities to go forward, there needs to
be a consensus on benefits, costs, and allocation of benefits and costs that can be embraced by
stakeholders and policymakers.
For example, due to lack of local consensus on benefits or cost allocation. San Diego Gas and
Electric’s Rainbow-Valley line was rejected by California Public Utility Commission (CPUC).
Also, Southern California Edison’s (SCE) initial Tehachapi transmission trunk-line proposal for
integration of wind resources and the proposed rate and cost recovery treatment was rejected
by the Federal Energy Resources Commission (FERC) notwithstanding the extensive
stakeholder review process and support from the CPUC, California Energy Commission
(Energy Commission) and CA ISO , although FERC did ultimately approve a hybrid approach
proposed by the CA ISO to address the ratemaking treatment of the trunk-line costs. Most
5
recently, SCE’s proposed Devers-Palo Verde No. 2 to import additional energy into California
was rejected by Arizona’s Public Service Commission in part because the project did not
demonstrate benefits for Arizona.
The Tehachapi Transmission Project to integrate 4,500 MW of renewable wind energy has since
been approved after changes were made to the original filing. The estimated project cost is
$1.8 billion. The key features of this project include:
6
o Multiple benefit streams and beneficiaries with varying timing.
The challenge associated with benefit quantification, cost allocation, and approval of new
transmission projects was recognized in a September 2007 report prepared by The Blue Ribbon
Panel on Cost Allocation 1.
While the wholesale electricity market has changed fundamentally, the framework for
enabling and encouraging investment that will better enable the grid to serve growing
competitive markets has not yet fully emerged. One area still largely unresolved is how
the costs incurred in transmission expansion will be allocated among users. While it is
clear that many traditional cost-allocation approaches are no longer appropriate, new
principles governing the allocation of cost responsibility for new transmission
investment have yet to be fully articulated and implemented.
Traditional approaches for benefit quantification, cost allocation and rate recovery may not be
adequate for justification and development of these transmission projects. This research project
focuses on investigating new approaches for quantification of benefit streams over time that
may better inform project participants, stakeholders, and policymakers on issues related to
project benefits, cost allocation and cost recovery of transmission investments.
1. The Blue Ribbon Panel on Cost Allocation, Sept 2007, A National Perspective On Allocating the Costs
of New Transmission Investment: Practice and Principles, p 1.
7
8
2.0 Research Goals and Objectives
For major regional transmission projects to go forward, there needs to be consensus on benefits,
costs, and allocation of benefits and costs that can be embraced by the multitude of players
impacted. Projects cannot go forward without cost recovery certainty. Cost recovery certainty
requires allocation of costs through tariffs or contracts. This requires an assessment of all of the
benefits, including strategic benefits, and then linking these benefits to beneficiaries. The
assignment of benefits could then be factored into project cost allocation and cost recovery
decisions.
To address these research issues, the project established the following research goals and
objectives:
To achieve goals stated above, the research team carried out review of benefit streams and
benefit quantification methods that have been used in recent transmission projects. The research
has addressed:
o Review and describe the current methodologies being used for cost allocation
and cost recovery of transmission projects.
9
o Develop a framework for linking cost allocation to different types of
transmission projects.
o Summarize alternative models for cost allocation and cost recovery.
The key research result of this project is the development of a framework that could be utilized
to guide cost allocation and cost recovery of transmission projects based on the benefits from
the projects.
There are many key policy questions that came up as part of this research, for example impact
of transmission technologies, impact of industry and regulatory changes, and lessons from
other regions and industries. These topics were reviewed and are discussed in the next Section.
The literature and reference list relied upon in this research project are shown in Appendix A.
Research project Fact Sheet is provided in Appendix G.
10
3.0 Review of Other Industries, Regions, Transmission
Technologies, Industry and Regulatory Changes
3.1. Review of Other Industries
Electric, gas, and telecommunication industries all rely on networks for transport. During the
1990’s, there was a tremendous expansion in telecom transport capacity. Also, gas pipeline
capacity has generally kept pace with demand as a result of new pipelines or expansion of
capacity of existing pipelines. All three industries rely on physical networks for transport, with
the exception that in the telecom industry where wireless technology is utilized for transmission
over short distances. While the 3 industries have a lot in common in terms of planning,
regulation, and network infrastructure, physical attributes of electric transmission networks
result in some important differences.
Electric transmission networks differ in some key respects when compared to other networks
such as gas and telecommunications. The most important difference is property rights—electric
networks are operated as open access networks with financial rights but not physical property
rights. The exception is non-network facilities such as DC lines, radial lines, and point to point
links. In addition, the transport capacity of an AC electric transmission line is often determined
by network characteristics and can change as a result of parallel network flows and system
configuration.
AC transmission lines have other major differences compared to the gas and telecom industries
– flows are not controlled (except by use of phase shifting transformers and other flow control
devices which can be costly), but determined by the physics of the network; transmission
delivery capacity is variable; and the use of transmission is subject to open access rules with
transmission owner (or contract right holder) being able to use the transmission on the same
terms and conditions for access as other market participants.
These differences result in transmission networks being viewed more as a “public good” as
compared to other networks with property rights.
11
• Strong Project Proponent, generally a utility
• Early Involvement by Regulators and Stakeholders
• Collaboration Among Regulators and Stakeholders Around the Region Impacted by
Transmission
• Transparent Planning and Benefit Quantification Process
• Benefit Sharing Among All Affected Participants and Stakeholders
• Predictable Ratemaking Processes for Cost Allocation and Cost Recovery
12
3.5. Implications for Transmission Projects
The structure of the transmission industry has changed in the last few years. Historically,
utilities planned and constructed new transmission lines, obtained regulatory approvals,
invested capital, and received a return on and of the capital by adding the investment to its rate
base after the regulatory approval and collecting a regulatory approved revenue requirement
for the new transmission added to its rate base. In return, the ratepayers of the utility received
all the benefits of this new transmission line such as importing firm capacity and energy,
importing or selling economy energy and the transmission revenue from other utilities using
this new line. The utility that owned the project was involved in planning, design, permitting,
construction, and finally, the operation of the new line.
In the restructured market in California, the CA ISO coordinates the planning with strong
participation and input from the utilities on planning and technical issues and involvement by
stakeholders. The operational control for grid projects is turned over to the CA ISO. Access to
the transmission is open and available to all via FERC approved tariffs. The cost of the new high
voltage transmission project is paid through the Transmission Access Charge by all customers
using the CA ISO grid. All users have the right to use of the new transmission. The high voltage
transmission grid in CA ISO has the characteristic of a “public good,” in that owners of the grid
cannot reserve the use of the grid for their private benefits. The transmission grid provides
social benefits such as reliability, market efficiency, and access to regional markets for all users
through payment of the Transmission Access Charges.
However, there are public goods where consumption by one party creates congestion and
reduced benefit to other parties, such as highways. High voltage transmission is similar to
highways where the use by one party may create congestion at times, but that is not denial of
the usage for others. Everyone will end up paying for congestion or in a word, the benefit
decreases for everyone. Of course a party can reduce the negative impact of congestion by
financial hedging.
Costs of public good projects are spread over all potential users and beneficiaries. This is the
case for highways, dams, flood control, and other public good projects. Under FERC rules,
transmission projects costs are spread over all users or socialized.
13
The research rationale for the use of social rate of discount for new transmission projects is
listed below:
14
tomorrow’s satisfaction. To discount later enjoyment in comparison with earlier ones is a
practice which is ethically indefensible and arises merely from the weakness in imagination.” 4
In the same article, he recommended that the rate of the increase of labor productivity should be
used as the basis for fixing the social rate of discount.
Social rate of discount has been recommended for economic evaluation of public projects in
sectors such as transport, agriculture, water resources development, and land-use. More
recently, there have been many reports and articles on the use of Social Discount Rate for
evaluation of projects for reducing the impact of global warming. This includes a 700-page
report, “The Stern Review: The Economics of Climate Change” in 2006, published by HM
Treasury, London. The Stern Review recommended using 0.1 percent for the social discount
rate and immediately we should invest 1% of the global gross domestic product to reduce the
impact of global warming. 5
Professor William D. Nordhaus of Yale, a noted economist, has a concern with the social
discount rate used by Sir Nicholas Stern, and recommends 3% as discount rate. 6
In a World Bank Policy Research Working Paper, Humberto Lopez estimates the social discount
rate for nine Latin American countries based on the recent track record in terms of growth. 7
These social discount rates are in the 3– to 4–percent range for Argentina, Bolivia, Brazil, Chile,
Columbia, Honduras, Nicaragua, Mexico, and Peru. The analysis is based on: i) pure time
preference rate, ii) the growth rate of per capita income/consumption; and, iii) the elasticity of
marginal utility of income/consumption.
Regarding pure time preference rate, there is long-standing debate in literature. On the low side
Stern Review uses 0.1%. On the other hand, some have suggested to put an upper bound of
3%. 8
Lopez, in his analysis for nine Latin America countries, sets the pure time preference rate at 1%.
Others have also used numbers around 1%. For example, Kula uses 1.2% for the United
Kingdom on the basis of the probability of death in 1975. 9 Scott estimates this rate at about 1.3%
15
based on a century of data on United Kingdom savings behavior. 10 Kula, in his study of the
social rate of discount for India, uses a value of 1.3%. 11 Evans and Sezer use range between 1
and 1.5% for six developed countries (Australia, France, Germany, Japan, United Kingdom, and
United States). 12
There is a good literature review in Humberto Lopez study for the other two elements for
estimating Social Discount Rate, i.e., per capita consumption growth rates and the elasticity of
marginal utility of consumption.
A standard approach taken in much of the existing empirical literature relies on generating the
expectations of the future rate of growth on the basis of past per capita consumption growth
rates.
In a study on the elasticity of marginal utility of consumption in a 2004 study 13, Evans and Sezer
estimate it at between 1.3% and 1.7% in six developed countries and then Evans in a 2005 paper
finds an average of 1.4 % in 20 OECD countries. 14
The techniques and equations similar to the ones used by Evans and Sezer, and Kula are being
used by many economists to estimate the Social Discount Rate for different countries.
David Evans and Haluk Sezer calculate the social discount rate based on 15:
10. A Review of Economic Growth, M. Scott, Clarendon Press, Oxford, United Kingdom, 1989
11. Estimation of a Social Rate of Interest for India, Kula E. Journal of Agricultural Economics,
55(1): 91-99, 2004
12. Social Discount Rates for Six Major Countries, Evans, D. and H. Sezer, Applied Economic
Letters, 11: 557-560, 2004
13. OP.cit
14. The Elasticity of Marginal Utility of Consumption: Estimates for 20 OECD Countries” D.
Evans, Fiscal Studies, 26(2):197-224, 2005
15. A Time Preference Measure of the Social Discount Rate for the United Kingdom, David
Evans and Haluk Sezer. Applied Economics, 2002, 1026 P.34
16
time discount rate
Based on this study, the result for United Kingdom for the period 1967-1997 was SDR =
4.87%.
Erhan Kula, using similar formulation, using the data for the period 1954-1976 for the
growth rate of consumption and the elasticity of the marginal utility consumption and
for using 1946-1970 data the annual average survival probability for United States and
1945-1975 data for Canada estimated SDR for United States = 5.3% and SDR for Canada =
5.2%. 16
16. Derivation of Social Time Preference Rates for the United States and Canada, Erham Kula
Quarterly Journal of Economics 1984, Vol 99, 11 P. 873-882
17
18
4.0 Current Methodologies For Benefit Quantification
4.1. Types of Projects
All transmission projects have attributes that relate to reliability, economics, and operations.
However, the processes that are used for economic evaluation and cost recovery of projects
varies depending on the type of project, and for this purpose, transmission projects are
generally grouped into four categories:
o Requested Upgrades.
o Generation Interconnection.
o Reliability (Base Plan Upgrades).
o Economic (Supplemental Upgrades).
Requested Upgrades are projects that meet specific request or requirements of a customer and
are usually paid by the customer.
Generation Interconnection is to connect a new power plant to the electrical system and is
usually paid by the generator. There may also be need for system upgrade as a new significant
generator is being added to the system.
Reliability projects are transmission improvement that may be required to satisfy the existing or
new reliability criteria. Without such a transmission, there is potential for reliability related
problems and failure to meet the established reliability criteria.
Research indicates that the first three types of projects—requested upgrades, generation
interconnection, and reliability projects have clear drivers or mandates and tend to go forward
with little or no opposition. However, economic projects (including projects that address
specific policy objectives such as renewables integration and debottle-necking) often get
stymied due to different perspectives on need, benefits, and cost responsibility.
The economic projects are proposed to reduce the total cost to society. This includes economic
projects that are used for reducing bottlenecks and congestion, expanding access to regional
markets, meeting policy goals such as Renewable Portfolio Standards (RPS), and providing
insurance against multiple contingencies.
In this research, the emphasis is on methods that can be used to quantify benefits and allocate
costs of Economic (Supplemental Upgrade) transmission projects. The research results are
applicable to other types of projects and to projects that exhibit multiple dimensions of
economics, reliability, and operations.
19
o Extreme Event Benefits.
There are also secondary benefits from new projects. These include: economic development, tax
base increase, use of right-of-way, and impact on infrastructure development. These secondary
benefits are not addressed in this study.
Primary or traditional benefits can be defined as cost reduction, congestion reduction and
expansion of access to regional markets to take advantage of load and resource diversity.
Primary benefits improve network reliability and result in lower cost of energy and capacity
adjusted for transmission losses.
There are also secondary benefits from new projects. These include: economic development, tax
base increase, use of right-of-way, and impact on infrastructure development. These secondary
benefits are not addressed in this study.
The types of benefits of new transmission projects depend on whether the region is at the
generation or exporting end or importing end of the transmission line. Benefits accruing to a
region are a function of location with respect to a transmission line as follows:
20
Access to renewables.
Fuel diversity.
Emission reduction.
Insurance against contingencies.
Increased deliverability.
Decrease Market Power.
o Exporting and Importing Region Benefits
- Seasonal exchange.
- Sales of surplus energy.
- Reserve sharing.
- Reliability improvement.
There are many uncertainties that impact the size of primary benefit and types of strategic
benefits from a new project. These uncertainties include load forecast, fuel prices, development
of new generation and retirement of existing power plants, regional prices for electricity, and
environmental regulation. Production cost-simulation, scenario analysis, stochastic modeling,
and other techniques have traditionally been utilized to estimate a base level of benefit and the
sensitivity analysis to take into consideration future uncertainties. These models tend to come
up with base case, sensitivity cases, and expected value of benefits.
Another category of benefits relates to extreme events. In recent years, the August 2003
Northeast Blackout and the California 2000–01 market dysfunction put a spotlight on the
significant economic (billions of dollars) and societal impact of such extreme events. The
challenge is that traditionally, there has been no attempt to quantify the benefit of mitigating
extreme events or when it is done, an expected value approach is utilized which understates the
societal value of mitigating these very low probability but very high impact events.
One of the research conclusions is that insurance against extreme events should be defined as
an additional societal benefit for reducing exposure to extreme market volatility and multi-
region-wide blackouts due to multiple contingencies. While there is general consensus on the
existence of these types of strategic benefits, they are not easily quantified or captured using
traditional models. For example, policymakers anecdotally acknowledge the value of
transmission projects as insurance against contingencies, but there is no definition or examples
of quantification of such values.
The above category of benefits can be defined as Extreme Event Benefits and are in addition to
the Primary and Strategic Benefits. The value of extreme event benefits can be put in context
when some of recent power system experiences are examined. For example:
o 2001 California market dysfunction and volatility with a cost of $20-40 billion.
o 2003 Northeast Blackout due to multiple contingencies with a cost of $5-
10 billion.
Extreme Event Benefits can be defined as:
21
1. Reliability—which is based on improved network load carrying capacity and ability to
reduce or mitigate impact of extreme events resulting from multiple contingencies (N-3,
4, 5, 6 events).
Society’s willingness to buy protection against extreme events is well established in the
insurance industry, for example hurricane insurance, life insurance, re-insurance against major
losses. In each of these examples, there is a well established actuarial data base that allows
valuation of such insurance. However, there is not a rich data base related to extreme events in
the electric power industry because major blackouts and market dysfunctions are infrequent
events. Hence, the research challenge is to come up with alternative approaches that address
these benefits rather than dismiss them due to difficulty in quantifying them.
For economic benefit quantification of new transmission projects, the basic approach is to utilize
a Production Simulation Model. The analysis includes two alternatives: one with and another
without the proposed new transmission project. Many commercial production simulation
models are available, such as PROSYM, GEMAPS, PROMOD, and PLEXOS. Using a least cost
dispatch principle, the models forecast production from different generation resources and
associated fuel consumption, and emissions. To have a balance between loads and resources,
additional generation resources are also introduced over time. Based on fuel prices, costs of
various emissions and variable O&M costs, the total production cost over time are calculated for
a given load forecast and associated load shape. The difference in the total production costs
from the two simulations defines the gross benefit for the new transmission project.
The net benefit of the transmission project is then calculated by subtracting the capital cost and
annual O&M of the transmission project from the estimated gross benefit. Benefit cost ratios and
internal rate of return can also be calculated from the information provided by the annual
production costs, capital, and O&M expenditure of the transmission project.
To take into consideration the uncertainty of factors such as fuel costs, load forecast, and capital
cost of the transmission project, Decision Analysis Models have been utilized to estimate the
expected value and the distribution of net benefit or benefit cost ratio. These may also utilize
22
Influence Diagrams that show the factors that have great impact on benefits and costs of the
project.
Carrying out detailed production cost simulation with and without the proposed project are
data intensive, time consuming, and expensive. This becomes more difficult when the detail of
transmission network is included in the model in addition to the generation system.
Furthermore, information on planned new generation development is based on market
economics and data is generally not available beyond 5 to 10 years, while transmission projects
are expected to last 50-years or more and deliver benefits during the entire period.
At the pre-feasibility level the use of a Spreadsheet Screening Analysis may facilitate studying
many transmission options quickly and at less time and expenditure than using detail
production simulation models. An example of this approach will be discussed later when the
benefit-cost analysis of Frontier Line is reviewed.
Spreadsheet Screening Analysis is useful when new generation resources at export region plus a
new transmission is compared with new generation resources at import region. This approach
allows comparison of many alternatives quickly. The results provide forecast of fuel
consumption, emission, and variable O&M and fixed O&M costs. Benefit and cost of a new
transmission is then calculated based on such information for different alternatives by including
capital costs of generation at export and import regions, fuel prices and capital cost of the
transmission project.
To concentrate the analysis on assumptions and relationships that greatly influence the project
benefits, the use of a Tipping Point Analysis method is sometimes utilized. In applying this
method, an economic criterion for the project is established. Potential tipping points which are
associated with key variables are listed and tested. The level of tipping point where benefit/cost
is less than one are determined and the potential for ending up with benefit/cost less than one
are evaluated and discussed for these tipping points.
In this section, the analytical tools and benefits quantification methods for benefit analysis for
three different projects are discussed. The three projects are Devers-Palo Verde No. 2 (DPV No.
2), Tehachapi, and Frontier Line.
23
o Enhance competition among generating companies supplying energy to
California.
o Provide additional transmission infrastructure to support the development of
additional generation capacity that will sell energy into California market.
o Provide increased reliability and flexibility in operating California’s transmission
system.
SCE has used a production cost simulation model (PROSYM) to estimate energy cost saving
resulting from the construction of DPV No. 2. This project is estimated to decrease electricity
prices in California, which is the primary benefit of this project. There will also be additional
third party transmission revenue due to increased CA ISO wheeling through or out of the CA
ISO grid.
Southern California Edison evaluation shows a B/C ratio for DPV No. 2 at 1.7. Energy benefits
are based on production cost simulation for 2009–2015 and then escalated at GDP price index
(around 2.28% per year) for the rest of economic life of the project.
At the request of CA ISO, SCE has provided energy production cost for Western Electricity
Coordinating Council (WECC) for the years 2009 through 2014 with and without DPV No. 2.
Using the cost saving numbers provided by SCE for WECC, the present value of the quantified
benefits from energy and third party transmission revenue is less than the capital cost of DPV
No. 2, using a 5% discount rate.
The WECC regional benefit for this project is low, in part, because strategic benefits such as
insurance value during extreme system conditions, reduction in generators market power,
potential for development of new generation outside of California and environmental benefits
beside NOx reductions are not quantified in WECC regional benefit calculation.
CA ISO has used its Transmission Economic Assessment Methodology (TEAM) approach and
PLEXOS cost production simulation model to quantify the benefits from DPV No. 2. Benefits
include cost saving in energy, transmission loss reduction, emissions reduction, market power
mitigation, and contingency. CA ISO’s proposed methodology for benefit quantification of the
transmission projects address the following major issues: modeling of market power;
development of a robust set of scenarios; selection of appropriate simulation tools or programs;
a detail representation of the transmission network and the assumptions of the future
generation system; and, selection of benefit tests. Detailed description of these elements is
provided in a report prepared by Consortium for Electric Reliability Technology
Solutions/Electric Power Group for the Energy Commission in June 2004 17.
17. Consortium for Electric Reliability Technology Solutions/Electric Power Group, June 2004. Economic
Evaluation of Transmission Interconnection in a Restructured Market, California Energy Commission
(CEC-700-04-007), pages 10-12.
24
o The participant/ratepayer test (benefits to those entities that will be paying for
the new facility).
o The societal test (benefits to all consumers, producers, and transmission owners,
regardless of who pays for the upgrades).
o The modified societal test recognizing or excluding non-competitive revenues
(monopoly rent) collected by some producers.
The societal test is measured by the change in production costs across the entire interconnection
(in case of DPV No. 2 over the entire WECC). A transmission expansion project is deemed to
pass the benefit test if: 1) it benefits each participant, and 2) the entire societal or the modified
societal benefit exceeds the project cost.
The WECC base case data is the foundation of the CA ISO modeling. CA ISO’s PLEXOS model
of the entire WECC requires significant amounts of input data. Due to the limited available CA
ISO staff time for the collection of input data for each year, CA ISO modeling for the economic
analysis of DPV No. 2 was done only for two years—2008 and 2013.
18. CA ISO Department of Market Analysis and Grid Planning, February 2005, Economic Evaluation of
the Devers-Palo Verde No. 2.
19. Transmission Economic Assessment Methodology (TEAM), Anjali Sheffrin, June 14, 2004. California
Energy Commission IEPR Workshop on 2004 Transmission Update.
25
CA ISO filed TEAM with CPUC in June 2004. CA ISO has demonstrated in actual studies the
use of TEAM for Path 26 and DPV No. 2. The methodology clearly indicates impacts of a new
upgrade at the participants’ level and also regional (WECC) levels.
Several new elements identified in this research could be added to TEAM to further expand
quantification of benefits, such as:
o Extreme event benefits such as improve network load carrying capacity under
multiple contingencies.
o Reduced vulnerability to extreme price volatility due to long term outages and
catastrophic events.
o Dynamic impact of a large transmission projects on the development and
construction of additional generation capacity in the exporting region.
By adding the above benefits to TEAM, the methodology will be able to capture the benefits
from risk mitigation of low probability/high impact extreme market events and the benefits of
development of new generation to both exporting and importing region. Without taking into
consideration such dynamic impacts, the analysis becomes a zero-sum game whereby there are
higher electricity prices in the exporting region with the implication that the investment in a
transmission line has negative impact on consumers of the exporting region. In fact, this factor
contributed to the recent rejection of DPV No. 2 by the Arizona Corporation Commission.
