The Economic Case for New Transmission in the United States:
Meeting the Need for Large-Scale Wind Energy
by
Laura Bruce
David Cieminis
Siobhan Doherty
Theodore Ludwick
A project submitted
in partial fulfillment of the requirements
for the degree of
Master of Science
(Natural Resources and Environment)
at the University of Michigan
December 2009
Faculty Advisor:
Professor Thomas Lyon
This page intentionally left blank.
i
Acknowledgements
Project Sponsors
Project Advisors
Sponsor Organization Advisors
 Michael Goggin, Electric Industry Analyst, AWEA
 Rob Gramlich, Policy Director, AWEA
Faculty Advisor
 Tom Lyon, Dow Professor of Sustainable Science, Technology and Commerce, Director
of the Erb Institute for Global Sustainable Enterprise
ii
Abstract
Recent years have seen a large increase in both the supply of and the demand for renewable
energy. Among non-hydro renewable technologies, wind generation has gained the largest share
due to its relative maturity and lower cost. In 2008, 8,300 MW of wind generation were
installed, making wind generation the largest source of energy capacity investment in the United
States. However, even with the recent large increases in wind generation investment, many of
the nation’s best wind resources have seen little development due to transmission constraints. As
a result, large increases in transmission investment will be needed in order to increase wind
generation’s role in the nation’s energy mix. Our paper evaluates whether large investments in
transmission infrastructure to reach high capacity factor wind resources are justified. We
examine the cost of wind generation and transmission and compare that cost to the cost of natural
gas generation without transmission. Natural gas generation provides a suitable comparison as it
was the second most installed generation in 2007, and similar to wind generation, it often fulfills
an intermediate load position in a region’s energy mix. Using a single variable analysis, we
identified specific cost drivers that impacted the cost of wind generation plus transmission and
natural gas generation. Our study found that the length of transmission line, voltage of
transmission line, load factor of transmission line, and site wind capacity factor have the largest
impact on the cost of wind generation. Additionally, in many scenarios, wind generation is cost
competitive with natural gas generation. However, under current conditions, we also found that
accessing distant wind resources is not the most cost competitive option due to the high
transmission costs. Therefore, we recommend policies that reduce transmission costs, improve
the competitiveness of wind generation and share those costs across all stakeholders. Such
policies include the creation of high voltage transmission networks, increasing transmission load
factors, limiting integration costs, providing continued tax credits, and putting a price on carbon
dioxide emissions.
iii
Table of Contents
Acknowledgements ......................................................................................................................... ii
Project Sponsors.......................................................................................................................... ii
Project Advisors .......................................................................................................................... ii
Abstract .......................................................................................................................................... iii
Table of Contents ........................................................................................................................... iv
List of Acronyms ........................................................................................................................... vi
List of Tables ................................................................................................................................ vii
List of Figures .............................................................................................................................. viii
Executive Summary ........................................................................................................................ 1
Key Findings ............................................................................................................................... 1
Recommendations ....................................................................................................................... 2
Introduction and Problems with Existing Energy System .............................................................. 3
Transmission Grid Far from Wind Resources ............................................................................ 3
Transmission History and Regulatory System ............................................................................ 4
Purpose of Study ......................................................................................................................... 6
Options to Meet our Energy Needs ................................................................................................. 8
Wind............................................................................................................................................ 9
Natural Gas ............................................................................................................................... 15
Comparison of Wind and Natural Gas ...................................................................................... 22
Challenges to Expanding Transmission ........................................................................................ 23
Transmission History and Current Needs ................................................................................. 23
Barriers to Implementation ....................................................................................................... 25
The Model ..................................................................................................................................... 31
Model Scenarios........................................................................................................................ 32
Cost of Wind Electricity ........................................................................................................... 35
Transmission ............................................................................................................................. 42
Cost of Natural Gas Electricity ................................................................................................. 52
Carbon Dioxide ......................................................................................................................... 56
Analysis of Model Results ............................................................................................................ 59
Sensitivity Analysis .................................................................................................................. 59
Integrated Scenarios .................................................................................................................. 62
iv
Comparison with Prior Studies ................................................................................................. 64
Recommendations ......................................................................................................................... 68
High Voltage System ................................................................................................................ 68
Load Factors.............................................................................................................................. 69
Manage Integration Costs ......................................................................................................... 70
ITC/PTC .................................................................................................................................... 72
Carbon Prices ............................................................................................................................ 72
Hedging Value of Wind Generation ......................................................................................... 73
Conclusion .................................................................................................................................... 74
Next Steps ................................................................................................................................. 75
Appendix ....................................................................................................................................... 76
A.
Model Assumptions and Calculations .............................................................................. 76
Capital Costs ............................................................................................................................. 76
B.
States within the JCSP Study Area with a RPS ................................................................ 83
C.
Brief Background on Carbon Legislation ......................................................................... 84
D.
Brief Background on Carbon Prices ................................................................................. 87
E.
Carbon Price Forecasts ..................................................................................................... 89
Bibliography ................................................................................................................................. 90
Endnotes...................................................................................................................................... 101
v
List of Acronyms
AC
AEP
AWEA
CC
CT
DC
DOE
EIA
ERCOT
FERC
GW
GWP
IOU
IPP
ISO
JCSP
kV
kW
kWh
LBNL
LDC
LNG
MAPP
MCF
MISO
MMBtu
MW
MWh
NERC
NIMBY
NREL
NYISO
O&M
PJM
POU
RPS
RTO
SIL
SPP
TCF
tCO2
TVA
Alternating Current
American Electric Power
American Wind Energy Association
Combined Cycle
Combustion Turbine
Direct current
Department of Energy
Energy Information Administration
Electric Reliability Council of Texas
Federal Energy Regulatory Commission
Gigawatt
Global Warming Potential
Investor Owned Utility
Independent power producer
Independent system operator
Joint Coordinated System Plan
Kilovolt
Kilowatt
Kilowatt hour
Lawrence Berkeley National Laboratory
Local Distribution Company
Liquefied natural gas
Mid-Continent Area Power Pool
Thousand cubic feet
Midwest Independent System Operator
Million British thermal units
Megawatt
Megawatt hour
North American Electric Reliability Corporation
Not in my backyard
National Renewable Energy Lab
New York Independent System Operator
Operations and Maintenance
PJM Interconnection
Publicly Owned Utility
Renewable portfolio standard
Regional transmission organization
Surge Impedance Loading
Southwest Power Pool
Trillion cubic feet
Tons of carbon dioxide
Tennessee Valley Authority
vi
List of Tables
Table 1: Emission Profile of Natural Gas Electricity Versus Other Fossil Fuels ......................... 21
Table 2: Summary of Natural Gas Versus Wind .......................................................................... 22
Table 3: Comparison of Wind Stakeholders ................................................................................. 27
Table 4: Comparison of Three Wind Scenarios ............................................................................ 33
Table 5: Comparison of Natural Gas Scenarios ............................................................................ 34
Table 6: Summary of Wind Integration Studies ........................................................................... 39
Table 7: Comparison of Natural Gas Wellhead Prices ($/MMBtu) ............................................. 54
Table 8: Sensitivity Analysis ........................................................................................................ 59
Table 9: JCSP Reference and 20 Percent Wind Scenarios Cost Comparison .............................. 65
Table 10: Unit Transmission Cost Increases with Length ............................................................ 66
Table 11: Over-Subscribed Mega-Projects ................................................................................... 69
Table 12: Comparison of Electricity Prices ($/kWh) with ITC, PTC or Neither ......................... 72
Table 13: Construction Costs Assumptions .................................................................................. 76
Table 14: O&M Assumptions ....................................................................................................... 76
Table 15: Capacity Factor Assumptions ....................................................................................... 77
Table 16: Fuel Cost Assumptions ................................................................................................. 77
Table 17: Transmission Cost Assumptions................................................................................... 79
Table 18: DC Converter Station Cost Assumptions ..................................................................... 79
Table 19: Series Compensation Cost Assumptions ...................................................................... 80
Table 20: Full Line Losses Assumptions ...................................................................................... 81
Table 21: Surge Impedance Loading (SIL) Assumptions ............................................................ 82
vii
List of Figures
Figure 1: Wind Resources and Existing Transmission Lines ......................................................... 4
Figure 2: NERC Regions ................................................................................................................ 5
Figure 3: Map of Regional Transmission Organizations and Independent System Operators ....... 5
Figure 4: Map of Current U.S. Transmission Grid ......................................................................... 6
Figure 5: Comparison of Annual New Capacity Additions for Different Electricity Resources ... 8
Figure 6: 2008 Year End Installed Wind Capacity (MW) .............................................................. 9
Figure 7: 2007 Wholesale Price of Wind vs. Grid Average ......................................................... 10
Figure 8: Wind Industry Structure ................................................................................................ 10
Figure 9: Trends in Wind Asset Ownership ................................................................................. 11
Figure 10: Utility Generation Curve (California, 2005) ............................................................... 12
Figure 11: Seasonality of Wind Generation and Load Center Demand ....................................... 14
Figure 12: Natural Gas Usage by Sector, 2008............................................................................. 16
Figure 13: Percentage of Natural Gas Used for Generating Electricity........................................ 16
Figure 14: 2006 U.S. Electric Power Industry Net Summer Generation Capacity....................... 17
Figure 15: Natural Gas Industry Structure .................................................................................... 18
Figure 16: Pictorial Representation of the Flow of Natural Gas from Wellhead to End-Use ...... 19
Figure 17: History of Power Plant Developments ........................................................................ 23
Figure 18: Transmission Construction Expenditures (billion $)................................................... 24
Figure 19: Conceptual New Transmission Line Scenario 2030 ................................................... 24
Figure 20: Transmission Stakeholder Structure ............................................................................ 27
Figure 21: Wind Project Interconnection Requests ...................................................................... 28
Figure 22: Current Interconnection Requests by Generation ....................................................... 28
Figure 23: Cost Structure: Wind Generation + Transmission ...................................................... 31
Figure 24: Cost Structure: Natural Gas Generation ...................................................................... 32
Figure 25: Electricity Cost Components ....................................................................................... 34
Figure 26: U.S. Wind Power Capacity Additions, 1999 to 2008 .................................................. 36
Figure 27: Impact of Tax Credits on Price of Electricity.............................................................. 38
Figure 28: Impact of Capacity Factors on Wind Electricity Costs ............................................... 41
Figure 29: Diagram of Transmission Costs in Model ................................................................... 43
Figure 30: Diagram of Transmission Line Capacity in the Model ............................................... 43
Figure 31: Line Length and Voltage Effect on Wind Electricity Prices ....................................... 45
Figure 32: Effect of Load Factors on the Price of Wind Electricity ............................................. 46
Figure 33: Effect of Series Compensation (Capacitors) on the Cost of Wind Electricity ............ 46
Figure 34: Effect of Transformer Costs on the Price of Electricity .............................................. 48
Figure 35: ROE Impact on the Cost of Wind Electricity .............................................................. 50
Figure 36: Impact of Cost Recovery Period on Electricity Cost .................................................. 51
Figure 37: Cost per kWh of Electricity in Illinois, Iowa, and North Dakota Scenarios ............... 52
Figure 38: U.S. Natural Gas Wellhead Price ($/MMBtu), 1967 to 2007 ..................................... 53
Figure 39: Comparison of U.S. Natural Gas Prices, 1997 to 2007 (2008$/MMBtu) ................... 54
Figure 40: Comparison of EIA Forecasts for Natural Gas Prices, 2006 to 2030 (2008$/MMBtu)
............................................................................................................................................... 55
Figure 41: Comparison of Cost of Natural Gas Generated Electricity at Different Natural Gas
Prices with Cost of Wind Electricity .................................................................................... 56
viii
Figure 42: Comparison of Carbon Prices Across Product Types ................................................ 57
Figure 43: Comparison of Cost of Natural Gas Electricity under Carbon Dioxide Pricing
Scenarios with Cost of Wind Electricity................................................................................. 58
Figure 44: Wind Capacity Impact on Electricity Price ................................................................. 62
Figure 45: Load Capacity Impact on Electricity Price.................................................................. 63
Figure 46: ERCOT Analysis of Wind Production Cost Savings and Transmission Costs ........... 65
Figure 47: Miles of New Transmission Lines Versus Unit Transmission Costs .......................... 66
Figure 48: LBNL Review of Incremental Generation Versus Unit Transmission Cost ............... 67
Figure 49: Benefits of Combining Balancing Areas ..................................................................... 71
Figure 50: Surge Impedance Loading (SIL) Curve ...................................................................... 81
ix
1. Executive Summary
1. Executive Summary
As a result of and energy and environmental policies, demand for renewable energy in the United
States is growing. This is particularly true for wind energy due to its relative maturity and lower
cost compared to other renewable energy resources. The highest quality wind resources,
however, are located in the Great Plains region of the country, which is far from load centers.
The current transmission system is not designed to transport electricity long distances, and
therefore new transmission infrastructure will be needed if the United States is going to access
these more remote wind resources.
This study provides an overview of wind and natural gas generation costs and capabilities as well
as the state of the transmission grid. We examine the costs of developing new wind energy in
high quality resource areas and the new transmission infrastructure required to access these
resources. We then compare these costs to the cost of developing new wind in lower quality
resource areas and new natural gas generation close to load centers, which requires less
transmission investment. Wind is compared to natural gas because these are the two most
common new generation sources in the United States. Transmission is considered as a cost
bundled with wind energy development due to the “cost causer pays” model, which assigns all
costs to the generating unit that requires the transmission upgrade.
We developed a model to analyze the costs of electricity based on several wind, transmission,
and natural gas development scenarios. Using this model, we determined the factors that have the
greatest ability to improve the cost competitiveness of wind and transmission in comparison to
natural gas. Our study is intended for a non-technical audience who would like to understand the
differences between wind and natural gas fueled electricity and ways to make wind development
more cost effective.
Our study begins with an introduction to the growing demand for electricity and renewable
energy and the state of the transmission grid. We next examine the generation characteristics and
industry structures of wind and natural gas, two generation resources that will play a major role
in meeting the growing demand for electricity. In the following section, we outline challenges to
developing transmission to meet future electricity demand. We then introduce our model, which
allows us to delve into the factors that will make wind and transmission investments cost
competitive with natural gas. Finally, based on the findings from our model, we make several
policy and operating recommendations that will boost the cost competitiveness of wind.
Key Findings
Our analysis focused on building a model to examine the cost of wind electricity, including
transmission, for three scenarios that differed in the length of the transmission line (150 miles,
600 miles and 1,000 miles) and the wind capacity factor (27 percent, 37 percent and 40 percent,
respectively). We compared the cost of wind and transmission primarily to the cost of electricity
from a combined cycle natural gas plant. We performed an in depth analysis of the multiple
factors that contributed to the cost of wind electricity, transmission and natural gas for each of
these transmission scenarios, and there were several factors that stood out as making a significant
impact in the cost competitiveness of wind and transmission versus natural gas, which are
discussed below:
1
1. Executive Summary






Investment Tax Credit (ITC) and Production Tax Credit (PTC): Without the tax credits,
wind plus transmission would not be competitive with natural gas, even with relatively
little transmission investment associated with the wind development. The tax credits make
wind competitive with natural gas at the 150 mile and 600 mile scenarios, but are not able
to make wind competitive at the 1000 mile scenario. The ITC makes wind plus
transmission lowest cost at the 150 mile scenario, costs are about equal for PTC and ITC
at the 600 mile scenario and lower for PTC than ITC at the 1000 mile scenario.
Wind Capacity Factor: Under the reasonable range of capacity factors that we analyzed,
the 1,000 mile transmission line scenario was not competitive with natural gas. While
higher capacity factors can make the 600 mile investment lower in cost than natural gas,
wind resources accessed with a 1,000 mile line are not competitive with natural gas even
at very high wind capacity factors.
Voltage and Series Compensation: Our model showed clear cost advantages of 765kV
lines with series compensation to boost the capacity (loadability) of transmission lines and
reduce losses.
Load Factor: The average capacity of a transmission line (load factor), has an especially
high impact on the per kWh cost of electricity for long distance lines because of the high
cost of the infrastructure and higher losses compared with shorter lines.
Natural Gas Prices: Wind was competitive with natural gas generation across the full
range of natural gas prices analyzed for the 150 and 600 mile line scenarios. However,
wind with a 1,000 mile line was only competitive with natural gas generation at gas prices
at $8/MMBtu and a wind capacity factor greater than 40 percent. High natural gas prices
and high wind capacity factors can make transporting wind across very long distances cost
competitive.
Price on Carbon Dioxide Emissions: Because of the low emissions factor of natural gas, a
price on carbon dioxide emissions is not a major driver for making wind more competitive
with natural gas. The price would need to rise to $40/tCO2e before natural gas combined
cycle would be competitive with wind requiring very long transmission lines.
Recommendations
The findings from our model provide support for several grid operation and policy reforms. Our
findings point to the importance of the following initiatives:
 Reform funding mechanisms and planning processes to spur development of a high
voltage inter-state transmission system.
 Improve load factors of very long lines by over-subscribing lines, accessing wind
generation in different wind regimes, or sharing lines with other types of generation or
storage.
 Maintain tax credits, such as the ITC or PTC, for wind investments.
 Manage integration costs by increasing the size of balancing areas and through energy
markets.
 Place a price on carbon dioxide emissions in order to improve the economics of renewable
energy compared to fossil fuel resources.
 Continue to research the hedging value of wind in order to capture the full value of this
resource.
2
2. Introduction
2. Introduction
At the end of 2008, the U.S. Energy Information Agency (EIA) projected energy growth to be
one percent annually between 2007 and 2030.1 While that number is now likely lower due to the
2008 to 2009 economic downturn, even a half percent growth equates to more than 500 million
megawatt hours (MWh) of new energy required and roughly 186,000 megawatts (MW) of new
generation capacity before 2030.2 Not only is overall energy demand growing, but demand for
renewable energy is rising at an even faster rate. The EIA projects that roughly 14 percent of
energy generated in 2030 will come from renewable sources, compared to the current nine
percent.3This will require installing more than 60 gigawatts (GW) of new renewable energy
capacity by 2030. The U.S. is already experiencing a significant increase in investment in
renewable energy. For instance, in 2008, 60 percent of all capacity brought online was from
renewable sources.4
Several factors are driving this increase in demand for renewables, including high fossil fuel
prices, higher capital costs for coal and natural gas due to new emission standards, renewable
portfolio standards (RPS), and potential greenhouse gas regulation. As of the end of 2008, 28
states had an RPS,5 and 12 separate climate change legislation bills had been introduced in the
U.S. legislative branch.6 Further, President Barack Obama has stated his support for a cap and
trade program to reduce U.S. greenhouse gas emissions 80 percent by 2050, as well as for a
federal RPS of 25 percent by 2025.7
The U.S. transmission system was not designed to handle the load or complexity of the current
electricity system, but will need to respond to the increasing demand for electricity, particularly
from renewable sources, in order to ensure that electricity can be reliably delivered to customers.
While most transmission investment has historically been focused near load centers, a key issue
for bringing additional wind resources online is that the best wind resources are located far from
load centers. This disconnect between high wind resource areas and historical development of
the grid poses a challenge for accessing new renewable energy resources.
Transmission Grid Far from Wind Resources
Prime wind resources are located in the middle of the United States, running in a band from
North Dakota to Texas, with total economic land based wind resources estimated to be greater
than 8,000 GW.8 As a reference point, in 2008, total nameplate capacity for all generation in the
United States was 1,087 GW.9 While that 1,087 GW of generation capacity includes resources
that wind does not compete against and could not fully displace, it is useful to illustrate the
magnitude of wind resources available.
The location of these prime wind resources is important, as most load centers are sited on the
country’s coasts, which necessitates new transmission infrastructure to deliver wind power to the
end user. Figure 1shows the quality of wind resources across the country, concentrated in the
Plains region and offshore. It also shows the major transmission lines, which for the most part
are located on the coasts where wind speeds are significantly lower.
3
2. Introduction
Figure 1: Wind Resources and Existing Transmission Lines
Source: See Endnote10.
Figure 1clearly illustrates that additional transmission will be necessary if high quality wind
resources in the United States are going to be accessed in order to meet the growing need for
electricity and requirements for renewable energy.
Transmission History and Regulatory System
The transmission system as it has developed to date is the product of more than 100 years of
technical and regulatory evolution. In the late 1800’s, electricity was a local affair. Thomas
Edison’s direct current (DC) generation and transmission system edged out Nicholas Tesla and
George Westinghouse’s alternating current (AC) system in a system that saw local power plants
serve nearby neighborhoods with short transmission lines. At the time, electric voltage at the
power plant matched the voltage of the end use (typically light bulbs). However, as transformer
technology improved and power plants generated greater amounts of electricity, these local
electric fiefdoms became larger. Further, the technology at that time made it easier and cheaper
to increase the voltage in AC systems than in a DC system. Higher voltages meant lower losses
over distance, and the entire system transitioned to AC technology in the early part of the 20th
century in order to serve the growing demand for electricity.
With the Great Northeast Blackout of 1965, the advent of nuclear technologies, and the
development of large hydro projects, it was clear that there was a need for a more robust and
better-managed power grid, better able to deliver the least expensive power to the end consumer.
4
2. Introduction
The North American Electric Reliability Corporation (NERC) was established in 1968 to do just
that. NERC develops and enforces reliability standards; monitors the reliability of the bulk
power system; evaluates users, owners, and operators of the electric grid for preparedness; and
educates, trains, and certifies industry personnel.11 NERC operates eight regions (Figure 2) under
the oversight of Canadian governmental authorities and the U.S. Federal Energy Regulatory
Commission (FERC), the regulatory body responsible for interstate transmission of electricity
and natural gas.
Figure 2: NERC Regions
Source: See Endnote 12.
Within the NERC regions, regional transmission organizations (RTOs) and independent system
operators (ISOs) coordinate and control the transmission grids. There are nine major RTOs and
ISOs (Figure 3).
Figure 3: Map of Regional Transmission Organizations and Independent System Operators
Source: See Endnote 13.
5
2. Introduction
The transmission grid is physically divided into three regions: the eastern interconnection,
western interconnection, and Texas interconnection (Figure 4). While RTOs and ISOs do
interact, the current physical structure of the grid means that they do not operate as a unified
system.
Figure 4: Map of Current U.S. Transmission Grid
Source: See Endnote 14.
The fragmented transmission regulatory structure has contributed to a grid that is not highly
interconnected. Because of this structure, designing and implementing regional transmission
plans that extend across multiple regulatory jurisdictions remains uncommon and difficult to
achieve. This is a particular challenge for wind energy, which is frequently situated far from
populated areas, requiring transmission to cross hundreds of miles to reach load centers.
The lack of a unified grid also results in broad differences in the prices charged to the end
consumer. Because transmission capacity does not currently exist in many locations to transport
power from more efficient plants to load centers, consumers must pay the rates charged by local
plants, which are not necessarily the most efficient producers. This lack of transmission capacity
has resulted in estimated annual transmission congestion costs of over $21 billion dollars in the
Eastern United States alone.15
Purpose of Study
Renewable energy sources bring a unique mix of issues to transmission planning; this report will
focus specifically on those issues related to utility-scale wind generation.16Wind resources, like
many renewables, offer an energy source with essentially zero fuel costs, but also introduce
additional transmission costs if wind is located far from load centers. While accessing wind
resources far from load centers is technically feasible given current transmission technology,
6
2. Introduction
assigning additional transmission costs to wind energy raises the cost of delivered electricity
from wind.
In comparison, traditional fossil fuel sources are subject to fluctuating fuel costs as well as
potential costs associated with carbon dioxide emissions but are not as site specific and so do not
require investment in long distance transmission lines.
Most transmission planning studies to date have focused either on a macro-scale analysis of the
potential for wind development in the United States or on a micro-scale analysis of the specific
impact that wind will have on particular grids. While both levels of analysis are extremely
important, the space between the two, in which regional transmission planners and wind
developers make resource and infrastructure investment decisions, has been relatively
unexplored and inaccessible for those without a technical background in transmission. This
study aims to address that area.
The purpose of this study is to determine the policies and decisions that result in competitive
wind electricity (as measured by a lower per kWh cost of electricity produced) taking into
account the cost of transmission, thereby providing policy makers and others with a tool to aid
their infrastructure investment decisions. Whether the most economically attractive choice for
new generation is new wind along with transmission or natural gas depends on several factors,
including the length of the required transmission line, the quality of the wind resource, the
projected price and volatility of natural gas, and costs associated with environmental impacts.
7
3. Options to Meet Our Energy Needs
3. Options to Meet Our Energy Needs
Rising demand for electricity in general and renewables in particular, has created an interesting
tension for new generation investments. With significant investment in new generation capacity
required, decision-makers must determine how to provide electricity that is clean, reliable and
affordable.
Of the renewable energy options available, wind energy is currently the most viable energy
source, for reasons that include the established, cost-competitive, and scalable nature of its
technology and social and political support. However, wind resources are often sited in locations
geographically distant from demand centers, thereby requiring additional transmission costs.
Of the fossil fuel options available to meet new energy demand, natural gas is currently the most
frequently built resource.17 Though coal generation has less-costly fuel inputs, natural gas has a
lower carbon footprint, similarly accessible fuel, and similar or shorter plant construction times.
Nuclear capacity, another potential generation source, has declined over the past decade due to
lengthy permitting and construction times.
In 2007, the most recent year for which complete data was available, the above factors resulted
in wind accounting for the second largest portion of capacity additions. Of the 15,026 MW of
capacity additions in 2007, wind accounted for 5,209 MW of new capacity and natural gas-fired
generation accounted for 7,587 MW (Figure 5).18In light of the rising prevalence of wind and
natural gas compared to other generation sources, this report compares the cost to meet new
demand using either of these sources. The two are examined in greater detail below.
Figure 5: Comparison of Annual Capacity Additions for Different Electricity Resources
10000
Capacity Additions (MW)
9000
8000
7000
6000
Coal
5000
Petroleum
4000
Natural Gas
3000
Hydro
2000
Wind
1000
0
1999
2000
2001
2002
2003
Year
Source: See Endnote 19.
8
2004
2005
2006
2007
3. Options to Meet Our Energy Needs
Wind
Wind has been one of the fastest growing energy resources over the past decade. In 2008, 8,545
MW of wind capacity were installed, a 50 percent year-over-year growth rate from the 2007
installed capacity additions of 5,209 MW. This followed a 45 percent year-over-year growth rate
in 2007.20 As shown in Figure 6, the majority of installed wind generation capacity is situated in
Texas (7,113 MW) and Iowa (2,791 MW), with California (2,517 MW), Minnesota (1,753 MW),
and Washington (1,375 MW) rounding out the top five.21 In 2008, wind installations in the
United States are estimated to have produced 49 million megawatt hours (MWh) of electricity,
just over 1.5 percent of the U.S. total.22
Figure 6: 2008 Year End Installed Wind Capacity (MW)
Source: See Endnote 23.
Wind Price
As this study examines the impact of transmission on the final cost of new wind generated
electricity, it is useful to understand the current baseline of prices for wind electricity, excluding
transmission, but including the production tax credit, which is approximately $0.02 per kWh.
Over the past 30 years, wind prices have declined from a price of roughly $0.45 per kWh24 to
2007’s capacity weighted average price of $0.045 per kWh (including the PTC).25 In
comparison, the average 2007 wholesale price for the entire United States was $0.0572 per kWh
(Figure 7).26 The factors affecting wind price include the capital costs of the system (turbine
blades, gear boxes etc.) as well as the services and infrastructure necessary to support wind. The
9
3. Options to Meet Our Energy Needs
past three years have seen wind prices rise slightly, primarily due to increased demand for
turbines and increased material costs.27
Figure 7: 2007 Wholesale Price of Wind vs. Grid Average
Source: See Endnote 28.
Wind Industry Structure
The wind energy industry encompasses seven main groups, as detailed in Figure 8 below.
Figure 8: Wind Industry Structure
Source: See Endnote 29.
As Figure 8 illustrates, the wind industry value chain is long and fragmented. This has particular
relevance in the discussion of transmission, as no single vertically integrated entity spans the
entire value chain from development to final consumer portion of the industry structure.
Developers are distinct from owner operators, neither of whom are transmission planners or
builders. Similarly, utility off-takers cannot coordinate transmission and generation activities
10
3. Options to Meet Our Energy Needs
and in some cases, may even have incentives not to build new infrastructure.30 The end result is
that there is no single force advocating for a complete system with incentives aligned to deliver
low cost electricity to the end consumer.
The fragmentation of the wind electricity structure is seen in the production of wind power.
Historically, independent power producers (IPPs) owned wind farms and sold electricity
generated on those farms to utilities using power purchase agreements. While that model
remains the dominant form for the industry, utilities have moved towards ownership in recent
years, as shown in Figure 9 below. Coldham et al. theorize that utilities are making this
transition in part to negate supplier power that independent power producers have.31
Figure 9: Trends in Wind Asset Ownership
Source: See Endnote 32.
It is still too early to determine the full impact of the shift towards utility ownership of wind
assets. However, it is worthwhile to note that the large number of players involved in the wind
value chain makes allocating transmission costs a complicated affair.
Wind Generation Characteristics
Utility-scale wind has several characteristics that distinguish it from traditional fossil resources
including the following:
 Utility load profile,
 Variability, and
 Seasonality.
We will discuss each of these characteristics in detail in the following sections.
11
3. Options to Meet Our Energy Needs
Utility Load Profile
Wind has distinct characteristics in terms of the utility load profile that it satisfies. In brief,
utilities, RTOs and ISOs attempt to match their generation capacity resources to the shape of
their customers’ daily demand curve (Figure 10, representative of general trends). Base load
plants, such as coal, nuclear, geothermal and some hydro, predictably run close to 24 hours a
day, generally feature longer turn on times, and typically have low fuel costs. Peaking plants,
like many natural gas plants, typically only run during peak demand hours. Peak demand
conditions occur for relatively short periods of time, such as to meet air conditioning demand on
hot summer afternoons. Peaking plants have short ramp up times and typically have higher fuel
costs. Intermediate generation plants, which are also often natural gas, are those that sit between
base and peak.
Figure 10: Utility Generation Curve (California, 2005)
Source: See Endnote 33.
Wind, however, does not fit easily into any of those three capacity categories. As discussed in
the DOE’s July 2008 report, “20% Wind Energy by 2030: Increasing Wind Energy’s
Contribution to U.S. Electricity Supply”, wind energy can be described as an energy resource
rather than a capacity resource.34 Capacity resources are those that are consistently available and
dispatchable on demand, while energy resources are those that are drawn upon when available.
The key distinction between capacity resources and energy resources is that capacity resources
focus on reliability, while energy resources generate low cost electricity. Without significant
levels of storage, a utility would have difficulty meeting its demand curve solely using energy
resources. However, the greater the amount of energy resources a utility can include in its
generation mix, the lower the total cost of electricity.
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3. Options to Meet Our Energy Needs
Historically, the majority of commercially viable power plants were capacity resources, and thus
grid planning focused on ensuring adequate capacity to meet demand. However, as large
hydroelectric generation plants came online, capacity planning became more complicated;
droughts and differing levels of rainfall impacted the amount of hydro energy capacity available,
which led to the creation of reliability models for an annually unpredictable resource. In the
same way that hydro resources vary on an annual basis, wind resources vary on significantly
shorter time horizons.
Variability
In fact, one of the largest differences between wind energy and traditional fossil fuel energy
plants is the variability of wind generation due to the fact that the wind speed in any given area is
not constant. Wind speed may rise or fall on a minute-by-minute basis and may also be stronger
on average at certain times of day, such as at night. Although recent technology and wind
forecasting allow grid operators to better plan for the variability of wind, wind resources cannot
be controlled and scheduled in the way that traditional generation can. The current fragmented
transmission system exacerbates the issue of wind variability. As noted in the Transmission
History section (pg. 4), the U.S. transmission system cannot be viewed as one large integrated
and coordinated system. Instead, the country’s grid is divided into over 130 largely autonomous
balancing areas, ranging in size from less than 100 MW to larger than 100,000 MW.35 Within
each area, operators must constantly adjust the output of power plants to ensure that electricity
supply and demand remains almost perfectly in balance.36 Although there are links between
each area, these links are limited in capacity and often do not allow efficient coordination when
moving power from one area to another.
This setup can exacerbate wind’s impact on the grid by heightening variability. Currently, many
operating areas have only one general wind regime. This means that the different wind farms in
an area have similar power curves.37 Because the wind farms only access one wind area, any
change in wind flow directly impacts the amount of electricity flowing into the grid.
Another criticism of wind rooted in variability is the belief that a significant amount of shadow
capacity will be needed to offset the variability of wind energy. Shadow capacity refers to power
plants, often natural gas, which can be quickly ramped up to provide power when another
generation source ramps down. Critics argue that variable wind capacity requires equivalent
natural gas capacity to ensure reliable generation. While it is true that additional natural gas
plants in some locations may be needed to cover gaps in wind generation, the actual required
amount of shadow capacity is minimal. A wind plant may have a capacity factor of 35 percent,
but the farm still produces some level of electricity about 80 percent of the year.38 Further,
transmission investments that reduce congestion and allow for excess capacity to be shared
across larger geographic areas lower the amount of total shadow capacity needed in a system.
Combining many of the best practices noted above and increasing investment in transmission
will drastically lower any threats that wind energy may provide to the nation’s grid while also
limiting the cost of new shadow capacity.
Seasonality
A final characteristic of wind generation that differs from traditional fossil generation is the
seasonal nature of wind. Seasonality can have a large effect on generation planning and
transmission load capacity factors. As Figure 11 illustrates, wind generation decreases during
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3. Options to Meet Our Energy Needs
the summer when load centers have their highest need for generation. In addition, wind
generation resources are the highest during the spring and fall when load centers have their
lowest need.39
Figure 11: Seasonality of Wind Generation and Load Center Demand
Source: See Endnote 40.
Overall, the impact of wind energy on the nation’s transmission system cannot simply be glossed
over. The current transmission system was not built to handle the variable nature and distant
generation sites of wind resources. However, these issues are symptoms of a larger problem:
years of transmission underinvestment resulting in an inadequate transmission system. While the
DOE found that most transmission systems, given some flexibility in interconnection and
operation, can integrate wind and other renewable energy resources into their system, truly
integrating a modern energy generation mix requires a modern transmission system. 41
Wind Environmental and Social Impact
Wind resources have a unique set of environmental and social issues compared to traditional
fossil resources including the following:
 Emissions in the manufacture of turbines and construction of farms,
 Bird and bat kills, and
 Sound and visual impacts.
Although wind electricity generation releases no greenhouse gas emissions because it requires no
fuel, there are some emissions in the process to manufacture and construct wind farms. A
lifecycle assessment performed by the consulting firm Elsam Engineering A/S and the turbine
manufacturer Vestas modeled the total impact of its 2 MW onshore wind turbine and compared
the results to traditional coal energy generation. Over the course of the turbine’s lifetime, wind
generation produced 93,000 fewer tons of carbon dioxide.42 The majority of the environmental
impact for the turbine stems from the extraction and processing of the metal used in its
14
3. Options to Meet Our Energy Needs
components. However, in the same way that recycling building material reduces the net lifecycle
impact of buildings, 80 percent of the material consumed in the construction of a turbine can be
recycled.
Critics of wind generation argue that turbines can impact birds and bats if not sited and operated
correctly. While this is certainly a concern for wind farm operators, the number of birds killed
by wind turbines is minimal compared to other causes. To provide perspective, house cats kill
1,000 birds for every turbine caused death, while buildings and windows cause 5,500 deaths for
every mortality from wind turbines.43 In fact, the Audubon Society strongly supports wind
energy when properly sited.44
Other critics argue that wind turbines have negative sound and visual impacts on the landscape,
though the degree to which those are problems depends on individual preference. According to
the American Wind Energy Association, at 350 meters, the sound of utility-scale turbines is
equivalent to the background sound found in a home.45
Natural Gas
Now that we have explored some of the characteristics of the wind industry, we turn to the
natural gas industry. Approximately 22 percent of the energy consumption of the United States
comes from natural gas.46In 2008, 23.2 Tcf of natural gas was consumed in the United States, a
slight increase from 2007. As shown in Figure 12, 29 percent or 6.6 Tcf was used to generate
electricity. The next largest amount was consumed by industrial users.47The United States
typically accounts for 20 to 25 percent of total worldwide consumption of natural gas making it
one of the worldwide leaders in natural gas consumption.48
Approximately 90 percent of the natural gas consumed in the United States is produced
domestically. The EIA estimates that there are 1,533 Tcf of technically recoverable natural gas
resources in the United States, implying that there is enough natural gas to meet over 75 years of
domestic consumption.49 Domestic natural gas production comes primarily from five states
(Louisiana, New Mexico, Oklahoma, Texas, and Wyoming), which were responsible for about
80 percent of total marketed natural gas production in 2007. Ninety percent of net imports of
natural gas into the United States come from Canada; equivalent to 3.49 Tcf and this level is
expected to decrease at an annual rate of 1.4 percent to a level of 2.56 Tcf per year in 2025.50
Liquefied natural gas (LNG) imports represent an increasingly important part of the natural gas
supply picture in the United States. LNG requires significantly less space than gaseous natural
gas, allowing it to be shipped much more efficiently. The United States gets a majority of its
LNG from Trinidad and Tobago, Qatar, and Algeria, and also receives shipments from Nigeria,
Oman, Australia, Indonesia, and the United Arab Emirates. According to the EIA, the United
States has slowly increased the percentage of natural gas imported in the form of LNG since
2002. LNG imports are expected to increase at an average annual rate of 15.8 percent, to levels
of 4.80 Tcf of natural gas by 2025.51
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3. Options to Meet Our Energy Needs
Figure 12: Natural Gas Usage by Sector, 2008
Lease & Plant Fuel Consumption
(5.53%)
Pipeline & Distribution Use (2.70%)
Residential Consumption (20.99%)
Commercial Consumption
(13.45%)
Industrial Consumption (28.59%)
Electric Power Consumption
(28.61%)
Source: See Endnote 52.
As shown in Figure 13below, over the past ten years, the percentage of natural gas used for
electricity generation has increased from 22 percent in 1999 to 29 percent in 2008.53Additionally,
natural gas’ role in our nation’s generation mix is expected to increase in the coming years as the
EIA expects 57 percent of new electric generation capacity built by 2025 will be natural gas
combined cycle or combustion turbine generation.54
Figure 13: Percentage of Natural Gas Used for Generating Electricity
Consumption of Natural Gas for Electricity
(%)
35%
30%
25%
20%
15%
10%
5%
0%
1997
1998
1999
2000
2001
2002
Year
Source: See Endnote 55.
16
2003
2004
2005
2006
2007
3. Options to Meet Our Energy Needs
As shown in Figure 14 below, natural gas capacity provides approximately 40 percent of the net
summer generation capacity in the United States. This is more than any other source of
capacity.56Further, one of the most important aspects of natural gas generation is its role as the
main source of peaking capacity. In particular, natural gas peaking plants are key generation
sources that provide stability to the nation’s electrical grid.
Gigawatts
Figure 14: 2007 U.S. Electric Power Industry Net Summer Generation Capacity
450
400
350
300
250
200
150
100
50
0
39.5%
31.4%
10.1%
10.0%
5.6%
3.0%
0.2%
0.1%
Source: See Endnote 57.
Natural Gas Price
In its Short-Term Energy Outlook released on March 10, 2009, the EIA projects that, due to the
current economic downturn, natural gas spot prices at the Henry Hub are expected to average
$4.54 per MMBtu in 2009 and $5.71 per MMBtu in 2010.58If prices fall further than currently
forecast, natural gas will become increasingly competitive with coal for base load power
generation in some regions. However, on the supply side, there has been a decrease in drilling
for new supplies due to current economic conditions. This reduced supply could contribute to
higher-than-expected prices if the economy begins to recover earlier than expected and
production is slow to react.59
The forecasted prices are much lower than prices in 2007 and 2008, demonstrating the price
volatility of natural gas. The average price paid for natural gas by electricity generators in
December 2008 was $6.74 per MMBtu, a 4.2 percent increase from the November 2008 level of
$6.47. The December 2008 price was 12.2 percent lower than the December 2007 price of $7.68
per MMBtu. Receipts of natural gas in December 2008 were 571.0 million MCF, up 3.9 percent
from November 2008 and up 5.3 percent from December 2007.60
Although the changes in natural gas generation prices are less than the changes in the price of
natural gas, if EIA’s recent predictions regarding the large drop in natural gas prices are accurate,
17
3. Options to Meet Our Energy Needs
one will see large decreases in the cost of natural gas generation. Further information on cost of
natural gas electricity can be found in Section 5 below.
Natural Gas Industry Structure
Similar to the wind industry, the natural gas industry’s structure is relatively fragmented as it is
made up of producers, processors, pipeline companies, storage operators, marketers and local
distribution companies (Figure 15).
Figure 15: Natural Gas Industry Structure
Source: See Endnote 61.
Natural gas producers explore for natural gas, drill the wells to extract gas and then maintain the
wells for long-term production. This is the riskiest part of the supply chain because there is no
certainty that natural gas will be found and even if it is found, it may be difficult or expensive to
access. Therefore the price of natural gas at this point has to recover both the cost of drilling and
the risk premium and is the most volatile component in the supply chain.62
A complex gathering system consisting of thousands of miles of pipes is used to move natural
gas from the wells in an area to a processing plant. Gathering systems can be owned by the
wellhead owners, the processing plant owners or by independent third parties. The cost of the
gathering system becomes a fixed adder to the price at the wellhead and in most circumstances is
set by tariff.63
Processing plants separate all of the various hydrocarbons and fluids from the pure natural gas, to
produce what is known as 'pipeline quality' dry natural gas. Major transportation pipelines
usually impose restrictions on the make-up of the natural gas that is allowed into the pipeline.
The output of the processing plant is “pipeline quality” gas and connects to the interstate pipeline
system and “market hubs”, such as the Henry Hub. This hub is where the natural gas is traded
and where there is enough volume changing hands to create the liquidity necessary to have price
transparency.64
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3. Options to Meet Our Energy Needs
The interstate natural gas pipeline network transports processed natural gas from processing
plants in producing regions to those areas with high natural gas demand. Interstate pipelines are
the "highways" of natural gas transmission. Marketers and larger end users can contract for
capacity on the interstate pipeline to move natural gas to desired destinations. Most natural gas
that moves on the interstate pipeline system is delivered to a Local Distribution Company
(LDC). While some large industrial, commercial, and electric generation customers receive
natural gas directly from high capacity interstate and intrastate pipelines (usually contracted
through natural gas marketing companies), most other users receive natural gas from a LDC.65
Once electric utilities receive the natural gas, either directly from a pipeline or through a
distribution company, it is used to generate electricity in a natural gas plant. The electricity is
then distributed to customers through the transmission and distribution system. Figure 16below
provides a pictorial representation of the movement of natural gas from the well to final end-use
customers.