Division of Ratepayer Advocates at CPUC has also carried out a review of the DPV No. 2. This
report was prepared in three volumes that were published in November 2005. Volume 3 of this
study describes the Tipping Point Analysis for DPV No. 2 20.
As described by Dr. House in his DRA Testimony, Tipping Point analysis has gained popularity
in the social sciences since Gladwell’s 2000 book, How Little Things Can Make a Big
Difference 21. The analysis starts with defining the topology of the interactions (similar to the
Influence Diagram in Decision Analysis). Then through some analysis it is determined which
interactions are critical to the outcome (tipping points).
Dr. House’s analysis shows that tipping point variables for the DPV No. 2 project are:
20. Testimony of Lon W. House, November 22, 2005, Tipping Point Analysis and Attribute Assessment
for DPV No. 2, Office of Ratepayer Advocate’s Devers Palo Verde No. 2 Testimony Vol. 3 of 3.
21. Malcolm Gladwell, 2000, The Tipping Point: How Little Things Can Make a Big Difference, Little
Brown and Company, New York.
26
“In order for DPV2 to be cost effective, the natural gas price differential between
Arizona and California has to be greater than $0.50/MMBtu, the wholesale Topoc
price of natural gas has to be greater than $5.00/MMBtu and Palo Verde (Nuclear
Generation Station) has to be operating.” 22
Furthermore, DPV No. 2 is more valuable to California in the event of an outage of San Onofre
Nuclear Generation Station (SONGS).
Tipping Point Analysis provides clear information on critical variables and allows the analyst to
concentrate on high impact factors rather than spend a great deal of time and effort on elements
that do not materially change the outcome of the analysis.
In addition, the project also addresses the reliability needs of the CA ISO controlled grid caused
by load growth in the Antelope Valley area, as well as transmission constraints South of Lugo.
The main benefit of this project is to enable California utilities to buy power from wind
generation projects and to comply with the state mandated Renewable Portfolio Standard (RPS)
program.
The project justification for Tehachapi is renewable resource integration and reliability. While
resource integration has an economic dimension, the project justification is based on meeting
state RPS mandates rather than benefit cost analysis. The Tehachapi project evolved from the
Tehachapi Collaborative Study Group, which was formed in 2004 at the direction of CPUC. The
goal was to develop a comprehensive phased transmission development plan for integration of
renewables planned for development in the Tehachapi area. Two reports were issued and
submitted to CPUC in March 2005 and in April 2006. The outcome was the identification of a
number of alternatives for the transmission infrastructure. A recommendation was made to
further study these alternatives by the CA ISO.
The CA ISO in full collaboration with SCE and stakeholders carried out the Tehachapi
Transmission Project study as part of its CA ISO South Regional Transmission Plan for 2006
(CSRTP-2006). A least-cost solution for the interconnection of planned generation was
developed by CA ISO.
The total cost of the Tehachapi Transmission Project is estimated at $1.8 billion in nominal
dollars. This cost excludes the cost of Interconnection Facilities (radial wind collector
transmission systems that will interconnect the individual generation projects to the grid and
27
will be the responsibility of generation developers). SCE is the Project Sponsor and the project is
subject to necessary regulatory approvals from CPUC and FERC, which have either been
received or expected.
The Tehachapi Transmission project phased development plan includes:
CA ISO has used the concept of clustering in the Tehachapi Transmission Project. Clustering
allows the study of the system impacts of a group of interconnection requests collectively,
rather than evaluating each potential generation project one at a time. This results in greater
efficiency in the design of needed network upgrades.
The clustering approach for the Tehachapi Transmission Project will result in substantial capital
cost saving compared to any piecemeal upgrade solution with a traditional project by project
approach.
However, in the Tehachapi Transmission Project, the CA ISO has deviated from a typical
clustered interconnection study. The CA ISO study considered only the network components or
network upgrades of the transmission system and excluded the radial wind collector
transmission systems. Furthermore, an element of clustering is the selection of a time window
for determining which generation projects in the queue will be included in the cluster (i.e., the
Queue Cluster Window). The Tehachapi Transmission Project defined the Queue Cluster
23. Armie Perez, Vice President of Planning and Infrastructure Development, January 18, 2007,
Memorandum to CA ISO Board of Governors, Page 6.
28
Window as the projects submitted from August 19, 2003 through April 2006, which exceeds
FERC limit of 180 days for the Queue Cluster Window.
Due to the specific circumstances presented by Tehachapi Project, CA ISO has filed a petition
with FERC for approval to proceed with the proposed study approach on a one-time basis.
CA ISO Board has approved the Tehachapi Transmission Project as the Network Upgrades
necessary to allow Generating Facilities in the Tehachapi Wind Resources Area to deliver their
output to CA ISO grid. The Board has directed SCE to proceed with the permitting and
construction of this project. FERC’s approval of the CAISO waiver request for provisions of
Large Generator Interconnection Procedures (LGIP) allowed this project to move forward.
To perform a screening level economic study, the Economic Analysis Subcommittee developed
a spreadsheet tool to quantify benefits and costs of multitude of possible alternatives and
scenarios. These alternatives included: a variety of load and resources scenarios, a myriad of
conceptual transmission links and configurations identified by the Transmission Subcommittee;
a wide range of natural gas prices and possible costs for new clean coal technology, including
integrated gasification combined cycle (IGCC) and carbon dioxide sequestration; and a broad
spectrum of potential policy actions such as regional and/or national renewable portfolio
standards, state and federal tax incentives for preferred resources such as wind or solar or clean
coal, and regulatory regimes in greenhouse gas emissions.
FEAST is a simple tool for knowledgeable users. It considers incremental resource additions,
not a complete supply stack which would include all the existing generators.
For this screening analysis, the Gross Benefits ($) of the transmission project is based on the
following formula:
29
Line Utilization is a function of the quantity and characteristics of resources available to be
imported as compared to the line’s energy potential. (Basically, capacity of generation resources
installed in exporting region multiplied by assumed capacity factors for each resource and
subject to the transmission line and system constraints.)
Regional Basis is the energy cost difference between the exporting region and the importing
region. This Regional Basis is influenced by many factors, including the capital cost of new
generation resources, fuel costs (gas, coal, and others), environmental mitigation costs,
renewable energy price premiums, Green House Gas (GHG) adders, and others.
Benefits in addition to energy benefits include: capacity, losses, emissions, insurance value
against extreme events, economic impacts due to construction of transmission and generation
facilities, tax benefits, reliability improvement and others.
Many of the subcommittee members provided input on fuel prices, capital cost for generation,
ranges for Green House Gas adder, capacity factor for wind energy in different regions, and
other assumptions. The FEAST Spreadsheet Model was developed by staff of PG&E.
FEAST can handle several exporting regions (source options): Wyoming and Montana (coal and
wind), and several importing regions (sink options), including Utah, Nevada, Arizona, and
California. Resources considered for importing regions can be gas-fired CT or CCGT or IGCC
and renewables (for Utah coal, gas, renewables). For exporting regions, resources can be wind
and/or clean coal.
A mix of generation resources for exporting and importing regions are assumed. Taking into
consideration capacity and capacity factor of these generation resources, the amount of energy
going from source to sink is calculated.
FEAST is an energy focused analysis. Attempt is made to balance energy produced from the
generation resources in the sinks and sources. The installed capacity of generation ends up
being different for sinks and sources.
The Economic Analysis Subcommittee performed its work using a participatory stakeholder
process. Volunteers led the effort to create FEAST inputs. Individual subcommittee members
were able to perform their own analysis based on some of their own inputs.
The final report of this subcommittee was submitted to Western Regional Transmission
Expansion Partnership (WRTEP) on April 27, 2007 24. Two most important conclusions of the
report were:
1. The benefits of the Frontier Line appear greater than the costs under a variety of
plausible scenarios.
2. Uncertainty associated with key inputs results in a wide range of benefit-cost outcomes.
24. Economic Analysis Subcommittee for Western Regional Transmission Expansion Partnership, Final
Report April 27, 2007, Benefit-Cost Analysis of Frontier Line Possibilities.
30
The economics of the Frontier Line, as expected, are very sensitive to natural gas prices and the
values used for GHG adder. Economics of the Line are also somewhat sensitive to capital costs
for clean coal technologies, including IGCC and CO2 sequestration.
The primary focus of the analysis that was carried out by the Economic Analysis Subcommittee
was economic efficiency from a total societal point of view, i.e., the analysis produced the
overall benefit-cost ratio for the region as a whole. Of course, it is important that the Frontier
Line produces benefit for each individual jurisdiction participating in the project, i.e., benefit be
greater than cost for each state. The Economic Analysis Subcommittee did not analyze cost
allocation so that each jurisdiction participating receives a net benefit from the project.
However, FEAST enables each user to perform its own analysis and assess benefits and costs
allocated.
As stated in the Final Report of the Benefit-Cost Analysis of Frontier Line, FEAST is not a
substitute for production costing simulation tools. Analysis using FEAST may be a first step to
quickly sort through a multitude of possibilities. FEAST is a tool to perform quick what-if
screening analysis. It is a simple spreadsheet-based tool enabling and empowering
sophisticated users to carryout a variety of analyses quickly, with the aim of developing user
insight rather than producing overly precise numerical results 25.
25. Reference 9 p 8.
31
Summary of Benefit Analysis of
Transmission Projects
Project Description Purpose Comments
Palo-Verde 500 kV line between Arizona and Reduce California Benefits to California estimated using
Devers California electricity costs production cost and sensitivity analysis
No. 2 Single utility and single rate Strategic and regional benefits not
jurisdiction (CA ISO) addressed
$500 million cost Static analysis – assumed generation
1,300 MW capacity capacity fixed
Tehachapi Designed in several phases to Enable integration Least cost solution to meet RPS mandate.
interconnect 4,350 MW of new wind of new wind
generation generation in CA
Required CA rate back-stop and ISO queue to meet
innovative CA ISO tariff to allocate RPS
costs
$1.8 billion cost
Costs allocation among generator
(gen-tie), CA ISO grid users, and CA
ratepayers for cost recovery back-stop
Frontier 500 kV Designed to enable Benefits estimated using screening
Line 3,000 MW construction of new model – FEAST
$2 billion cost
generation in Benefits result from cost differential
Wyoming/Montana (capital and fuel) between resources
Multi-state, multi-utility, multi-
for export to CA, developed in CA vs. WY/MT
jurisdiction NV, UT, AZ Strategic benefits not quantified
Strong state government support in
exporting regions
No strong utility project sponsor
Of the three projects, Tehachapi is moving forward. Palo Verde-Devers No. 2 was rejected by
the Arizona Commission and SCE, the project sponsor, is moving ahead to construct the
California segment of the transmission line and continuing to pursue approval from FERC for
the Arizona portion. Frontier Line is still in the conceptual planning stages.
From this review, the following observations and conclusions are presented.
32
o Analysis required data intensive assumptions about future loads, resources, fuel
prices, and policies.
3. Problems encountered by projects
o Limited showing of benefits for key stakeholders, e.g., Palo Verde-Devers No. 2.
o Ambiguity about objectives and goals, including changing policies, e.g., Frontier
Line.
33
34
5.0 Benefit Quantification Methods
5.1. Assessment of Current Methods
Primary method to quantify the benefits of a transmission project is the use of a production cost
simulation model such as PROSYM, GEMAPS, PROMOD, and PLEXOS. The difference in the
total production cost for with and without the transmission project provides information on
gross benefit from such a project.
Key input variables in the production cost simulation models that impact the benefit of a new
transmission project are:
For example, during California’s 2001 electricity crises, the electric markets were dysfunctional.
Market prices were persistently high and led to state government intervention on behalf of
California consumers. This electricity crises cost the California consumers $20-40 billion.
Additional transmission would have mitigated these impacts of market dysfunction but current
benefit quantification methods do not take such extreme events into account. Similarly, the
August 14, 2003 Northeast 26 blackout, another extreme event, cost between $5– to $10 billion,
and the impact would have been substantially less of additional transmission was in place by
reducing the footprint and magnitude of this extreme reliability event. This short-coming of
current methods was also recognized in a report prepared by the WECC Seams Steering
Group 27, which noted that:
26. U.S.-Canada Power System Outage Task Force, April 2004, Final Report on the August 14,
2003 Blackout in the United States and Canada: Causes and Recommendations
27. “Framework for Expansion of the Western Interconnection Transmission System”, Seams
Steering Group – Western Interconnection (SSG-WI), Oct 2003. (Citation 57 from page 30), The
Battle Group International Review of Transmission Arrangements, Oct 2007
35
The real societal benefit from adding transmission capacity come in the form of
enhanced reliability, reduced market power, decreases in system capital and variable
operating costs and changes in total demand. The benefits associated with reliability,
capital costs, market power and demand are not included in this {type of production
cost} analysis.
Review of current methods used to quantify transmission project benefits leads to the following
conclusions:
However, use of cost of capital as the basis for discounting the future benefits tends to
understate the benefits of long life assets such as transmission. An alternative approach is to use
the social rate of discount instead of using a rate based on cost of capital. The social rate of
discount (around 5%) can be used to calculate the present value of benefits for the new
transmission projects since transmission system has become a public good with assets having
long life, and benefits occurring over a long period. 28
28. Consortium for Electric Reliability Technology Solutions/Electric Power Group, June 2004, Economic
Evaluation of Transmission Interconnection in a Restructured Market, California Energy Commission
CEC-700-04-007.
36
The impact of using the social rate of discount around 5% compared to the current weighted
cost of capital of 10% on present value of benefits is significant. For a project with uniform
benefit over 50-years of economic life, the use of 5% discount rate rather than 10% will increase
the present value of benefits by around 60% or more.
All of the production cost simulation models capture primary benefits from transmission
projects. They include energy, capacity, transmission loss reduction, and environmental values
(emissions). Strategic benefits such as access to new renewable resources, fuel diversity,
improved deliverability - reduced congestion and insurance against contingencies such as dry
hydro condition and performance of some major base load generation and intertie transmission
can also be quantified through scenario and sensitivity analysis or stochastic modeling.
Quantification of some of the strategic benefits, such as mitigation of market power is more
difficult, but procedures have been developed recently to capture these types of benefits. Effort
by CA ISO and the development of TEAM approach for benefit quantification of transmission
projects is a good example of the recent efforts.
In summary, current analytical models capture most of the primary and strategic benefits of the
new transmission projects. These models utilize the expected value approach and, therefore,
tend to average extreme low probability/high impact events. However, extreme market
volatility and system events can be very costly to society and the societal risk preference and
tolerance is not captured in current models. Furthermore, cost of such events multiplied by their
probability will under-estimate the financial and social significance of these events and their
long term financial dislocation. Extreme market volatility can be very costly to society, such as
2001 California market dysfunction with $20 to $40 billion cost. The value of transmission in
mitigating societal impact from these types of events is not captured in current production cost
simulation models.
Reliability benefits of new transmission in strengthening the grid and reducing the likelihood of
the impact of extreme multiple contingency events is also not considered or quantified in
benefit-cost analysis. A good example is the 2003 Northeast Blackout with $5 to $10 billion cost.
Another type of benefit that is not captured in the dynamic impacts of a large transmission
project is the natural gas price reduction when the transmission project provides access to
significant amount of renewable resources, or production from clean coal generation plants
with CO2 sequestration. Such projects may reduce the demand on natural gas significantly and
therefore reduce the price for this fuel. Another dynamic impact is the development of
additional generation capacity in the exporting region when a new transmission project is
constructed.
37
1. Use of Social Rate of Discount for Calculating Present Worth of Benefits of
Transmission Projects.
o Transmission projects produce societal benefits and are a long life asset. Use of
transmission is subject to open access or common carrier rules such that
transmission owners cannot reserve transmission for their own exclusive use.
Transmission is hence a public good and use of social rate of discount as opposed
to the higher cost of capital is appropriate.
2. Fuel Diversity Benefit Quantification.
o The marginal fuel for electricity generation is natural gas. Addition of large
amounts of renewables will displace fossil fuels which, in turn, reduce cost of
natural gas (price elasticity) and reduced power costs (more efficient dispatch).
These benefits can be quantified and linked to large regional transmission
projects.
3. Extreme Reliability Event Mitigation—Reduced Vulnerability to Multiple System
Contingency Events.
o Power systems are generally designed to meet N-1 or N-2 criteria. Extreme
events, such as the August 2003 Northeast blackout and the 1996 Western
Interconnection blackout were all multiple contingency events. Additional
transmission projects would help mitigate the magnitude, duration, and
footprint of blackouts. This can be estimated by simulating the reduction in
blackout footprint from extreme events with addition of transmission.
4. Market Risk Mitigation Quantification.
o Market prices are volatile. Societal risk tolerance to runaway market prices or
market dysfunctions is limited. Individually and societally, insurance vehicles
help mitigate such risks. Additional transmission will help mitigate against
market dysfunction and runaway market prices.
5. Dynamic Analysis Application to Transmission.
o Use of dynamic analysis methods to recognize changing benefit streams over the
life a transmission asset can be used to quantify benefits of major new regional
transmission projects.
The research also identified methods to generate stakeholder and policy consensus to value
strategic benefits of transmission projects. Such methods can be used in addition to or in
combination with quantification methods discussed above. The research project results
identified two methods for generating stakeholder consensus.
38
that should be assigned to transmission projects, as a percentage of total cost of
the project.
2. Resource Portfolio Analysis.
o Portfolio construction and analysis is commonly used in the financial industry to
develop investment portfolios that perform well under a variety of scenarios.
Portfolio analysis methods can be used to evaluate benefits of transmission
projects under a variety of future scenarios and hence better inform policy and
decision makers.
Methods to produce policy and stakeholder consensus such as application of Delphi and
Portfolio Analysis can be used instead of the more rigorous but resource intensive
quantification methods discussed above.
39
40
6.0 Application Of New Methods For Benefit Quantification
The methods listed in Section 5 above could be applied in the benefit quantification of new
transmission projects, as described in the following sections.
Social discount rates more appropriately value the long term benefits that transmission projects
provide to society than does current practice of reliance on the utility weighted cost of capital.
This is due in part to the fact that current open access policies applicable to the transmission
system mean that the benefits of new transmission lines accrue to society as a whole as the lines
are now operated as common carriers. This is in stark contrast to the period prior to open access
when ownership of transmission also meant reservation of use of lines by owners for private
use. Today, the benefits to the transmission line owner are limited to a regulated return on
invested capital.
Transmission projects have useful operating lives in excess of fifty years and benefit society at
large, i.e., they are a public good. A summary of the research rationale for use of social rate of
discount for evaluating transmission projects is listed below:
o Currently benefits are present-worth using cost of capital, generally in the 10%
range.
o Adoption of a social rate of discount to estimate present value of benefits of
transmission projects will recognize the public good nature of transmission
projects.
o Transmission projects are long life—50 plus years. Benefits start to accrue as use
of line increases over time. Current methods discount future benefits that occur
beyond the first 10–years of project life to a point where they are not
consequential.
41
o With a 10% discount rate, total present value of all benefits beyond 10-years in a
50-year project life is approximately 38% present worth of benefits.
o A social rate of discount, generally 3 to 5% is used to evaluate long life public
works and public goods projects such as dams, roads, bridges.
o Public or societal benefits of transmission projects include fuel diversity,
common carrier use, integration of renewables, insurance against extreme events,
and meeting public policy goals.
o The present value of benefits using a 5% social discount rate are 60 to 70% higher
than using a 10% cost of capital.
The application of a social rate of discount can be illustrated by calculating present value of
benefits using different discount rates. If a project has annual benefits of $50 million, the present
value of benefits over a 30-year economic life using a 10% discount rate (cost of capital) is
$472 million. However, if a 5% discount rate is used (social rate of discount), the present value
of the same stream of benefits is $769 million or more than 60% higher. The present value of
benefits under different discount rate assumptions for a project with a 30-year life and
$50 million in annual benefits are shown in Figure 2 below.
769
5% 7.5% 10%
Discount Rate
F igure 2. P res ent V alue of B enefits Us ing Different Dis c ount R ates —30-year life, $50 million
Annual B enefit
The social rate of discount is a function of per capita consumption growth, the elasticity of the
marginal utility of consumption and the probability of survival of the average consumer from
one period to the next. For public works projects, discount rates of 3 to 5% have been used
historically. For U.S., the social rate of discount is around 5%.
42
The California gross system power for 2006 shows that approximately 107 billion kWh was
produced from natural gas in-state 29. Therefore the Tehachapi Transmission Project has the
potential to reduce by 12.4% the gas consumption for power production. Furthermore, gas for
electric production is about 40% of total California natural gas consumption. Therefore, the
impact of 4,350 MW of new wind generation will be to reduce the total natural gas consumption
of California by about 4.8%.
In a recent study, the price elasticity for natural gas is estimated to be at 0.8 to 2.0%. 30 If we
make a conservative assumption of 1% price reduction for 1% demand reduction for natural
gas, then 4.8% reduction in natural gas consumption due to 4,350 MW of wind generation will
reduce the price for natural gas by 4.8%. Assuming a gas price of $6/MMBtu, this is a reduction
of $0.29/MMBtu. With wind providing 13B kWh to California and assuming no other change,
electricity produced by gas will reduce from 107 billion kWh to 94 billion kWh. Assuming a
heat rate of 9,000 BTU/kWh, the $0.29/MMBtu price reduction translates to an annual cost
saving of about $250 million.
Figure 3 presents the above example for calculation of fuel diversity benefit.
Note: Including price impact on non-electric sector, benefit will be 2.5 times, or $625 million.
Illustration ignores timing and present value for simplicity.
*Wiser, Bolinger, and St. Clair, January 2005, Easing the Natural Gas Crisis: Reducing Natural Gas Prices through
Increased Deployment of Renewable Energy and Energy Efficiency
29. 2006 Net System Power Report, 4/12/07, Energy Commission Publication CEC-300-2007-007
30. Wiser, Bolinger, and St. Clair, January 2005, Easing the Natural Gas Crisis: Reducing Natural Gas
Prices through Increased Development of Renewable Energy and Energy Efficiency, Ernest Orlando
Lawrence Berkeley National Laboratory (LBNL-56756)
43
If the price reduction benefit is also assumed for gas consumed in other sectors, then this annual
benefit can exceed $600 million over 30-year life of Tehachapi transmission line. The present
value of this benefit using an annual discount rate of 10% will be over $6.2 billion, while the
total cost of the line is estimated to be $1.8 billion.
To calculate the reliability benefit due to reduced vulnerability to extreme events, the analysis
steps are as follows.
This approach can also be utilized retrospectively, for example in the analysis of the 2003
Northeast blackout. The estimated cost of the blackout was $5 to 10 billion 31. If the network is
simulated assuming one or more major new transmission lines, for example, American Electric
Power’s proposed 765 kV line, then the impact on the blackout footprint can be estimated.
Assuming that the addition of major new lines reduces the simulated load loss by 40%, then, as
a first approximation, the reliability benefit will be a 40% reduction of the loss or $2 to 4 billion.
The steps in the application of this approach are enumerated in Figure 4.
31. U.S.-Canada Power System Outage Task Force, April 2004, Final Report on the August 14, 2003
Blackout in the United States and Canada: Causes and Recommendations
44
Quantification of Reliability Benefit Due to Reduced
Vulnerability to Extreme Events – 2003 Blackout
Example
Alternatively, a policy or expert consensus approach can be used for this benefit as being equal
to a fixed percentage of project cost. This can also be estimated using the concept of reserve
margins in resource planning. Generation is generally planned to a reserve margin of 15%, that
is capacity should be 115% of peak load forecast. If one assumes a similar transmission reserve
margin as a means of insurance against multiple contingencies or extreme events, then 15% of
project costs can be assigned to benefits attributed to mitigation of extreme events. Such an
approach requires further analysis and policy acceptance for application to transmission
projects.
(a.) Define base case and estimate locational margin prices (LMPs).
(b.) Define an extreme event and rerun base case to estimate locational margin prices
under extreme event.
(c.) Add new transmission lines in base case.
(d.) Estimate locational margin prices under same extreme event defined in (b) above
but with new transmission lines as defined in (c).
45
(e.) Estimate societal value due to reduced market price spikes as measured by LMPs
and resulting reduced societal cost of extreme events.
In effect, such a methodology quantifies the benefit of new transmission during extreme events
by reducing congestion, market power, and price volatility.
The insurance industry utilizes extreme event probability distributions for hurricanes and
earthquakes to determine insurance premium for such events. These analysis and approaches
are data dependent. In the absence of such data to calculate the insurance value of avoiding
extreme price volatility due to the construction of new transmission projects, a policy consensus
approach may be useful. Such policy consensus can be generated via polling of policy makers or
more formal approaches such as the Delphi method, value at risk and risk tolerance analysis.
Consensus may translate the insurance value of a transmission project to be equal to a
percentage of project cost.
Without such feedback, the amount of new generation construction in the exporting region will
be underestimated and the benefit from a new transmission line understated. Furthermore,
transmission projects have long life. There is need to incorporate benefits from unanticipated
uses over the project life. This could be done based on historical experience from the
construction of older transmission projects and their impact on generation expansion and
interregional power trading.
For incorporating dynamic planning benefits of new transmission project, the analytical steps
are:
46
weights and worth (out of a total of 100) to different decision criteria or variables. The results
are shared among the panel and they are offered an opportunity to reassign weights and worth
based on consensus and results from the first iteration. Generally, 2 to 4 iterations result in
views converging.
The Delphi approach could be adapted to assign values to different benefit categories by
stakeholders or constituent groups. Benefit categories could be pre-specified, for example
production costs, fuel diversity, reliability and market volatility. The stakeholders then assign
values out of a total of 100 and the process is repeated in an effort to narrow the differences and
move to a converged view that can be supported by stakeholders.
Delphi or other stakeholder consensus building could hence be utilized to incorporate societal
or strategic benefits. Figure 5 illustrate the application of Delphi and stakeholder consensus
approach for such an application. In the example shown in Figure 11, there is a consensus that
societal benefits for this transmission project under consideration should be valued at 26.25% of
the project cost. Therefore, the primary benefits from the project have to be equal or larger than
73.75% of the project cost, for this project to be economical and cost effective.
47
It can be utilized in the electric power industry to develop a robust portfolio of resource options
that performs well under a wide range of future scenarios.
The value of portfolio diversification is implicitly recognized in the electric power industry, but
its application is generally through policy mandates such as RPS or load management goals.
The emphasis in this report has been on quantification of strategic benefits of a new
transmission project, rather than on portfolio approach to planning and resource development
that looks into diversification to reduce overall risk and prevent extreme costs. A portfolio
approach tested against a range of future scenarios and uncertainties could be applied to
generate policy consensus on need for transmission.
In the financial markets diversification and allocation of asset among different investment
categories to achieve a low level of risk correlation between asset classes is the underpinning of
portfolio construction to maximize risk adjusted returns. It is estimated that asset allocation can
account for up to 80 percent of investment returns with market timing and individual stock
selection contributing only the remaining 20 percent. This is why modern investment theory
calls for portfolios based on overall risk/reward characteristics instead of that of individual
stocks.
In the electric industry diversification of the supply resources has also become an important
element in planning for uncertainty. Utilities, instead of concentrating their supply on one or
two type of resources such as coal and oil/gas, nowadays have a portfolio of resources such as
demand side management, renewable resources, nuclear, coal, hydro, and gas. In addition, the
high voltage transmission system has enabled many utilities to import significant portion of
their need from other utilities and/or merchant plants. Seasonal power exchanges have also
provided benefit due to diverse load and resource patterns of different regions.
This resource diversification have decreased the risk due to fuel price uncertainty, performance
of different types of generation resources, load uncertainty, major generation failure, and
natural events such as fire, earthquake, etc. Tools used in planning for uncertainty has included
scenario planning, sensitivity analysis, decision analysis and of course various probabilistic
production simulation models. However, the basic element in evaluation and approval of new
transmission and generation projects has been benefit-cost analysis for a specific project.
48
The primary goal in the resource planning may become the determination of optimum mix of
resources of different categories. Then, within this mix, select the best projects for each category,
to minimize the overall risk of the portfolio of resources.
a. Other industries, such as insurance finance, use portfolio approaches for risk
mitigation.
b. Portfolio approaches depend on established historical data base to correlate variables
– application to transmission requires research and data. As we gain more
experience with market operations, data may becomes more available.
c. In planning for societal risk management, a diversified portfolio of resources may be
more important than the precise quantification of benefit-cost of an individual
project.
d. Portfolio resource diversification should be based on overall societal risk/reward
characteristics instead of benefit-cost analyses of individual projects.
e. There is a need to carryout research on the application of modern portfolio
management to determine the portfolio of resources such as demand side program,
various generation technologies including renewable resources, and transmission to
access resources from other regions.
f. Portfolio analysis steps
- Resource allocation – mix of demand, renewables, gas, coal, nuclear,
transmission
- Resource risk – price, performance, probability
- Portfolio performance under alternative futures.
The results of such analysis could then be used to generate policy consensus on need for new
transmission that could be mandated. This will have a result similar to what happened in the
case of Tehachapi transmission.
Recommendation is made to augment TEAM’s benefit quantification in: using social rate of
discount, fuel diversity, and Delphi method for low probability/high impact and other strategic
benefits. Figure 6 lists these recommendations.
49
Recommendations To Augment
Benefit Quantification Methods
Public Good
Use of social rate of discount to calculate the present value of
benefits for the new transmission project
Fuel Diversity
Include the benefit from potential decrease of natural gas price
due to the construction of a new transmission project that
integrates a significant amount of new renewable resources
Low Probability / High Impact Events
Add risk mitigation benefit to society for low probability/high
impact extreme market events and extreme system multiple
contingency events – scenarios or Delphi method for
stakeholder consensus
a. Dynamic Analysis
o Recognize the impact of new transmission projects on the construction of new
generation capacity in exporting regions
50
b. Portfolio Analysis
o Adapt portfolio analysis methods utilized in the financial industry to
transmission – construct and assess performance of portfolios including demand
response, new generation (renewables and fuel based), new transmission, energy
conservation
c. Quantification of Extreme Event Benefits (Insurance Value)
o Reliability – benefit of new transmission in reducing blackout footprint due to
extreme (N-n) events and the societal value of reduced vulnerability
o Market Volatility -- benefit of new transmission in reducing market volatility due
to extreme (N-n) events and the societal value of reduced vulnerability to run-
away market prices
51
52
7.0 Cost Allocation And Cost Recovery
7.1. Framework for Cost Allocation and Cost Recovery
Cost responsibility for different types of transmission projects varies depending on the type of
transmission project. Figure 7 provides a framework for who should pay for new transmission
projects.
For economic transmission projects, the goal should be to allocate costs to project beneficiaries.
The principle of beneficiaries should pay or that cost causers should be cost bearers applies.
For economic transmission projects, the ownership of the project could be: the utility in whose
service area the project is located, a merchant owner, or joint transmission owners when the
transmission line goes through several service areas and the line in each service area is owned
by the utility of that service area.
Cost recovery could be based on: transmission access charge, contract rights, subscription or
auction. In an RTO, if the transmission is a reliability upgrade and is needed to maintain the
integrity of the transmission grid, the costs are rolled in to the transmission charge. Costs can be
rolled-in: (a) fully, (b) partially with remaining costs allocated to zones or beneficiaries, and (c)
by using a voltage test and either 100% of the cost is rolled-in to an RTO wide rate or 100% into
zonal rate(s).
Alternatives for cost allocation of economic type transmission projects in an RTO could be:
53
5. 100% of the cost is rolled into RTO base rate.
As above alternatives for cost allocation shows, the size and distribution of the project benefits
may be utilized for cost allocation among beneficiaries. Therefore, improved benefits
quantification will be useful in: 1) providing guidance on cost allocation among multiple
participants and jurisdictions, and 2) selecting cost recovery methodology.
The cost of service is then allocated over billing determinants. Currently, there are three
alternative transmission rates used in different jurisdictions:
a. Energy—postage stamp.
c. Distance—Megawatt-mile.
Cost recovery is accomplished through rate cases that are submitted by the transmission owner
(TO) utilities to the commission in each state. In addition, FERC filing may also be required to
establish the rate for use of transmission. FERC has exclusive jurisdiction over transmission
rates. To eliminate transmission rate pancaking (paying multiple wheeling charges for a path),
FERC has been encouraging formation of ISOs and RTOs.
To stimulate the construction of new transmission lines, FERC has indicated that it will allow
performance-based regulation proposals and consider innovative transmission pricing
proposals including a higher rate of return on equity, levelized rates, accelerated depreciation
and incremental pricing for new transmission projects.
Figure 8 shows a framework for the use of benefit quantification for both cost effectiveness and
cost allocation under single and multiple utilities and single and multiple jurisdictions.
54
Framework for Use of Benefit Quantification for
Project Cost Effectiveness and Cost Allocation
Transmission Project
F igure 8. F ramework for Us e of B enefit Quantific ation for P rojec t C os t E ffec tivenes s and C os t
Alloc ation
For multi jurisdiction projects, the preferred way for the cost allocation will be first to allocate
the cost to each of the jurisdictions and then allow each jurisdiction to allocate their share of cost
among utilities and other users based on that jurisdiction’s cost allocation methodology. Cost
allocation to the multiple jurisdictions could be based on the following alternatives:
a. Participation Ratio
- Allocate costs and MW capacity of the transmission according to participation
ratio or native load ratio.
b. Subscription Open Season
- Participation based on requested subscription (need and benefits assessment
by each utility), each subscriber performs individual benefit assessment. Cost
allocated based on the requested level of subscription.
c. Auction Methodology
- This method promotes MW allocations to participants who will get the
highest benefit from the utilization of the new transmission project.
The project sponsor or RTO can establish an auction to allocate the capacity that becomes
available from a new transmission line. Participants, based on their own assessment of how
55
much benefit they will receive from the new project, can submit bids into the auction process.
Capacity of the line will be allocated to users who value this capacity most.
At least two auction methods can be designed for this capacity allocation. First is a round of
ascending price auction similar to CA ISO annual FTR auction. Second is the single price and
quantity bids auction.
In the first method, the auction starts for a given period with a $/MW-year payment at a level
close or just below the annual revenue requirement for the project. Each period could be one
year, or to encourage multi-year power contract and construction of new generation, it could be
multiple of 5-years for a total of say 30-years.
If the result from the first round of bids is a total MW of bids higher than the transmission line
capacity, the payment will be increased and the second round of the auction will be carried out.
The auction round will be repeated until there is a balance between total bids and the online
capacity available. This last round will determine the line capacity allocation amongst different
parties and the payment for each MW-year.
The same auction process will then be carried out for the next period (next year or next 5-year
period). This per period allocation could be repeated to cover the entire economic life of the
project (or the duration for repayment of entire capital cost of the project).
Total payments generated from the auction over the periods have to be equal or greater than
total revenue requirements to show that the project is cost effective. (Project sponsor has to
come up with fixed revenue requirement. The project cost has, therefore, to include reasonable
contingency cost. The allowed rate of return may be somewhat higher than normal allowed
rate to compensate for fixed cost for the construction of the line.)
If the total payments generated in an auction are higher than the fixed revenue requirements
and variable O&M cost, then the overpayments will be retained by project sponsor or RTO for
decreasing the cost of grid reliability improvement projects.
If the total payments generated in an auction are not sufficient to cover the revenue requirement
of the project then the project should not be developed, since the beneficiaries are not willing to
pay the total cost of the project.
In the second type of auction, each bidder submits a payment and quantity for each period.
Based on all bids received, a demand curve is developed for each period. The intersection of the
demand curve and the capacity of the transmission line would determine the payment level for
each MW and the amount of capacity to be allocated to each one of the winning bidders for this
period.
The auction process is repeated for each period until the last period. Again, if the total
payments are higher than the total revenue requirement, a process will be developed to use this
surplus fund.
56
In both auctions, every participant pays the same market clearing price for a given period. The
auction provides a mean to allocate the line capacity to participants who value such capacity
most.
A description of the Cost Allocation Methodologies and Cost Recovery, and research
recommendations are in Appendix C.
57
58
8.0 Framework For Incorporating Benefit Quantification
Enhancements In Transmission Planning
Within the areas where cost-benefit tests are applied, there is a range of approaches
taken to the measurement of benefits. Most systems follow a “traditional” approach that
models only savings in production costs. However, it is increasingly recognised {sic}
that this approach underestimates the benefits of transmission upgrades, which can also
include increased reliability, enhanced competition, lower generation investment costs
and other factors. The most comprehensive cost-benefit framework formally specified
by a transmission planner we are aware of is the Transmission Economic Assessment
Methodology (“TEAM”) recently adopted by the California ISO.
While the TEAM approach is progressive as acknowledged above, it could be further
augmented to fully consider the full range of benefits of major new transmission projects.
The CA ISO TEAM method has been developed over a period of time. This could be
strengthened as follows:
32. The Brattle Group, October 2007, International Review of Transmission Planning Arrangements, – A
report for the Australian Energy Market Commission, page 6.
59
portfolio could be used to develop public policy consensus on need for new
transmission, for example to access renewables and other markets.
4. Initiate research on quantifying extreme event benefits (Value at Risk, Insurance
Premium, and other methods).
60
9.0 Project Outreach and Briefings
The research project benefited from feedback and guidance received formally and informally
during the project. The following briefings and presentations were made during the project.
A. Technical Advisory Committee (TAC). The TAC was convened in-person twice during
the research project. These meetings took place January 19, 2007 and September 10, 2007.
In addition, TAC was consulted informally on key issues and provided briefings and
draft report for review, comment and feedback.
B. Briefings were made to the Frontier Line team twice during the research project.
C. Consortium for Electric Reliability Technology Solutions (CERTS) Industry Advisory
Board was briefed on the project at its regularly scheduled meeting on November 8,
2007.
D. The CA ISO management and staff briefing on February 27, 2008.
E. The CPUC briefing on April 23, 2008.
F. Briefing for Western Electricity Coordinating Council Transmission Expansion Planning
Policy Committee on June 12, 2008.
G. Briefing for the Energy Commission management and Commissioner Byron on July 2,
2008.
The CPUC has a current proceeding “Order Instituting Investigation (OII) on the Commission’s
Own Motion to actively promote the development of transmission infrastructure to provide
access to renewable energy resources in California. The CPUC’s Division of Ratepayers (DRA)
filed a motion in March 2008, to supplement the record in that proceeding to “…consider and
discuss the ongoing quantification analyses being done under the auspices of the Transmission
Research Program of the Public Interest Energy Research (PIER) Program administered by the
California Energy Commission (CEC), entitled Strategic Benefits Quantification of Transmission
Projects. The particular documents DRA wishes to make a part of the record are: (1) Project
Introduction Briefing, Strategic Benefits Quantification of Transmission Projects, presented by
Virgil Rose, Senior Advisor, at the California Public Utilities Commission, April 23, 2008; (2)
Consortium for Electric Reliability Solutions, Strategic Benefits Quantification for Transmission
Projects, Electric Policy (sic) Group, project briefing for the California Public Utilities
Commission, April 23, 2008.”
61
62
10.0 Utilization of Research Results
The benefits of this research will be realized through use of research results. This can be done in
transmission projects being considered in California and the Western grid. There are three key
elements. The first is application of the research to strengthen benefit quantification methods
used in California, for example, CA ISO’s TEAM approach. Second is the wide spread sharing
of research results through outreach and participation in different transmission forums to
discuss, debate and refine the proposed methods. Third is additional research on benefit
quantification methods such as portfolio analysis, dynamic planning, and extreme event benefit
quantification. Fourth is to advocate more transparent, inclusive and predictable planning
processes. A summary of uses of research results is presented below:
63
64
11.0 Key Conclusions And Research Recommendations
11.1. Recommendations for Benefit Quantification
1. Social Rate of Discount:
Since the transmission system has become a public good, the use of a social rate of
discount, instead of allowed weighted cost of capital, to calculate the present worth of
benefits of a new transmission project is recommended.
2. Screen Tools:
In early stages of the project, the use of a screening tool similar to the one developed by
PG&E for application to the Frontier Line (FEAST) can be very productive. Simple
spreadsheet-based tools will enable and empower project participants to carryout a
variety of analyses quickly, with the goal of developing and testing the benefit of
multiple alternatives. Spreadsheet tools are useful screening devices but are not a
substitute for detail production costing simulation for detailed benefit analysis. They
are, however, useful to perform quick what-if screening analysis and can test the impact
of the various types of benefits and risks.
Screening and current production cost simulation tools are capable of quantifying
primary benefits and some of the strategic benefits of a new transmission project. The
main missing benefit quantifications are:
Initiate research into use of dynamic analysis approaches that could then be used to
strengthen current methods.
65
The CA ISO TEAM method has been developed over a period of time. This could be
strengthened as follows:
Attempts should be made to quantify primary and strategic benefits of transmission projects in
a transparent way so that project participants and beneficiaries can agree on the level of benefits
and who gets what share of these benefits and who pays what share of the costs.
If there is too much uncertainty in forecasting the size and distribution of benefits and/or some
of the important strategic benefits are difficult to quantify, then it may not be possible to
develop a consensus amongst beneficiaries on size and distribution of benefits. This may be
especially true with projects where there are multiple utilities and multiple jurisdictions.
Alternative Description
b. Participation Ratio Costs and MW of transmission capacity are allocated according
to participation ratio or native load ratio
c. Subscription Open Season Participation is based on requested subscription. Each
subscriber performs individual benefit-cost assessment.
d. Auction It is based on willingness to pay approach and on benefits
assessment by each entity. May result in revenues in excess of
costs. Such excess revenues are used for reliability improvement
projects or reallocated among participants. Auction promotes
MW allocation to participants with highest benefit.
There may be cases that exporting region, owners of surrounding area of right-away, or some of
the participants are negatively impacted by the construction of a new transmission line. This
may happen even if strategic benefits are included in the analysis. In such cases, side payments
to negatively impacted parties may be justified. These side payments could be in from of
improvement/construction of some infrastructures such as roads, parks, sport facilities, and
electrical reliability improvement projects.
66
If an auction is utilized to allocate the capacity of the new transmission project, the revenues
from the auction will usually exceed project costs if the benefits are larger than costs. Such
excess revenues can be utilized for side payments or the cost of new infrastructure as side
payments.
67
Glossary
CT Combustion Turbine
TO Transmission Owner
68
Bibliography
1. 1. The Blue Ribbon Panel on Cost Allocation, Sept 2007, A National Perspective On Allocating the
Costs of New Transmission Investment: Practice and Principles, p 1.
2. Consortium for Electric Reliability Technology Solutions/Electric Power Group, June 2004.
Economic Evaluation of Transmission Interconnection in a Restructured Market, California
Energy Commission (CEC-700-04-007). pages 10-12.
3. CA ISO Department of Market Analysis and Grid Planning, February 2005, Economic Evaluation
of the Devers-Palo Verde No. 2.
4. Transmission Economic Assessment Methodology (TEAM), Anjali Sheffrin, June 14, 2004.
California Energy Commission IERP Workshop on 2004 Transmission Update.
5. Testimony of Lon W. House, November 22, 2005, Tipping Point Analysis and Attribute
Assessment for DPV No. 2, Office of Ratepayer Advocate’s Devers Palo Verde No. 2 Testimony
Vol. 3 of 3.
6. Malcolm Gladwell, 2000, The Tipping Point: How Little Things Can Make a Big Difference, Little
Brown and Company, New York.
7. Reference 5, Page 38.
8. Armie Perez, Vice President of Planning and Infrastructure Development, January 18, 2007,
Memorandum to CA ISO Board of Governors, Page 6.
9. Economic Analysis Subcommittee for Western Regional Transmission Expansion Partnership,
Final Report April 27, 2007, Benefit-Cost Analysis of Frontier Line Possibilities.
10. Reference 9 p 8.
11. U.S.-Canada Power System Outage Task Force, April 2004, Final Report on the August 14, 2003
Blackout in the United States and Canada: Causes and Recommendations
12. “Framework for Expansion of the Western Interconnection Transmission System”, Seams
Steering Group – Western Interconnection (SSG-WI), Oct 2003. (Citation 57 from page 30), The
Battle Group International Review of Transmission Arrangements, Oct 2007
13. Consortium for Electric Reliability Technology Solutions/Electric Power Group, June 2004,
Economic Evaluation of Transmission Interconnection in a Restructured Market, California
Energy Commission CEC-700-04-007.
14. 2006 Net System Power Report, 4/12/07, Energy Commission Publication CEC-300-2007-007
15. Wiser, Bolinger, and St. Clair, January 2005, Easing the Natural Gas Crisis: Reducing Natural Gas
Prices through Increased Development of Renewable Energy and Energy Efficiency, Ernest
Orlando Lawrence Berkeley National Laboratory (LBNL-56756)
16. U.S.-Canada Power System Outage Task Force, April 2004, Final Report on the August 14, 2003
Blackout in the United States and Canada: Causes and Recommendations
17. The Brattle Group, October 2007, International Review of Transmission Planning Arrangements,
– A report for the Australian Energy Market Commission, page 6.
69
18. A Mathematical Theory of Saving, Frank P. Ramsey, Economic Journal 1928 (December) pages
543-559.