Figure 16: Pictorial Representation of the Flow of Natural Gas from Wellhead to End-Use
Source: See Endnote 66.
The DOE is responsible for the regulation of natural gas imports and exports in the United
States. While FERC regulates such things as tariffs for different components of the natural gas
supply chain and the siting and building of natural gas pipeline.67
Natural Gas Generation Characteristics
There are two main types of natural gas-fired power plants, combustion turbines and combined
cycle units, each of which have different operating characteristics.
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3. Options to Meet Our Energy Needs
Combustion Turbine Plants
In combustion turbine units, hot gases from burning fossil fuels (particularly natural gas) are
used to turn the turbine and generate electricity and are used primarily for peak-load demands.
Thermal efficiency for these plants is about 35 to 40 percent for newer plants and 25 to 35
percent for older plants.68Combustion turbine plants are ideal for meeting peak demand because
they have low capital costs, which minimizes a utility’s investment in equipment that is only run
for short periods of time.69 In addition, it is possible to quickly and easily ramp up production. In
2007 the average capacity factor for simple cycle natural gas-fired generation was 11.4
percent.70These plants have increased in popularity due to advances in technology and the
availability of natural gas. However, combustion turbines are still less efficient than large steamdriven power plants,71 and they have high operating costs because a large proportion of their
energy input is lost to the environment as exhaust.72
Combined Cycle Plants
Many of the recently built natural gas-fired power plants are combined cycle units. In these types
of generating facilities, gas turbine and steam units are housed in the same plant. The gas turbine
operates in much the same way as a normal gas combustion turbine, using the hot gases released
from burning natural gas to turn a turbine and generate electricity. In combined cycle plants, the
waste heat from the gas turbine process is directed towards generating steam, which is then used
to generate electricity much like a steam unit.
Because of the secondary use of heat energy released from the natural gas, combined cycle plants
are much more efficient than steam units or gas turbines alone and typically produce electricity
that is less costly than that produced by combustion turbines. In fact, combined cycle plants can
achieve high thermal efficiencies, 73up to 50 to 60 percent if the plant produces only electricity.74
In the case of combined heat and power generation, the energy utilization factor (overall
efficiency) can increase to 85 percent.
In 2007, the average capacity factor for combined cycle generation was 42 percent. In 2003, the
average capacity factor for combined cycle generation was 33.5 percent. The 8.5 percentage
point improvement in the average capacity factor reflects both the increased reliance on
combined cycle generation to meet energy requirements and efficiency gains in combined cycle
generation technology.75
Capital costs for combined cycle plants are higher than for combustion cycle plants, but lower
than for coal or nuclear plants. Further, combined cycle plants have shorter construction times
and greater operational efficiency than coal or nuclear plants. With a higher fuel cost than coal
or nuclear, combined cycle natural gas plants are built to meet the variable needs of electricity
generating utilities, while coal and nuclear are used to meet base load needs.76
Natural Gas Environmental and Social Impact
One of the benefits of natural gas is that it burns more cleanly than other fossil fuels. It has
fewer emissions of sulfur, carbon, and nitrogen than coal or oil, and, when it is burned, it leaves
almost no ash particles.77 The average emissions rates in the United States from natural gas-fired
generation are 1,135 lbs/MWh of carbon dioxide, 0.1 lbs/MWh of sulfur dioxide, and 1.7
lbs/MWh of nitrogen oxides. Compared to the average air emissions from coal-fired generation,
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3. Options to Meet Our Energy Needs
natural gas produces half as much carbon dioxide, less than a third as much nitrogen oxides, and
one percent as much sulfur oxides at the power plant (Table 1).78Although natural gas is more
environmentally friendly than other fossil fuels, it should be noted that, because natural gas is
made up mostly of methane (another greenhouse gas), small amounts of methane can sometimes
leak into the atmosphere from wells, storage tanks and pipelines.79
Table 1: Emission Profile of Natural Gas Electricity Versus Other Fossil Fuels
Fossil Fuel Emission Levels
Pounds per Billion Btu of Energy Input
Pollutant
Natural Gas Oil
Coal
Carbon Dioxide
117,000 164,000 208,000
Carbon Monoxide
40
33
208
Nitrogen Oxides
92
448
457
Sulfur Dioxide
1
1,122
2,591
Particulates
7
84
2,744
Mercury
0
0.007
0.016
Source: See Endnote 80.
.
In addition, the process of extraction, treatment, and transport of the natural gas to the power
plant generates emissions.81Further, exploring and drilling for natural gas has a negative impact
on land and marine habitats. However, new technologies, such as satellites, global positioning
systems, remote sensing devices, 3-D and 4-D seismic technologies, horizontal and directional
drilling are reducing the number and size of areas disturbed by drilling, making it possible to
access natural gas with a lower environmental impact than in the past.82
The National Renewable Energy Lab conducted a life cycle assessment of a combined cycle
natural gas power generation system and found that the greenhouse gas emissions from such as
system were 439.7 g/kWh CO2, 2.8 g/kWh CH4, and .00073 g/kWh NO2 for a combined global
warming potential (GWP) of 499 g CO2 equivalent / kWh. Approximately three-quarters of the
emissions were generated from power plant operations and one quarter from natural gas
production and distribution, and less than 1% from plant construction and decommissioning and
ammonia production and distribution. For comparison, the GWP for an average coal-fired power
generation system is 1,042 g CO2 equivalent / kWh.83
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3. Options to Meet Our Energy Needs
Comparison of Wind and Natural Gas
Table 2below provides a summary comparison of the major characteristics of electricity
generated from natural gas and wind.
Table 2: Summary of Natural Gas Versus Wind
2007 Price per kWh
Industry Structure
Generation
Characteristics
Environmental and Social
Impact
Wind
$0.03 - $0.065
(including the PTC)
Turbine manufacturers sell to
project developers, who create
the farms that owner/operators
operate. Electricity from farms
moves along high voltage
transmission lines to offloaders, who pass the electricity
through local distribution lines
to the end consumer.
Energy Resource, those that are
drawn upon when available;
with no fuel costs but a
capacity factor that is a fraction
of the nameplate capacity.
Potential impact on wildlife,
dependant on siting; minimal
emission and resource
consumption profile.
Natural Gas
$0.066
The natural gas industry is
made up of producers,
processors, pipeline
companies, storage operators,
marketers and local
distribution companies.
Capacity Resource, those that
are consistently available on
demand; with capacity factor
dependent upon demand and
the price of fuels.
Burns more cleanly than other
fossil fuels; fewer emissions
of sulfur, carbon, and nitrogen
than coal or oil, and leaves
almost no ash particles.
Exploration and drilling
impact terrestrial and marine
habitats.
Sources: See Endnote 84.
The generation characteristics of combustion turbine plants and combined cycle plants determine
when wind electricity would be used instead of natural gas electricity. As mentioned above,
combustion turbine plants are ideal for meeting peak demand because they have low capital costs
and it is possible to quickly and easily ramp up production.85Therefore, if wind electricity is
available at a peak demand period, it is most likely to displace electricity from a natural gas
combustion turbine plant. In contrast, combined cycle natural gas plants are built to meet the
variable needs of electricity generating utilities, and when decisions for building new plants are
being made, wind plants are most likely to be compared with natural gas combined cycle plants.
22
4. Challenges to Expanding Transmission
4. Challenges to Expanding Transmission
Following our examination of the different characteristics of wind and natural gas generation, we
turn our attention towards a survey of the recent trends in transmission investment. In particular,
we will consider the barriers to expanding and updating the nation’s transmission system, which
are necessary to bring additional wind generation online.
Transmission History and Current Needs
History of Transmission Investment
Each period of new power plant construction in the United States has been accompanied by
construction of new transmission facilities to connect those power plants with load centers.
Examples of these expansions include federal hydropower developments from the 1930s through
the 1950s and nuclear power plant development in the 1960s and 1970s (Figure 17).86 In the
mid-1970s, investment in transmission was approximately $5.5 billion per year, while in the
second half of the 1990s investment in transmission was under $3 billion per year.
Figure 17: History of Power Plant Developments
Source: See Endnote 87.
Deploying large amounts of wind energy will also require investment in new transmission
facilities. Historically, transmission infrastructure was built to bring electricity from relatively
remote areas to load centers. However, the development of gas-fired generation units in the
1990s, which can be located at a closer proximity to load centers, resulted in reduced
investments in transmission.88 This lack of investment in transmission was further exacerbated
by uncertainty around the outcome of electricity market restructuring.89 As shown in Figure 18,
investment in transmission infrastructure decreased by approximately $117 million per year
between 1975 and 2000. While investment has recently rebounded to $6.9 billion in 2006, the
relatively low investment in prior decades has had a negative impact on the nation’s transmission
system. The recent increase in new transmission investment is a reflection of two factors – a
need to catch up in local transmission and new commitments to backbone transmission systems
for major new generation, intra- and inter-regional trade, and increased reliability.90 The costs
and shape of that transmission build-out are discussed in further detail below.
23
4. Challenges to Expanding Transmission
Figure 18: Transmission Construction Expenditures (billion $)
Source: See Endnote 91.
Projection of Transmission Needs
According to the DOE’s “20% by 2030” report, it would be cost effective to build more than
12,000 miles of new transmission, an increase of about 5 percent of the existing transmission
system at a cost of approximately $20 billion in net present value terms.92This investment could
support the 300 GW of installed wind energy, which would be needed to meet the target of 20
percent of electricity requirements in the United States by 2030.93 The figure below shows one
possible configuration of the location of new transmission lines necessary to bring 300 GW of
wind energy to load centers.
Figure 19: Conceptual New Transmission Line Scenario 2030
Source: See Endnote 94.
24
4. Challenges to Expanding Transmission
The DOE’s analysis suggests that approximately $60 billion (undiscounted) will be necessary to
build the transmission infrastructure to accommodate 20 percent of electricity generation from
wind by 2030. This is an incremental increase of approximately $3 billion annually over the next
22 years.95To put this in perspective, this matches the recent low of $3 billion invested in 2004
and is less than half of the expected investment for 2007 of $8 billion.96
Barriers to Implementation
Despite the need for more transmission investment, numerous challenges make large-scale
transmission expansions difficult. There are multiple technical, financial and institutional
challenges to building new transmission infrastructure to access wind resources in the United
States. New transmission and wind resources need to be integrated with existing transmission
and generation systems in order to maintain the reliability of the grid. There are both technical
challenges to this integration, given the unfamiliarity of many operators with integrating such
resources, as well as financial hurdles, due to the capital cost of infrastructure and additional
costs of integrating wind energy. Institutionally, transmission planning processes and the
complexity of stakeholder relationships also present a barrier to developing wind resources and
the necessary transmission to bring this electricity to load centers. Finally, mechanisms for
sharing the cost of transmission among all consumers who benefit from a more efficient, reliable
grid need to be developed. This section examines these barriers to implementing new wind and
transmission resources.
Capital Cost
Transmission infrastructure projects are capital intensive, requiring billions of dollars on an
annual basis to meet new renewable energy generation needs. In a report released in February
2009, Lawrence Berkeley National Lab (LBNL) examined the costs of transmission by
comparing transmission planning studies from across the country and found that capital costs
varied widely from $0/kW to $1,500/kW.97A capital cost of $0/kW occurs when the energy
developer does not need any new transmission to carry generation to load centers, but this is
increasingly rare as the wind sites close to transmission have already been developed. The
median value was $300/kW. This accounts for approximately 15 percent of a $2000/kW wind
generation installation, which was the average wind installed capacity cost calculated by LBNL.
The majority of transmission studies that LBNL analyzed estimated costs at below 25 percent of
wind generation capital costs (less than $500/kW). LBNL concludes that transmission costs can
be expected to be no more than 33 percent of total wind electricity prices.98
In terms of cost per unit of electricity transmitted rather than capacity, LBNL assumed a 35
percent capacity factor for all facilities resulting in a range of costs from $0/MWh to $79/MWh.
The median was $15/MWh and the majority of estimates came in at below $25/MWh.
Although transmission infrastructure costs are high, access to capital is not a major issue for
project developers, even during the current credit crisis, if there is certainty around cost recovery
from ratepayers. For instance, in December 2008, ITC Holdings, a publicly-traded transmission
company, issued $125 million in bonds and debt.99
25
4. Challenges to Expanding Transmission
Complicated Stakeholder Arrangements
A further complication surrounding new transmission construction relates to the breadth and
depth of stakeholders involved. At the highest level, decisions made by FERC and NERC set the
regulations that broadly govern the interstate wholesale electricity, natural gas, and oil markets.
In addition, FERC was granted siting authority in the Energy Act of 2005 in designated national
energy corridors. However, this power is currently being challenged by various stakeholders in
different court battles. It remains to be seen when and if FERC will be able to utilize this
authority.100
Sitting beneath those national regulators, nine major and more than 130 minor regional
transmission operators and independent system operators manage the operation, balance and
integrity of the transmission grid. The major ISOs and RTOs operate across state boundaries and
are responsible for the load balance and power management on the physical transmission lines.
Housed within the RTO and ISO boundaries, individual state public utility commissions set the
regulations that shape retail electricity markets and infrastructure construction. These state
bodies approve physical infrastructure improvements, including transmission siting, and regulate
retail rate structures.
Finally, a host of non-governmental players are involved in the transmission picture. These
groups cover a wide range of viewpoints, and, although they rarely hold direct regulatory power,
they are an important force in public opinion and therefore do wield influence. AWEA, the wind
industry trade association is an example of one group that supports transmission expansion.
AWEA has a membership base of 1,600 member companies and operates at the national and
state levels to lobby in favor of increased transmission development (among other issues).
Another transmission supporter is the Consumer Federation of America, which counts 300 nonprofits and more than 50 million consumers as its members. The Edison Electric Institute, an
association of U.S. shareholder-owned utilities, represents roughly 70 percent of the U.S. electric
power industry and supports transmission expansion to “meet the needs of a growing
population,”101 as does WIRES, an electricity transmission industry trade group (whose members
include independent system operators, utilities and equipment manufacturers). The National
Electrical Manufacturers Association, which includes approximately 450 member companies,
supports upgrades in the transmission and distribution system. The organization of Midwest ISO
(MISO) states and the organization of PJM Interconnection states, composed of public service
commissions from their respective geographic regions, also both support transmission
development.
Many environmental groups are conditionally supportive of transmission activities. Prominent
among these are Earthjustice (a nonprofit environmental law firm), the League of Conservation
Voters (an environmental lobbying group), the National Audubon Society (a nonprofit focused
on ecosystem preservation and restoration), the Natural Resources Defense Council (a nonprofit
with 1.2 million members focused on a broad array of issues), the Sierra Club (a 1.3 million
member nonprofit focused on protecting wild spaces, combating climate change, and ensuring a
healthy living environment), the Union of Concerned Scientists (a science-based nonprofit
focused on a healthy environment and a safer world), and the Wilderness Society (a nonprofit
focused primarily on wilderness protection).
26
4. Challenges to Expanding Transmission
Anti-transmission groups tend to fall into three groups. The first of these are local groups that
oppose transmission because of NIMBY (not in my back yard) issues. This type of opposition,
made infamous through the media coverage of the Cape Cod wind farm projects, can lead to
significant delays in transmission construction. The second group is composed of large industrial
electricity users, who typically oppose transmission infrastructure investments because they
already enjoy relatively favorable rates and are concerned that new investment can lead to short
term electricity cost increases. The final group is composed of environmental groups who in
general support renewable energy but oppose development on specific “pristine” land.
The transmission stakeholder structure and decision making power are summarized in the figure
and table below.
Figure 20: Transmission Stakeholder Structure
Source: See Endnote 102.
Table 3: Comparison of Wind Stakeholders
Stakeholder
NERC/FERC
Influence Mechanism
Regulation
RTO/ISO
Regulation/Operation
State
NGOs/others
Regulation
Lobbying/Public opinion
Decision Making Authority
Interstate oil, natural gas, and electricity
wholesale markets; overall system integrity.
Physical management of transmission grid
systems.
Retail markets and transmission infrastructure
approval
Little, though groups do wield public relations
tools.
Source: See Endnote 103.
Connection/Queuing Issues
With the rise of wind projects in many states, one of the largest problems that grid operators face
is the increasing number of connection and queuing requests and the accompanying studies
required to address them (Figure 21). These interconnection studies attempt to find adverse
reliability impacts of proposed projects on the transmission system. Although these studies are
an important part of maintaining the reliability of the grid, the dramatic increase in wind
27
4. Challenges to Expanding Transmission
interconnection studies has created unnecessary levels of bureaucracy and costly delays that
impact the entire power generation industry.
Figure 21: Wind Project Interconnection Requests
Source: See Endnote 104.
In 2008, the interconnection requests from wind projects were more than all other projects
combined (Figure 22). The severity of problems regarding interconnection requests differs
greatly by region, as RTOs and ISOs with significant wind generation potential have much
higher interconnection requests.
Figure 22: Current Interconnection Requests by Generation
Source: See Endnote 105.
MISO is one of the regions that had a large increase in wind interconnection requests, which led
to one of the most congested interconnection queues. As of June 26, 2008 MISO reported
28
4. Challenges to Expanding Transmission
cumulative total of 402 active generator interconnection requests in its queue with 135 submitted
just in 2008. This problem was further exacerbated in regions with high wind potential, such as
the Buffalo Ridge, Minnesota area, in which there were requests to transmit 23,000 MW. Under
MISO’s first-come, first-served process, it would have taken until approximately 2050 to process
the interconnection requests.106 Such a flood of requests had practically paralyzed the planning
system.
However, in the past year, FERC has approved queue reforms for MISO and CAISO and
additional reforms in other regions are expected shortly. Initial Interconnection Request
Deposits increased from $10,000 on average to $120,000 and $250,000 for MISO and CAISO
respectively.107 Additionally, new policies necessitating site control and eliminating long pauses
in the interconnection process will hopefully eliminate speculation and increase the efficiency of
the process. Most supporters of interconnection and queue reform hope to move away from the
simple first-come, first-served approach towards one based more on milestone payments, in
which developers must make payments for reaching specific application, planning, and
feasibility study stages.108 These payments are intended to screen out uneconomical projects and
improve the efficiency of the interconnection process.
Despite the broad support for reforms, it is still unclear which reforms will be enacted and to
what degree additional complexity will be added to the system. The large call for queue reform
highlights a weakness of the current regulatory system. Even with new transmission
investments, improvements in the regulatory system surrounding transmission are needed to
allow for increased renewable generation.
Cost Sharing and Cost Recovery
The issue of cost sharing can also be an impediment to transmission investments.109 Until the
1990s, most electric utilities planned generation and transmission in an integrated process. In the
1990s federal open access rules required the separation of transmission and generation
businesses, which created problems for transmission planning and cost allocation.
In the industry at large, there has been a lack of consensus about who should pay for
transmission, especially where benefits are either in dispute or accrue to parties other than the
traditional customers of the transmission company that would need to make the investment.
Many have pointed to this lack of consensus as a cause of underinvestment in the grid. The
problem stems in part at least from a mismatch between jurisdictional boundaries and market
realities.
While the benefits of transmission investment may be widely dispersed, the most common
current cost sharing model, assigns all costs to the generating unit that requires the transmission
upgrade. This model is referred to as “cost causer pays.” This system requires generators seeking
to connect to the electric grid to pay for the full cost of upgrades to the transmission network,
such as new transformers and equipment, even if the upgrades are hundreds of miles away. Such
costs can be as much as the cost of the plant and can have a large impact on the economics and
competitiveness of wind energy.
29
4. Challenges to Expanding Transmission
At the same time, the generator does not gain any benefits for reducing overall congestion and
the majority of the benefits of these upgrades accrue to electricity consumers spread across a
broad region and competitors that can piggyback on this investment.110 As a result, potential
investors in transmission infrastructure have a strong incentive to let others pay for upgrades,
with the overall impact being that no one steps forward to build the transmission.111
However, it is also important to understand that new transmission has a wide array of benefits,
and it is challenging to accurately predict the benefits that will accrue to any specific party as a
result of a new transmission line. Further, it is likely impossible to prove that benefits accrued to
those parties that were anticipated to receive benefits, and it is likely that those benefiting from
the transmission upgrade may change over time.112
The primary concerns that those opposed to transmission investment have are as follows:
 Those living in areas with low generation costs are concerned that transmission
investment will allow greater access to low cost generation sources, thereby equalizing
generation costs across a larger area, increasing the average cost of electricity in low
generation cost areas and decreasing the average cost of electricity in higher generation
cost areas.
 Concern over the prospect of environmental and land-use impacts in one state when most
of the benefits of new lines are identified as flowing to consumers in another state.
 Confusion over how to best allocate the cost of new transmission investment when it only
partially benefits local users, who have been supporting, in their electricity rates, all (or
most) of the costs associated with the local utility’s transmission investment, while the
majority of benefits from the transmission investment accrue to non-local customers.
 Concern by generators in areas with high electricity rates that new transmission will
allow more low cost electricity to flow into the region and decrease their revenue.113
Creating a more equitable system that recognizes the benefits of reducing congestion and spreads
out the costs of system upgrades would be greatly beneficial to expanding wind generation. A
government agency is the most likely group to create such a system whereby cost allocations are
more equitably distributed.114 Under the Federal Power Act, FERC is responsible for
determining those transmission cost allocations. For regions with RTOs or ISOs, FERC has
typically reviewed generic cost allocation plans proposed by these organizations and approved
the plans with modifications the commission finds appropriate. In areas without RTOs or ISOs,
prospective transmission developers propose cost allocation arrangements to FERC on a projectby-project basis. FERC reviews the proposals, calls for additional information if needed, and
approves, rejects, or conditionally approves each proposal.115
Recently, federal regulators have been attempting to accommodate the controversy on these
topics by adopting cost-allocation proposals resulting from settlement discussions or negotiated
agreements among stakeholders in specific geographic areas. However, what is needed is a set
of common, predictable principles supporting transmission investment for the interconnected
grid that serves broad regions. While a regional approach is understandable from a pragmatic
point of view, it is inadequate to the task of creating a sustainable and viable environment for
continuing to attract capital for transmission projects.116
30
5. The Model
5. The Model
Following our review of the challenges and current climate for transmission investment, we now
turn to the development and presentation of our model for comparing wind generation and
natural gas generation with a particular focus on the variables that can affect overall electricity
prices. The model compares the levelized cost of wind and transmission with the levelized cost
of natural gas generation on a per kWh basis and is intentionally not site specific. Unlike larger
transmission studies that tend to present higher-level macro scenarios, our analysis is looking to
capture the factors influencing decision-making for individual transmission and wind generation
projects.
The model allows us to look at the impact that different variables have on the competitiveness of
wind with natural gas. We compare wind to natural gas because both often serve an intermediate
or cycling role within an ISO’s power mix. Their roles, while not interchangeable, are similar
enough for comparison. Although wind electricity is more variable than natural gas, we have
accounted for this by adding integration costs into the cost of wind electricity. In addition,
natural gas is expected to account for the majority of new installed capacity through 2025,
according to the EIA.117
Through an examination of the cost drivers that impact wind generation, transmission and natural
gas generation, we identify the factors most relevant to making wind generation competitive with
natural gas. Because wind generation costs can be heavily impacted by transmission costs, this
is where the majority of our analysis occurs.
The assumptions and data used in our model are in line with the Joint Coordinated System Plan,
the Department of Energy’s “20% by 2030” report, and other studies. Additional details
regarding the structure, assumptions and calculations in the model can be found in Appendix A.
The graphic below (Figure 23) highlights the main categories that make up the cost of wind
generation. The lightly shaded sections (transmission costs and tax credits) are the main focus of
our model and discussion due to the many factors that influence the impact of these factors. The
second graphic (Figure 24) illustrates the cost categories involved in our calculation of the cost
of natural gas generation. The lightly shaded sections (fuel costs and carbon dioxide costs) are
the most variable and are the focus of our analysis.
Figure 23: Cost Structure: Wind Generation and Transmission
31
5. The Model
Figure 24: Cost Structure: Natural Gas Generation
The model is intended to be helpful for numerous stakeholders in the electric power and
renewable energy arena. Such stakeholders may include:
 Electric utilities considering meeting new generation options,
 Wind project developers looking to understand what factors have the most significant
impacts on the cost of transmission,
 Government officials who are looking to support policies friendly towards wind
generation while minimizing costs to consumers, and
 Anyone looking to understand the many factors influencing the cost of transmission and
wind generation.
Model Scenarios
In order to better examine the influence of different factors on wind generation costs, we created
three base scenarios for our analysis: a short distance transmission line (150 miles), a medium
distance line (600 miles), and a long distance line (1,000 miles). For visualization purposes,
these three scenarios can represent energy delivered from Illinois, Iowa, and North Dakota,
respectively, to the Chicago metropolitan area, though the conclusions presented are applicable
across any similarly defined transmission lines.
In determining the degree to which different factors affect wind generation costs, we examined
those factors that had gained significant attention from policymakers or academics; in particular
we looked at factors that could be affected either by new policies or investments. While capital
costs and O&M have a large effect on the wind generation costs, we did not directly manipulate
these costs because they cannot be directly changed through policy. In addition, we assumed
that both wind and natural gas generation technologies have reached relative periods of maturity
and only incremental cost increases or decreases were likely. Therefore, the capital costs and
O&M costs were static throughout the scenarios we ran through the model, and we did not run
scenarios with significantly higher or lower capital costs or O&M costs.
Attempting to further study the relative importance of each factor, we established a base case for
each scenario and ranges for each of the factors listed below based on real-world examples or
assumptions utilized by previous studies. Keeping all other factors constant, we examined the
costs of wind generation and transmission as we adjusted each independent factor within a
reasonable range. The assumptions we made in these three base cases are noted in Table 4.
Along with isolating individual factors in wind generation and transmission, we examined costs
associated with natural gas generation. In this analysis, we evaluated both combined cycle and
combustion turbine natural gas plants. In a similar manner to the range used for wind and
32
5. The Model
transmission factors, we looked at a reasonable range of natural gas prices, taking into account
recent volatility. In addition, we included the possibility of additional costs from carbon
legislation. We did not add transmission costs to natural gas generation because we assumed that
natural gas generators could be sited closer to load centers and make use of existing transmission
infrastructure. The different natural gas generation scenarios are listed in Table.
We then ran several trials combining the most significant factors to develop integrated scenarios
replicating a more realistic situation in which changes would not be made in isolation.
The results from our model and subsequent integrated scenarios helped us determine those
factors with the greatest impact on the cost competitiveness of wind generation, including the
cost of transmission, compared to natural gas generation.
Table 4: Comparison of Three Wind Scenarios
Capital Costs
O&M
Tax Credits
Wind Integration
Costs
Wind Capacity
Factor
Illinois
Iowa
N. Dakota
Reasonable
Range
$1,713/kW
$1,713/kW
$1,713/kW
NA
$0.0045/kWh
$0.0045/kWh
$0.0045/kWh
NA
ITC
ITC
ITC
ITC, PTC or
neither
$0.005/kWh
$0.005/kWh
$0.005/kWh
NA
27%
37%
40%
± 5% for each
scenario
Transmission
Transmission Line
Length
150 Miles
600 Miles
1,000 Miles
NA
AC - 765 kV
AC - 765 kV
AC - 765 kV
AC - 345 kV, 500
kV, 765 kV
Transmission Load
Factor
60%
60%
60%
40%-70%
Series
Compensation
Yes
Yes
Yes
No or Yes
$80 million
$80 million
$80 million
$0 - $160 million
12%
12%
12%
10% -14%
20 years
20 years
20 years
10-25 years
Voltage
Transformer Costs
Return on Equity
Cost Recovery
Period
Sources: See Appendix A.
33
5. The Model
Table 5: Comparison of Natural Gas Scenarios
Capital Costs
O&M
Capacity
Factor
Natural Gas
Fuel Price
Carbon Dioxide
Natural Gas
Combined Cycle
Natural Gas
Combustion Turbine
Reasonable Range
$857/kW
$597/kW
NA
$0.0086/kWh
$0.0086/kWh
NA
50%
50%
40% -60%
$6 per MMBtu
$6 per MMBtu
$4-$8 per MMBtu
$0
$0
$0- $60
Sources: See Appendix A.
An overview of the results from our analysis is shown below. Figure 25 shows the cost of
electricity from a natural gas combined cycle plant, natural gas combustion turbine, and our three
wind and transmission scenarios under our base case assumptions. The rest of this section
analyzes each of the cost components of wind, transmission and natural gas electricity and the
factors that contribute to these costs.
Figure 25: Electricity Cost Components
Electricity Costs $/kWh
Components of Electricity Costs
0.12
0.11
0.1
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0
Integration
Transmission
Fuel
O&M
Capital Costs
Natural
Gas CC
Natural Wind - 150 Wind - 600
Gas CT
miles
miles
Source: Model. Assumptions as in base case.
34
Wind 1,000
miles
5. The Model
Cost of Wind Electricity
In this section, we examine the underlying assumptions contributing to the cost of wind
electricity in our model and analyze single cost variables in isolation.
Capital Costs
In our model, capital costs are based on overnight capital costs, an interest rate, lifetime of the
plant, a cost recovery factor, length of the plant construction period and a construction time
factor. Overnight capital costs are the capital costs of a project if it could be constructed
overnight. This cost does not include the interest cost of funds used during construction. Our
analysis therefore adjusted the overnight cost to account for interest and the construction period.
Our numbers are based on the JCSP study reference case.118For our model, we used the
overnight capital cost of wind power facilities that was used in the JCSP study, which was the
2007EIA value with a 30 percent escalation and adjustment for inflation. We used similar
assumptions to JCSP because it is the most recent transmission planning study available to us.
JCSP escalated costs because of the increased cost of materials in 2008.
Operations and Maintenance Costs
Operations and maintenance costs for wind were based on assumptions used in the JCSP study
and were held constant for all three scenarios.
Tax Credits
Over the last several years, the United States has experienced significant growth in wind power
capacity. One of the driving forces behind this growth has been the federal production tax
credit (PTC) [Section 45 of the Internal Revenue Code], which offers an incentive for investors
in wind and other renewable power plants.119 The PTC, which was originally created under the
Energy Policy Act of 1992 (at a value of 1.5 cents/kilowatt-hour and adjusted annually for
inflation),120 is a per kWh tax credit for electricity generated by qualified energy resources for
the first 10years of a renewable energy facility's operation.121 The reference price and the
inflation adjustment factor (IAF) for each calendar year are published in the Federal Register.122
For calendar year 2008, the effective credit rate was 2.1 cents per kWh.123
Criticisms of the Production Tax Credit
Despite the growth of renewable generation associated with the PTC, there are two primary
criticisms of the PTC. The PTC has been subject to short-term expiration dates and some
consider the PTC to be too narrowly applicable.
Since its establishment in 1992, the PTC has undergone a series of short-term extensions, and
has been allowed to lapse in three different years: 1999, 2001 and 2003. Each time the PTC has
expired, the wind industry has seen a 73 to 93 percent drop in wind energy installations in the
subsequent year.124 This "on-again/off-again" status has contributed to a boom-bust cycle of
development in the wind industry (Figure 26). The cycle begins with the wind industry
experiencing strong growth in development around the country during the years leading up to the
PTC's expiration. Lapses in the PTC then cause a dramatic slowdown in the implementation of
planned wind projects. When the PTC is restored, the wind power industry takes time to regain
35
5. The Model
its footing and then experiences strong growth until the tax credits expire.125 According to
Baratoff et al., one MW of wind is between 15 and 25 percent more expensive today due to the
inconsistency of the PTC.126
Figure 26: U.S. Wind Power Capacity Additions, 1999 to 2008
Source: See Endnote 127.
The PTC was extended as part of the Emergency Economic Stabilization Act of 2008 that
President Bush signed on October 3, 2008.128 This legislation extended the in-service deadlines
for all qualifying renewable technologies to December 31, 2009; expanded the list of qualifying
resources to include marine and hydrokinetic resources, such as wave, tidal, current, and ocean
thermal; and made changes to the definitions of several qualifying resources and facilities.129
This marks just the third time that the PTC was extended by Congress before it had been allowed
to expire.130
Short-term extensions of the PTC will allow the wind industry to continue building on previous
years' momentum but are insufficient for sustaining the long-term growth of renewable energy.
The planning and permitting process for new wind facilities can take up to two years or longer to
complete. As a result, many renewable energy developers that depend on the PTC to improve a
facility's cost effectiveness may hesitate to start a new project due to the uncertainty that the
credit will still be available when the project is completed.131 Further, the economic downturn of
late 2008 has left many renewable energy investors, such as banks, with dwindling profits. As
their profits slump, these equity investors have less “appetite” for tax credits. Despite the
existence of the PTC, the lack of tax equity investors is expected to decrease renewable energy
development considerably in 2009.132
To counter the negative implications of this type of boom-bust cycle, some organizations have
suggested extending the PTC to a five year or 10-year cycle. According to a November 2007
study by LBNL, the impact of a PTC extension on wind power deployment is uncertain and
depends significantly on model assumptions. LBNL referenced two analyses of an extension of
36
5. The Model
the PTC; one by the EIA based on the National Energy Modeling System (NEMS) and one by
the National Renewable Energy Lab (NREL) based on the Wind Deployment Systems (WinDS)
model. According to the EIA analysis, relative to the Annual Energy Outlook 2007 reference
case, a five year PTC extension would increase wind generation by 40 percent in 2030, while a
permanent extension of the PTC would more than triple wind generation by the same date and
allow wind power to grow to serve roughly 3 percent of U.S. electricity supply. The Annual
Energy Outlook predicts only 18 GW of wind by 2030 absent new policies and not considering
the impacts of state renewables portfolio standards, with non-hydro renewable electricity
increasing from 2.8 percent of total U.S. electric supply in 2006 to 3.6 percent by 2030. In
contrast, NREL estimated that an extension of the PTC through 2020 could stimulate enough
wind power to serve as much as 17 percent of the nation’s electricity supply by 2030,133
compared to approximately 7 percent under the base scenario with no PTC extension.134
The discrepancy in these two analyses is due to differences in each model’s design and
assumptions. The WinDS model was specifically designed to forecast wind deployment. In
particular, this model has access to GIS-based wind resource data from NREL and has more
detailed geographic resolution at four different geographic levels – interconnect regions, NERC
sub-regions, balancing areas, and wind resource areas.135In contrast, NEMS was designed to
project the energy, economic, environmental, and security impacts on the United States of
alternative energy policies and of different assumptions about energy markets.136 NEMS was
designed to handle macro-level issues, such as the elasticity of demand and the complete fossil
fuel economy, and therefore is based on a geographic resolution of only 13 regions.137
A second criticism of the PTC is that it is too narrowly applicable, which restricts the types of
investors that can efficiently make use of it. First, as a tax credit, the PTC is not available to
entities that do not pay taxes (e.g., publicly owned electric utilities, rural electric cooperatives,
government bodies, and non-profits). Secondly, due to several design features, the PTC is also
not easily accessible by certain tax-paying entities. As a result, most developers need to create
complicated financial structures in partnership with commercial providers of capital to fully
utilize the tax benefits. The complexity of these deals adds significant transaction costs to
renewable energy power generation.138These restrictions have led to a concentration of wind
project ownership in the hands of relatively few entities with sufficient tax liabilities to make use
of the credit, as well as a proliferation of relatively high transaction cost ownership structures
designed to maximize the value of federal tax incentives. The result may be some inefficiency in
the use of the PTC, the possible loss of this small amount of key investors, and certainly some
lack of parity in what types of entities can realistically participate in wind project ownership.139
American Recovery and Reinvestment Act of 2009
Both of these criticisms were at least partially addressed by the American Recovery and
Reinvestment Act (ARRA) of 2009. ARRA extended the Production Tax Credit for wind energy
through December 31, 2012. Further, the ARRA allows an entity otherwise eligible to claim the
PTC to elect to claim a 30 percent investment tax credit (ITC) in lieu of the PTC for facilities
placed in service in 2009, 2010, 2011, or 2012.140This is an option, not a requirement. Electing
to convert the PTC into an ITC allows wind facilities to be leased, or subject to a sale and
leaseback, without a loss of the credit. The ITC is different from the PTC because it is a credit to
the capital cost of the wind plant and is available at the start or very early stages of a new wind
37
5. The Model
power project. This is different from the PTC, which is based on the actual production of a
facility and therefore is provided on an annual basis once the project is in operation.
Role of Tax Credits in Transmission
Since the PTC and now the ITC are expected to drive a significant amount of wind power
development, they play an important role in planning for transmission to meet the needs of wind
power. Accessing substantial amounts of wind energy will require investments in the
transmission grid. The certainty in the future of the PTC and ITC provided in ARRA makes
transmission planning for wind less challenging because the economic attractiveness of wind
projects – and therefore expanding the transmission system for those projects – hinges in many
cases on the tax credits.141
PTC/ITC Model Inputs
The ARRA makes both the PTC and ITC available to wind project developers. Therefore, we
alternatively plugged each into the model to observe their relative effects. The PTC reduces the
price of wind-generated electricity by roughly 2.1¢/kWh. Because the PTC directly reduces the
amount of federal income taxes paid, we subtracted 2.1¢ from the total cost per kilowatt hour of
wind-generated electricity. The ITC allows a project developer to claim a 30 percent credit on
the cost of capital equipment. Therefore, to incorporate the ITC, we subtracted 30 percent from
the capital cost of a wind plant in our model. Since a wind farm operator can opt to receive
either the PTC or ITC, we ran each separately and did not run a scenario including both the ITC
and the PTC.
Impact of Tax Credits
Based on our analysis, we found that the ITC results in a lower electricity price for the shorter
transmission distance, approximately the same price for the middle distance and a slightly higher
price for the long distance (Figure 27). The reason for these differences is that distant plants
access better wind resources and therefore spread the ITC capital cost reductions over a greater
number of kWh, resulting in higher $/kWh prices. In general, projects with higher capacity factors
and lower installed costs tend to favor the PTC over the ITC (i.e., a higher capacity factor means that
more PTCs are generated, while lower installed costs mean that the value of those PTCs will add up
to a higher percentage of installed costs.142
Price of Electricity ($/kWh)
Figure 27: Impact of Tax Credits on Price of Electricity
0.14
0.12
0.10
0.08
ITC
0.06
PTC
0.04
Neither
0.02
0.00
150 miles
600 miles
1,000 miles
Tax Credit
Source: Model. Assumptions as in base case except for Tax Credits.
38
5. The Model
We decided to include the ITC as the base case scenario in our analysis. There are many factors
beyond distance to load centers that will determine whether a wind project will take advantage of
the PTC or the ITC. Higher capital costs may make the ITC more cost effective. The current
economic downturn has resulted in lower capital costs, which over the long run could result in a
lower total tax credit available. Secondly, because the ITC is available very early in a project
and the PTC is spread over the first 10 years of operation of the project, a wind developer will
need to consider the value of receiving the credit up front versus spreading it out. Finally, due to
current credit constraints, a project developer may want to choose the ITC over the PTC.
Wind Integration Costs
The variability of wind requires that additional capacity resources be available and sometimes
deployed to maintain the reliability of the grid. These costs are commonly referred to as
integration costs and have been detailed in regional wind integration studies. For the model, we
included integration costs of $0.005/kWh or $5.00/MWh, which may over-estimate the total
costs, given that studies to date have calculated integration costs in the range of $1.85/MWh to
$4.97/MWh. The DOE “20% by 2030” study provides an overview of wind integration studies
and components of integration costs (Table 6).143
Table 6: Summary of Wind Integration Studies
Date
Study
Wind
Regulation
Capacity
Cost
Penetration
($/MWh)
(%)
Xcel - UWIG
3.5
0
0.41
1.44
na
Total
Operatin
g Cost
Impact
($/MWh)
1.85
Xcel MNDOC
MN/MISO
15
0.23
na
4.37
na
4.60
35
(25% energy)
0.25
na
4.26
na
4.41
4
0.45
na
na
na
na
Jun-03
CA RPS
Multi-year
Analysis
We Energies
4
1.12
0.09
0.69
na
1.9
Jun-03
We Energies
29
1.02
0.15
1.75
na
2.92
PacifiCorp
20
0
1.6
3
na
4.6
Apr-06
Xcel - PSCo
10
0.2
na
2.26
1.26
3.72
Apr-06
Xcel - PSCo
15
0.2
na
3.32
1.45
4.97
May-03
Sep-04
Nov-06
Jul-04
2005
Load
Following
Cost
($/MWh)
Unit
Commitment
Cost
($/MWh)
Gas
Supply
Cost
($/MWh)
Source: See Endnote 144.
This overview shows that, despite popular concern about the impact of wind energy on grid
reliability, the additional cost required to manage wind variability is relatively small. All studies
reviewed found integration costs to be less than half of a cent per kWh.
Integration costs include both the cost of having spare capacity at the ready and actually
dispatching generation when needed. The cost of having generators at the ready is broken down
by timeframe, depending on whether the idle generators can begin generating within minutes
39
5. The Model
(regulation), hours (load following), or days (unit commitment). An additional cost, gas supply,
refers only to the fuel used when electricity is actually generated by natural gas peakers to
account for variability in wind energy production. These types of integration costs are
summarized in Table 6and discussed in more detail below.
Regulation Costs
Regulation refers to matching electricity supply with demand on a minute-by-minute basis. The
DOE reports that the cost associated with regulating the variability of wind is $0.5/MWh on
average with a range from $0/MWh to $1.12/MWh.145 This includes the cost of securing
resources to provide minute-by-minute matching if needed, but does not include gas supply when
these resources are actually required, which is calculated separately below.