19. The Social Discount Rate, Andrew Caplia and John Leaky, Journal of Political Economy, 2004, Vol
112, No. 6
20. Essay on Economic Growth, Maurice Dobb, Long, 1960 Chapter II
21. Recalculating the Costs of Global Climate Change, Hal Varian, New York Times, December 14,
2006
22. The Social Discount Rate: Estimates for Nine Latin American Countries. Humberto Lopez, Policy
Research Working Paper, The World Bank, Latin America and the Caribbean Region, Office of
the Chief Economist, June 2008
23. Social Interest Rate for Public Sector Project Appraisal in the UK, USA, and Canada, Kule E,
Project Appraisal, 2: 169-174, 1987
24. A Review of Economic Growth, M. Scott, Clarendon Press, Oxford, United Kingdom, 1989
25. Estimation of a Social Rate of Interest for India, Kula E. Journal of Agricultural Economics, 55(1):
91-99, 2004
26. Social Discount Rates for Six Major Countries, Evans, D. and H. Sezer, Applied Economic Letters,
11: 557-560, 2004
27. The Elasticity of Marginal Utility of Consumption: Estimates for 20 OECD Countries” D. Evans,
Fiscal Studies, 26(2):197-224, 2005
28. A Time Preference Measure of the Social Discount Rate for the United Kingdom, David Evans
and Haluk Sezer. Applied Economics, 2002, 1026 P.34
29. Derivation of Social Time Preference Rates for the United States and Canada, Erham Kula
Quarterly Journal of Economics 1984, Vol 99, 11 P. 873-882
30. 2006 Net System Power Report, 4/12/07, Energy Commission Publication CEC-300-2007-007
31. Wiser, Bolinger, and St. Clair, January 2005, Easing the Natural Gas Crisis: Reducing Natural Gas
Prices through Increased Development of Renewable Energy and Energy Efficiency, Ernest
Orlando Lawrence Berkeley National Laboratory (LBNL-56756)
70
Appendices
Appendix F Existing Process for Transmission Project Approvals and Case Histories
1. The Blue Ribbon Panel on Cost Allocation, Sept 2007, A National Perspective On Allocating the
Costs of New Transmission Investment: Practice and Principles, p 1.
2. Consortium for Electric Reliability Technology Solutions/Electric Power Group, June 2004.
Economic Evaluation of Transmission Interconnection in a Restructured Market, California
Energy Commission (CEC-700-04-007), pages 10-12.
3. CA ISO Department of Market Analysis and Grid Planning, February 2005, Economic Evaluation
of the Devers-Palo Verde No. 2.
4. Transmission Economic Assessment Methodology (TEAM), Anjali Sheffrin, June 14, 2004.
California Energy Commission IERP Workshop on 2004 Transmission Update.
5. Testimony of Lon W. House, November 22, 2005, Tipping Point Analysis and Attribute
Assessment for DPV No. 2, Office of Ratepayer Advocate’s Devers Palo Verde No. 2 Testimony
Vol. 3 of 3.
6. Malcolm Gladwell, 2000, The Tipping Point: How Little Things Can Make a Big Difference, Little
Brown and Company, New York.
7. Armie Perez, Vice President of Planning and Infrastructure Development, January 18, 2007,
Memorandum to CA ISO Board of Governors, Page 6.
8. Economic Analysis Subcommittee for Western Regional Transmission Expansion Partnership,
Final Report April 27, 2007, Benefit-Cost Analysis of Frontier Line Possibilities.
9. U.S.-Canada Power System Outage Task Force, April 2004, Final Report on the August 14, 2003
Blackout in the United States and Canada: Causes and Recommendations
10. “Framework for Expansion of the Western Interconnection Transmission System”, Seams
Steering Group – Western Interconnection (SSG-WI), Oct 2003. (Citation 57 from page 30), The
Battle Group International Review of Transmission Arrangements, Oct 2007
11. Consortium for Electric Reliability Technology Solutions/Electric Power Group, June 2004,
Economic Evaluation of Transmission Interconnection in a Restructured Market, California
Energy Commission CEC-700-04-007.
12. 2006 Net System Power Report, 4/12/07, Energy Commission Publication CEC-300-2007-007
13. Wiser, Bolinger, and St. Clair, January 2005, Easing the Natural Gas Crisis: Reducing Natural Gas
Prices through Increased Development of Renewable Energy and Energy Efficiency, Ernest
Orlando Lawrence Berkeley National Laboratory (LBNL-56756)
14. The Brattle Group, October 2007, International Review of Transmission Planning Arrangements,
– A report for the Australian Energy Market Commission, page 6.
15. A Mathematical Theory of Saving, Frank P. Ramsey, Economic Journal 1928 (December) pages
543-559.
16. The Social Discount Rate, Andrew Caplia and John Leaky, Journal of Political Economy, 2004, Vol
112, No. 6
17. Essay on Economic Growth, Maurice Dobb, Long, 1960 Chapter II
APA-1
18. Recalculating the Costs of Global Climate Change, Hal Varian, New York Times, December 14,
2006
19. The Social Discount Rate: Estimates for Nine Latin American Countries. Humberto Lopez, Policy
Research Working Paper, The World Bank, Latin America and the Caribbean Region, Office of
the Chief Economist, June 2008
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22. Estimation of a Social Rate of Interest for India, Kula E. Journal of Agricultural Economics, 55(1):
91-99, 2004
23. Social Discount Rates for Six Major Countries, Evans, D. and H. Sezer, Applied Economic Letters,
11: 557-560, 2004
24. The Elasticity of Marginal Utility of Consumption: Estimates for 20 OECD Countries” D. Evans,
Fiscal Studies, 26(2):197-224, 2005
25. A Time Preference Measure of the Social Discount Rate for the United Kingdom, David Evans
and Haluk Sezer. Applied Economics, 2002, 1026 P.34
26. Derivation of Social Time Preference Rates for the United States and Canada, Erham Kula
Quarterly Journal of Economics 1984, Vol 99, 11 P. 873-882
27. 2006 Net System Power Report, 4/12/07, Energy Commission Publication CEC-300-2007-007
28. System Analysis, Inc., Application Guides – Equipment Damage Curves Conductors, 2006,
www.skm.com
29. Electric Transmission Week, November 2004, “Two new transmission cables reaching market;
China seen as strong opportunity”
30. Composite Technology Corporation News Release August 30, 2004
31. Transmission & Distribution, August 1, 2006 “United States and Mexico Cross-Border
Connection” by Rob O’Keefe and David Kidd, American Electric Power, page 1
32. GE Energy, Variable Frequency Transformers – Grid inter-tie, www.ge-
energy.com/prod_serv/products/transformers_vft/en/downloads/vft_brochure.pdf
33. Transmission & Distribution World, October 1, 2004 “First VFT System in Service for
TransEnergie, a Unit of Hydro-Quebec,
http://license.icopyright.net/user/tag.act?tag=3.5531%3ficx_id=tdworld.com/mag/power_
united_states_mexico/index.html
34. Narain G. Hingorani in IEEE Spectrum magazine, 1996.
35. Donald Beaty et al, "Standard Handbook for Electrical Engineers 11th Ed.", McGraw Hill, 1978
37. Wiser, Bolinger, and St. Clair, January 2005, Easing the Natural Gas Crisis: Reducing Natural Gas
Prices through Increased Development of Renewable Energy and Energy Efficiency, Ernest
Orlando Lawrence Berkeley National Laboratory (LBNL-56756)
APA-2
38. Public Policy Institute of California www.ppic.org
39. Energy Information Administration - http://tonto.eia.doe.gov/FTPROOT/electricity/0562.pdf
40. Derived from Edison Electric Institute, EEI Pocketbook of Electric Utility Industry Statistics
(1983), p. 21
41. CPUC web site - http://www.cpuc.ca.gov/static/aboutcpuc/puhistory.htm
42. FERC web site - http://www.ferc.gov/students/whatisferc/history.htm
43. NRC web site - http://www.nrc.gov/about-nrc/history.html#aec-to-nrc
44. Energy Information Administration, "Fuel Choice in Steam Electric Generation: A Retrospective
Analysis," Volume 1, Overview, Draft Report, Table 2.
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46. Edison Electric Institute web site - Energy Policy Act of 2005 – Summary of Title XII – Electricity,
Title XVIII – Studies and Related Provisions
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DOE/EIA-0439(83) (Washington, DC, December 1983), p. 8.
48. http://www.nucleartourist.com/events/tmi.htm
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50. http://www.energyvortex.com/energydictionary/public_utility_regulatory_policies_act_of_1978_(
purpa).html
51. NRC web site - http://www.nrc.gov/about-nrc/history.html#aec-to-nrc
52. Energy Information Admin., Survey of Nuclear Power Plant Construction Costs 1984, DOE/EIA-
0439(84), pg. 13
53. SustainableFacility.com -
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Policy Act of 2005” by Duncan & Allen
56. Center for Study of Markets - University of California.
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APA-3
62. CPUC - Procurement and Resource Adequacy -
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63. CPUC Renewable Portfolio Standard Program -
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APA-4
Appendix B
o Requested Upgrades.
o Generation Interconnection.
o Reliability (Base Plan Upgrades).
o Economic (Supplemental Upgrades).
Requested Upgrades are projects that meet specific request or requirements of a customer and
are usually paid by the customer.
Generation Interconnection is to connect a new power plant to the electrical system and is
usually paid by the generator. There may also be need for system upgrade as a new significant
generator is being added to the system.
Reliability projects are transmission improvement that may be required to satisfy the existing or
new reliability criteria. Without such a transmission, there is potential for reliability related
problems and failure to meet the established reliability criteria.
Research indicates that the first three types of projects—requested upgrades, generation
interconnection, and reliability projects have clear drivers or mandates and tend to go forward
with little or no opposition. However, economic projects (including projects that address
specific policy objectives such as renewables integration and debottle-necking) often get
stymied due to different perspectives on need, benefits, and cost responsibility.
The economic projects are proposed to reduce the total cost to society. This includes economic
projects that are used for reducing bottlenecks and congestion, expanding access to regional
markets, meeting policy goals such as Renewable Portfolio Standards (RPS), and providing
insurance against multiple contingencies.
In this research, the emphasis is on methods that can be used to quantify benefits and allocate
costs of Economic (Supplemental Upgrade) transmission projects. The research results are
applicable to other types of projects and to projects that exhibit multiple dimensions of
economics, reliability, and operations.
APB-1
o Extreme Event Benefits.
There are also secondary benefits from new projects. These include: economic development, tax
base increase, use of right-of-way, and impact on infrastructure development. These secondary
benefits are not addressed in this study.
Primary or traditional benefits can be defined as cost reduction, congestion reduction and
expansion of access to regional markets to take advantage of load and resource diversity.
Primary benefits improve network reliability and result in lower cost of energy and capacity
adjusted for transmission losses.
There are also secondary benefits from new projects. These include: economic development, tax
base increase, use of right-of-way, and impact on infrastructure development. These secondary
benefits are not addressed in this study.
The types of benefits of new transmission projects depends on whether the region is at the
generation or exporting end or importing end of the transmission line. Benefits accruing to a
region are a function of location with respect to a transmission line as follows:
APB-2
Access to renewables.
Fuel diversity.
Emission reduction.
Insurance against contingencies.
Increased deliverability.
Decrease Market Power.
o Exporting and Importing Region Benefits
- Seasonal exchange.
- Sales of surplus energy.
- Reserve sharing.
- Reliability improvement.
There are many uncertainties that impact the size of primary benefit and types of strategic
benefits from a new project. These uncertainties include load forecast, fuel prices, development
of new generation and retirement of existing power plants, regional prices for electricity, and
environmental regulation. Production cost-simulation, scenario analysis, stochastic modeling,
and other techniques have traditionally been utilized to estimate a base level of benefit and the
sensitivity analysis to take into consideration future uncertainties. These models tend to come
up with base case, sensitivity cases, and expected value of benefits.
Another category of benefits relates to extreme events. In recent years, the August 2003
Northeast Blackout and the California 2000–01 market dysfunction put a spotlight on the
significant economic (billions of dollars) and societal impact of such extreme events. The
challenge is that traditionally, there has been no attempt to quantify the benefit of mitigating
extreme events or when it is done, an expected value approach is utilized which understates the
societal value of mitigating these very low probability but very high impact events.
One of the research conclusions is that insurance against extreme events be defined as
additional societal benefit for reducing exposure to extreme market volatility and multi-region-
wide blackouts due to multiple contingencies. While there is general consensus on the existence
of these types of strategic benefits, they are not easily quantified or captured using traditional
models. For example, policymakers anecdotally acknowledge the value of transmission projects
as insurance against contingencies, but there is no definition or examples of quantification of
such values.
The above category of benefits can be defined as Extreme Event Benefits and are in addition to
the Primary and Strategic Benefits. The value of extreme event benefits can be put in context
when some of recent power system experiences are examined. For example:
o 2001 California market dysfunction and volatility with a cost of $20-40 billion.
o 2003 Northeast Blackout due to multiple contingencies with a cost of $5-
10 billion.
Extreme Event Benefits can be defined as:
APB-3
3. Reliability—which is based on improved network load carrying capacity and ability to
reduce or mitigate impact of extreme events resulting from multiple contingencies (N-3,
4, 5, 6 events).
4. Market Volatility—which is based on societal benefit of reduced vulnerability to extreme
price volatility which could result from extreme system events, market dysfunction, or a
combination of factors.
Society’s willingness to buy protection against extreme events is well established in the
insurance industry, for example hurricane insurance, life insurance, re-insurance against major
losses. In each of these examples, there is a well established actuarial data base that allows
valuation of such insurance. However, there is not a rich data base related to extreme events in
the electric power industry as major blackouts and market dysfunctions are infrequent events.
Hence, the research challenge is to come up with alternative approaches that address these
benefits rather than dismiss them due to difficulty in quantifying them.
For economic benefit quantification of new transmission projects, the basic approach is to utilize
a Production Simulation Model. The analysis includes two alternatives: one with and another
without the proposed new transmission project. Many commercial production simulation
models are available, such as PROSYM, GEMAPS, PROMOD, and PLEXOS. Using a least cost
dispatch principle, the models forecast production from different generation resources and
associated fuel consumption, and emissions. To have a balance between loads and resources,
additional generation resources are also introduced over time. Based on fuel prices, costs of
various emissions and variable O&M costs, the total production cost over time are calculated for
a given load forecast and associated load shape. The difference in the total production costs
from the two simulations defines the gross benefit for the new transmission project.
The net benefit of the transmission project is then calculated by subtracting the capital cost and
annual O&M of the transmission project from the estimated gross benefit. Benefit cost ratios and
internal rate of return can also be calculated from the information provided by the annual
production costs, capital, and O&M expenditure of the transmission project.
To take into consideration the uncertainty of factors such as fuel costs, load forecast, and capital
cost of the transmission project, Decision Analysis Models have been utilized to estimate the
expected value and the distribution of net benefit or benefit cost ratio. These may also utilize
Influence Diagrams that shows the factors that have great impact on benefits and costs of the
project.
APB-4
Carrying out detailed production cost simulation with and without project are data intensive,
time consuming, and expensive. This becomes more difficult when the detail of transmission
network is included in the model in addition to the generation system. Furthermore,
information on planned new generation development is based on market economics and data is
generally not available beyond 5 to 10 years, while transmission projects are expected to last 50-
years or more and deliver benefits during the entire period.
At the pre-feasibility level the use of a Spreadsheet Screening Analysis may facilitate studying
many transmission options quickly and at less time and expenditure than using detail
production simulation models. An example of this approach will be discussed later when the
benefit-cost analysis of Frontier Line is reviewed.
Spreadsheet Screening Analysis is useful when new generation resources at export region plus a
new transmission is compared with new generation resources at import region. This approach
allows comparison of many alternatives quickly. The results provide forecast of fuel
consumption, emission, and variable O&M and fixed O&M costs. Benefit and cost of a new
transmission is then calculated based on such information for different alternatives by including
capital costs of generation at export and import regions, fuel prices and capital cost of the
transmission project.
To concentrate the analysis on assumptions and relationships that greatly influence the project
benefits, the use of Tipping Point Analysis method is sometimes utilized. In applying this
method, an economic criterion for the project is established. Potential tipping points which are
associated with key variables are listed and tested. The level of tipping point where benefit/cost
is less than one are determined and the potential for ending up with benefit/cost less than one
are evaluated and discussed for these tipping points.
In this section, the analytical tools and benefits quantification methods for benefit analysis for
three different projects are discussed. The three projects are Devers-Palo Verde No. 2 (DPV No.
2), Tehachapi, and Frontier Line.
APB-5
o Provide additional transmission infrastructure to support the development of
additional generation capacity that will sell energy into California market.
o Provide increased reliability and flexibility in operating California’s transmission
system.
SCE has used a production cost simulation model (PROSYM) to estimate energy cost saving
resulting from the construction of DPV No. 2. This project is estimated to decrease electricity
prices in California, which is the primary benefit of this project. There will also be additional
third party transmission revenue due to increased CA ISO wheeling through or out of the CA
ISO grid.
Southern California Edison evaluation shows a B/C ratio for DPV No. 2 at 1.7. Energy benefits
are based on production cost simulation for 2009–2015 and then escalated at GDP price index
(around 2.28% per year) for the rest of economic life of the project.
At the request of CA ISO, SCE has provided energy production cost for Western Electricity
Coordinating Council (WECC) for the years 2009 through 2014 with and without DPV No. 2.
Using the cost saving numbers provided by SCE for WECC, the present value of the quantified
benefits from energy and third party transmission revenue is less than the capital cost of DPV
No. 2, using a 5% discount rate.
The WECC regional benefit for this project is low, in part, because strategic benefits such as
insurance value during extreme system conditions, reduction in generators market power,
potential for development of new generation outside of California and environmental benefits
beside NOx reductions are not quantified in WECC regional benefit calculation.
CA ISO has used its Transmission Economic Assessment Methodology (TEAM) approach and
PLEXOS cost production simulation model to quantify the benefits from DPV No. 2. Benefits
include cost saving in energy, transmission loss reduction, emissions reduction, market power
mitigation, and contingency. CA ISO’s proposed methodology for benefit quantification of the
transmission projects address the following major issues: modeling of market power;
development of a robust set of scenarios; selection of appropriate simulation tools or programs;
a detail representation of the transmission network and the assumptions of the future
generation system; and, selection of benefit tests. Detailed description of these elements is
provided in a report prepared by Consortium for Electric Reliability Technology
Solutions/Electric Power Group for the Energy Commission in June 2004 33.
o The participant/ratepayer test (benefits to those entities that will be paying for
the new facility).
33. Consortium for Electric Reliability Technology Solutions/Electric Power Group, June 2004. Economic
Evaluation of Transmission Interconnection in a Restructured Market, California Energy Commission
(CEC-700-04-007), pages 10-12.
APB-6
o The societal test (benefits to all consumers, producers, and transmission owners,
regardless of who pays for the upgrades).
o The modified societal test recognizing or excluding non-competitive revenues
(monopoly rent) collected by some producers.
The societal test is measured by the change in production costs across the entire interconnection
(in case of DPV No. 2 over the entire WECC). A transmission expansion project is deemed to
pass the benefit test if: 1) it benefits each participant, and 2) the entire societal or the modified
societal benefit exceeds the project cost.
The WECC base case data is the foundation of the CA ISO modeling. CA ISO’s PLEXOS model
of the entire WECC requires significant amounts of input data. Due to the limited available CA
ISO staff time for the collection of input data for each year, CA ISO modeling for the economic
analysis of DPV No. 2 was done only for two years—2008 and 2013.
34. CA ISO Department of Market Analysis and Grid Planning, February 2005, Economic Evaluation of
the Devers-Palo Verde No. 2.
35. Transmission Economic Assessment Methodology (TEAM), Anjali Sheffrin, June 14, 2004. California
Energy Commission IEPR Workshop on 2004 Transmission Update.
APB-7
CA ISO filed TEAM with CPUC in June 2004. CA ISO has demonstrated in actual studies the
use of TEAM for Path 26 and DPV No. 2. The methodology clearly indicates impacts of a new
upgrade at the participants’ level and also regional (WECC) levels.
Several new elements identified in this research could be added to TEAM to further expand
quantification of benefits, such as:
o Extreme event benefits such as improve network load carrying capacity under
multiple contingencies.
o Reduced vulnerability to extreme price volatility due to long term outages and
catastrophic events.
o Dynamic impact of a large transmission projects on the development and
construction of additional generation capacity in the exporting region.
By adding the above benefits to TEAM, the methodology will be able to capture the benefits
from risk mitigation of low probability/high impact extreme market events and the benefits of
development of new generation to both exporting and importing region. Without taking into
consideration such dynamic impacts, the analysis becomes a zero-sum game whereby there are
higher electricity prices in the exporting region with the implication that the investment in a
transmission line has negative impact on consumers of the exporting region. In fact, this factor
contributed to the recent rejection of DPV No. 2 by the Arizona Corporation Commission.
Division of Ratepayer Advocates at CPUC has also carried out a review of the DPV No. 2. This
report was prepared in three volumes that were published in November 2005. Volume 3 of this
study describes the Tipping Point Analysis for DPV No. 2 36.
As described by Dr. House in his DRA Testimony, Tipping Point analysis has gained popularity
in the social sciences since Gladwell’s 2000 book, How Little Things Can Make a Big
Difference 37. The analysis starts with defining the topology of the interactions (similar to the
Influence Diagram in Decision Analysis). Then through some analysis it is determined which
interactions are critical to the outcome (tipping points).
Dr. House’s analysis shows that tipping point variables for the DPV No. 2 project are:
36. Testimony of Lon W. House, November 22, 2005, Tipping Point Analysis and Attribute Assessment
for DPV No. 2, Office of Ratepayer Advocate’s Devers Palo Verde No. 2 Testimony Vol. 3 of 3.
37. Malcolm Gladwell, 2000, The Tipping Point: How Little Things Can Make a Big Difference, Little
Brown and Company, New York.
APB-8
“In order for DPV2 to be cost effective, the natural gas price differential between
Arizona and California has to be greater than $0.50/MMBtu, the wholesale Topoc
price of natural gas has to be greater than $5.00/MMBtu and Palo Verde (Nuclear
Generation Station) has to be operating.” 38
Furthermore, DPV No. 2 is more valuable to California in the event of an outage of San Onofre
Nuclear Generation Station (SONGS).
Tipping Point Analysis provides clear information on critical variables and allows the analyst to
concentrate on high impact factors rather than spend a great deal of time and effort on elements
that do not materially change the outcome of the analysis.
In addition, the project also addresses the reliability needs of the CA ISO controlled grid caused
by load growth in the Antelope Valley area, as well as transmission constraints South of Lugo.
The main benefit of this project is to enable California utilities to buy power from wind
generation projects and to comply with the state mandated Renewable Portfolio Standard (RPS)
program.
The project justification for Tehachapi is renewable resource integration and reliability. While
resource integration has an economic dimension, the project justification is based on meeting
state RPS mandates rather than benefit cost analysis. The Tehachapi project evolved from the
Tehachapi Collaborative Study Group, which was formed in 2004 at the direction of CPUC. The
goal was to develop a comprehensive phased transmission development plan for integration of
renewables planned for development in the Tehachapi area. Two reports were issued and
submitted to CPUC in March 2005 and in April 2006. The outcome was the identification of a
number of alternatives for the transmission infrastructure. A recommendation was made to
further study these alternatives by the CA ISO.
The CA ISO in full collaboration with SCE and stakeholders carried out the Tehachapi
Transmission Project study as part of its CA ISO South Regional Transmission Plan for 2006
(CSRTP-2006). A least-cost solution for the interconnection of planned generation was
developed by CA ISO.
The total cost of the Tehachapi Transmission Project is estimated at $1.8 billion in nominal
dollars. This cost excludes the cost of Interconnection Facilities (radial wind collector
transmission systems that will interconnect the individual generation projects to the grid and
APB-9
will be the responsibility of generation developers). SCE is the Project Sponsor and the project is
subject to necessary regulatory approvals from CPUC and FERC, which have either been
received or expected.
The Tehachapi Transmission project phased development plan includes:
CA ISO has used the concept of clustering in the Tehachapi Transmission Project. Clustering
allows the study of the system impacts of a group of interconnection requests collectively,
rather than evaluating each potential generation project one at a time. This results in greater
efficiency in the design of needed network upgrades.