Load Following
Load following refers to matching generation with load over a time frame ranging from 10
minutes up to several hours in advance. The DOE concludes, based on Zavadil et al., that 20
percent wind energy penetration will require more active load following capability or load
management ability with associated cost increases.146Estimates of load following costs vary from
$0.09/MWh to $1.6/MWh in the integration studies reviewed by DOE.147
Unit Commitment
Grid operators must secure day-ahead capacity resources to balance the variability of wind as
well. This is the largest component of integration costs because of the challenge of accurately
forecasting wind from day-to-day, as opposed to minute-to-minute or hour-to-hour. This increase
in day-ahead uncertainty contributes up to $5.00/MWh in integration costs for wind energy
penetration levels up to 20 percent.148
Gas Supply
At times, generation will need to be dispatched to counteract drops in wind generation. This
results in additional natural gas consumption as gas turbines are deployed. In the short-term,
existing spare capacity is expected to be able to accommodate increased levels of wind energy
penetration without the need to build additional power plants. The DOE concludes, however, that
load growth could reduce the spare capacity available if new dispatchable generation is not
planned and constructed.149Therefore, for levels currently under consideration (up to 25 percent
wind electricity), existing reserves are expected to be adequate, contributing to the low cost of
wind integration to date. Integration studies have found the cost of gas supply to be up to
$1.45/MWh.150
Wind Capacity Factor
A wind site’s capacity factor determines the actual productivity of a turbine over a period of time
compared to its maximum potential output. In the United States, most wind farms are sited with
capacity factors ranging from about 25 percent to over 40 percent. Small changes in a site’s
capacity factor can have a large impact on the cost of wind power. During the past few years,
many of the nation’s wind developers have been furiously trying to secure land rights for wind
sites with the highest capacity factors knowing that a percentage point difference for a whole
wind farm could cost a company millions of dollars in revenue. As shown earlier in Figure 1on
pg. 4, the regions with the highest capacity factors are located in the Great Plains, far from the
40
5. The Model
nation’s load centers. The best sites in this region may have capacity factors over 40 percent
while the capacity closer to load centers in the Midwest may only be 30 percent.
Due to the importance of capacity factors in project economics, our group anticipated that it
could have one of the largest impacts on competitiveness of wind power. Using our three base
case scenarios, we looked at a realistic range of capacity factors at each site (Figure 28).
Figure 28: Impact of Capacity Factors on Wind Electricity Costs
Cost of Wind Electricity ($/kWh)
0.12
0.10
0.08
Illinois
0.06
Iowa
0.04
North
Dakota
0.02
22%
23%
24%
25%
26%
27%
28%
29%
30%
31%
32%
33%
34%
35%
36%
37%
38%
39%
40%
41%
42%
43%
44%
45%
0.00
Capacity Factors
Source: Model. Assumptions as in base case except for range of wind capacity factors.
According to this sensitivity analysis, the cost of wind generation in the Illinois scenario was
most impacted by changes in capacity factor. From our results above, one can see that moving
from a resource with 22 percent to 32 percent capacity factor lowers the costs of wind electricity
by 2.8 cents per kWh in the Illinois scenario. The spread is less with the 600 and 1,000 mile
lines as the costs decrease 1.4 cents and 1.3 cents respectively. This difference is caused by
spreading capital costs over fewer kWh at the lower capacity factors that we modeled in our
Illinois scenario. As wind capacity factors increase, one sees diminishing returns. Although the
cost decrease is less for the Iowa and North Dakota scenarios compared to the Illinois scenario,
these costs differences are still important enough to impact the competitiveness of wind
generation.
Perhaps more importantly, these findings indicate that a relatively close wind resource (150
miles) with only 26 percent capacity factor has the same costs as a much better wind resource
with 37 percent wind capacity that is 600 miles from its load center. Wind on the 150 mile line
is competitive with wind on the 600 mile line, and vice versa, in several cases. While it is still
very important for wind developers to locate projects with the highest capacity factor, in regions
with lower capacity factors, it is even more important to build projects with the highest possible
capacity factor as a one percent change in capacity factor will have a larger effect on project
economics.
41
5. The Model
Finally, the 1,000 mile line was never cost competitive with wind on the 150 or 600 mile lines.
Despite accessing better wind resources, transporting wind across very long distances was never
the most economic option in our analysis due to the high cost of transmission, which will be
discussed in the next section.
Transmission
While transmission lines have historically traversed relatively short distances to connect power
plants with load centers, renewable resources, such as high-speed wind areas in the West, are
often hundreds of miles from population centers. Building longer transmission corridors allows
for these high-quality renewable resources to be tapped, potentially boosting the return on
investment for wind developers and lowering the levelized cost of electricity from wind. The
trade-off, however, is the additional cost of long distance transmission lines and line losses.
Our model incorporates transmission costs by calculating the per kWh cost of transmission
infrastructure and adding this cost to the cost of wind generation. The model calculates the per
kWh cost of transmission by determining the total transmission cost for a particular investment
and levelizing this cost across the kWh carried per year. The transmission cost included in the
model can vary by the following five factors:
1. Distance: Miles of transmission line,
2. Voltage: whether the line is AC 345kV, 500kV or 765kV,
3. Load Factor: the percent of transmission line capacity that is in use on average,
4. Series Compensation: this refers to transmission infrastructure that can be installed in
order to boost the capacity of transmission lines, and
5. Transformers: This additional equipment is needed to step down high voltage lines to low
voltage lines. By including transformer costs with a high voltage (765kV line), we
assume that the grid is a low voltage system as is most common in the United States.
Figure 29 and Figure 30 show how the model calculated total transmission cost and the capacity
of the line used to calculate the per kWh transmission cost.
42
5. The Model
Figure 29: Diagram of Transmission Costs in Model
Figure 29shows how the inputs of voltage, miles and series compensation affect the four costs
(transmission line, transformers, substations, and series compensation) that comprise total
transmission costs.
Figure 30: Diagram of Transmission Line Capacity in the Model
Figure 30 illustrates how we calculated transmission line capacity, which was expressed in MW
and then converted into kWh based on the hours per year that the transmission line would be in
use, which is determined by the transmission load factor. Transmission line capacity is
determined by first calculating the loadability, or maximum capacity of the line, then
43
5. The Model
determining the average load on the line by multiplying by the load factor, and finally,
subtracting line losses, to determine the total transmission line capacity.
In order to get a levelized cost of transmission on a per kWh basis, we assumed a return on
equity (ROE) for transmission developers, a construction period and a payback period. The
impact of these factors on transmission costs will also be discussed in more detail.
We assigned all transmission costs to wind electricity because of the “cost-causer pays model”
that is currently used to allocate transmission costs as described in the section on Cost (pg. 29).
Natural gas generation is assumed to require no additional transmission investment for this
analysis because it can be sited close to load centers.
The following section provides background information on the five transmission variables that
feed into the model as well as variables used to levelize these costs (ROE, construction period
and payback period).
Transmission Line Length
We examine a range of distances from 150 to 1,000 miles of transmission needed between wind
generation and load centers. We analyzed three base cases with wind generation located 150, 600
and 1,000 miles from load centers. For visualization purposes, these three scenarios can
represent energy delivered from Illinois, Iowa, and North Dakota, respectively, to the Chicago
metropolitan area, though the conclusions presented are applicable across any similarly defined
transmission lines.
Voltage
In general, voltage is important because higher voltage lines have higher costs, both for the line
itself as well as for associated equipment, such as series compensation, transformers, and
substations. While higher voltage lines have higher costs, the load bearing capacity of a line
(loadability) increases as the voltage increases. For instance, a 765 kV line has a relative
loadability of 2,400 MW while a 345 kV line’s loadability is only 390 MW. The 345 kV line,
however, is approximately half the cost per mile of the 765 kV line.
It is important to keep in mind the loadability of lines when comparing investment options. The
model should not be used to compare transmission investment options since it does not hold the
loadability of lines constant. For instance, we did not compare the cost of transmitting 1000 kWh
by 345 versus 765 kV. Rather our tool evaluates the levelized cost of electricity per kWh given
the use of different types of transmission infrastructure by wind generators.
Our model favors high voltage lines that carry large volumes because of the economies of scale
on a per kWh basis. However, in many instances, it may not make sense operationally to build a
transmission project to carry thousands of MW of power as a 765 kV line is capable of doing.
Instead, in such cases, while a low voltage line with a lower loadability would be the cheaper
option in terms of the overall capital cost of the transmission project, it would lead to a higher
per kWh cost for wind generation. This approach is consistent with our stated goal of identifying
the cost drivers for wind and transmission and seeking ways to make wind competitive with
natural gas.
44
5. The Model
Impact of Line Length and Voltage
For the three distances considered in our scenarios, the model indicates 765 kV lines, with their
associated higher loadability, as the most economic choice for supporting wind development for
a range of line lengths (Figure 31). These differences become much more pronounced over 400
miles.
Figure 31: Line Length and Voltage Effect on Wind Electricity Prices
Cost of Wind Electricity ($/kWh)
0.9
0.8
0.7
0.6
0.5
AC - 345 kV
0.4
AC - 500 kV
0.3
AC - 765 kV
0.2
0.1
0
100
200
300
400
500
600
700
800
900
1000
Transmission Line Distance
Source: Model. Assumes 60% load factor, 37% wind capacity factor, series compensation, transformers.
Transmission Load Factor
Another important factor to consider is the sharing of transmission lines among different types of
generation resources. Our analysis assumes that lines have a load factor of 60 percent on
average, and we analyze a range from 40 percent to 70 percent.
Although the capacity factor for wind does not exceed 40 percent in our base scenarios, it is still
possible to achieve higher transmission line load factors. High load factors can be obtained by
accessing more wind capacity than the capacity of the line, allowing for over-subscription of the
transmission line; accessing wind in different wind regimes in order to reduce overall variability;
or sharing the line with less variable generators or energy storage in order to achieve higher
transmission line load factors. We will go into more detail as to how to achieve high load factors
in the Recommendations section at the end of this paper.
As the model calculates transmission costs per kWh, it does not differentiate based on which
generation source makes up the remaining line capacity. It could be one large wind project using
the line 60 percent of the time on average or a mix of resources.
Impact of Transmission Line Load Factor
Figure 32summarizes the effects of different load factors on the cost of electricity. For low load
factors, the short line is the most competitive. The model indicates, however, that achieving high
load factors above 60 percent can make medium distance lines more cost effective on a per kWh
basis than short lines. The very long lines (1,000 miles) are never cost competitive across the 40
to 70 percent load factor range.
45
5. The Model
Cost of Wind Electricity ($/kWh)
Figure 32: Effect of Load Factors on the Price of Wind Electricity
0.14
0.12
0.1
0.08
1000 miles
0.06
600 miles
0.04
150 miles
0.02
0
40%
45%
50%
55%
60%
65%
70%
Transmission Load Factor
Source: Model. Assumptions as in base case except for load factor.
Series Compensation
Series compensation refers to equipment (capacitors) that allow the capacity of transmission
lines to be increased. Transmission developers use series compensation to boost the amount of
electricity that can be carried without changing the voltage or number of lines built. Series
compensation can be installed on existing or new lines.151For our analysis, we only considered
series compensation associated with a new transmission line.
Impact of Series Compensation
Series compensation makes economic sense for longer lines as it boosts the loadability of the
line, compensating for losses (Figure 33). Our analysis shows that series compensation lowers
the per kWh cost of lines and significantly improves the economics of longer lines. The graph
below shows the impact of series compensation on the cost of wind electricity. The effect is
exponential showing that series compensation makes relatively little difference for short lines but
results in significant savings for long distance lines.
Figure 33: Effect of Series Compensation (Capacitors) on the Cost of Wind Electricity
Cost of Wind Electricity ($/kWh)
0.18
0.16
0.14
0.12
0.1
No Series Compensation
0.08
Series Compensation
0.06
0.04
0.02
0
150 miles
600 miles
1000 miles
Source: Model. Assumptions as in base case except for series compensation.
46
5. The Model
Transformer Costs
Today, most of the U.S. grid’s long distance transmission is rated below 765 kV with 500 kV
predominant in the Southeast and West and 345 kV predominant in the Northeast (see Figure 4,
pg.6). Because of this existing network, interconnection with high voltage 765 kV lines bears
additional costs for transformers to step down voltage to the existing network as well as for
additional miles of lower voltage lines to integrate the large amount of additional capacity into
the grid. For instance, the Electric Reliability Council of Texas (ERCOT) found that, in some
transmission planning scenarios, the cost of additional 345 kV circuits needed in conjunction
with a 765 kV backbone was greater than the high voltage line itself.152In this way, the existing
system is self-perpetuating, as adding lower voltage lines will not require this extra cost.
In addition, the regulatory framework for transmission investments is such that it is planned in
small pieces, favoring shorter, lower voltage lines within a single regulatory jurisdiction, rather
than long, high voltage, cross-regional investments. The Edison Electric Institute (EEI) tracks
planned and completed transmission projects. EEI reports that, from 2006 to 2007, several lower
voltage lines ranging from 161 kV to 500 kV came online across the country but does not
identify any newly operational high voltage lines.153
There are several projects underway to build high voltage networks and some are specifically
designed to access renewable energy. For instance, EEI reports on four proposed projects that are
planning to use 765 kV lines in its review of transmission projects accessing renewable energy
resources.154EEI also identifies three high voltage DC lines that are under construction in order
to bring additional renewable energy online.155This suggests that while lower voltage lines have
been the norm to date, several long distance high voltage lines are currently in the planning
stages or under construction, reinforcing the viability of such infrastructure despite the nature of
the existing grid.156 As noted above, the increase in higher voltage lines should positively affect
wind generation because of their lower per kWh costs.
In the model, the state of the underlying grid is accounted for by adding the cost of transformers
for high voltage lines. Each transformer costs $40 million. Including transformer costs for high
voltage lines would be realistic in a scenario where there is not an existing high voltage network.
However, the model is an abstraction and does not fully account for the state of the underlying
grid for any specific location. It also does not account for low voltage circuits that may be
necessary to distribute large amounts of power brought into a local grid from high voltage lines.
Impact of Transformers
Adding transformer costs increases the cost of electricity incrementally, but does not change the
relative cost effectiveness of different scenarios as illustrated in Figure 34.
47
5. The Model
Figure 34: Effect of Transformer Costs on the Price of Electricity
Cost of Wind Electricity ($/kWh)
0.12
0.1
0.08
No Transformers
0.06
2 Transformers
4 Transformers
0.04
0.02
0
150 miles
600 miles
1000 miles
Source: Model. Assumptions as in base case except for transformer costs.
Additional Transmission Characteristics
The two major classifications of transmission lines are alternating current (AC) and direct
current (DC). The U.S. transmission system is comprised primarily of AC lines. DC lines are
point-to-point, transferring power from one region to another, while AC lines can be easily
connected with other lines at multiple intersection points.157DC lines are viable options for long
distances. AEP concludes that DC lines generally are competitive with AC lines for projects
greater than 300 miles,158 while JCSP finds that DC lines are more cost effective for distances
greater than 600 miles.159
While we initially considered 800 kV DC lines in our model, in this paper we compare only AC
lines because our model found 800 kV DC lines to be very similar in cost to 765 kV lines. In
order to simplify our analysis and enable comparison across the three distance scenarios we have
focused our analysis on AC lines.
Return on Equity
Many observers have surmised that underinvestment in transmission for the past thirty years has
potentially been caused by a combination of issues from difficult coordination across states,
NIMBY issues and a lack of financial incentives. In recent years, there has been a concerted
effort to improve financial incentives, such as the rate of return for transmission projects.
Because transmission operates within a regulated environment, transmission providers are only
permitted to gain a set rate of return on their transmission investments. These rates are
established by federal, regional and state regulators and then passed on to consumers as
transmission or delivery charges. In a transmission market with no barriers to entry, one would
assume that if the set rate of return was sufficient to cover the cost of building and maintaining
transmission assets and allow for reasonable profit, the market would be filled with interested
companies and perhaps even an overinvestment in transmission would occur. However, in
reality, the historically monopolistic nature of power generation and transmission caused by
48
5. The Model
regulation and planning barriers throws out this assumption and the current state of
underinvestment occurs.
FERC Order 679
In response to the problem of underinvestment, the Energy Policy Act of 2005 asked FERC to
establish new rules that would encourage transmission infrastructure investment. In response,
FERC issued Order 679, which established “incentive-based (including performance-based)rate
treatments for the transmission of electric energy in interstate commerce by public utilities for
the purpose of benefiting consumers by ensuring reliability and reducing the cost of delivered
power by reducing transmission congestion.”160 This new order allows FERC to approve a “cost
adder” or additional 0.25 percent to 2.5 percent to a project’s base return on equity. However,
this incentive still needs to fall within a “just and reasonable” range. For example, seven of the
eight segments of Pacific Corp’s Energy Gateway Transmission Expansion Project in the
Northwest received a two percent cost adder while one segment was denied any cost adder due to
a lack of evidence that the segment met FERC’s requirements of benefiting consumers and
reducing costs.161 A second component of FERC Order 679 that may increase investment in
transmission is a provision guaranteeing 100 percent recovery of abandoned plants that are
canceled due to factors beyond the firm’s control. This additional policy further decreases the
risk associated with transmission planning and investment.
At first glance, it would appear that FERC Order 679 is a very positive step towards increasing
transmission investments. FERC chairman Joseph T. Kelliher recently commented that “grid
investment has been moving in the right direction in this country - investment has nearly doubled
in recent years. That is partly the result of the rate incentives granted by FERC.”162 However,
some economists argue that the new order will not increase transmission investment, but in fact
decrease their investment. If transmission operators are monopolists, they are more likely to
under-invest in transmission as they benefit from congestion.163
Impact of Return on Equity
Despite disagreements on the impact of cost adders on transmission investment, it is important to
understand the impact of changes in ROE on the wind generation costs. Regulators must work to
find the proper balance between an increased ROE which incentives transmission investment
without increasing electricity costs too much. Overall, the impact of the cost adder to a new
transmission project has a mixed effect on the cost of wind power (Figure 35). The effect of the
cost adder on the cost of wind generation increases for longer lines. For example, in the Illinois
scenario, the cost of wind power increases by about $0.0002 per kWh based on a one percent
increase. Such increases in cost should have very little impact on the cost competitiveness of
wind generation. However in the North Dakota scenario, the cost of wind power increases by
about $0.005 per kWh based on a one percent increase.164 Therefore a two percent cost adder
could increase the cost of wind generation by $0.01 per kWh. Such an increase could affect a
utility’s decision regarding investment in wind generation. The increase in ROE may be the
difference between transmission expansion or status quo. Despite the disagreements over the
effectiveness of cost adders, the flexibility that the FERC has been granted under the Energy Act
of 2005 does appear to decrease the risk of pursuing new transmission projects by increasing
investment returns.
49
5. The Model
Figure 35: ROE Impact on the Cost of Wind Electricity
0.14
0.12
10%
$ per kWh
0.10
11%
0.08
12%
0.06
13%
0.04
14%
0.02
0.00
150 Miles
600 Miles
1,000 Miles
Source: Model. Assumptions as in base case except for ROE.
Cost Recovery Period
Another area that can impact transmission investment is the payback period or depreciation life
of transmission assets. In response to the Energy Policy Act of 2005’s call for FERC to increase
transmission investments, FERC Order 679 created new opportunities for accelerated
depreciation of transmission assets for a period as short as 15 years. Traditionally, transmission
assets were depreciated over a period of 20 years. FERC determined that in “some circumstances
allowing accelerated depreciation is warranted to encourage investment in transmission
infrastructure because it provides improved cash flow and better positions public utilities for
longer-term transmission investments.”165 Similar to rulings on cost adders, accelerated cost
recovery will not be granted for all projects but only those that are deemed to reduce congestion.
Additionally, in certain cases, the period might even be lowered to less than 15 years.
In our model, the impact of accelerated cost recovery on wind power costs was greater than the
impact of cost adders. As can be seen in Figure 36, the changes in recovery periods follow a
non-linear form with costs greatly increasing when extreme cases of accelerated cost recovery
are granted. In all scenarios, we assume that the transmission developer is able to recover costs
across the five-year construction period as well at the same rate as when the project is in
operation.
50
5. The Model
Figure 36: Impact of Cost Recovery Period on Electricity Cost
0.14000
0.12000
$ per kWh
0.10000
10 years
0.08000
15 years
0.06000
20 years
0.04000
25 years
0.02000
0.00000
150 Miles
600 Miles
1000 Miles
Source: Model. Assumptions as in base case except for Cost Recovery Period.
Allowing transmission companies or utilities to record 15-year accelerated depreciation for
projects increases the cost of wind power especially for longer distance projects. The impact is
even greater if FERC allows companies to record 10-year accelerated depreciation on new
transmission investments. However, such an extreme move is unlikely for long distance
projects. For longer distance projects, the impact on the cost of wind power is more substantial
than shorter distance projects because of the exponentially higher capital cost of transmission.
Moving from a 20-year period to a 15-year period increases the cost by $0.006 per kWh in the
North Dakota scenario. Similar to the ROE cost-adder, there is a tension between the need to
incentivize transmission expansion and protecting customers from unnecessary rate increases. In
this case, granting accelerated depreciation is likely to have a more pronounced effect on
incentivizing transmission investment than increasing the costs of wind generation.
Transmission Costs Versus Wind Quality
Having outlined the factors that comprise the cost of wind electricity generation and
transmission, we can now compare the relative impacts of each component of these costs and the
cost to access wind at different distances from load centers. Figure 37 shows the cost breakdown
for our three base case scenarios. It is clear that accessing better wind capacity factors at 1,000
miles from load centers, such as those found in the Great Plains, did not bring down the cost of
wind power. In fact, the cost of wind power increases. Transmission costs comprise only 3.5
percent of the total cost for wind and transmission at 150 miles but 30 percent of costs at 600
miles and the majority of costs (51 percent) for the 1,000 mile scenario given our capacity factor
assumptions.
51
5. The Model
Figure 37: Cost per kWh of Electricity in Illinois, Iowa, and North Dakota Scenarios
Electricity Costs ($/kWh)
0.12
0.1
0.08
Integration
0.06
Transmission
O&M
0.04
Capital Costs
0.02
0
Wind - 150 miles Wind - 600 miles
Wind -1,000
miles
Source: Model. Assumptions as in base case.
The relative higher cost of wind electricity in the North Dakota region (1,000 miles) is due to the
significantly higher transmission costs. If we remove transmission costs from this scenario, the
remaining costs are close to two cents per kWh less than the Illinois region because of the higher
wind capacity factor in the North Dakota scenario. However, the higher capacity factor and
consequent lower costs are not large enough to offset the more than five cents per kWh of
transmission costs that this generation must bear. Even the best wind generation site in North
Dakota is unlikely to have lower costs than a marginal wind generation site with lower
transmission costs. As a result, it may be important to consider fully utilizing those wind
resources relatively close to load centers before accessing distant wind resources in order to keep
down the per kWh cost of wind generation.
Cost of Natural Gas Electricity
After looking at the cost drivers for wind generation, we next examine the costs of electricity
from combined cycle and combustion turbine natural gas plants. For each plant type, we break
natural gas costs into three areas – capital costs, operations and maintenance costs, and fuel
costs. The sections below address each of these three types of costs.
Capital Costs
Our treatment of capital costs is the same as for wind generation. These costs are based on
overnight capital costs, interest rate, lifetime of the plant, a cost recovery factor, the length of the
plant construction period and a construction time factor. Overnight capital costs do not include
the interest cost of funds used during construction. At $0.0228, the capital costs of the combined
cycle plant are higher than the capital costs of the combustion turbine plant ($0.0159 per kWh).
52
5. The Model
Operations and Maintenance Costs
The operations and maintenance costs for natural gas generation are higher than the O&M costs
of wind generation. The costs for the combined cycle plant are $0.00987 per kWh, which is
slightly higher than the O&M costs for the combustion turbine plant, which are $0.00871 per
kWh. The data for the operations and maintenance cost section is based on fixed and variable
O&M numbers used in the JCSP study.
Capacity Factor
In contrast to wind capacity factors, which are based on when and how strong the wind is,
natural gas capacity factors are based on how often the natural gas plants are used. As
mentioned above, both combustion turbine and combined cycle plants can be turned on to
generate electricity fairly quickly to meet peak demands.
Natural Gas Fuel Price
Fuel costs are based on the cost of fuel and the heat rate for each type of plant. The combined
cycle plant is significantly more efficient than the combustion turbine and therefore has a lower
heat rate. This efficiency results in lower overall fuel costs for the combined cycle plant even at
the same fuel price levels. Regardless of efficiency, however, the price of electricity generated
by natural gas plants corresponds to the price of natural gas. We evaluated historical natural gas
prices, electricity fuel prices, and EIA forecasts to arrive at three natural gas price levels, which
we believe to be realistic scenarios based on historical price trends, current economic conditions
and current natural gas price forecasts.
Historical Natural Gas Prices
Over the past 40 years, while natural gas prices have generally trended upwards, there have been
several extreme increases and decreases in response to supply shortages or demand increases as a
result of severe weather (Figure 38).These huge volatility swings can make it difficult for natural
gas users to plan and manage their contracts for purchasing natural gas.
Figure 38: U.S. Natural Gas Wellhead Price ($/MMBtu), 1967 to 2007
$8.00
$7.00
$/MMBtu
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
Year
Source: See Endnote 166.
53
2007
2005
2003
2001
1999
1997
1995
1993
1991
1989
1987
1985
1983
1981
1979
1977
1975
1973
1971
1969
1967
$-
5. The Model
Since 1967, natural gas prices have ranged from $0.16/MMBtu to $7.13/MMBtu. Even over just
the past decade, prices have experienced a range of $5.22/MMBtu, from $1.91/MMBtu in 1998
to $7.13/MMBtu in 2005 (Table 7).167
Table 7: Comparison of Natural Gas Wellhead Prices ($/MMBtu), 1967 to 2007 and 1997 to 2007
Mean
Standard Deviation
Minimum
Maximum
1967 - 2007
1997 - 2007
$ 2.05
$ 4.21
1.759304
1.840035
$ 0.16
1967-1968 $ 1.91
1998
$ 7.13
2005 $ 7.13
2005
Source: See Endnote 168.
Electricity Fuel Prices
The natural gas electric power price is the price of gas used by electricity generators (regulated
utilities and non-regulated power producers) whose line of business is the generation of power.
From 1997 through 2007, the U.S. natural gas electric power price has closely followed price
movements for the U.S. natural gas wellhead price and has averaged about 17 percent
higher(Figure 39).The wellhead price is the value at the mouth of the well. In general, the
wellhead price is considered to be the sales price obtainable from a third party in an arm's length
transaction.169The Henry Hub is a market hub based in Louisiana. This hub is where natural gas
is traded and where there is enough volume changing hands to create the liquidity necessary to
have price transparency.
$/MCF
Figure 39: Comparison of U.S. Natural Gas Prices, 1997 to 2007 (2008$/MMBtu)
$10.00
$9.00
Electric Power
$8.00
Price
$7.00
$6.00
Henry Hub
$5.00
Futures
$4.00
Contract
Wellhead Price
$3.00
$2.00
$1.00
$-
Year
Source: See Endnote 170.
EIA Forecasts
The early release version of the 2009 DOE Energy Information Administration’s Annual Energy
Outlook predicts that natural gas prices will decrease sharply from the high prices seen in 2008
and then significantly increase over the next 30 years, eventually exceeding 2008 prices (Figure
40).171In the figure below, the electric power price is the most relevant price; the other prices are
provided as a comparison.
54
5. The Model
Figure 40: Comparison of EIA Forecasts for Natural Gas Prices, 2006 to 2030 (2008$/MMBtu)
$10.00
$9.00
$8.00
$/MMBtu
$7.00
Wellhead
Price
$6.00
Electric
Power Price
$5.00
$4.00
Henry Hub
Spot Price
$3.00
$2.00
$1.00
2030
2028
2026
2024
2022
2020
2018
2016
2014
2012
2010
2008
2006
$-
Year
Source: See Endnote 172.
In contrast, the Short Term Energy Outlook, published in March 2009 predicts prices
significantly lower than the Annual Energy Outlook. According to the Short Term Energy
Outlook, the Henry Hub spot price averaged $4.52/MMBtu below the average spot price in
January.173 The economic downturn has brought about demand reductions, which are reflected
in lower prices. The Henry Hub spot price is expected to average $4.54/MMBtu in 2009 and
$5.71/MMBtu in 2010.174
On the supply side, the current drilling pullback could contribute to higher-than-expected prices
if the economy begins to recover earlier than expected and production is slow to react.175
Price Scenarios
Based on historical price volatility, current prices and forecasts for future prices, we have used
prices of $4/MMBtu, $6/MMBtu and $8/MMBtu in the model.
Impact of Natural Gas Fuel Prices
Except at the lowest natural gas prices, wind generated at the short and medium distances is a
cheaper electricity option than electricity generated from natural gas. The long distance wind
scenario does not become cost competitive until the cost of natural gas fuel is over $7 for the
combustion turbine and close to $8 for the combined cycle turbine (Figure 41).
55
5. The Model
Figure 41: Comparison of Cost of Natural Gas Generated Electricity at Different Natural Gas Prices with
Cost of Wind Electricity
0.14
Cost of Electricity ($/kWh)
0.12
CT
0.10
CC
0.08
1000
miles
0.06
600 miles
150 miles
0.04
0.02
0.00
$4 / MMBTU
$6 / MMBTU
$8 / MMBTU
Source: Model. Assumptions as in base case except for natural gas fuel prices.
Carbon Dioxide
While there is currently no cost associated with carbon dioxide emissions in the United States,
this could become a significant cost for natural gas generators in the future. We examine the
likelihood of a price on carbon dioxide, possible price ranges, and the impact this would have on
the competitiveness of natural gas with wind electricity.
Role of Carbon Dioxide in Transmission and Generation Planning
In 2006, total U.S. greenhouse gas emissions were 7,054.2 million metric tons carbon dioxide
equivalent (MMtCO2e).176 The majority of greenhouse gas emissions are the result of
combustion of fossil fuels. Electricity generation was responsible for 39 percent of U.S. carbon
dioxide emissions in 2006.177 Transmission, generation and planning will likely have two effects
on emissions of carbon dioxide. Firstly, a better transmission system will allow more low- or nocarbon resources, such as wind and solar, to access load centers. Secondly, improving the
transmission system will lead to efficient transmission of electricity, resulting in reduced
congestion and fewer losses, and reducing the total amount of electricity that must be generated
to meet demand. For the purposes of this study, we will be primarily focused on the first impact.
Based on the current political climate, it is likely that Congress will pass legislation limiting
emissions of greenhouse gases and creating a cap and trade, or other similar system which places
a price on carbon dioxide emissions, over the next two years. In February 2009, President
Obama asked Congress to draft and send legislation putting a cap on emissions of carbon dioxide
56
5. The Model
and other greenhouse gases and has listed combating global warming as one of his three priority
areas, along with healthcare and education, for his first budget.178
While combustion of natural gas has lower greenhouse gas emissions than other fossil fuels, it
does have some emissions. This will add a cost to electricity generated from natural gas
depending on the eventual price of carbon dioxide. We estimated the price of carbon dioxide
based on proposed legislation, regional cap and trade systems, the price of carbon dioxide in the
voluntary market and the price of carbon dioxide in international markets. We then ran several
scenarios to estimate the impact that different carbon dioxide prices would have on the cost of
developing natural gas generation.
Forecasts/Scenarios
In order to determine the different scenarios we should consider for carbon dioxide prices in our
model, we benchmarked historical and current prices for the following carbon dioxide trading
instruments:
 European Union Allowances (EUA),
 Certified Emission Reductions (CER),
 Emission Reduction Units (ERU),
 Carbon Financial Instruments (CFI) on the Chicago Climate Exchange (CCX),
 Voluntary Emissions Reductions (VER) traded through the voluntary market in the
United States and internationally.
Figure 42below shows the maximum, minimum and average prices of carbon dioxide per ton for
these commonly traded credits.
Figure 42: Comparison of Carbon Prices Across Product Types (2007$ per ton of CO2 equivalent)
$60.00
$50.00
$ / tCO2e
$40.00
$30.00
$20.00
$10.00
$-
EUA
CFI
CER
VER
ERU
Max
$34.13
$4.20
$17.00
$50.00
$13.54
Min
$16.54
$1.62
$12.00
$1.80
$8.13
Average
$24.31
$3.15
$12.67
$6.10
$11.62
57
5. The Model
Sources: See Endnote 179.
Based on this analysis, we evaluated the impact of a cost for carbon dioxide on electricity from
natural gas at the following four carbon dioxide price levels:
 $0/tCO2
 $20/tCO2
 $40/tCO2
 $60/tCO2
Impact of Carbon Dioxide Prices
According to our analysis, at the $6/MMBtu natural gas price level, the cost of carbon dioxide
does not have an impact on the cost competitiveness of the short distance (Illinois) wind scenario
or the medium distance (Iowa)wind scenario as electricity from these two scenarios is already
cheaper than electricity from natural gas (Figure 43). However, the cost of carbon dioxide does
play a role in making the longer distance (North Dakota) scenario cost competitive with
electricity from combined cycle natural gas. The long distance wind scenario is very close to
competitive with natural gas from the combustion turbine technology at a $0 per ton cost of
carbon dioxide; the long distance wind is only $0.007/kWh more than the electricity from the
combustion turbine. A carbon dioxide cost as low as $1.25/ton will make the 1,000 mile
scenario cost competitive with electricity from a natural gas-fired combustion turbine. The long
distance wind scenario becomes cost competitive with electricity generated from a combined
cycle turbine at a carbon dioxide cost of approximately $43/ton.
Figure 43: Comparison of Cost of Natural Gas Electricity under Carbon Dioxide Pricing Scenarios with Cost
of Wind Electricity
0.16
Cost of Electricity ($/kWh)
0.14
CT @ $6 /
MMBTU
CC @ $6 /
MMBTU
1000 miles
0.12
0.10
0.08
600 miles
0.06
150 miles
0.04
0.02
0.00
$0 / Ton
$20 / Ton
$40 / Ton
$60 / Ton
Cost of Carbon Dioxide ($/tCO2)
Source: Model.Assumptions as in base case except for carbon dioxide prices.
58
6. Analysis of Model Results
6. Analysis of Model Results
Sensitivity Analysis
Following our examination of the individual variables affecting wind and natural gas electricity
costs, we examined this data in aggregate to summarize the conditions under which wind is
competitive with natural gas and to determine which variables had the largest effect on costs.
The sensitivity analysis table below (Table 8) provides an organized manner by which to view
these results. In the tables for the three wind scenarios, we have shaded the cases in which wind
is cheaper than our base case scenario for natural gas. The reference case scenario for natural
gas is for a combined cycle plant at a fuel price of $6/MMBtu and no price on carbon, which
gives a $0.0867 per kWh levelized cost of electricity. We have also provided the delta between
the two extremes of the range we analyzed and highlighted the factors that have the greatest
impact on wind generation costs.
Table 8: Sensitivity Analysis
Illinois-150 Miles
Cost of Wind Electricity
($/kWh)
Base
Range
ITC
Yes
Yes or No
$0.0757
$0.1020
$0.0263
Wind Capacity Factor
27%
22% - 32%
$0.0912
$0.0651
$0.0261
Voltage
Transmission Load
Factor
765 kV
AC 345 kV, AC 500 kV, AC 765 kV
$0.0810
$0.0757
$0.0053
60%
40% - 70%
$0.0770
$0.0754
$0.0016
Series Compensation
Yes
Yes or No
$0.0757
$0.0780
$0.0023
Transformers
$80 million
0 - $160 million
$0.0754
$0.0761
$0.0007
Return on Equity
12%
10% - 14%
$0.0753
$0.0762
$0.0009
10 - 25 years
$0.0766 $0.0756
For comparison with cost of wind electricity
$0.0010
Cost Recovery Period
20 years
Reference Natural Gas $0.0867
Electricity Price
59
Range
Δ
Factor
6. Analysis of Model Results
Iowa-600 Miles
Cost of Wind Electricity
($/kWh)
Base
Range
ITC
Yes
Yes or No
$0.0775
$0.0967
$0.0192
Wind Capacity Factor
37%
32% - 42%
$0.0853
$0.0716
$0.0137
Voltage
Transmission Load
Factor
765 kV
AC 345 kV, AC 500 kV, AC 765 kV $0.1563
$0.0775
$0.0788
60%
40% - 70%
$0.0888
$0.0743
$0.0145
Series Compensation
Yes
Yes or No
$0.0775
$0.1006
$0.0231
Transformers
$80 million
0 - $160 million
$0.0766
$0.0784
$0.0018
Return on Equity
12%
10%-14%
$0.0741
$0.0813
$0.0072
Cost Recovery Period
20 years
$0.0867
Reference Natural Gas
Electricity Price
Wind Cheaper than Natural Gas
Range
Δ
Factor
10 - 25 years
$0.0849 $0.0764
For comparison with cost of wind electricity
$0.0085
Factors with the Greatest Cost Impact
N. Dakota-1,000 Miles
Cost of Wind Electricity
($/kWh)
Δ
Range
Factor
Base
Range
Tax Credits
Yes
Yes or No
$0.1049
$0.1227
$0.0178
Wind Capacity Factor
40%
35% - 45%
$0.1115
$0.0998
$0.0117
Voltage
Transmission Load
Factor
765 kV
AC 345 kV, AC 500 kV, AC 765 kV
$0.7781
$0.1049
$0.6732
60%
40% - 70%
$0.1313
$0.0974
$0.0339
Series Compensation
Yes
Yes or No
$0.1049
$0.1647
$0.0598
Transformers
$80 million
0 - $160 million
$0.1036
$0.1062
$0.0026
Return on Equity
12%
10% - 14%
$0.0968
$0.1138
$0.0170
10 - 25 years
$0.1223 $0.1023
For comparison with cost of wind electricity
$0.0200
Cost Recovery Period
20 years
Reference Natural Gas $0.0867
Electricity Price
Wind Cheaper than Natural Gas
Factors with the Greatest Cost Impact
60
6. Analysis of Model Results
Natural Gas Combined Cycle
Factor
Base
50%
Capacity Factor
$6/MMBtu
Natural Gas Fuel Price
$0
Carbon Price
Cost of NG CC Electricity
($/kWh)
Range
Δ
Range
40%-60%
$4 - $8
$0 - $60
$0.0943
$0.0687
$0.0867
$0.0816
$0.1046
$0.1117
$0.0127
$0.0359
$0.0250
Natural Gas Combustion Turbine
Factor
Base
50%
Capacity Factor
Natural Gas Fuel Price $6/MMBtu
$0
Carbon Price
Range
40% - 60%
$4 - $8
$0 - $60
Cost of NG CT Electricity
($/kWh)
Range
Δ
$0.1090
$0.0771
$0.1042
$0.1010
$0.1313
$0.1419
$0.0080
$0.0542
$0.0377
Source: Model
Depending on the scenario, different variables had greater sensitivities and relative importance.
In the Illinois scenario, the two factors that held the greatest impact on the cost of generation
were the presence of the ITC and different wind capacity factors. The impact of both variables
can be seen as the lack of an ITC and the lowest wind capacity factor (22 percent) are the two
scenarios in which wind plus transmission is more expensive than our reference natural gas
generation.
The Iowa scenario brings different factors to importance, as the voltage of the line and the
presence of series compensation have the largest impact on wind costs. Series compensation
should be present in most new transmission projects because it is the least cost option on a per
kWh basis. In a similar fashion to the Illinois scenario, the ITC still had a rather large impact on
the cost of wind generation. Load factor, efficiently using transmission infrastructure, begins to
be of high importance as well. Additionally, one can see that the costs of wind generation have
increased, making only about half of the range cheaper than natural gas generation.
Finally, the North Dakota scenario reveals many interesting trends. First, one can see that the
cost of wind generation has increased substantially relative to the other two scenarios. This
increase means that the cost of wind generation is not competitive with natural gas at $6 per
MMBtu and no price on carbon dioxide emissions. The main reason for this is the large increase
in transmission costs. Another important aspect of this scenario is the change in relative
importance of many of the scenario factors. First, the voltage of line used and the presence of
series compensation still have the largest effect on cost. However, transmission load factor is
more important. Wind generation that is served by transmission lines with low load factors will
have much higher costs. Because of the large transmission costs, the ITC is less important for
this scenario, as the ITC is only based on wind capital costs and is spread over more kWh in this
scenario. Finally, we see that the impact of wind capacity factors has decreased by more than
half from the Illinois scenario. While building a wind farm in an area with an additional two
percent wind capacity factor may increase revenue, it may not be worth it if additional costs from
the transmission preclude the wind farm from a cost competitive position.
61
6. Analysis of Model Results
Integrated Scenarios
Based on the sensitivity analysis and our expectations for which factors can be controlled most
easily by participants, we found transmission line voltage, wind capacity factor, and transmission
load capacity factor to be the most important factors to consider in our integrated scenarios. We
decided not to analyze factors such as series compensation further because it clearly reduces the
cost of wind, so most projects will end up using this technology because of its overall cost
advantage.
Our first integrated scenario examined the influence of wind capacity factors, line voltage and
distance from load center on wind generation competitiveness with natural gas (Figure 44). The
bars in Figure 44 show wind electricity prices for a ± 5 percent range of capacity factors. The
starting capacity factors in each scenario are the same as the base cases stated in Table 4(pg. 33)
and Table 5 (pg. 34). In addition, the natural gas generation costs are for combined cycle plants
with no cost of carbon.
Figure 44: Wind Capacity Impact on Electricity Price
Capacity Factors Impact on Wind Generation Costs
$0.12
Cost of Electricity ($/kWh)
$0.11
Natural Gas = $8 per MMBTU
$0.10
$0.09
Natural Gas = $6 per MMBTU
$0.08
$0.07
Natural Gas = $4 per MMBTU
$0.06
345 kv
500 kv
150 Miles
765 kv
345 kv
500 kv
600 Miles
765 kv
345 kv
500 kv
765 kv
1000 Miles
Source: Model. Values not represented on graph are outside range.
This combined scenario shows the cost disadvantage of wind generation transported from long
distances versus natural gas generation. Even when accessing wind resources with capacity
factors over 40 percent, wind generation is only cost competitive with natural gas if the price of
gas is $8 per MMBtu or more. Such realizations may impact plans to access distant wind
resources or at least allow for the understanding that long distance wind generation is rarely cost
competitive with cheaper generation options if all of the transmission costs are born by wind
generators. Many of the current plans to reach distant wind resources in the Dakotas or
Wyoming will not bring down the cost of wind power.
62
6. Analysis of Model Results
The results from this comparison demonstrate that wind generation in the first two scenarios, 150
miles and 600 miles, is cost competitive with natural gas for a range of fuel prices, particularly
when using a 765 kV line. While the cost of wind generation is not cost competitive with natural
gas generated electricity when natural gas prices are $4 per MMBtu, such fuel costs are unlikely
to occur outside of economic recessions. Wind generation and transmission appears to be
competitive with natural gas at prices of $6 per MMBtu for the 150 mile and 600 mile scenarios.
Finally, one can see that the range of wind generation costs is the widest on the 150 mile
scenario. The potential benefits from accessing slightly better wind resources can have a marked
impact on wind generations cost. This realization has led to fierce competition for the best wind
resources close to load centers as they provide the lowest cost for wind generation.