The clustering approach for the Tehachapi Transmission Project will result in substantial capital
cost saving compared to any piecemeal upgrade solution with a traditional project by project
approach.
However, in the Tehachapi Transmission Project, the CA ISO has deviated from a typical
clustered interconnection study. The CA ISO study considered only the network components or
network upgrades of the transmission system and excluded the radial wind collector
transmission systems. Furthermore, an element of clustering is the selection of a time window
for determining which generation projects in the queue will be included in the cluster (i.e., the
Queue Cluster Window). The Tehachapi Transmission Project defined the Queue Cluster
39. Armie Perez, Vice President of Planning and Infrastructure Development, January 18, 2007,
Memorandum to CA ISO Board of Governors, Page 6.
APB-10
Window as the projects submitted from August 19, 2003 through April 2006, which exceeds
FERC limit of 180 days for the Queue Cluster Window.
Due to the specific circumstances presented by Tehachapi Project, CA ISO has filed a petition
with FERC for approval to proceed with the proposed study approach on a one-time basis.
CA ISO Board has approved the Tehachapi Transmission Project as the Network Upgrades
necessary to allow Generating Facilities in the Tehachapi Wind Resources Area to deliver their
output to CA ISO grid. The Board has directed SCE to proceed with the permitting and
construction of this project. FERC’s approval of the CAISO waiver request for provisions of
Large Generator Interconnection Procedures (LGIP) allowed this project to move forward.
To perform a screening level economic study, the Economic Analysis Subcommittee developed
a spreadsheet tool to quantify benefits and costs of multitude of possible alternatives and
scenarios. These alternatives included: a variety of load and resources scenarios, a myriad of
conceptual transmission links and configurations identified by the Transmission Subcommittee;
a wide range of natural gas prices and possible costs for new clean coal technology, including
integrated gasification combined cycle (IGCC) and carbon dioxide sequestration; and a broad
spectrum of potential policy actions such as regional and/or national renewable portfolio
standards, state and federal tax incentives for preferred resources such as wind or solar or clean
coal, and regulatory regimes in greenhouse gas emissions.
FEAST is a simple tool for knowledgeable users. It considers incremental resource additions,
not a complete supply stack which would include all the existing generators.
For this screening analysis, the Gross Benefits ($) of the transmission project is based on the
following formula:
Energy Potential is the rated capacity of the line multiplied by 8,760 hours. For example, if the
Frontier Line is rated 3,000 MW, then energy potential would be 3,000x8760 or 26,280 GWh per
year.
APB-11
Line Utilization is a function of the quantity and characteristics of resources available to be
imported as compared to the line’s energy potential. (Basically, capacity of generation resources
installed in exporting region multiplied by assumed capacity factors for each resource and
subject to the transmission line and system constraints.)
Regional Basis is the energy cost difference between the exporting region and the importing
region. This Regional Basis is influenced by many factors, including the capital cost of new
generation resources, fuel costs (gas, coal, and others), environmental mitigation costs,
renewable energy price premiums, Green House Gas (GHG) adders, and others.
Benefits in addition to energy benefits include: capacity, losses, emissions, insurance value
against extreme events, economic impacts due to construction of transmission and generation
facilities, tax benefits, reliability improvement and others.
Many of the subcommittee members provided input on fuel prices, capital cost for generation,
ranges for Green House Gas adder, capacity factor for wind energy in different regions, and
other assumptions. The FEAST Spreadsheet Model was developed by staff of PG&E.
FEAST can handle several exporting regions (source options): Wyoming and Montana (coal and
wind), and several importing regions (sink options), including Utah, Nevada, Arizona, and
California. Resources considered for importing regions can be gas-fired CT or CCGT or IGCC
and renewables (for Utah coal, gas, renewables). For exporting regions, resources can be wind
and/or clean coal.
A mix of generation resources for exporting and importing regions are assumed. Taking into
consideration capacity and capacity factor of these generation resources, the amount of energy
going from source to sink is calculated.
FEAST is an energy focused analysis. Attempt is made to balance energy produced from the
generation resources in the sinks and sources. The installed capacity of generation ends up
being different for sinks and sources.
The Economic Analysis Subcommittee performed its work using a participatory stakeholder
process. Volunteers led the effort to create FEAST inputs. Individual subcommittee members
were able to perform their own analysis based on some of their own inputs.
The final report of this subcommittee was submitted to Western Regional Transmission
Expansion Partnership (WRTEP) on April 27, 2007 40. Two most important conclusions of the
report were:
1. The benefits of the Frontier Line appear greater than the costs under a variety of
plausible scenarios.
2. Uncertainty associated with key inputs results in a wide range of benefit-cost outcomes.
40. Economic Analysis Subcommittee for Western Regional Transmission Expansion Partnership, Final
Report April 27, 2007, Benefit-Cost Analysis of Frontier Line Possibilities.
APB-12
The economics of the Frontier Line, as expected, are very sensitive to natural gas prices and the
values used for GHG adder. Economics of the Line are also somewhat sensitive to capital costs
for clean coal technologies, including IGCC and CO2 sequestration.
The primary focus of the analysis that was carried out by the Economic Analysis Subcommittee
was economic efficiency from a total societal point of view, i.e., the analysis produced the
overall benefit-cost ratio for the region as a whole. Of course, it is important that the Frontier
Line produces benefit for each individual jurisdiction participating in the project, i.e., benefit be
greater than cost for each state. The Economic Analysis Subcommittee did not analyze cost
allocation so that each jurisdiction participating receives a net benefit from the project.
However, FEAST enables each user to perform its own analysis and assess benefits and costs
allocated.
As stated in the Final Report of the Benefit-Cost Analysis of Frontier Line, FEAST is not a
substitute for production costing simulation tools. Analysis using FEAST may be a first step to
quickly sort through a multitude of possibilities. FEAST is a tool to perform quick what-if
screening analysis. It is a simple spreadsheet-based tool enabling and empowering
sophisticated users to carryout a variety of analyses quickly, with the aim of developing user
insight rather than producing overly precise numerical results 41.
41. Reference 9 p 8.
APB-13
Summary of Benefit Analysis of
Transmission Projects
Project Description Purpose Comments
Palo-Verde 500 kV line between Arizona and Reduce California Benefits to California estimated using
Devers California electricity costs production cost and sensitivity analysis
No. 2 Single utility and single rate Strategic and regional benefits not
jurisdiction (CA ISO) addressed
$500 million cost Static analysis – assumed generation
1,300 MW capacity capacity fixed
Tehachapi Designed in several phases to Enable integration Least cost solution to meet RPS mandate.
interconnect 4,350 MW of new wind of new wind
generation generation in CA
Required CA rate back-stop and ISO queue to meet
innovative CA ISO tariff to allocate RPS
costs
$1.8 billion cost
Costs allocation among generator
(gen-tie), CA ISO grid users, and CA
ratepayers for cost recovery back-stop
Frontier 500 kV Designed to enable Benefits estimated using screening
Line 3,000 MW construction of new model – FEAST
$2 billion cost
generation in Benefits result from cost differential
Wyoming/Montana (capital and fuel) between resources
Multi-state, multi-utility, multi-
for export to CA, developed in CA vs. WY/MT
jurisdiction NV, UT, AZ Strategic benefits not quantified
Strong state government support in
exporting regions
No strong utility project sponsor
Of the three projects, Tehachapi is moving forward. Palo Verde-Devers No. 2 was rejected by
the Arizona Commission and SCE, the project sponsor, is moving ahead to construct the
California segment of the transmission line and continuing to pursue approval from FERC for
the Arizona portion. Frontier Line is still in the conceptual planning stages.
From this review, the following observations and conclusions are presented.
APB-14
o Analysis required data intensive assumptions about future loads, resources, fuel
prices, and policies.
3. Problems encountered by projects
o Limited showing of benefits for key stakeholders, e.g., Palo Verde-Devers No. 2.
o Ambiguity about objectives and goals, including changing policies, e.g., Frontier
Line.
APB-15
APB-16
Appendix C
For economic transmission projects, the goal should be to allocate costs to project beneficiaries.
The principle of beneficiaries should pay or that cost causers should be cost bearers applies.
For economic transmission projects, the ownership of the project could be: the utility in whose
service area the project is located, a merchant owner, or joint transmission owners when the
transmission line goes through several service areas and the line in each service area is owned
by the utility of that service area.
Cost recovery could be based on: transmission access charge, contract rights, subscription or
auction. In an RTO, if the transmission is a reliability upgrade and is needed to maintain the
integrity of the transmission grid, the costs are rolled in to the transmission charge. Costs can be
rolled-in: (a) fully, (b) partially with remaining costs allocated to zones or beneficiaries, and (c)
by using a voltage test and either 100% of the cost is rolled-in to an RTO wide rate or 100% into
zonal rate(s).
Alternatives for cost allocation of economic type transmission projects in an RTO could be:
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10. 100% of the cost is rolled into RTO base rate.
As above alternatives for cost allocation shows, the size and distribution of the project benefits
may be utilized for cost allocation among beneficiaries. Therefore, improved benefits
quantification will be useful in: 1) providing guidance on cost allocation among multiple
participants and jurisdictions, and 2) selecting cost recovery methodology.
The cost of service is then allocated over billing determinants. Currently, there are three
alternative transmission rates used in different jurisdictions:
d. Energy—postage stamp.
f. Distance—Megawatt-mile.
Cost recovery is accomplished through rate cases that are submitted by the transmission owner
(TO) utilities to the commission in each state. In addition, FERC filing may also be required to
establish the rate for use of transmission. FERC has exclusive jurisdiction over transmission
rates. To eliminate transmission rate pancaking (paying multiple wheeling charges for a path),
FERC has been encouraging formation of ISOs and RTOs.
To stimulate the construction of new transmission lines, FERC has indicated that it will allow
performance-based regulation proposals and consider innovative transmission pricing
proposals including a higher rate of return on equity, levelized rates, accelerated depreciation
and incremental pricing for new transmission projects.
Figure 8 shows a framework for the use of benefit quantification for both cost effectiveness and
cost allocation under single and multiple utilities and single and multiple jurisdictions.
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Framework for Use of Benefit Quantification for
Project Cost Effectiveness and Cost Allocation
Transmission Project
F igure 8. F ramework for Us e of B enefit Quantific ation for P rojec t C os t E ffec tivenes s and C os t
Alloc ation
For multi jurisdiction projects, the preferred way for the cost allocation will be first to allocate
the cost to each of the jurisdictions and then allow each jurisdiction to allocate their share of cost
among utilities and other users based on that jurisdiction’s cost allocation methodology. Cost
allocation to the multiple jurisdictions could be based on the following alternatives:
a. Participation Ratio
- Allocate costs and MW capacity of the transmission according to participation
ratio or native load ratio.
b. Subscription Open Season
- Participation based on requested subscription (need and benefits assessment
by each utility), each subscriber performs individual benefit assessment. Cost
allocated based on the requested level of subscription.
c. Auction Methodology
- This method promotes MW allocations to participants who will get the
highest benefit from the utilization of the new transmission project.
The project sponsor or RTO can establish an auction to allocate the capacity that becomes
available from a new transmission line. Participants, based on their own assessment of how
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much benefit they will receive from the new project, can submit bids into the auction process.
Capacity of the line will be allocated to users who value this capacity most.
At least two auction methods can be designed for this capacity allocation. First is a round of
ascending price auction similar to CA ISO annual FTR auction. Second is the single price and
quantity bids auction.
In the first method, the auction starts for a given period with a $/MW-year payment at a level
close or just below the annual revenue requirement for the project. Each period could be one
year, or to encourage multi-year power contract and construction of new generation, it could be
multiple of 5-years for a total of say 30-years.
If the result from the first round of bids is a total MW of bids higher than the transmission line
capacity, the payment will be increased and the second round of the auction will be carried out.
The auction round will be repeated until there is a balance between total bids and the online
capacity available. This last round will determine the line capacity allocation amongst different
parties and the payment for each MW-year.
The same auction process will then be carried out for the next period (next year or next 5-year
period). This per period allocation could be repeated to cover the entire economic life of the
project (or the duration for repayment of entire capital cost of the project).
Total payments generated from the auction over the periods have to be equal or greater than
total revenue requirements to show that the project is cost effective. (Project sponsor has to
come up with fixed revenue requirement. The project cost has, therefore, to include reasonable
contingency cost. The allowed rate of return may be somewhat higher than normal allowed
rate to compensate for fixed cost for the construction of the line.)
If the total payments generated in an auction are higher than the fixed revenue requirements
and variable O&M cost, then the overpayments will be retained by project sponsor or RTO for
decreasing the cost of grid reliability improvement projects.
If the total payments generated in an auction are not sufficient to cover the revenue requirement
of the project then the project should not be developed, since the beneficiaries are not willing to
pay the total cost of the project.
In the second type of auction, each bidder submits a payment and quantity for each period.
Based on all bids received, a demand curve is developed for each period. The intersection of the
demand curve and the capacity of the transmission line would determine the payment level for
each MW and the amount of capacity to be allocated to each one of the winning bidders for this
period.
The auction process is repeated for each period until the last period. Again, if the total
payments are higher than the total revenue requirement, a process will be developed to use this
surplus fund.
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In both auctions, every participant pays the same market clearing price for a given period. The
auction provides a mean to allocate the line capacity to participants who value such capacity
most.
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Appendix D
There are several options for transmitting energy from remote generation resources to the
various load centers within the Western Interconnection. The amount of energy to be
transmitted and the overall distance become key factors as to which of the options becomes
more desirable, as is the impact that a new transmission project will have on the existing WECC
grid. The following is a recap of the research findings:
• The use of new technology conductors appear to be best utilized and cost effective in the
integration of new or upgraded transmission lines into urban transmission networks.
• Superconducting cables appear to also be best utilized in urban areas, especially where
extremely high capacity underground transmission is required.
• The use of High Voltage Alternating Current (HVAC) (765 kV) transmission would
allow for the movement of bulk power over great distances. This new technology is in-
service in the Eastern Interconnection and performing as anticipated. Because there is
no existing 765 kV infrastructure within the WECC, adding a single 765 kV line (to
deliver 3,000 MW) would have a negative impact on grid stability and unscheduled
flow. Developing the supporting infrastructure to integrate 765 kV into the western grid
would have some significant costs consequences.
• To use 500 kV AC (to deliver 3,000 MW), two lines would be required to carry large
amounts of energy (500 kV AC lines are typically rated at 1200-1600 MW/line). This
option will require additional Right-of-Way.
• Utilization of Variable Frequency Transformers (VFT) and Phase Shifting Transformers
has the ability to protect the rights of participants when AC transmission options are
used.
• Utilization of Flexible AC Transmission System (FACTS) is expected to be an essential
element of all future AC transmission lines to ensure grid reliability, and can assist in
managing the flow of power over specific lines in a transmission network.
• At this time, to transmit 3,000 MW of energy, or higher over long distances (over 400 to
500 miles), the most cost effective method is the implementation of a High Voltage
Direct Current (HVDC) line for the following reasons:
o HVDC affords the ability to explicitly control the power flow on the transmission
lines
o HVDC will not negatively impact unscheduled flow.
o HVDC is isolated from AC system faults.
o HVDC system multi-terminal converters could be utilized if multiple pick-up
and drop-off points are required. This technology is available and in-service
today.
HVDC can be integrated with the AC system to create a hybrid form of transmission. This
option provides a HVDC link over the longest line section to a central delivery facility at which
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point the project participant(s) can take delivery into their respective AC system. This option
eliminates the need for multi-terminal converters.
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1.0 Introduction
The need for investments in transmission infrastructure and new technologies has been
accepted for some time. In recent years, this has translated into policy support for new
transmission projects. Recently, there has been much discussion regarding the construction of
new EHV transmission lines in the Western Interconnection. The governors of California,
Nevada, Utah and Wyoming had proposed a new interstate EHV transmission line across the
Western U.S., from Wyoming with terminal connections in Utah, Nevada and California. Some
of the Arizona utilities and others are considering an EHV transmission project from Wyoming
to the Desert Southwest area, and PG&E has proposed an EHV project from British Columbia to
Northern California. Within California, projects in the various stages of planning and regulatory
approval include Palo Verde Devers No. 2, Tehachapi, Transbay cable, Greenpath, and Sunrise.
Such new transmission projects would provide the necessary links to new and diverse
generating resources, such as renewable and clean coal resources. The development of any of
these new transmission projects in the Western Interconnection would bring the following
benefits:
The purpose of this research is to review available technologies and assess implications on cost
allocation and cost recovery for new infrastructure investments.
Construction of new EHV transmission lines between the various sub-regions of the Western
Interconnection is being driven by the following four (4) needs:
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• California faces a significant need for new generation. Using a historic growth rate of
2% per year, California must add 1,000 MW of new capacity each year, net of
retirements, into the foreseeable future. New transmission lines into California are
essential in meeting that need. In addition, California needs to find new renewable
resource supplies to meet the State mandated Renewable Portfolio Standard (RPS).
• As a region, the West has seen load growth of more than 60 percent in the last 20 years,
but investment in high-voltage transmission lines increased less than 20 percent.
Investment in new EHV transmission, besides providing a pathway to new generation
resources, will ease existing transmission bottlenecks and enhance the overall reliability
of the region.
• New EHV transmission lines provide an insurance benefit that will help mitigate the
impacts of adverse hydro conditions, fuel price volatility, and potential market power
abuse and better ensure against catastrophic events like blackouts.
One of the key implications for cost recovery and cost and benefit allocation is the capability of
any proposed transmission project to dependably deliver power over the intended transmission
path(s). Electric power flows according to physical laws, not contract laws, and as such, power
moves over the transmission lines that offer the lowest resistance (impedance) between the
source generators and the load. The ability to manage and control new power deliveries to
travel over the facilities designed and installed to accommodate those deliveries is expected to
significantly affect the ability of the project developers to allocate costs and benefits among the
project participants, and to assure that the participants are able to recover their costs through
dependable power deliveries, while not adversely affecting adjacent transmission systems.
Technologies that can deliver the benefits of new investment to the owners are likely to
influence debates regarding cost allocation.
This review of transmission technologies examines the several options from the perspective of
their ability to increase power deliveries and manage the flow of power.
The U.S. electricity transmission system is an essential component to our nation’s economic
vitality.
Within the Western Interconnection, the investment in new transmission facilities has declined
over the past few decades, the customer demand is increasing and there is the continuing need
to operate a reliable grid. The expansion of the electricity delivery system is crucial to the
region’s economic and security. In addition, the transmission system is vital to supporting an
ongoing competitive wholesale electricity market and in achieving the states Renewable
Portfolio Standards.
The objective of this report is to identify how the use of new transmission technology may
impact the operation of new transmission facilities and cost allocation of a project. In order to
effectively discuss the role of advanced transmission technologies, consideration must be given
to how they can be deployed in the grid and their functionality.
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1.1. Conductors
Heat is the prime enemy of conductors. The more power that is pushed through them, the
more they heat and sag, and it is sag and clearance that ultimately determine maximum
conductor loading.
The manufacturers of conductors have, with the assistance of the 2005 Federal Energy Act,
developed new conductors that can be loaded to higher current levels by reducing the sag
component of their conductors.
The current carrying capacity or ampacity of a conductor is directly proportional to the cross-
sectional area of the conducting material. This cross sectional area is usually measured in
square inches. In the late 1800s, the U.S. electric industry standardized conductor sizing by
agreeing to use circular mils for measuring the cross-sectional area of conductors. A circular
mil is the area of a circle with a diameter of one mil (0.001 inch). The abbreviation of circular
mils is cmil. There are 1,273, 200 circular mils in one square inch. For conductors having a
cross-sectional area smaller than or equal to 211,600 circular mils, the industry elected to adopt
the Brown and Sharpe wire gage designated in 1857, what we now call American Wire Gauge
(AWG). The area of a large conductor is often designated in kcmil (thousand circular mils)
rather than cmil. For example, the cross-sectional area of 4/0 AWG is 211,200 cmil or 211.2
kcmil.
APD-5
This conductor is made from aluminum-silicon alloy of high electrical conductivity containing
enough magnesium silicide high strength aluminum alloy 42 to give it better mechanical
properties after treatment. These conductors are generally made out of aluminum alloy 6201.
This conductor as compared to the industry standard ACSR has the advantage of lower power
losses (the inductive effects of the steel core in the core is eliminated), excellent corrosion
resistance in environments conducive to galvanic corrosion, better strength to weight ratio,
improved electrical conductivity than ACSR of equal diameter and greater resistance to
abrasion than that for Type 1350 aluminum used for ACSR. The two conductor types (AAAC
and ACSR) are similar in that the fittings are the same and the sag characteristics are similar.
The ACSS conductor can operate continuously at high temperatures without any detriment to
its mechanical properties. It will sag significantly less at high temperatures than ACSR
conductors when the maximum tension is present under ice and wind loading. The sag-tension
performance of ACSS is not affected by long time creep of aluminum. This material has a high
capability for damping mechanical oscillations, such as those associated with wind vibration. It
also has a high degree of immunity to vibration fatigue.
The ACSS aluminum wire strands are annealed, giving them low yield strength. Because of
their low yield strength, inelastic elongation of the aluminum strands occurs quite rapidly when
tension is applied to the conductor, thereby forcing most of the load onto the steel core. The
designation “Aluminum Conductors – Steel Supported” derives from the fact that under most
normal operating conditions there is little or no stress in the aluminum wires and even under
maximum tension there is minimal reliance on the strength of the aluminum.
ACSS aluminum is soft; some additional emphasis must be given to normal precautions to
avoid scuffing of the surface during installation and maintenance. When used to replace the
same size ACSR this conductor is normally heavier and thus requires higher tension and can
result in tower modification. It is also higher cost than ACSR.
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Both new ACSS products have a full line of sizes. ACSS sizes range from 266.8 kcmil to 2312
kcmil; ACSS/TW conductor sizes range from 477 to 2627 kcmil.
Installation of the ACCR is similar to that of conventional ACSR conductor. Listed below are
the locations where this conductor is already installed or being installed.
The installation of this new family of conductors has a few differences in the methods of
installation as compared to the standard ACSR. The pulling of the conductor requires, in most
cases, larger rollers at the tower. For instance, in a recent installation of the 3M ACCR, 3M
provide the first roller from the pulling dolly, and recommended the use of larger rollers (28
inch) at each tower (note: the larger rollers are readily available). The splice is made with a
special process and splice kit. The kit is also provided by the manufacturer, as is an on-site
technical advisor.
44. System Analysis, Inc., Application Guides – Equipment Damage Curves Conductors, 2006, www.skm.com
45. Electric Transmission Week, November 2004 “Two new transmission cables reaching market; China seen as strong opportunity
APD-7
Even though this material is new, it is making an impact in the industry since its introduction.
A 2004 news release reporting on a reconductor project indicated “This initial installation in the
city of Holland, Michigan utilized over three thousand feet of ACCC conductor.” 46
China is purchasing 175 miles of the ACCC to be delivered in the first quarter of 2007.
ACCC has a core made of a carbon fiber composite. The outer layer is softer aluminum with a
trapezoidal strand design. The rated operating temperature is 180°C, with a recommended
short term maximum operating temperature of 200°C. The glass transition temperature (Tg) 47
of the core is 215°C. At temperatures above the Tg, the properties of the core change and
strength is affected.
High temperature superconductor (HTS) wire enables power transmission and distribution
cables with three to five times the capacity of conventional underground AC cables and up to
ten times the capacity of DC cables. They support general load growth, add controllability of
power over a meshed grid, and can be implemented with low environmental impacts.
The inherently low impedance of this type of cable assembly enables control of power flows
over the surrounding grid network. Liquid nitrogen, the dialectic and coolant of choice to
APD-8
maintain the HTS wire at its operating temperature, is inexpensive, abundant and
environmentally safe, eliminating the oil used in some conventional power cables.
Superconducting cables are ideal solutions for grid bottlenecks. In addition to enabling more
effective transmission and distribution of energy, superconducting cables are also inherently
able to regulate the power flow through the cable. As an HTS Cable overload begins, the
superconducting HTS wire begins to overheat, reducing its superconducting properties,
increasing its resistance, and hence reducing the power flow through the cable.
HTS Cables are “out of the lab” and being deployed in multiple projects in the grid, including 4
US projects (Albany, NY; Long Island, NY; and Columbus, OH; and Carrollton, GA) as well as
at other locations around the world.
The capabilities of HTS superconducting cables suggest that the most practical applications will
be in urban settings where greater underground power delivery capabilities are required than
can be supported by conventional cables.
In addition to its cable application, HTS superconductors are effectively used in dynamic
reactive power compensation modules, such as SuperVAR Synchronous Condensers, Dynamic
VAR Compensators, and Distributed Superconducting Magnetic Energy Storage Systems (D-
SMES). These are devices that make use of superconducting windings in synchronous
condensers or superconducting magnets to provide technology that can dynamically inject or
absorb reactive power to regulate grid voltages and enhance grid stability. The first SuperVAR
Synchronous Condenser was installed in December of 2003 in the TVA system.
Superconducting motors and generators are also being developed and deployed.
Today, the application of superconducting VAR devices is primarily focused on the distribution
system, but these devices could be used to provide dynamic voltage support to the EHV grid to
enhance grid stability and power delivery capability.
APD-9
The new higher temperature conductors could have a very significant impact on the utility
industry around the country and the world. It allows utilities to revisit their needs knowing
that there are feasible alternatives that can be implemented to tackle their demand. Even
though these new conductors have a greater current carrying capacity, they appear to be better
suited for upgrading transmission lines in urban areas than in new transmission line
construction, because of the high cost of the advanced conductors.
48 49 50 51 52 53
ACSR AAC AAAC ACSS ACCC ACCR
795 kcmil 1094 lbs 745 lbs 865 lbs 1040 lbs 891 lbs 896 lbs
Weight/kFt
APD-10
2.0 Unscheduled Power Flow
Controlling power flow in one or more of the various parallel AC transmission lines would
permit more effective use of transmission resources. Conventional devices for power-flow
control include series capacitors to reduce line impedance, phase shifters, and fixed shunt
devices that are switched to the end of a line to adjust voltages. All of these devices employ
mechanical switches, which are relatively inexpensive and proven but also slow to operate and
vulnerable to wear, which means that it is not desirable to operate them frequently and/or use a
wide range of settings; in short, mechanically switched devices are not very flexible controllers.
Nonetheless, they are still the primary means use for stepped control of high power flows.
The following sections will discuss the various transmission components and technology that
provides the capability for flow control on both AC and DC transmission grids.
54. http://www.ornl.gov/~webworks/cppr/y2001/misc/122375.pdf
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2.1. Phase Shifters
As discussed above, the fundamental characteristic that makes transmission planning and
investment so difficult is the lack of control of the power flows over the grid and the inability to
control the flow through individual transmission elements. Devices such as phase shifters and
direct current (DC) links allow control, but are much more expensive than traditional AC
transmission facilities. Each transmission element is part of a network that is a common
resource available to all. Phase shifters are used in many applications.
Phase shifting transformers (PST) are used to control the flow of real power in transmission
lines by manipulating the phase angle difference. The phase angle shift is obtained by
combining the voltages from different phases in the PST. Phase-shifting transformers, when
combined with standard capacitors and reactors, can even provide control of reactive power
and fault current limitation.
The natural impedance and phase angle differences in a network often lead to unscheduled
flow. Phase-shifting transformers redirect the power flow, allowing existing lines to be loaded
closer to their thermal limits.
The core technology of the VFT is a rotary transformer with three-phase windings in both the
rotor and stator sides. Power flow is proportional to the magnitude and direction of the torque
applied to the rotor. This torque is applied to the rotor by a drive motor, which is controlled by
a variable-speed drive system. If torque is applied in one direction, then power flows from the
stator windings to the rotor windings. If torque is applied in the opposite direction, then power
flows from the rotor windings to the stator windings. If no torque is applied, then no real
power flows through the rotor transformer.
A closed-loop power regulator maintains power transfer according to the operator set point.
The regulator compares measured power with the set point and adjusts motor torque as a
APD-12
function of power error. The power regulator will respond quickly to network disturbances
and maintain stable power transfer. 55
Regardless of power flow, the rotor inherently orients itself to follow the phase angle imposed
by the two asynchronous systems, and will rotate continuously if the grids are at different
frequencies. The motor and drive system are designed to continuously produce torque while at
a standstill. If the power grid on one side experiences a disturbance that causes a frequency
excursion, the VFT will rotate at a speed proportional to the difference in frequency between the
two power grids. During such a disturbance, if the VFT is transferring power, it will continue
without interruption and at full-expected power. The VFT is designed to continuously regulate
power flow with drifting frequencies on both grids. Unlike power-electronic alternatives, the
VFT produces no harmonics and cannot cause undesirable interactions with neighboring
generators or other equipment on the grid. 56
VFT control system utilizes GE PowerLink Advantage™ HMI PC’s provide for superior user
interface & monitoring, multi-level dispatch, ramp rate setting and sequence of events
recording. The main control cabinet is based on GE D2000 substation automation platform for
multi-unit functions, SCDA interface for unmanned operation and data concentration for
individual protective devices and units. Individual unit control cabinet, for each 100 MW unit
utilizes GE Fanuc PLCs, GE’s Multilin Universal Relays, and GE’s Turbine Static Starter Control
for the fast power and torque regulators.
The first VFT completed commission testing at TransEnergie, Hydro Quebec’s Langlois
Substation in Quebec, Canada as reported in the October 2004 Transmission and Distribution
World. With the VFT in service Hydro-Quebec expects to transfer an extra 100 MW of power
between grids. The VFT’s 100 MW units can be combined for up to 400 MW in a single
installation. 57
55. Transmission & Distribution, August 1, 2006 “United States and Mexico Cross-Border Connection” by Rob O’Keefe and David Kidd,
American Electric Power page 1
57. Transmission & Distribution World, October 1, 2004 “First VFT System in Service for TransEnergie, aUnit of Hydro-Quebec,
http://license.icopyright.net/user/tag.act?tag=3.5531%3ficx_id=tdworld.com/mag/power_united_states_mexico/index.html
APD-13
the existing AC network, as it would provide some form of protection of the rights of the line
owner(s).
One major advantage of the VFT over PSTs is the absence of the tap changer, which historically
has caused maintenance issues and prevented the owner from achieving the maximum benefits.
The limiting factor of the VFT is the 400 MW limitation at each installation. The two
installations that will be using the VFT will be operating at 120 kV and 138 kV. Information for
units for higher voltages have not been found as of now.
APD-14
3.0 Multiple Phase Transmission Line
The use of more than three phases for electric power transmission has been studied for many
years. Using six or even 12 phases allows for greater power transfer capabilities within a
particular right of way, and reduced EMF’s because of greater phase cancellation. The technical
challenge is the cost and complexity of integrating such high-phase order lines into the existing
three-phase grid.
In the late 1970’s both six and twelve phase lines were built, tested, and shown to work as
predicted. Other theoretical work was done on compact line and the idea of suspending a
circuit as though it were insulated conductor bundle. It could, with the aid of ACCR, allow
some low voltage single circuit towers to carry three separate circuits.
A less dramatic but quite practical idea, now in use both in Russia and Brazil, greatly expands
mid span intra-bundle spacing thereby achieving very low reactance and higher than normal
reactive power generation. 58
This is new technology and still in the development stage. With the advancement of this
technology we will find several advantages. Research has been conducted in high phase order
(HPO) power transmission where in 6 or 12 phases are used to transmit power in less physical
space and with reduced environmental effects than conventional design.
If a three-phase circuit is replaced by a six phase circuit using the same conductor wire diameter
and material and operated at the same phase to neutral voltage, then for the same total power
transfer (MW), the six-phase conductors will carry only one-half the current of a three-phase
2
conductor line. Also, since the power loss is I R, the loss per conductor in the six-phase circuit
will be ¼ of that of the three-phase circuit, however, there will be twice as many conductors, so
the total line loss will be half of that of the corresponding three-phase line. 59
58. http://www.ece.cmu.edu/~electriconf/old2004/Barthold_The%20Future%20of%20Transmission%20Technology.pdf
59. http://www.patentstorm.us/patents/5070441-description.html
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4.0 Flexible AC Transmission Systems (FACTS)
Flexible Alternating Current Transmission System (FACTS) is a class of static equipment used
to enhanced controllability and increase the power transfer capability of AC transmission of
electrical energy. The FACTS devices are generally power electronics-based devices used for
the dynamic control of voltage, impedance and phase angle of voltage AC transmission lines.
The FACTS equipment can be connected in series with the power system (series compensation),
in shunt with the power system (shunt compensation), or both in series and in shunt with the
power system.
FACTS is defined by the IEEE as “a power electronic based system and other static equipment
that provides control of one or more AC transmission system parameters to enhance
controllability and increase power transfer capability.”
• Shunt capacitive compensation is used to improve the power factor on the transmission
line. Wherever an inductive load is connected to the transmission line, power factor lags
because of lagging load current. To compensate for this power factor lag shunt
capacitance is connected to the transmission system, which draws current leading the
source voltage and the net result is an improvement in power factor.
• Shunt inductive compensation is connected across the transmission line to prevent,
under some conditions, the receiving end voltage from becoming double the sending
end voltage. The device will limit high open end voltage when energizing a long
APD-17
transmission line or high voltage conditions at the receiving end of a long transmission
line, during periods light line loading.
4.2.1. Static Var Compensators (SVC’s)
These most important FACTS devices have been used for a number of years to improve
transmission line economics by resolving dynamic voltage problems. The accuracy, availability
and fast response enable SVCs’ to provide high performance steady state and transient voltage
control compared with classical shunt compensation. SVC’s are also used to dampen power
swings, improve transient stability, and reduce system losses by optimized relative power
control.
4.2.2. STATCOMS
STATCOMS are GTO (gate turn-off type thyristor) based on SVC technology. Compared with
conventional SVC’s they don’t require large inductive and capacitive components to provide
inductive or capacitive reactive power to high voltage transmission systems. This results in
smaller land requirements. An additional advantage is higher reactive output similar to a
synchronous condenser. Thus STATCOMs are able to provide dynamic voltage support to the
power system at the bus to which they are connected. The mitigation of voltage instability and
system transient stability issues are improved with the use of STATCOMs.
One adaptation of the smart grid concept is the use of adaptive distributed FACTS devices
installed on several transmission or distribution lines. Devices such as Distributed FACTS (D-
FACTS) can either inject series capacitance to reduce the line impedance, inject series reactance
to increase the line impedance, or inject shunt series capacitance to support the grid voltage.
Another adaptation, called Smart Wire, is the use of autonomous distributed current limiting
conductor (CLiC) modules to control power flow, increase T&D system capacity, and enhance
APD-18
reliability. These devices (called distributed series impedance modules) can inject a small series
impedance into the line as the current in the line increases above a predetermined set-point.
With the goal of installing many CLiC modules in each phase of a transmission or distribution
line, the current (and power flow) can be tuned to increase the overall grid performance by
eliminating the first (and subsequent) thermal line limits by redirecting the power flows.
Because these devices operate based solely on the transmission line phase current, they can be
distributed and autonomous (requiring no communications system to coordinate their
operation). If a communications system is available, CLiC devices that can inject both series
inductance or series capacitance can be installed.
CLiC concept implementing devices are currently being developed for testing. Initial
development will focus on the lower transmission voltages of 161-230 kV, higher voltage
devices may be feasible. Because the CLiC concept relies on rebalancing power flows based on
line currents, it is useful only in transmission situations where thermal overloads are the basis
for limits. Simulation studies suggest that widespread application of CLiC devices can alleviate
line loading and congestion issues on complex transmission grids.
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results in an over voltage of the line which can lead to a line trip. SVC’s or STATCOMS
counteract the over voltage and avoid line tripping.
APD-20
5.0 High-Voltage Direct Current
HVDC transmission systems contrast with the more common alternating-current systems as a
means for the bulk transmission of electrical power. The modern form of HVDC transmission
uses technology developed extensively in the 1930’s in Sweden by ASEA. Early commercial
installations include the USSR in 1951 between Moscow and Kashira, and a 10-20 MW system in
Gotland, Sweden in 1954 60
The grid controlled mercury arc valve became available for power transmission during the
period 1920 to 1940. In 1941 a 60 MW, +/- 200 kV, 115 km buried cable link was designed for the
city of Berlin using mercury arc valves (Elbe-Project), but owing to the collapse of the German
government in 1945 the project was never completed. 64 The equipment was moved to the Soviet
Union and was put into service there. 65
Introduction of the fully-static mercury arc valve to commercial service in 1954 marked the
beginning of the modern era of HVDC transmission. Mercury arc valves were common in
systems designed up to 1975, but since then HVDC systems use only solid-state devices.
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5.1.1. Advantages of HVDC over AC Transmission
In a number of applications the advantages of HVDC makes it the preferred option over AC
Transmission.
The conversion electronics also present an opportunity to effectively manage the power grid by
means of controlling the magnitude and direction of power flow. An additional advantage of
the existence of HVDC links, therefore, is potential increased stability in the transmission grid.
HVDC can carry more power per conductor, because for a given power rating the constant
voltage of a DC line is lower then the peak voltage in an AC line. This voltage determines the
insulation required and conductor spacing. This allows existing transmission line corridors to
be used to carry more power into an area of high power consumption, which can lower costs.
HVDC allows bulk power transmission between two asynchronous AC systems, thereby
improving system stability by preventing cascading failures from propagating from one part of
a wider power transmission grid to another, whilst still allowing power to be imported or
exported in the event of an AC failure. This has caused many power systems to contemplate
wider use of HVDC technology for its stability benefits alone.
66. http://en.wikipedia.org/wiki/HVDC
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5.1.3. Disadvantages of HVDC
The required static converters (rectifiers and inverters) are expensive and cannot withstand
significant overloads. At shorter transmission distances the losses in the static converters may
be higher than in an AC power line, and the cost of the converters may not be offset by
reductions in line construction cost. Recent economic assessments suggest that for deliveries of
3,000 MW of capacity, HVDC is economical compared to 500 kV AC when the delivery distance
exceeds 400 to 500 miles.
Multi-terminal HVDC links, connecting more than two points, are rare. The configuration of
multiple terminals can be series, parallel, or a mixture of series and parallel. Parallel
configuration tends to be used for large capacity stations, and series for lower capacity stations.
An example is the 2000 MW Quebec-New England transmission system commissioned as the
first large multi-terminal facility in 1992 67.
The Garabi station power rating is a 2,200 MW configuration. The AC transmission systems in
Brazil and Argentina consist of a 500 kV network. The DC voltage between the two valve
groups is +/- 70 kV. The main reason for choosing HVDC is the fact that Argentina operates at
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50 cycles and Brazil at 60 cycles. The control system utilizes ABB’s Capacitor Commutated
Converters (CCC). The first phase was placed in service in 2000 and the second in 2002.
The chart below shows the cost broken down for line, station and losses for both AC voltages
and DC voltage options. 68
68..http://www02.abb.com/global/seitp/seitp202.nsf/0/5392089edc1b3440c12572250047fd78/$file/800+kV+DC+technology.pdf
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6.0 Extra-high Voltage Transmission Lines
The four popular transmission AC voltages used in the United States is 230, kV, 345 kV, 500 kV
and 765 kV. The WECC utilizes 500, 345 and 230 kV as the primary voltages for shipping large
quantities of power. This technology is well established. The use of 765 kV extra-high AC
transmission voltage has enhanced the Eastern Interconnection’s ability to move massive
amounts of energy from source to customer. With the 765 kV transmission lines, several times
the power of lower voltage lines can be transmitted over long distances with only 200 feet of
right of way.
Transmission at 765 kV also offers greater reliability due to its line design. With only one line
outage per 100-mile year, 765 kV reliability surpasses all other voltage classes. 69 In addition, 765
kV faults are usually momentary and involve only one of three phases, allowing application of
single-phase tripping.
Station equipment for 765 kV has matured and transformer bank sizes up to 3,000 MVA have
been demonstrated throughout the world. The necessity of using banks of single-phase
transformers allows spare units to be used easily achieved with a fourth single-phase
transformer connectable to any phase without physical moves, reducing outage duration.
A 765 kV system is an alternating current (AC) transmission, which lends itself to ready
integration with existing and future infrastructure. Direct current (DC) transmission is also
useful over long distances, but cannot be integrated well without significant cost.
Assuming the need to transport 3,000 MW, one 765 kV line with six bundled conductors per
phase would be required. Using 500 kV would require two circuits, each carrying 910 MW, and
six 345 kV lines would be required. The Eastern Interconnection is utilizing 765 kV transmission
lines and have found that the cost per mile is acceptable for their systems. This is not true for
the Western Interconnection, since there is no 765 kV infrastructure is this region. A recent
study conducted by the participants of the TransWest Express Transmission Project evaluated
the costs of several transmission alternatives related to a 3,000 MW transmission system (AC vs
DC) from the Wyoming Region to the Desert Southwest Region. The cost of a two line 500 kV
system was approximately $4.5 billion, the cost of a two line 765 kV system was approximately
$5.3 billion and the cost for a single bi-polar DC line was approximately $2.3 billion. Note: the
cost for the 765 kV option is higher, due to additional infrastructure requirements (e.g.
transformers), but the facilities could ultimately be utilized to transfer up to 5,000 MW.
69. Electric Light and Power, Jan 2007 – The Next Interstate System: 765 kV Transmission
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Appendix A of Appendix D
HVDC Systems
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration Remarks
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Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration Remarks
Upgraded
Benmore Haywards, in 1991.
HVDC
Dam, New New Zealand 40 km/ 570 km/ +270 1200 MW 1965 Pole 1 is
Inter-
Zealand 25 354 miles kV still
Island
miles -350 kV Mercury
Arc. Pole
2 is
Thyristors
HVDC Replaced
back to Sakkuma, Sakuma, - - +/- 125 300 MW 1965 in 1993
back Japan Japan kV with
station Thyristors
Sakuma
APD-27
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration
HVDC Kingsnorth, Lindon-
Kingsnorth UK Beddington, 85 km/ - +/- 266 640 MW 1975
UK: 53 kV
London- miles
Willesden,
UK
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration
HVDC New New
back to Brunswick, Brunswick, - - 80 kV 320 MW 1972
back Canada Canada
station Eel
River
Cross- Tjele, Kristiansand, 30 km/ 100 km/ +/- 250 1000 MW 1977
Skagerrak Denmark Norway 64 62 miles kV
1&2 miles
APD-28
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration
HVDC Shin, Shin, 600 MW 1977
back to Shinano, Shinano, - - +/- 250
back, Shin Japan Japan kV
Shinano
APD-29
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration
HVDC back
to back Artesia, New Artesia, New - - 82 kV 200 MW 1983
Artesia, New Mexico Mexico
Mexico
HVDC Foz do Sao Roque, _ 785 km/ +/- 600 3150 MW 1984
Itaipu 1 Iguacu, Sao Paulo 488 miles kV
Parana
HVDC Foz do Sao Roque, - 805 km/ +/- 600 3150 MW 1984
Itaipu 2 Iguacu, Sao Paulo 500 miles kV
Parana
HVDC back Oklaunion Oklaunion - - 82 kV 200 MW 1984
to back
Oklaunion
APD-30
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration
HVDC back Miles City Miles City _ _ +/- 82 200 MW 1985
to back Miles kV
City
Nelson River Sundance, Rosser, - 937 km/ +/- 500 1800 MW 1985
Bipole 2 Canada Canada 582 miles kV
APD-31
Length
Length of
Converter Converter of overhead Transmissi
Name Station 1 Station 2 Cable line Voltage on power Inauguration
HVDC Mc Neill, Mc Neill, Canada - - 42 kV 150 MW 1989
back to Canada
backMc
Neill
HVDC Sileru, India Barsoor, India - 196 km/ +/- 200 400 MW 1989
Sileru- 122 miles kV
Barsoor
Nicolet, Quebec:
Radisson, Des Cantons, - 1100 km/ +/- 450 2000 MW 1991
Quebec-
Quebec Quebec; 684 miles kV
New
Comerford, New
England
Hampshire;James
Bay, Mass.
HVDC Rihand, Dadri, India - 814 km/ +/- 500 1500 MW 1992
Rihand- India 506 miles kV
Delhi
APD-32
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration
SACOI 2 Suvereto, Lucciana, 118 304 km/ 200 kV 300 MW 1992
India France km/ 189 miles
Codrongianos, 73
Italy miles
HVDC Benmore Haywards, 40 km/ 570 km/ 350 kV 640 MW 1992
Inter-Island Dam, New New Zealand 25 354 miles
2 Zealand miles
HVDC back
to Vienna, Vienna, - - 142 kV 600 MW 1993
backVienna- Austria Austria
Southeast
APD-33
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration
HVDC Hellsjoen, Graengesberg, - 10 km/ 180 kV 3 MW 1997
Hellsjon- Sweden Sweden 6 miles
Grangesberg
HVDC Orno, Leyton Ormoc, Luzon 21 km/ 430 km/ 350 kV 440 MW 1998
Leye-Luzon 13 267 miles
miles
HVDC Nas, Sweden Visby, Sweden 70 km/ - 80 kV 50 MW 1999
Visby-Nas 43
miles
Swepol Starno, Slupsk, Poland 245 - 450 kV 600 MW 2000
Sweden km/
152
miles
HVDC Italy- Galatina, Italy Arachthos, 200 110 km/ 400 kV 500 MW 2001
Greece Greece km/ 68 miles
124
miles
Kii Channel Anan, Japan Kihoku, Japan 50 km/ 50 km/ +/- 500 1400 MW 2000
HVDC 31 31 miles kV
miles
HVDC Auchencrosh, Ballycronan 63.5 - 250 kV 250 MW 2001
Moyle UK More, UK km/
39
miles
HVDC Khlong Ngae, Gurun, - 110 km/ 300 kV 300 MW 2002
Thailand- Thailand Malaysia 68 miles
Malaysia
APD-34
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration
HVDC back to Minami- Minami- 125 kV 300 MW 1999
back Minami- Fukumitsu, Fukumitsu, - -
Fukumitsu Japan Japan
HVDC three Longquan, Zhengping, - 890 km/ +/- 500 3000 MW 2003
Gorges- China China 553 miles kV
Changzhou
Imera Power
HVDC Wales- Leinster, Anglesea, 130 - +/- 400 500 MW 2008
Ireland, East Ireland Wales km/ kV
West 81
Interconnector miles
APD-35
Length
Converter Converter of Transmission
Name Station 1 Station 2 Cable Voltage power Inauguration
NorNed Feda, Norway Eemshaven, 580 +/- 450 700 MW 2010
Netherlands km/ kV
360
miles
HVDC back to Vishakapatinam, Vishakapatinam,
back India India -
Vishakapatinam
Length
Length of
Converter Converter of overhead Transmission
Name Station 1 Station 2 Cable line Voltage power Inauguration Remarks
HVDC Tjaereborg, Tjaereborg, 4.3 km/ - +/- 9 kV 7.2 MW 2000 Wind
Tjaereborg Denmark Denmark Power
3 miles
Cross New Haven, Shoreham, 40 km/ - +/- 150 330 MW 2002 Underwater
Sound Connecticut Long kV cable
25 miles
Cable Island
Murraylink Berri, Red Cliff, 177 km/ - +/- 150 220 MW 2002 Land
Australia Australia kV CableHVDC
110
miles
APD-36
Estlink Espoo, Finland Harku, 105 km/ - +/- 150 350 MW 2006
Estonia kV
65 miles
APD-37
Appendix E
List of Tables
California’s electric industry went through a growth spurt in the 1950’s, 60’s, and early 70’s.