Our second integrated scenario examines the impact of transmission line load factors on the price
of wind (Figure 45). The bars in Figure 45 show wind electricity prices when transmission load
factors have a range of 40 percent to 70 percent. Exploring this factor is particularly important
when considering the characteristics of wind noted earlier in the paper. Even the best wind
resources have capacity factors below 50 percent. However, the base case in our model assumes
a 60 percent load factor for all transmission lines. In the Recommendations section, we discuss
options for achieving 60 percent load factors. Moving from a 60 percent load factor to a 40
percent load factor would increase costs by over two cents per kWh, a relatively large effect on
prices.
Figure 45: Load Capacity Impact on Electricity Price
$0.13
Cost of Electricity ($/kWh)
$0.12
$0.11
Natural Gas = $8 per MMBTU
$0.10
$0.09
Natural Gas = $6 per MMBTU
$0.08
$0.07
Natural Gas = $4 per MMBTU
$0.06
345 kv
500 kv
150 Miles
765 kv
345 kv
500 kv
600 Miles
Source: Model. Values not represented on graph are outside range.
63
765 kv
345 kv
500 kv
1000 Miles
765 kv
6. Analysis of Model Results
This graph demonstrates the relative unimportance of transmission load factors on wind
generation located close to load centers. However, when large transmission investments are
needed, it is very important to fully utilize the line to spread the costs over a greater number of
kWh. When this occurs, wind generation is competitive with natural gas generation at $8 per
MMBtu. The large spread of 3.7 cents per kWh in the North Dakota scenario further
demonstrates the importance of having high transmission load factors.
Comparison with Prior Studies
The results from our model can be compared to a range of other studies, including transmission
planning studies and evaluations of the cost of wind and fossil fuel electricity. This section
compares our results to those of other relevant studies and, where possible, notes how and why
our study differs from the existing body of literature.
Cost of Wind and Transmission Versus Fossil Fuel Electricity
Analyses comparing the cost of wind against other types of electricity usually do not account for
transmission. For instance, Figure 7(pg. 10) shows LBNL’s calculation of wind electricity prices
compared with wholesale electricity prices. These prices, however, are busbar prices,180which do
not include transmission and therefore do not reflect the true cost of delivering wind electricity.
Therefore, in the LBNL analysis, wind is shown at a lower price than wholesale electricity. This
analysis also does not include integration costs.181
LBNL found a weighted average wind electricity sales price of $0.046/kWh, ranging from
$0.031 to $0.067/kWh.182Due to the reasons outlined above, this is significantly lower than the
cost of wind calculated in our model. Removing transmission and integration costs from our
model, we achieve resulting wind electricity costs on par with those found by LBNL, ranging
from $0.0459/kWh to $0.0681/kWh (2008$) depending on the wind capacity factor.
Regional Studies
Some transmission planning studies provide support for the benefits of wind and transmission
versus natural gas expansion.183
ERCOT’s analysis of Competitive Renewable Energy Zones (CREZ) calculated the net benefits
of wind and transmission expansion and found that the cost savings of additional wind
generation (from lower fuel costs) are greater than the additional costs of transmission. The
ERCOT study concluded that, in every scenario analyzed, the production cost savings of
additional wind energy outweighed the carrying cost of transmission investment (Figure 46). In
the ERCOT CREZ study, 75 percent of the electricity displaced by wind power is from natural
gas combined cycle plants, five percent is from gas-fired steam generators, and the remaining 20
percent is from coal and lignite sources.184
The ERCOT study concludes that transmission investment would pay for itself through
production cost savings, thus illustrating that wind and transmission is economic. However,
ERCOT’s analysis is not directly comparable with our model as it compares wind and
transmission to installed natural gas production costs rather than to new natural gas investment.
64
6. Analysis of Model Results
As a result, the costs of natural gas generation in the ERCOT study are less than our modeled
costs. In addition, ERCOT’s analysis does not include a price on carbon dioxide emissions.
Figure 46: ERCOT Analysis of Wind Production Cost Savings and Transmission Costs
Source: See Endnote 185.
JCSP offers a slightly different set-up, comparing a reference fossil fuel scenario to a 20 percent
wind scenario and found overall costs to be higher in the 20 percent renewable energy scenario
(Table 9). The reference scenario includes five percent renewable energy to meet RPS standards
in place in 2007 in the region. Neither scenario includes a price on carbon emissions, which
would further raise the price of the fossil fuel generation. In the reference scenario, the bulk of
new generation comes from coal-fired plants, a distinct difference with our analysis and a feature
which contributes to the reference case being the lower cost option.186
Table 9: JCSP Reference and 20 Percent Wind Scenarios Cost Comparison (2024 $)
Costs
Transmission Capital Costs
Overnight Construction Costs
Production Costs
Total Costs
Reference Scenario 20% Wind Scenario
3,968
4,177
674,346
1,050,213
104,294
85,167
782,608
1,139,557
Source: See Endnote 187.
Transmission Costs of Accessing Wind
In February 2009, LBNL reviewed transmission costs in 40 wind and transmission planning
studies drawing several conclusions that are relevant comparisons with the results from our
model.188
65
6. Analysis of Model Results
First, LBNL did not definitively determine that unit transmission costs (transmission cost in
$/MW) are higher in plans that add long distance transmission lines. LBNL notes that low
transmission costs for long distance lines are possible if significant amounts of new generation
are added and thus the overall per kW cost remains low. Also, LBNL’s analysis is based on
miles of transmission line installed and does not distinguish between multiple short lines and a
single long line. In the LBNL analysis, five 100-mile lines are treated the same as one 500-mile
line. Therefore, LBNL’s study is unable to draw conclusions about the cost of long transmission
lines, while our model does just that. Figure 47 plots miles of new transmission lines against unit
transmission costs, showing that there is little relation in the studies reviewed by LBNL.189
Figure 47: Miles of New Transmission Lines Versus Unit Transmission Costs
Source: See Endnote 190.
In our model, the cost of transmission increases with the length of transmission lines. In
addition, these higher costs can be attributed to higher line losses. The per kWh cost of
transmission for different lengths of line according to our model is shown in Table 10.
Table 10: Unit Transmission Cost Increases with Length
Length of
Transmission Line
150 Miles
Cost of Transmission
($/kWh)
$0.0030
Source: Model. Assumptions as in base case.
66
600 Miles
1,000 Miles
$0.0237
$0.0552
6. Analysis of Model Results
Second, LBNL also did not find a strong correlation between incremental generation and unit
transmission cost (Figure 48). LBNL notes that this could be due to differences in methodology,
geography and underlying assumptions of each of the studies.
Figure 48: LBNL Review of Incremental Generation Versus Unit Transmission Cost
Source: See Endnote 191.
LBNL could, however, determine that unit transmission costs increase for long distance lines
that add little new generation. This agrees with our model as shown in Figure 32, (pg. 46)
demonstrating that lower load factors result in higher transmission costs per kWh.
Finally, LBNL’s calculation of average transmission costs to access wind energy is in line with
our calculations. The median transmission cost according to LBNL was $0.015/kWh with a max
of $0.079/kWh, compared with our range of $0.0030 to $0.0552/kWh.192
67
Recommendations
7. Recommendations
Using our model, we determined that wind with new transmission is competitive with natural gas
for a range of scenarios. In particular, the following factors are able to make wind and
transmission more competitive with natural gas:
 High voltage (765 kV) network instead of low voltage network,
 High transmission load factors, particularly for very long distance lines,
 Presence of PTC or ITC,
 Price on carbon dioxide emissions, or
 Value on wind as a hedge against natural gas price increases.
Policy recommendations that address these factors and therefore help to make wind competitive
with natural gas are discussed in the following section. In addition, we discuss the potential for
larger balancing areas, flexible scheduling, and energy markets to lower wind integration costs,
although we do not consider integration costs to be a major barrier for making wind and
transmission competitive with natural gas.
High Voltage System
High voltage transmission lines have lower losses and clear economies of scale in transporting
power across long distances. For this reason, our analysis found that 765 kV lines were more cost
effective than lower voltage lines for a large range of distances.
The cost advantage of high voltage lines is greatest at long distances. However, capital costs and
line losses also increase with length. Accessing higher capacity factor wind resources is critical
in order to make long distance lines economically justifiable as seen in Figure 28(pg. 41).
Analysis of transmission plans indicates that, in many cases, transmission planners are
continuing to use low voltage lines.193 This may be the case because of the existing low voltage
infrastructure and because of planning and cost recovery mechanisms that favor regional rather
than trans-regional infrastructure. High-level, trans-regional studies, such as JCSP, seem to
favor high voltage lines, supporting the proposition that coordinated transmission planning
across regions allows for economies of scale to be recognized.
Funding mechanisms need to be implemented to encourage the coordinated build-out of a high
voltage network. Assigning all transmission costs to wind is unlikely to make this option cost
competitive with natural gas if wind resources must be transported over very long distances
(1,000 miles). The only scenario we analyzed in which wind and transmission over 1,000 miles
long was cheaper than natural gas electricity was when natural gas prices or carbon prices were
high. However, transmission build out is unlikely to only benefit wind generators, even if this is
the initial impetus for the infrastructure investment. For instance, our study does not examine
other benefits that long distance, high voltage networks bring, such as meeting RPS requirements
or relieving congestion. Therefore, if long distance, high voltage lines are to be implemented,
cost sharing mechanisms other than “cost causer pays” will need to be adopted.
68
Recommendations
Finally, a high voltage system transporting power across hundreds of miles is likely to cross state
and ISO/RTO borders. Cost allocation measures that fairly allocate costs but also allow
necessary transmission to be built regardless of whether benefits accrue to local communities
will be needed in order for transmission developers to invest in this infrastructure.
Load Factors
As the model indicates, higher load factors on transmission lines can significantly reduce the unit
cost of wind electricity as the capital costs of transmission lines are spread over more generation.
There are several ways to boost the load factor of transmission lines serving wind generation
including over-subscribing the transmission lines with wind generation, sharing lines with other
generators, and utilizing energy storage mechanisms.
Over-subscribing a line with wind could allow it to reach a high level of average line utilization.
Over-subscription refers to installing more wind capacity than line capacity. For most of the
year, there would be more than enough line capacity to carry the entire output of the wind farm
because of the variability of the wind resource.
Installing 10 to 30 percent more wind than transmission capacity has been shown to bring
transmission capacity to the 60 percent level generally accepted as the threshold for making
transmission economically viable. Some researchers have proposed mega-projects of 1,000 MW
of wind capacity or more to capture economies of scale and allow for oversubscription of
transmission lines. The table below indicates how over-subscription of transmission lines with
wind resources affects line loading.
Table 11: Over-Subscribed Mega-Projects
Nameplate
Wind Capacity
(MW)
1,000
1,100
1,200
1,300
Generation
Over-Build
110%
120%
130%
Native Wind
Capacity
Factor, Net
45%
45%
45%
45%
Wind
Generation
MWh/yr
3,942,000
4,336,200
4.730,400
5,124,600
Capacity
Factor per
1000 MW
45%
50%
54%
59%
Transmission
Line Loading
45%
50%
54%
59%
Source: See Endnote 194.
It should be noted that over-subscribing lines results in curtailment during times when wind
facilities are operating at above average capacity factors. Losses from curtailment need to be
considered when determining the most economic loading level for a transmission line.
By accessing wind across a large geography that extends across different wind regimes, the
capacity factor of resources utilizing a transmission line could be boosted, allowing for higher
transmission line utilization. Including wind farms in different wind regimes increases the
average capacity factor of the wind resource because, when the wind is low in one area, it may
be high in another. This decrease in variability also reduces integration costs.
69
Recommendations
However, Pattanariyankool and Lave have found that the cost of transmission lines to link wind
farms in different wind regimes may outweigh the benefit of accessing wind with lower
correlation.195Therefore, site-specific analysis needs to be conducted taking into consideration
the correlation of wind resources, transmission line distance and wind capacity factor.
Co-locating wind farms with fossil fuel or other generation in order to share high voltage (high
capacity) transmission lines is another way to increase the load factor of transmission lines.
LBNL has studied the possibility of Advanced Coal Wind Hybrid (ACWH) systems in the West
to share transmission lines and provide low cost, low emission base-load power. The levelized
cost of electricity from such a system was calculated to be $0.073/kWh with CO2 emissions of
0.056 tCO2/MWh.196 (For comparison, the average coal plant has emissions of
0.41tCO2.MWh).197 Therefore, it may be possible to co-site wind with low-CO2 fossil fuel
generation in order to maximize the use of transmission lines and avoid additional wind
integration costs as the variable wind power is firmed up by the coal-fired plant.198
Finally, energy storage is another proposed solution for better utilizing transmission lines. Largescale energy storage, such as pumped hydro or compressed air energy storage, could be coupled
with wind turbines and an over-subscribed transmission line in order to allow for wind energy to
be stored during what would otherwise be curtailment periods.
Manage Integration Costs
Because of its variability, wind energy requires some backup capacity from other sources in
order to meet demand. To address this, we included integration costs of $0.005/kWh in our
model, based on average estimates provided by DOE. That level of cost does not have a
significant impact on the competitiveness of wind in comparison with other resources. However,
that cost estimate assumes that spare capacity is available to balance wind energy variability.
Using existing spare capacity efficiently is key to keeping the cost of integrating wind energy
low.199 Integration costs can also be lowered by using larger balancing areas and incorporating
greater flexibility into power scheduling and energy markets.
Larger Balancing Areas
Accessing wind from larger balancing areas reduces integration costs by reducing variability.
Larger operating areas allow for greater geographic diversity of wind resources. Wind is more
likely to be blowing at some location within a larger operating area, therefore variability is
reduced and the generation curve flattens.
Illustrating this point, the 2008 JCSP Report found that it was better to select a mix of wind
farms with north to south variability than to select projects with longitudinal variability. Such
north to south variability in generation created a smoother aggregate supply.200
Larger balancing areas also decrease the total amount of ramping capacity needed in the system.
One option is to consider combining two or more balancing areas to create one larger balancing
area. While the net variability from wind generation will stay the same or decrease, ramping
capacity increases since the spare capacity in both balancing areas is now available. Like wind
variability, load variability also does not increase. In this way, larger balancing areas allow for
70
Recommendations
existing resources to be used for ramping, reducing the cost of wind integration (Figure
49).201Larger balancing areas decrease variability and give grid operators more flexibility in
meeting demand.
Figure 49: Benefits of Combining Balancing Areas
Source: See Endnote 202.
One region that is attempting to create a single balancing area is MISO. MISO recently
completed the process of consolidating its 26 operating areas into a single balancing area, with
expected annual savings of $113-208 million in operating costs, which exceed the annualized
cost of making the transition by a factor of 3.7 to 6.7.203
One issue to consider in creating larger balancing areas is the sharing of costs. Currently,
integration costs associated with electricity exported from one balancing area to another are paid
by the exporting region and not shared across all consumers. Local customers, therefore,
subsidize all consumers benefitting from the integrated electricity balancing areas. To address
this, contracts could be structured to distribute integration costs to all customers benefiting from
wind generation.204
Flexible Scheduling and Markets
In addition to creating larger balancing areas, additional laws or best practice measures can be
adopted to reduce integration costs for wind through more flexible scheduling of power plants.
Currently, most power plants are scheduled to produce power in hourly blocks. However, due to
the variability of renewable resources and the variable nature of demand, scheduling generation
in shorter time intervals creates a more efficient solution.205Wind resources within an operating
area are statistically less likely to be correlated across shorter time periods of minutes or seconds.
Being able to balance load and generation across smaller timeframes increases correlation among
load and wind and therefore reduces variability and the need for ramping, resulting in lower
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Recommendations
integration costs.206 This same logic applies to energy markets, in which the opportunity to trade
in smaller time increments better accommodates integration of wind. A recent study found that
grid operators in California that scheduled power plant output in 5-minute blocks drastically
reduced the cost of integrating renewable energy into the state’s grid.207
ITC/PTC
We assessed the price of electricity from wind with both the 30 percent ITC and the PTC. The
extension of the PTC and ITC will provide both lower prices and greater stability to the wind
power market, thereby encouraging greater investment in wind power and the necessary
transmission to move wind power to load centers.
The ITC and PTC both result in electricity prices that are approximately $0.02 less than
electricity prices without the tax credits (Table 12). This is slightly greater than the change in
electricity price that results with a $2.00 increase in natural gas prices. According to our
analysis, the ITC results in a lower electricity price for the shorter transmission distance,
approximately the same price for the middle distance and a slightly higher price for the long
distance. This is likely because the ITC directly reduces the capital costs for building a wind
plant. These costs are approximately the same per kW regardless of the distance of the plant
from load centers. However, because plants that are farther from load centers are accessing
better wind resources, they will spread the capital cost savings over a greater number of kWh
thereby resulting in higher per kWh electricity prices.
Table 12: Comparison of Electricity Prices ($/kWh) with ITC, PTC or Neither
150 miles
600 miles
1,000 miles
ITC
PTC
Neither
$0.0757
$0.0775
$0.1049
$0.0810
$0.0757
$0.1017
$0.1020
$0.0967
$0.1227
Difference Between ITC
& PTC
-$ 0.00530
$0.0018
$0.0032
Source: Model. Assumptions as in base case except for tax credits.
Carbon Prices
Including a price on carbon has a minimal impact on the cost of electricity from natural gas. For
the cases where electricity from natural gas is less expensive than electricity from wind, a price
on carbon can make the electricity from wind and transmission cost competitive with natural gas
prices. A $5.00 change in the price of carbon results in a $0.0021 increase in the price of
electricity from natural gas. This is 10 percent of the change that results from increasing the
natural gas price by $2.00 or including the ITC or PTC in the cost of electricity from wind
energy.
However, including a price for carbon emissions directly increases the cost of natural gas and
therefore makes wind with new transmission more attractive. Further, because carbon regulation
will impact coal more strongly than natural gas, demand for natural gas will increase, which
should raise the price of natural gas and make wind even more attractive.
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Recommendations
Hedging Value of Wind Generation
A final area that has gained significant interest from both wind advocates and utilities is the
potential hedging value of wind energy within a utility’s grid mix. The price volatility associated
with natural gas generation is a risk to utilities and consumers. A recent LBNL study stated that
“a utility looking to expand its resource portfolio should compare the cost of renewable
technologies to the hedged or guaranteed cost of new natural gas-fired generation, rather than to
projected costs based on uncertain gas price forecasts.”208 One of the first attempts to quantify
the value of wind power was LBNL’s 2002 study estimated the hedging value of wind to be
$0.005 kWh.209 That value offsets the integration costs associated with wind generation.
However, because the hedging value changes based on numerous conditions including natural
gas volatility, the percentage of natural gas generation in a region, the efficiency of natural gas
generation units, and the wind price in a region, hedging values will be different in each region.
Hedging values will be higher in areas with lower wind generation prices and greater reliance on
inefficient gas units.210 Overall, adding wind reduces the risk associated with natural gas
volatility, therefore providing value to both utilities and consumers.
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Conclusion
8. Conclusion
The EIA projects that more than 500 million MWh and more than 186,000 MW of new
generation capacity will be required by 2030.211 Currently, the two most frequently built
generation resources are wind (accounting for 35 percent of new capacity in 2007) and natural
gas (accounting for 50 percent of new capacity in 2007).212 Regardless of which sources are
used to meet the increasing demand for energy, upgrades to the electricity grid will be necessary.
Further, accessing clean and cost competitive wind sources requires a significant investment in
new transmission infrastructure and adds additional upfront costs to wind. This study analyzed
and modeled the impact of transmission, wind, and natural gas characteristics on the overall cost
of wind in comparison to natural gas.
Based on our analysis, for short distance wind projects (our 150 mile “Illinois” scenario) the
capacity factor and investment tax credit had the largest effect on overall electricity cost,
impacting wind by roughly 2.6 cents each over the variable ranges studied. In middle distance
scenarios (our 600 mile “Iowa” scenario), series compensation and line voltage had the biggest
impact on cost, impacting the cost of wind by 2.3 and 7.8 cents respectively over the variable
ranges studied. Finally, in our long distance scenario (the 1,000 mile “North Dakota” scenario),
the transmission load factor, series compensation and line voltage had the most significant
effects, with 3.3 cent, 6 cent and 67 cent impacts, respectively, over the variable ranges analyzed.
We found that the cost of wind generation for the 150 and 600 mile scenarios was cost
competitive with $6/MMBTU natural gas generation with no price on CO2 emissions when the
PTC/ITC was included. However, wind with very long transmission (1,000 mile scenario) was
not cost competitive until natural gas reached $8/MMBTU or $43/tCO2e.Although wind capacity
factors were higher in this scenario, the additional costs of transmission made wind generation
less cost competitive with natural gas.
It should be noted that our model did not fully quantify all the benefits for accessing remote wind
generation such as the environmental and health benefits of expanded clean energy generation,
possible congestion alleviation, and meeting a possible national Renewable Portfolio Standard.
By capturing these benefits, the 1,000 mile scenario may make greater economical sense.
Additionally, technological improvements such as better DC lines or new cost sharing
mechanisms for transmission costs could also reduce the costs for accessing remote wind
generation.
Based on our findings, we believe the most significant steps to make wind more cost competitive
are to create a high voltage network, increase transmission load factors (particularly for long
distance lines), provide tax credits, manage integration costs (through energy markets and larger
balancing areas), put a price on carbon dioxide emissions, and value wind as a hedge against
volatile natural gas prices. Each recommendation serves to lower the cost of wind or raise the
price of natural gas generation making wind comparatively more cost competitive. With these
recommendations, wind can fill a significant and growing portion of the United States’ energy
demand.