Many of the major transmission interconnection projects were built, planned, or conceived
during this time period. These projects were planned and built by vertically integrated utilities
with the primary purpose of connecting new generation or accessing new or surplus energy and
capacity.
The picture today is much different. Open access transmission rules separate ownership of
transmission from rights to transmission. Transmission planning has shifted to California
Independent System Operator for at least the investor-owned utilities. It is no longer possible
for utilities to simply plan new transmission and expect cost recovery.
This research effort has focused on the changes that have taken place within the electric
industry over the past five decades in an effort to better understanding their impacts on the
transmission planning process. The key impacts on the transmission planning process:
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Executive Summary
California’s electric industry went through a growth spurt in the 1950’s, 60’s, and early 70’s.
Many of the major transmission interconnection projects were built, planned, or conceived
during this time period. These include for example, transmission into California from:
The picture today is much different. Open access transmission rules separate ownership of
transmission from rights to transmission. Utilities are no longer integrated—generation and
transmission functions are separated. Transmission planning has shifted from the utilities to
California Independent System Operator (CA ISO) for at least the investor-owned utilities. In
many cases an Independent Power Producer (IPP) is the project sponsor for new power plants
and, in some instances, an Independent Transmission Company (ITC) will sponsor a new
transmission line (e.g. Path 15 upgrade).
These changes are the culmination of 50-years of changes in the electric industry—regulatory,
legislative, and structural. California’s electric industry evolution in terms of time period, policy
issues, and transmission planning changes are described throughout the various sections of this
report. These evolutionary changes in the electric industry have had a significant impact on
planning for new transmission, cost allocation, and cost recovery. It is no longer possible for
utilities to simply plan new transmission and expect cost recovery. The consequences of these
changes can be summarized as follows:
Pre 80’s Major new utility planned transmission primarily to connect new generation or access
surplus energy or capacity.
Project planned by vertically integrated utilities based on long term (20-years or
longer) resource plans.
80’s & 90’s Few transmission interconnections built due to capacity surpluses, environmental
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opposition, regulatory uncertainties, industry restructuring, and changing
transmission business landscape due to advent of open access and non utility
generation.
Post New transmission planning processes start to take shape.
California Transmission planning more open and collaborative with heavy stakeholder
Energy Crisis involvement.
in 2001 Planning focus shifted from utilities to CA ISO
Projects starting to be approved.
Issues regarding project sponsorship, analysis methodologies, cost recovery
evolving.
The following sections of this report are a historical review of the California Electric Power
Industry and the changes it underwent over the past five decades.
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1.0 Background
This project was commissioned to provide research and background information for a research
project on the broader topic of Benefit Quantification and Cost Allocation. As part of the Benefit
Quantification and Cost Allocation Research Project, the research team performed a scoping
study to understand transmission benefit quantification, cost allocation, cost recovery, and
project approval processes with a particular focus on recommending new methods for
improved benefit quantification and cost allocation that better fits the new electric industry
structure and planning environment. There were many key policy questions that came up as
part of this broader research, for example impact of transmission technologies, lessons learnt
from other regions and industries and the subject of this report impacts of industry and
regulatory changes.
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2.0 Introduction
As indicated above, this research project was used to provide information to the broader subject
of Benefit Quantification and Cost Allocation. As part of that project it was determined that, for
the most part, utility efforts to develop new transmission projects that are local in nature,
address well documented reliability needs, are required for interconnecting new load or
generation are generally supported and have been gaining regulatory approvals and
stakeholder support. However, major regional transmission projects that involve multiple
jurisdictions and utilities and are needed for integrating remote resources, reducing costs,
improving market operations, providing long term strategic benefits and improving operating
flexibility, don’t have a clear path forward….. Why? In an attempt to help answer this question,
the project team was asked to research the electric industry and regulatory changes that
occurred over the past five decades and determine the impacts they had on the transmission
planning process.
The following section of this report covers the time span from the 1950’s through 2005+ and
provides a non-technical summary of the industry changes that were occurring each decade,
changes or shifts in the state and federal regulatory process, and a recap of the utility and
regional transmission planning process during each decade.
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3.0 Project Approach
The research approach used for this project included the following components:
• Information Collection
o Compiled data from various industry web sites.
o Reviewed and processed data for pertinent information and time lines.
• Conducted interview with Electric Power Group Team members and other industry
leaders with first-hand knowledge of industry changes and planning processes.
Produce report of research findings.
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4.0 History Of The California Electric Power Industry—Time
Periods, Issues, And Transmission Planning
4.1. Golden Era – The 50’s and 60’s
There were several drivers to a healthy and robust electric industry during this time period:
• Electrification—the conversion from gasoline and natural gas use to an expanded use of
electric energy to improve industry production and efficiency (e.g., steel mills,
agricultural irrigation).
• Double digit growth—during the 50’s and 60’s the population in California doubled
from approximately 10 million to 20 million 70 requiring significant utility investment in
both power plants and transmission/distribution infrastructure in an effort to keep up
with the growing energy demand. Also, the average household started to increase in
size (1950 average was 850 square feet 71) which required more heating and cooling and
also bigger and more appliances and equipment.
• Declining Rates—a major contributor to the reduction in electric rates during these two
decades was the construction of new and larger fossil fuel power plants that provided
significant improvements in plant efficiency. The power plants built prior to the 50’s
consisted of units that varied in size from 30 to 90 megawatt (MW) and, between the 50’s
and 60’s, the plants consisted of units growing in size from 130 MW to 800 MW. In
addition, the plants implemented the use of new technology that included automated
controls and computers allowing the conversion from drum type boilers to super-critical
boilers for improved efficiency. The heat rates of the new plants were approximately
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10,800 British thermal unit (Btu) per kilowatt-hour 72, almost a 30% improvement over
the pre-1950 vintage plants that had a heat rate in excess of 15,000 Btu per kilowatt-hour.
This era was also the beginning of nuclear generation in California. In 1968, San Onofre
Unit 1 went into operation, the first of six nuclear plants to be built in California.
4.1.1. Regulation and Planning Process for the Investor-Owned Utility (IOU),
during the 50’s and 60’s:
State of California:
• CPUC—The CPUC reviewed and approved generation and transmission projects and
established retail rates.
In 1912, the Legislature passed the Public Utilities Act 73, expanding the Railroad Commission's
regulatory authority to include natural gas, electric, telephone, and water companies, as well as
railroads and marine transportation companies. In 1946, the Commission was renamed the
California Public Utilities Commission (CPUC).
Federal:
• Federal Energy Regulatory Commission (formerly FPC) - FERC reviewed and approved
hydro plant licensing, wholesale power and transmission service rates.
In 1920, Congress established the Federal Power Commission (FPC) 74 to coordinate
hydroelectric projects under federal control. The Federal Power Act of 1935 and the Natural Gas
Act of 1938 gave the FPC the power to regulate the sale and transportation of electricity and
natural gas.
Transmission Planning:
72. Derived from Edison Electric Institute, EEI Pocketbook of Electric Utility Industry Statistics (1983), p.
21
73. CPUC web site - http://www.cpuc.ca.gov/static/aboutcpuc/puhistory.htm
74. FERC web site - http://www.ferc.gov/students/whatisferc/history.htm
75. NRC web site - http://www.nrc.gov/about-nrc/history.html#aec-to-nrc
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• 50’s—The transmission planning process consisted of vertically integrated planning and
review process with some coordination with adjacent utilities.
• 60’s—The transmission planning consisted of vertically integrated planning and review
process and extensive coordination and review with sub-regions of the Western
Electricity Coordinating Council (e.g. Pacific Northwest and Desert Southwest) and
adjacent utilities. During the late 60s, as a result of the 1965 Northeast blackout, the
North American and regional reliability councils (NERC/WECC) were in the early
formation stages. Several major new transmission lines were built—almost all designed
to integrate new generation power plants, including for example, Mohave, Four
Corners, and Navajo coal plants.
• Environmental concerns.
• Drastic increases in fossil-fuel prices and double digit inflation.
• Conservation.
• Problems in the nuclear power industry after the Three Mile Island event.
4.2.1. Environmental Concerns
By the early 1970’s, there was a much greater emphasis being put on the environmental issues
and that had a noticeable impact on the electric industry in the form of environmental
requirements and electric utility costs, including the cost of building and operating power
plants.
The Clean Air Act of 1970 (CAA, P.L. 91-604) and its amendments in 1977 (P.L. 95-95) required
utilities to reduce pollutant emissions, particularly SO2, causing increases in capital, fuel, and
operating costs.
• Air Quality and Environmental Impacts—In the early 1970, the primary fuel being
burned at generating plants within California was oil. Natural gas was reserved for the
gas company’s core residential, commercial and industrial customers and was only
available to the electric power industry on an interruptible basis. This high dependency
on oil and the associated air quality issues required the utilities, with poor air quality in
their service territory (e.g., Southern California Edison) to do two things: 1), to
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implement nitrogen oxides (NOX) dispatch programs for their fossil fuel generation
resources as opposed to least cost dispatch; and, 2) procure only low sulfur oil to burn in
the boilers.
• The new coal-fired power plants in the Desert Southwest, that the California utilities
participated in, were experimenting with emission control equipment to decrease the
amount of sulfur dioxide (SO2) emitted into the atmosphere. In addition, the flue gases
were passed through precipitators that removed much of the particulate matter and the
gas was sent up tall emission stacks to better disperse the SO2.
• The National Environmental Policy Act of 1969 (NEPA, P.L. 91-190) required utilities
seeking Federal permits for new power plants to prepare and defend environmental
impact statements (EIS) as a part of the permit process.
4.2.2. High oil prices and double digit inflation
In the 1970’s the cost of imported oil rose sharply. Petroleum costs more than doubled in 1974
alone and increased an average of over 26% a year for the period 1970-1980. Coal price increases
averaged almost 16% a year. For the first time in the history of U.S. electric power, electricity
prices rose consistently, with nominal price increases averaging 11% a year. 76
Inflation and real labor and materials cost increases quickly affected construction costs of
nuclear power plants, while high interest rates raised financing costs. Capital costs rose from
76. Energy Information Administration, "Fuel Choice in Steam Electric Generation: A Retrospective
Analysis," Volume 1, Overview, Draft Report, Table 2.
77. Edison Electric Institute, Historical Statistics of the Electric Utility Industry Through 1970
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about $150 per kilowatt in 1971 to over $600 after 1976. Utilities building commercial nuclear
facilities faced financial difficulties in justifying and meeting these increased costs 78. Costs of
nuclear power plants increased to over $2,000/kilowatt (kW) and coal plants to over $1,200/kW.
In March 1979, an event occurred at the Three Mile Island Unit 2 (Harrisburg, Pennsylvania)
that resulted in the first case of melted fuel in a full scale commercial nuclear power plant.
There had been prior cases of small scale fuel melting (e.g., the Fermi 1 reactor near Monroe,
Michigan). Three Mile Island Unit 2 was the Nation's most significant commercial nuclear
accident 79.
During the 70’s, the climate between nuclear power advocates and environmentalists was
confrontational. While voters failed to pass a 1972 proposal placing a 5-year moratorium on
nuclear plant construction, conservation and environmental groups worked throughout the
decade to stop construction of several proposed plants, especially along the coast and near fault
lines.
In 1976, Governor Brown passed three nuclear safeguard laws; one of which included the
provision that the Resources Conservation and Development Commission of California and the
Legislature determine at least one method of disposing of radioactive waste material safely 80.
These safeguard laws, in essence created a moratorium on new nuclear power plant
construction in California.
4.2.5. Public Utility Regulatory Policies Act of 1978 (PURPA) and Power Plant
Industrial Fuel Use Act (PIFUA-1978)
PURPA and PIFUA, both passed in 1978 ushered in non-utility generation and limited use of
gas in utility power plant due to a concern about a gas bubble and diminishing gas supplies.
The PURPA law was a direct response to the increased concern over U.S. dependency on
foreign oil in the wake of the OPEC oil embargos of the 70’s and was also intended to encourage
more energy-efficient and environmentally friendly commercial energy production. PURPA
defined a new class of energy producer called a qualifying facility (QF). Qualifying Facilities
(QFs) were defined as non-utility power wholesalers that were either co-generators, or small
power producers using specified renewable energy resources. When a facility of this type met
the FERC's requirements for ownership, size and efficiency, a utility company was obliged to
purchase the energy from these facilities based on their avoided cost rates, established by the
Public Utility Commissions. In California, these rates tended to be highly favorable to the
producer, and were intended to encourage more production of this type of energy as a means of
78. Energy Information Administration, 1983 Survey of Nuclear Power Plant Construction Costs,
DOE/EIA-0439(83) (Washington, DC, December 1983), p. 8.
79. http://www.nucleartourist.com/events/tmi.htm
80. http://infodome.sdsu.edu/about/depts/spcollections/collections/sdgesundesert.shtml
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reducing emissions and dependence on other sources of energy 81. In the late 70’s and early 80’s
the CPUC took the next step in an attempt to break-up the utilities’ monopoly over generation.
The CPUC established four Standard Offer contracts (based somewhat on the various resource
technologies) for QFs. The pricing structure was front loaded with high capacity payments and
the avoided fuel cost was developed based on a forecast of oil being at $100 per barrel by 1990.
The utility was required to accept energy from all QFs who signed a Standard Offer contract
and could deliver or have it delivered to the investor-owned utility.
4.2.6. Regulation and Planning Process for the Investor-Owned Utility during
the 70’s
State of California:
• CPUC–the CPUC reviewed and approved generation and transmission projects and
established retail rates. In stakeholder proceedings they also established avoided costs
pricing for QFs.
• The California Energy Commission is the state's primary energy policy and planning
agency. Created by the Legislature in 1974 (Warren-Alquist Act) and located in
Sacramento, the Energy Commission has five major responsibilities:
o Forecasting future energy needs and keeping historical energy data.
o Licensing thermal power plants 50 megawatts or larger.
o Promoting energy efficiency through appliances and building standards.
o Developing energy technologies and supporting renewable energy.
o Planning for and directing state response to energy emergency.
Federal:
81.
http://www.energyvortex.com/energydictionary/public_utility_regulatory_policies_act_of_1978_(purpa).
html
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• Nuclear Regulatory Commission 82—NRC reviewed and approved nuclear plant
licensing.
Transmission Planning:
Excess Capacity:
Starting in 1982 through 1988, there were seven nuclear units that came on-line that the
California utilities either owned or participated in. These seven units added approximately
8,000 MW of capacity in the California and Desert Southwest region, with 5,400 MW of that
capacity in California. The nuclear plants were:
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slow load growth, left the utility with excess capacity. In some cases the installed capacity
reserves were in the 30% range.
High Rates
The causes for the high consumer rates were a continuation of the high power plant fuel costs,
sky rocketing construction costs for nuclear plants, high payments for QF energy and the
continued double digit rate of inflation that was driving all operating costs higher within the
utility. As an example of prices getting out of hand was nuclear construction cost. During the
mid-70’s the cost for a nuclear plant was approximately $600/per kilowatt and by early 80’s the
cost had doubled to approximately $1,200/per kilowatt 83. The requirements and modifications
coming out of the Three Mile Island event were significant drivers in the higher nuclear
construction costs.
84
F igure 14. U.S . T otal Average R evenue P er kW H
83. Energy Information Admin., Survey of Nuclear Power Plant Construction Costs 1984, DOE/EIA-
0439(84), pg. 13
84. SustainableFacility.com -
http://www.sustainablefacility.com/CDA/Archives_EPM/d554b6f99be38010VgnVCM100000f932a8c0____
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Slow Growth and Conservation:
The bottom line of all the above higher costs meant annual double digit rate increases for the
consumer and as a result they continued their energy conversation efforts, with a net result of
either a slowing or a negative load growth at the utilities.
Utility Diversification:
In the mid-1980’s, there was much uncertainty as to the future direction of the electric industry
partially as a result of FERC’s PURPA and many industrial customers wanting to or converting
from being a customers to cogeneration. To head off some of this uncertainty the electric
utilities ventured into diversification, or expansion into non-regulated industries. This was
made possible for some utilities because of large cash flows being available following
completion of major plant construction programs in the early 1980's, the cash flows exceeded
their immediate needs. Industry officials believe that usage of these cash flows to diversify into
non-regulated industries would smooth out the financial risks of the regulated business, while
providing companies an opportunity to earn returns above those allowed by regulation. To
facilitate diversification, many electric utilities, formed holding companies under which the
parent company holds both regulated and non-regulated subsidiaries 85.
There was mixed results from utilities venturing into diversification, those utilities that stayed
in areas close to their core competence (power plant ownership and operations) were normally
very successful, but for those who ventured far from their core competence (e.g., banking, small
retail food stores, roofing, security services) it proved somewhat disastrous.
4.3.1. Regulation and Planning Process for the Investor Owned Utility during
the 80’s
State of California:
• CPUC—the CPUC reviewed and approved generation and transmission projects and
established retail rates. In stakeholder proceedings they also established avoided costs
pricing for QFs.
• The California Energy Commission is the state's primary energy policy and planning
agency. During the 80’s there primary focus was on licensing thermal QF power plants
50 megawatts or larger.
Federal:
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• 80’s - The transmission planning process consisted of:
o Vertically integrated planning and review process.
o Extensive coordination and review between sub-regions of the WECC.
o Transmission projects reviewed at WECC for compliance with planning
standards and transfer capability ratings.
o Transmission interconnections for QF power plants.
The EPAct of ‘92 authorized FERC to require a jurisdictional entity, owning transmission, to
provide transmission services, including any upgrades and expansion of transmission capacity
necessary to provide transmission services to any one making such a request that is an electric
utility, Federal Power marketing agency, or any other person generating electric energy for sale
or resale.
86. Document describing “What Public Power Utilities Must Know To Survive Under the Energy Policy
Act of 2005” by Duncan & Allen
APE-18
EPAct 1992 reformed PUHCA and created a new category of power producers called Exempt
Wholesale Generators who would be exempt from PUHCA, subject to the FPA, not required to
be a co-generator or renewable resource (PURPA QF requirements) and jurisdictional entities
were not mandated to purchase power from them (which was a requirement under PURPA).
To ensure the marketing of EWGs, the EPAct of 1992 instructed FERC to require jurisdictional
utilities to make transmission service available at just and reasonable rates.
Following EPAct 1992, FERC issued Order Nos. 888 and 889 which identified the specific details
and requirements for wholesale electricity transactions and established the requirement for
entities to implement a real-time transmission trading system designed to better facilitate open
access transmission service.
APE-19
of a formal process to consider how the CPUC restructuring vision could be accomplished.
Below are some of the desired attributes and issues related to a restructured electric industry:
The bill used the CPUC Policy Decision as a starting point. There were, however, several
important provisions that either modified or redirected the CPUC in a few areas. Primary
among these were:
• Going beyond the CPUC’s call for a retail rate freeze it mandated a 10% rate cut during
the four-year transition period that allowed for stranded asset cost recovery.
• Public purpose programs, most of which had been legislatively mandated, required
modification in a restructured environment.
• Creation of the California Power Exchange (PX) to operate a day-ahead hour-by-hour
spot market, in which generators could sell and retailers could buy power.
o The IOUs, to ensure that the market would be liquid, were required to meet the
energy demands of their native loads with energy purchases from the Power
Exchange.
o The IOUs were required to sell all the energy from their remaining generation
assets through the Power Exchange.
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• Creation of The California Independent System Operator to manage the IOU’s
transmission assets and to:
o Maintain grid reliability.
o Congestion management.
o Providing ancillary services.
o Real-time balancing between demand and generation.
4.4.4. California’s Competitive Market
On April 1, 1998, the Power Exchange and CA ISO commenced operation. It was hoped that the
creation of the Power Exchange and CA ISO would establish the necessary foundation for a
successful competitive market. In addition, the three IOUs had divested themselves of their gas-
fired generation and by 1999 the generation ownership in the CA ISO’s control area was as
indicated in Table 1 below:
The divested generation was purchased by five independent power producers (AES, Duke,
Dynegy, Reliant, and Mirant), each purchasing roughly a fifth of the divested plant.
• CPUC—the CPUC reviewed and approved generation and transmission projects and
established retail rates.
o Identified the need for and foundation for a competitive electric market in
California.
o Implemented a cost recovery program for un-economical generation in a
competitive market.
APE-21
o Established retail rate caps.
• The California Energy Commission is the state's primary energy policy and planning
agency.
Federal:
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4.6. Meltdown – 2000/2001
APE-23
Table 2 for the PX was almost $100 /megawatt-hour (MWh) higher than any previous month,
going back to the start of the market. There were also numerous price spikes. Prices reached the
CA ISO’s $750/MWh price cap in either the real-time or ancillary service markets 23 times. In
June the wholesale prices averaged $132/MWh. Wholesale price caps were lowered to
$500/MWh in July and $250/MWh in August but average wholesale prices remained high
during the summer. Wholesale prices eased somewhat during the fall but then spiked
dramatically in December. By the end of January, the collapse was complete. Blackouts occurred
on eight days during the winter and spring even though demand was far below the summer
peak. The Power Exchange suspended operations, and the CA ISO, SCE, and PG&E were all
insolvent.
All these long-term or external factors served to expose and amplify design flaws in an overly
complex deregulatory scheme. The design flaws, notably a massive over-reliance on spot
markets and capped retail prices, are often cited as the main reasons for California's problems,
but all of the ingredients listed above contributed to creating the crisis 88.
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T able 2. C alifornia W holes ale E lec tric ity P ric es – Monthly Means ($/MW h)
APE-25
he would allow retail rates to increase, but only after PG&E (as well as SCE) sold the state their
transmission assets as payment for the debt and, in addition, agreed to provide energy for ten
years. This plan was unacceptable to PG&E and they elected to seek protection under Chapter
11, allowing them to continue operations, until they could get things worked out with the state
and their creditors 90.
4.6.5. Regulation and Planning Process for the Investor-Owned Utility, during
the Energy Crisis
State of California
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o Get sufficient generation resources under long-term contracts.
o Stabilize a dysfunctional market.
o Establish a portfolio management organization and an energy purchasing agent
for the IOUs.
• The California Energy Commission is the state's primary energy policy and planning
agency.
Federal
• Energy Crisis Years—the transmission planning process remained the same as in the
90’s, but due to the utilities financial situation and a need to conserve scarce capital, the
mode of operation was to perform fix-and-repair work only. No major new transmission
projects were built due to financial constraints and regulatory focus on the energy crises.
4.7. 2005 +
92
F igure 17. E nergy P olic y Ac t 2005
The Energy Policy Act of 2005 (EPAct 2005) was signed into law on August 8, 2005. The purpose
of the EPAct 2005, as it relates to the electric industry, was in response to the many weaknesses
resulting from the disparate changes associated with electric industry restructuring. The
industry restructuring had its roots with the passage of Energy Policy Act of 1992 and the
subsequent FERC Order Nos. 888 and 889. Under 888 and 889, the FERC jurisdictional utilities
92. EEI’s web site - Energy Policy Act of 2005 – Summary of Title XII – Electricity, Title XVIII – Studies
and Related Provisions
APE-27
transitioned from the traditional vertically integrated utility to the unbundling of generation,
transmission, and distribution. In addition, as a result of the EPAct 2002, FERC was driving the
jurisdictional utilities to put their transmission assets under the control of an Independent
System Operator (ISO) and later a Regional Transmission Organization (RTO).
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On June 24, 2004, the CA ISO Board of Governors approved a market redesign and technology
upgrade program for the CA ISO in order to gain economic and technical efficiencies. The
program will be operational in 2008:
• Market improvements to assure grid reliability and more efficient and cost effective use
of resources. The CA 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 Day–Ahead Market will
determine the best use of resources available and identify the least cost method of
procuring required components.
• New Market Rules—the market redesign introduces new market rules and penalties that
prevent gaming and manipulation. Through revised tariffs the CA ISO has been granted
new authority by the 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.
• Locational Marginal Prices (LMP)—LMP will identify the cost of producing power as
well as the cost of delivery. This information gives the CA 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.
• Technology upgrades to strengthen the entire CA ISO computer backbone. The
technology upgrades will provide a more precise model of the grid using the latest
computer technology to allow the CA ISO to better predict how energy scheduled a day-
ahead of time will flow in real-time. The CA ISO will be able to see all potential
transmission congestion a day-ahead of time, rather than waiting until real-time.
CPUC - Procurement and Resource Adequacy (RA) 94
California’s RA policies have been under development for several years, but the first active
compliance period commenced in June 2006. The purpose of the program is for the review and
approval of:
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In 2002, Senate Bill 1078 (SB 1078, Sher, Chapter 516) established the RPS program, which
requires an annual increase in renewable generation by the utilities equivalent to at least 1% of
sales, with an aggregate goal of 20% by 2017. The CPUC accelerated the goal, requiring the
IOUs to obtain 20% of their power from renewables sources by 2010 (Senate Bill 107 codified
this goal in state law). Currently, the Commission is considering ways to achieve 33 percent
renewable energy by 2020.
Recently, there has been much discussion regarding the construction of new EHV transmission
lines in the Western Interconnection. The governors of California, Nevada, Utah and Wyoming
had proposed a new interstate EHV transmission line across the Western U.S., from Wyoming
with terminal connections in Utah, Nevada and California. Some of the Arizona utilities and
others are considering an EHV transmission project from Wyoming to the Desert Southwest
area, and PG&E has proposed an EHV project from British Columbia to Northern California.
APE-30
APE-31
Appendix F
Figure 6. Trans Bay Cable Project (Source Babcock and Brown) ............................................. APF-8
Figure 8. Green Path Project (Source Imperial Irrigation District) ............................................. APF-9
Figure 9. PG&E’s Proposed Central California Clean Energy Transmission Project (source
PG&E) ....................................................................................................................................... APF-11
List of Tables
Table 1. Recap of Changes and the Impacts on Transmission Planning for the California IOUs
................................................................................................................................................... APF-12
The historical CA ISO transmission planning process consisted of:
On June 24, 2004, the CA ISO Board of Governors approved a market redesign and technology
upgrade program for the CA ISO in order to gain economic and technical efficiencies. The
program will be operational in 2008:
• Market improvements to assure grid reliability and more efficient and cost effective use
of resources. The CA 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 Day–Ahead Market will
determine the best use of resources available and identify the least cost method of
procuring required components.
• New Market Rules—the market redesign introduces new market rules and penalties that
prevent gaming and manipulation. Through revised tariffs the CA ISO has been granted
new authority by the 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.
• Locational Marginal Prices (LMP)—LMP will identify the cost of producing power as
well as the cost of delivery. This information gives the CA 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.
• Technology upgrades to strengthen the entire CA ISO computer backbone. The
technology upgrades will provide a more precise model of the grid using the latest
computer technology to allow the CA ISO to better predict how energy scheduled a day-
ahead of time will flow in real-time. The CA ISO will be able to see all potential
transmission congestion a day-ahead of time, rather than waiting until real-time.
APF-1
CPUC - Procurement and Resource Adequacy (RA) 97
California’s RA policies have been under development for several years, but the first active
compliance period commenced in June 2006. The purpose of the program is for the review and
approval of:
In 2002, Senate Bill 1078 (SB 1078, Sher, Chapter 516) established the RPS program, which
requires an annual increase in renewable generation by the utilities equivalent to at least 1% of
sales, with an aggregate goal of 20% by 2017. The CPUC accelerated the goal, requiring the
IOUs to obtain 20% of their power from renewables sources by 2010 (Senate Bill 107 codified
this goal in state law). Currently, the Commission is considering ways to achieve 33 percent
renewable energy by 2020.
Recently, there has been much discussion regarding the construction of new EHV transmission
lines in the Western Interconnection. The governors of California, Nevada, Utah and Wyoming
had proposed a new interstate EHV transmission line across the Western U.S., from Wyoming
with terminal connections in Utah, Nevada and California. Some of the Arizona utilities and
others are considering an EHV transmission project from Wyoming to the Desert Southwest
area, and PG&E has proposed an EHV project from British Columbia to Northern California.
In a letter, date 8/01/05, from Armie Perez, at that time Director of Transmission Planning, he
described the historical CA ISO planning process as follows 99:
APF-2
1. The Participating Transmission Owners (PTOs) submitted yearly transmission
assessment and expansion plans to the CA ISO covering the next five years in detail plus
a tenth year. The CA ISO reviewed the assessment to ensure it was adequate. The
expansion plans were reviewed to determine if the proposed projects: (1) solved an
identified problem, (2) were the best alternative from a system point of view, and (3)
were the most economical alternative.
2. CA ISO Management approved projects that met the CA ISO evaluation criteria and had
an estimated cost below $20 million or submitted the project for CA ISO Board approval
if they had an estimated cost exceeding $20 million.
3. Additionally, the CA ISO combined the individual PTOs plans submitted into one and
performed an independent and comprehensive analysis to make sure that “nothing fell
through the cracks”.
4. Finally, the CA ISO conducted studies to determine Reliability Must Run (RMR)
Generation requirements.
In 2005, CAISO revamped its transmission planning process to be more proactive. As a result of
the CA ISO’s reassessment of their transmission planning process the following Figure 1 and
Figure 2 will show how the new process is more interactive and involved all stakeholders:
http://www.CA ISO.com/docs/2005/08/01/2005080111170126493.pdf
APF-3
Figure 2. CA ISO’s New Interactive Transmission Planning Process
APF-4
o Governor’s Office—through the Western Governors Association, establish a
vision for EHV transmission projects in the Western Interconnection.
• The California Energy Commission
o Primary organization for long-term growth forecast.
Federal:
APF-5
Figure 3. Path 15 (source CA ISO)
2. Tehachapi – Several phases approved. The purpose of the project is to interconnect and
integrate forecast development of renewable energy projects totaling 4,500 MW. The
project will be built in eleven (11) phases with a total cost of approximately $1.8 billion.
APF-6
3. Palo Verde Devers No. 2 – Approved. A second 500 kV transmission line that extends 230
miles along the existing right-of-way between SCE's Devers Substation near Palm
Springs and the Palo Verde Generating Station switchyard west of Phoenix, Ariz. This
project would facilitate the delivery of new merchant generation from the Palo Verde
area to California. The project is expected to add an additional 1,200 MW of transfer
capability between Arizona and Southern California, for a cost of approximately $680
million.
5. Trans Bay Cable – Final Stages of Licensing - The project is being developed to supports the
energy import requirements into the San Francisco peninsula. The line consists of a HVDC cable
(+- 500 kV) with a transfer capability of approximately 400 MW, at a cost of $300 million.
APF-7
Figure 6. Trans Bay Cable Project (Source Babcock and Brown)
7. Green Path. The Green Path Project will improve the grid reliability within the IID
service area and facilitate exporting the geothermal energy from the Imperial Valley to
APF-8
the rest of the state. Cost of the project is approximately $430 million. The project
participants have agreed to link the Green Path Project with SDG&E’s Sunrise Powerlink
at Imperial Substation.
8. Frontier Line. The Governors of California, Nevada, Utah and Wyoming agreed to
support developers seeking to build the $5 billion Frontier Line transmission project,
which will allow access to the State of Wyoming’s vast coal resources and potential
development of renewable resources.
9. British Columbia to Northern California. Pacific Gas & Electric Company (PG&E) has
initiated the WECC Regional Planning Project Review of electric transmission
alternatives to connect Canada and the Pacific Northwest to Northern California.
Potential project alternatives would include both 500 and 765 kilovolt (kV) alternating
APF-9
current (AC) and high voltage direct current (HVDC) lines, via overhead or undersea
routes.
The proposed line is intended to provide three main benefits:
10. Central California Clean Energy Transmission Project 101. Pacific Gas & Electric Company
has proposed a new 150-170 mile 500 kV line between Midway Substation and the
Fresno area on new R/W. The project would increase the Path 15 transfer capability by
approximately 1,250 MW. The project has an operating date of 2013 at a cost of $0.7 to 1
billion. Benefits of the project are:
o Helps integrate southern California renewables with northern California.
o Increase utilization of the Helms PSP to enhance the value of off-peak generation.
o Increase reliability to Yosemite/Fresno area.
o Reduce Fresno Area local capacity requirement.
APF-10
Figure 9. PG&E’s Proposed Central California Clean Energy Transmission Project (source PG&E)
• Renewables integration.
• Stakeholder participation.
• Transmission project economic evaluation methodology.
• Market information on new generation for use in transmission planning.
• Coordination and collaboration with CPUC, Energy Commission, and other state
agencies.
To the extent that new transmission is within the CA ISO footprint and transmission costs are
rolled into the CA ISO TAC, the issue of cost allocation and cost recovery is moot. However, for
transmission projects involving multiple jurisdictions or where the project does not receive
rolled in rate treatment, the issue of cost allocation among jurisdictions and participating
utilities and associated tariff-based cost recovery becomes critical.
APF-11
4.9. Research Findings and Conclusions
As the research team reviewed the many industry changes over the past five decades they
found the changes have impacted the transmission planning process in the following five (5)
key areas:
Table provides a recap of the changes that have occurred in the various phases of the California
transmission planning process.
Table 1. Recap of Changes and the Impacts on Transmission Planning for the California IOUs
APF-12
Appendix G
Fact Sheet
TRANSMISSION RESEARCH PROGRAM
June 2008
B E N E F IT Q U A N T IF IC A T IO N A N D C O S T A L L O C A T IO N R E S E A R C H P R O J E C T
There is general policy consensus on the need quantification, cost allocation, cost recovery and
for new transmission projects to advance the project approval processes with a particular focus on
policy objectives of renewables integration, recommending methods for improved benefit
reliability management, efficient market quantification and cost allocation that better fits the
operations, interconnect new load and new electric industry structure and planning
generators, reduce transmission congestion environment.
and bottlenecks, and expand access to regional
The research focus was to identify different benefit
power markets. Historically, major transmission
streams, outline methodologies to quantify benefits
projects were sponsored and owned by utilities
including strategic benefits that have in the past
and generally proposed as part of new power
been handled qualitatively, and outline approaches
plant development by integrated utilities.
for assessment of benefits and assignment of
This landscape has changed with the separation benefits that could be factored into project cost
of generation and transmission assets and allocation and cost recovery decisions of major
separation of transmission operations from transmission projects that may involve multiple
ownership by shifting the responsibility of utilities and regulatory jurisdictions.
transmission operations from utilities to
Independent System Operators/Regional
Transmission Operators (ISOs/RTO’s) such as Background
CA ISO. These changes in industry structure, Utility efforts to develop new transmission projects
operations, and planning impact how new that are local in nature, address well documented
transmission projects are planned, evaluated reliability needs, are required for interconnecting
and approved. Approval of proposed major new load or generation are generally supported and
regional transmission projects in this new have been gaining regulatory approvals and
environment has proved to be challenging, stakeholder support. However, major regional
witness the difficulty in moving forward with transmission projects that involve multiple
several California based projects such as the jurisdictions and utilities and are needed for
Palo-Verde Devers No.2 line, Sunrise, integrating remote renewable resources, reducing
Greenpath, and others. This difficulty has costs, improving market operations, providing long
brought into focus the need for research on term strategic benefits and improving operating
benefit quantification and cost allocation flexibility, don’t have a clear path forward. Projects
methods to help with the approval of major cannot go forward without cost recovery certainty.
regional transmission projects. Cost recovery certainty requires allocation of costs
through tariffs or contracts. For a major regional
transmission project involving multiple jurisdictions
Problems Addressed and utilities to go forward, there needs to be a
This project was commissioned to perform a scoping consensus on benefits, costs, and allocation of
study to understand transmission benefit
APG-1
benefits and costs that can be embraced by part of the project research and key conclusions
stakeholders and policymakers. include:
The challenge associated with benefit quantification, Transmission Technologies – How do they
cost allocation, and approval of new transmission impact benefits, influence cost allocation, impact
projects was recognized in a September 2007 report stakeholders?
prepared by The Blue Ribbon Panel on Cost - Technologies Impact Line Capacity or
Allocation 102. Ratings, Power Flows, Grid Reliability
While the wholesale electricity market has changed - Selection of technologies impacts size of
fundamentally, the framework for enabling and benefits and distribution of benefits
encouraging investment that will better enable the Industry and Regulatory Changes – How have
grid to serve growing competitive markets has not things changed and what does it mean for large
yet fully emerged. One area still largely unresolved regional transmission projects?
is how the costs incurred in transmission expansion - Shift from utility centric integrated planning
will be allocated among users. While it is clear that to regional planning with stakeholder
many traditional cost-allocation approaches are no participation
longer appropriate, new principles governing the Review of Other Regions and Industries – What
allocation of cost responsibility for new transmission can we learn and apply for transmission in
investment have yet to be fully articulated and California and the Western Interconnection?
implemented.
- ISOs have similar planning processes
- Jointly owned multi-jurisdictional projects
Project Goals are almost exclusive to the west
A summary of the goals of this project are: - ISOs moving towards postage stamp
1. Assess current methods and develop (everybody pays) approaches with FERC
recommendations to improve benefit quantification
encouragement
methods.
2. Describe benefit quantification and cost allocation - Transparency in transmission planning,
approaches and how they may be utilized to inform predictable cost allocation/cost recovery
policy discussions, regulatory proceedings and methods, and length of experience with
stakeholder processes related to transmission planning process is important for acceptance
projects.
by stakeholders
3. Identify areas for research to improve the state-of-the
art for benefit quantification. - Telecom and gas industries are indeed
different – property rights
The project is not attempting to achieve stakeholder
The research focused on assessment of Benefit
consensus with respect to research findings and
recommendations on benefit quantification or to suggest a Quantification, Cost Allocation, and Approval
specific methodology for any proposed transmission Processes and Recommendations for improvements
project. The research is focused on developing a in methods.
framework for use in transmission planning and approval
processes.
APG-2
Benefits of the Project Task 1: Benefit Streams, Quantification Methods,
The investigation identified seven research methods Cost Recovery, Recent Transmission Projects
that can augment existing benefit quantification Task 2: Framework to Evaluate Future Transmission
approaches to quantify the full range of
Projects and Benefits
transmission project benefits – these seven methods
are: Task 3: Research Cost Recovery and Cost Allocation
1. Public Good – long asset life benefit–use of Methodologies
social rate of discount Task 4: Review Technology Options and Impact on
2. Fuel Diversity Benefit–renewable resource System Utilization and Cost Allocation
integration
Task 5: Review and summarize examples of
3. Reliability Improvement from Extreme System
Multiple Contingency Events–new concepts alternative approaches that have been utilized for
transmission project approvals.
4. Risk Mitigation for Low Probability/High
Impact Extreme Market Events–new concepts Task 6: Review existing process for transmission line
5. Incorporate societal or strategic benefits through approval, rate determination and cost recovery.
processes that lead to stakeholder consensus
Task 7: Reports and Briefings
6. Resource Portfolio Analysis
7. Dynamic Analysis (impact of new transmission Task 8: Technical Advisory Committee (TAC)
on construction of new generation in the A TAC was formed to serve as a sounding board for
exporting region)
the research project and provide feedback on
research direction. The TAC is comprised of:
Application of Improved Benefit Quantification Dede Hapner, Vice President, FERC and ISO
Approaches Relations, Pacific Gas & Electric.
Utilizing the seven proposed research methods to Les Starck, Director of T&D Business Unit,
quantify the benefits of transmission projects will Southern California Edison.
enable policymakers, utilities, and stakeholders to
Caroline Winn, Director of T&D Asset
quantify the benefits for projects, understanding
Management, San Diego Gas & Electric.
distribution of benefits among participants, and
enabling each utility or jurisdiction to evaluate the Sean Gallagher, Director of Energy Division,
impacts on their individual constituency. The California Public Utilities Commission.
different uses of the benefit quantification methods Steve Ellenbecker, Energy Advisor to Wyoming
for proposed new transmission projects include: Governor Freudenthal.
Calculating and quantifying the distribution of
Jim Bushnell, Research Director, University of
benefits among participants and jurisdictions.
California Energy Institute.
Demonstrating and sharing benefits for direct
and indirect participants and critical
stakeholders.
Enabling each utility or jurisdiction to analyze
benefits of projects (or package of projects)
Providing guidance on cost allocation among
multiple participants and jurisdictions
Selecting cost recovery methodology.
APG-3
Project Schedule Program Contact Information
The project was approved and commissioned in California Institute for Energy and the Environment
October 2006. The TAC workshops were held in
(CIEE, for the California Energy Commission)
January and September 2007. A total of four project
briefings at several forums have been made. A Bonderson Building, 901 P Street, Suite 142A
briefing at CAISO was held in February 2008.
Sacramento, CA 95814-6424
Commissioners: James D. Boyd, Jeffrey Byron, Karen Douglas, Arthur H. Rosenfeld 3.01.08
APG-4
Appendix H
Electric, gas, and telecommunication industries all rely on networks for transport. During the
1990’s, there was a tremendous expansion in telecom transport capacity. Also, gas pipeline
capacity has generally kept pace with demand as a result of new pipelines or expansion of
capacity of existing pipelines.
This section provides a comparative assessment of the three industries and summarizes key
differences between electricity and the Gas and Telecom industries that have a bearing on
development of new capacity, cost allocation, and cost recovery.
APH-1
2.0 Industry Comparison
All three industries rely on physical networks for transport, with the exception that in the
telecom industry where wireless technology is utilized for transmission short distances 103. The
key characteristics of the three networks can be compared in terms of:
Planning
Infrastructure Characteristics
Approvals, Cost Recovery and Rate Making
A comparative summary of the three industries is provided in Table 1.
INFRASTRUCTURE
CHARACTERISTICS Gas Telecom Electricity
APH-2
Amount of Known Known Variable in an AC network
Transport Capacity due to parallel flows and
lack of flow control
Approvals, Cost
Recovery & Rate
Making Gas Telecom Electricity
APH-3
approvals – lead agency
Construction permit –
utility commissions
Cost Responsibility Subscription Owner’s risk Negotiated solution
contracts based on amongst project
open season or participants subject to
owner’s risk regulatory approvals
Cost Recovery FERC approved tariff Market FERC approved ISO tariff
2.1. Planning
In the gas industry, interstate pipeline companies develop plans for new pipelines or expansion
of existing pipelines. The need for such facilities is demonstrated through an “open-season”
subscription process. Lead times are generally 2– to 5–years and the project justification is
generally based on meeting market need as evidenced by subscriptions for capacity.
Telecom industry planning decisions are generally based on individual company commercial
decisions and lead times are short ranging from 1– to 3–years.
Electric transmission planning involves multiple levels of review and stakeholder participation.
Traditionally, planning was carried out by utilities. Now, the planning function has shifted to
Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs).
However, transmission projects may also be planned by new entrants or stakeholders. The
planning process now involves utilities, RTOs/ISOs and stakeholders, and ultimately Western
Electricity Coordinating Council (WECC) (in the west) for review of proposed transmission
project for reliability and to establish a rating. The lead time is 5– to 10–years.
Telecom infrastructure consists of copper, microwave, satellite or fiber lines. The copper and
fiber are often buried along existing rights-of-ways of railroad tracks, gas pipelines or other
infrastructure (e.g. cables over electric transmission lines). As in the case of gas, the transport
capacity for voice and data is fixed based on equipment (for example, number of lit fibers in the
case of fiber to transport voice and data). Microwave repeater facilities are typically located at
the tops of prominent geographic features, such as mountains, to achieve the greatest distance
between repeaters (microwave communication depends on a line-of-sight between repeater
stations). In urban areas, repeaters are frequently mounted on towers atop buildings. Satellite
APH-4
antennas may be placed at ground level or on building roofs where clear line-of-sight to the
communications satellite is available.
Electric transmission lines require much larger rights-of-ways (100 to 300’) and offer limited
opportunities for multiple uses. Rights-of-way (ROW) costs are one reason why transmission
line costs can be several times greater than gas or telecom for the same distance. In addition, the
transport capacity of an AC electric transmission line is often determined by network
characteristics and can change as a result of parallel network flows and system configuration.
AC transmission lines also have other major differences compared to the gas and telecom
industries – flows are not controlled (except by use of phase shifting transformers and other
flow control devices which can be costly), but determined by the physics of the network;
transmission delivery capacity is variable; and the use of transmission is subject to open access
rules with transmission owner (or contract right holder) being able to use the transmission on
the same terms and conditions for access as other market participants.
Telecom approvals are primarily a commercial decision with some FCC licensing requirements
Transmission projects require approvals by:
These different levels of approvals also involve stakeholders and the process can be time
consuming, expensive, and uncertain.
A summary of the key differences between Electricity and Gas/Telecom that Impact Cost
Allocation and Cost Recovery are presented in Table 2.
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Table 2
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3.0 ANALYSIS AND CONCLUSIONS
The open season subscription approach used in the gas industry could be used in the electric
industry. In a sense, if a new project is proposed and approved by the California ISO for
integration into the CAISO system with rolled in rates, it is the equivalent of full subscription by
CAISO on behalf of CAISO users. The subscription approach is more directly applicable to DC
lines (or AC with flow control). In any event, certainty about cost recovery including a return on
investment is key for transmission projects to move forward.
It is unlikely that transmission will be built by investors taking on “commercial risk” as is the
case in telecom due to the regulatory and rate approval processes that govern transmission.
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