74
Conclusion
Next Steps
Our study highlighted several areas of further inquiry. The first of these is an investigation of the
impact of natural gas price volatility on the relative attractiveness of renewable energy in
general, and wind in particular. We also believe that policy mechanisms to allocate the cost of
electricity more fairly across the energy value chain are a significant enough topic to warrant
study. Finally, the use of smart grid technology, especially in relation to load shaping and
demand side management, could have a significant impact on the integration of wind resources.
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Appendix
9. Appendix
A. Model Assumptions and Calculations
Cost of Wind Electricity in $/kWh = Capital Costs + O&M Costs + Integration Costs –
Investment Tax Credit + Transmission Cost
Cost of Natural Gas Electricity in $/kWh = Capital Costs + O&M Costs + Fuel Costs + Carbon
Dioxide Emissions Costs
Capital Costs
Table 13: Construction Costs Assumptions (2008 USD)
Natural Gas CC
Overnight capital costs in
$/kW (costs)
Lifetime in years (Tgen)
Construction period in years
(Cgen)
Interest Rate (Rgen)
$857.00
Natural Gas
CT
$597.00
Wind
30
3
30
2
25
3
10%
10%
10%
$1,713.00
Source: See Endnote 213.
Calculations:
Cost Recovery Factor (CRFgen) = Rgen /(1-(1+Rgen)-Ngen
Construction Time Factor (Kgen) = 1+(Cgen-1)*Rgen/2
Total Capital Costs in $/kWh = CRFgen*costs*Kgen/hours of operation per year
Operations & Maintenance (O&M) Costs
Table 14: O&M Assumptions
Fixed O&M ($/kWyr)
Variable O&M ($/MWh)
Natural Gas CC
$34.01
$2.11
Source: See Endnote 214.
76
Natural Gas CT
$17.72
$3.66
Wind
$15.91
$0.00
Appendix
Table 15: Capacity Factor Assumptions
Capacity Factor
Natural Gas CC
50%
Natural Gas CT
50%
Wind
30%
Source: See Endnote 215.
Calculations:
Hours per year = 365.25*24 = 8766
Hours of operation per year = capacity factor * hours per year
Total O&M Costs in $/kWh=Fixed O&M/hours of operation per year+Variable
O&M/1,000
Fuel Costs
Table 16: Fuel Cost Assumptions
Fuel costs ($/MMBtu)
Heat Rate (Btu/kWh electricity)
Escalation rate
Natural Gas CC
$6.00
7196
2%
Natural Gas CT
$6.00
10842
2%
Wind
0
Source: See Endnote 216.
Calculations:
Fuel Costs in $/kWh = Fuel Costs in $/MMBtu*1MMBtu/1,000000Btu*heat rate*R/(Rescalation rate)
Carbon Dioxide Emissions Costs
In order to determine the different scenarios we should consider for carbon prices in our model,
we benchmarked historical and current prices for the following carbon trading instruments:
 European Union Allowances (EUA)
 Certified Emission Reductions (CER)
 Emission Reduction Units (ERU)
 Carbon Financial Instruments (CFI) on the Chicago Climate Exchange (CCX)
 Voluntary Emissions Reductions (VER) traded through the voluntary market in the
United States and internationally
Further, we analyzed projections on the cost of carbon included in several cap and trade bills
presented to Congress.
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Appendix
Based on this analysis, we evaluated the impact of a cost for carbon on electricity from natural
gas at the following four carbon cost levels:
 $0/tCO2
 $15/tCO2
 $40/tCO2
 $60/tCO2
Conversion Factors:
15 kg C/GJ217
1,000 kg/ton
1055 J/Btu
12 kg C/44 kg CO2
Calculations:
Emissions tCO2/kWh = heat rate *1055/10^9*15/1,000*44/12
Cost of CO2 Emissions $/kWh = emissions*price of carbon
Wind Integration Costs
DOE “20% by 2030” report cites IEEE that integration costs are expected to be less than 10
percent of wholesale electricity costs. We use 10% *(transmission costs + O&M costs + capital
costs) as the base case and analyzed a range from 8 percent to 12 percent.
Wind Investment Tax Credit
The investment tax credit provides a credit of 30 percent of the cost of capital equipment for
generation of wind electricity. For additional information, see the ITC/PTC section above.
Wind Production Tax Credit
The production tax credit provides a credit of $0.021 per kWh of electricity generated from wind
energy. For additional information, see the ITC/PTC section above.
Transmission
Cost of Transmission ($/kWh): CRFtrans*Ktrans*Total Transmission Cost/Yearly kWh carried
Transmission Cost Recovery Factor (CRFtrans): Rtrans /(1-(1+ Rtrans)-Ntrans
Transmission Construction Time Factor (Ktrans): (1+(Ctrans-1)*Rtrans/2
Return on Equity (Rtrans): the rate of return captured by the transmission developer. We assume
12 percent base case and range of 10 percent to 14 percent based on informal review of recent
transmission projects.
Cost Recovery Period (Ntrans): the number of years over which the transmission owner will
recover the capital cost of the transmission line. We assume 20 years based on current law and
practices.
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Appendix
Construction Time Period (Ctrans): Time it takes to construct the transmission infrastructure. We
assume 5 years based on informal review of transmission projects.
Total Transmission Cost: transmission cost + substation + series compensation + transformers.
Transmission Cost: Cost per Mile * miles
Cost per Mile: the capital costs for the transmission line.
Table 17: Transmission Cost Assumptions
Type of Line
AC - 345 kV
AC - (2) 345 kV
AC - 500 kV
AC - 765 kV
DC - 500 kV
DC - 800 kV
Total Cost per Mile
$1,300,000
$1,500,000
$2,080,000
$2,600,000
$1,857,636
$2,413,998
Source: See Endnote 218.
Miles: We compared three line lengths: 150 miles (Illinois), 600 miles (Iowa), and 1,000 miles
(North Dakota).
Substation Costs: additional costs for substations/converters. If AC line, substation costs are
assumed to be 25 percent of transmission costs. If DC line, converter station costs depend on the
type of DC line.
Table 18: DC Converter Station Cost Assumptions
Type of DC Line
Converter Station Cost
DC - 500 kV
$582,787,733.33
DC - 800 kV
$699,345,280.00
Source: See Endnote 219.
Series compensation cost: cost of series compensation equipment if installed to boost capacity of
line. We analyzed each type of line with and without series compensation. Installing series
compensation doubled the SIL and therefore the loadability of the line.
79
Appendix
Table 19: Series Compensation Cost Assumptions
Type of Line
AC - 345 kV
AC - (2) 345 kV
AC - 500 kV
AC - 765 kV
DC - 500 kV
DC - 800 kV
Series Compensation
$22,000,000
$44,000,000
$30,000,000
$40,000,000
$44,000,000
NA
Source: See Endnote 220.
Transformer Cost: needs to be included if high voltage line is being interconnected with low
voltage line. Assume $40 million/transformer. We analyzed zero, two, and four transformers.
Yearly kWh Carried (kWh): the amount of electricity transmitted on the transmission line.
Calculated by total transmission capacity converted to kW * 8766 hours per year
Total Transmission Capacity (MW): Average load – adjusted full line losses * miles.
Average Load: load factor * loadability
Load Factor: the average percent of capacity of the transmission line that is used. 60% load
factor is based on estimate of level that is economic and possible from with over-subscribing the
line.221 We analyzed a range from 40 percent to 70 percent.
Loadability: The amount of electricity (MWs) that can be carried on a transmission line.
Loadability refers to the line’s load carrying ability. It does not take into account load factor.
Often expressed as a multiple of a line’s surge impedance loading (SIL). Without series
compensation, use SIL curve (see figure below) to determine loadability factor based on line
length. Multiply loadability factor by the surge impedance loading (MW), which depends on the
type of line. With series compensation, multiply loadability as calculated above by factor of
two.222
80
Appendix
Figure 50: Surge Impedance Loading (SIL) Curve
3.5
Loadability Factor
3
2.5
2
xSIL
1.5
Power (xSIL)
1
0.5
y = 42.272x-0.662
0
0
100
200
300
400
500
600
Source: See Endnote 223.
Adjusted Full Line Losses: the amount of losses in MW per mile. Each type of line has a
different rate of loss per mile when fully loaded. This is referred to as the Full Line Losses
(FLL). The FLL needs to be adjusted downward to take into account the fact that the line will not
be fully loaded. Adjusted FLL= load factor * FLL + load factor2 * FLL/2.224
Table 20: Full Line Losses Assumptions
Type of Line
AC - 345 kV
AC - (2) 345 kV
AC - 500 kV
AC - 765 kV
DC - 500 kV
DC - 800 kV
FLL (MW/mile)
0.3351
0.6703
0.2214
0.1542
0.3654
0.3212
Source: See Endnote 225.
Surge Impedance Loading (SIL): the level of line loading at which natural reactive power
balance occurs.
81
Appendix
Table 21: Surge Impedance Loading (SIL) Assumptions
Type of Line
AC - 345 kV
AC - (2) 345 kV
AC - 500 kV
AC - 765 kV
DC - 500 kV
DC - 800 kV
Source: See Endnote 226.
SIL (MW)
390
780
910
2,400
910
4,800
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Appendix
B. States within the JCSP Study Area with a RPS
Table 21: Current RPS by State
Region
ISO New
England
MISO
NY ISO
PJM
State
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Illinois
Indiana
Iowa
Michigan
Minnesota
Missouri
Montana
Nebraska
North Dakota
South Dakota
Wisconsin
New York
Delaware
Maryland
New Jersey
North Carolina
Ohio
Pennsylvania
Virginia
West Virginia
SPP
Arkansas
Kansas
Louisiana
New Mexico
Oklahoma
Texas
TVA
Alabama
Georgia
Kentucky
Tennessee
Source: See Endnote 227.
RPS
27% by 2020
30% by 2000
15% new by 2020 with 1% annual increase
25% by 2025
16% by 2020
25% by 2025
25% by 2025
-105 MW
10% by 2015
25% by 2025, 30% by 2020 for Xcel Energy
15% by 2021
15% by 2015
-10% by 2015 (not mandatory)
10% by 2015 (not mandatory)
10% by 2015
25% by 2013
20% by 2019, minimum 2% from solar
20% by 2022, minimum 2% from solar
22.5% by 2021, minimum 2% from solar
12.5% by 2021
25% by 2025 from alternative energy, 12.5% from
renewables
18% by 2020, minimum 0.5% from solar
12% of 2007 sales by 2020 (not mandatory)
----20% by 2020
-5,880 MW by 2015
-----
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Appendix
C. Brief Background on Carbon Legislation
Policymakers have two primary options for regulating emissions; they can choose a command
and control approach or a market-based approach. A command and control approach involves
placing a tax on all emissions of greenhouse gases or dictating the specific types of technologies
that must be implemented to reduce greenhouse gas emissions. A market-based approach allows
for more flexibility by enabling companies to determine how and when to reduce emissions.
Cap and trade policies are one example of a market mechanism for regulating emissions. The
majority of climate legislation, including regional domestic legislation, international policies and
proposed U.S. national policies, is based on the cap and trade approach. Under a cap and trade
program, regulators set a cap on emissions and identify which industries or sectors will be
covered by this cap. The cap equals the sum of all allowed emissions from the sectors included
under the cap. Regulators then decide how to allocate emissions allowances, which determine
the amount that each facility can emit. Allowances can be either auctioned, freely allocated or
some combination of the two. Each allowance allows the emission of a specified amount of
pollution. Trading of allowances will occur between organizations that are able to reduce
emissions at lower cost and organizations for which it is more difficult or expensive to control
emissions. Organizations that are producing emissions below the cap can sell or trade their extra
emissions to companies that are not meeting the cap. Unlike a tax, a cap and trade program
would place an upper limit on the amount of emissions, but the cost of reducing emissions would
vary on the basis of fluctuations in energy markets, the weather (for example, an exceptionally
cold winter would increase the demand for energy and make meeting a cap more expensive), and
the technologies available for reducing emissions.228
Kyoto Protocol
On March 21, 2004, the United Nations Framework Convention on Climate Change (UNFCCC)
came into force. This is an international treaty ratified by 192 countries to begin to identify ways
to reduce global warming and to cope with unavoidable climate changes.229 The Convention on
Climate Change sets an overall framework for intergovernmental efforts to tackle the challenge
posed by climate change. It recognizes that the climate system is a shared resource whose
stability can be affected by industrial and other emissions of carbon dioxide and other
greenhouse gases (GHG). Under the Convention, governments agree to:
 Gather and share information on GHG emissions, national policies and best practices;
 Launch national strategies for addressing GHG emissions and adapting to expected
impacts, including the provision of financial and technological support to developing
countries; and
 Cooperate in preparing for adaptation to the impacts of climate change .
The Kyoto Protocol is an international agreement linked to the United Nations Framework
Convention on Climate Change. The major feature of the Kyoto Protocol is that it sets binding
targets for 37 industrialized countries and the European community for reducing GHG
emissions. These targets amount to an average of five percent reductions against 1990 levels
over the five-year period from 2008 to 2012. The major distinction between the Protocol and the
Convention is that while the Convention encouraged industrialized countries to stabilize GHG
emissions, the Protocol commits them to do so. The Kyoto Protocol was adopted in Kyoto,
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Appendix
Japan, on December 11, 1997 and entered into force on February 16, 2005. To date, 183 Parties
of the Convention have ratified the Protocol.230
Parties with commitments under the Kyoto Protocol (Annex B Parties) have accepted targets for
limiting or reducing emissions. These targets are expressed as levels of allowed emissions, or
“assigned amounts”. The allowed emissions are divided into “assigned amount units” (AAUs).
Emissions trading allows countries that have emission units to spare - emissions allotted to them
but not "used" - to sell excess emission allowances to countries that are over their targets.231
While this market could potentially be very large, in the order of several billion tons of CO2e, no
known trades have yet taken place.232
In addition to AAUs, the Kyoto protocol allows the following three other units to be transferred
under the scheme with each unit equal to one ton of CO2.
 A removal unit (RMU) on the basis of land use, land-use change and forestry (LULUCF)
activities such as reforestation;

An emission reduction unit (ERU) generated by a Joint Implementation project; and
 A certified emission reduction (CER) generated from a Clean Development Mechanism
project activity.
Joint Implementation allows a country with an emission reduction or limitation commitment
under the Kyoto Protocol (Annex B Party) to earn emission reduction units (ERUs) from an
emission reduction or emission removal project in another Annex B Party, each ERU is
equivalent to one ton of CO2 and can be counted towards meeting the country’s Kyoto target.
Joint implementation offers Parties a flexible and cost-efficient means of fulfilling a part of their
Kyoto commitments, while the host Party benefits from foreign investment and technology
transfer.233
The Clean Development Mechanism (CDM) allows an Annex B Party to implement an emission
reduction project in a developing country to earn saleable certified emission reduction (CER)
credits, which can be counted towards meeting Kyoto targets. CDM is the first global,
environmental investment and credit scheme of its kind, providing a standardized emissions
offset instrument, CERs. The mechanism stimulates sustainable development and emission
reductions, while giving industrialized countries some flexibility in how they meet their emission
reduction or limitation targets.234
Domestic Legislation
In the United States, there is some legislation currently in force which allows for the regulation
of emissions of carbon dioxide. Under the Clean Air Act 42 U.S.C. 7602(g) the Administrator of
the Environmental Protection Agency has the authority to set standards for air pollutants emitted
by new motor vehicles when, in the judgment of the administrator, they “cause, or contribute to,
air pollution, which may reasonably be anticipated to endanger public health or welfare.”
Included in this legislation is the provision that climate and weather are components of the term
welfare. The April 2, 2007 Supreme Court ruling in Massachusetts et al. vs. U.S. EPA legally
cemented the definition of greenhouse gases as pollutants under the CAA and established the
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Appendix
EPA as the responsible regulatory authority. Although this rule didn’t require action on the part
of the government, it set the stage for the development of national climate change policy.
In the 110th Congress, 12 bills with cap and trade systems were proposed. The most well-known
is probably the Boxer-Lieberman-Warner Climate Security Act. Other proposed bills include the
following:
1. Investing in Climate Action and Protection Act, proposed by Rep. Markey,
2. Climate Stewardship and Innovation Act S. 280, proposed by Senators Lieberman and
McCain,
3. Global Warming Pollution Reduction Act, proposed by Senators Sanders and Leahy,
4. Electric Utility Cap and Trade Act, proposed by Senators Feinstein and Carper
5. Climate Stewardship Act, proposed by Rep. Oliver and Gilchrist,
6. Global Warming Reduction Act, proposed by Senators Kerry and Snowe,
7. Safe Climate Act, proposed by Rep. Waxman,
8. Clean Air Planning Act, proposed by Senator Carper,
9. Clean Air/Climate Change Act of 2007, proposed by Senators Alexander and Lieberman,
10. Clean Power Act, proposed by Senator Sanders, and
11. Low Carbon Economy Act, proposed by Senators Bingaman and Specter.
While eight different plans for controlling climate change were introduced in the U.S. Senate
during the 110th Congress, only one made it out of committee – the Lieberman-Warner Climate
Security Act of 2008. The bill was officially submitted on October 18, 2007 as S. 2191. On
December 5, 2007 the Lieberman-Warner Climate Security Act of 2007 was voted out of the
Senate Environment and Public Works committee. This represented the first time that climate
change legislation has been voted out of congressional committee. On May 20, 2008, Senator
Boxer introduced the bill to the Senate as S. 3036. This bill included the original language of S.
2191, but also included revisions to address concerns raised by the Congressional Budget Office.
On June 6, 2008, the Senate voted 48 to 36 to filibuster the Lieberman-Warner Climate Security
Act (S. 3036). Sixty votes would have been required to achieve cloture and limit debate. Sixteen
senators – six Democrats and ten Republicans – failed to vote. The vote was specifically on
cloture for Senator Barbara Boxer’s (D-CA) substitute amendment (S.A. 4825) to the bill.
While S. 3036 was ultimately filibustered, it helped to move the debate on climate change one
step closer to resolution; what one article referred to as "clearing the underbrush.” As many in
Congress do not focus on the finer details of legislation until it is set for a vote, bringing this
legislation to a vote encouraged Senate offices that never before explored the weeds of climate
policy to take a very deep dive.235
Frustration with lack of action at the federal level has led states and regions to pass systems for
regulating carbon dioxide. These currently include California Assembly Bill 32, the Regional
Greenhouse Gas Initiative, the Western Regional Climate Initiative, and the Midwestern
Governors GHG Accord.
86
Appendix
D. Brief Background on Carbon Prices
In order to determine the different carbon price scenarios to use in our model, we benchmarked
historical and current prices for the following carbon trading instruments:
1. European Union Allowances
2. Certified Emission Reductions (CERs)
3. Emission Reduction Units (ERUs)
4. Carbon Financial Instruments (CFIs) on the Chicago Climate Exchange (CCX)
5. Voluntary Emissions Reductions (VERs) traded through the voluntary market in the
United States and internationally
European Union Allowances
Approximately 70 percent of EUAs were traded in the brokered over-the-counter (OTC) market
while the rest were traded on exchanges.236 The London Energy Brokers Association (LEBA)
accounted for 54 percent of the OTC trading activity in 2007. There are four primary exchanges
– the European Climate Exchange, which accounted for 87 percent of the volume traded through
exchanges, the Oslo-based Nord Pool, which accounted for 6.3 percent of the volume, and finally
the French Powernext, which accounted for 5.5 percent of the volume.237
According to Point Carbon, the European Union Emission Trading Scheme (EU ETS) saw a
traded volume in 2007 of 1.6 gigatons (Gt) and a value of €28 billion representing a volume
growth of 62 percent and a value growth of 55 percent over 2006 and an average price of
€17.50.238A World Bank report estimated the traded volume in 2007 as 2,061 MtCO2e and the
value at €37 billion ($50.1 billion) representing a volume growth rate of 87 percent and value
growth of 105 percent over 2006 and an average price of €17.95 ($24.31).239
According to a Point Carbon survey, respondents to the survey expect EUA prices to rise to €24
per ton in 2010 and €35 per ton in 2020.240 Over the course of 2007, EUAs for delivery by
December 2008 traded in a range between €12.25 and €25.28241 with a consistent range of €20 to
€25/tCO2e from May 2007 through the end of the year.242
Certified Emission Reductions
The Clean Development Mechanism (CDM) market saw a traded volume in 2007 of 947 million
tons (Mt) and a value of €12 billion representing a volume growth of 68 percent and a value
growth of 199 percent over 2006.243Prices in the primary CER market depend on project stage,
project type and counterparty. Prices for registered projects were approximately €12/tCO2e,
while prices for issued CERs were between €14 and €17244 with an average price of
approximately €12.67.245 The secondary CER (sCER) market was the fastest growing segment of
the carbon market in 2007 with a traded volume of 350 Mt in 2007 versus 40 Mt in 2006. The
sCER contract for delivery by December 2008 began 2007 at approximately €14, but fell through
the winter to an all-time low of €10.70 in February and then recovering to an all-time high of
€17.45 in May.246
87
Appendix
Emission Reduction Units
The Joint Implementation market saw a traded volume in 2007 of 38 Mt and a value of €326
million representing a volume growth of 81 percent and a value growth of 243 percent. 247 On
average, ERU price ranges increased in 2007 compared to 2006. Cited ERU prices for standard
off-take contracts varied from €6 to €10 depending on project risk248 and were on average €8.58
per ton.249
Carbon Financial Instruments
Carbon Financial Instruments (CFIs) are traded on the Chicago Climate Exchange, which is a
voluntary cap and trade system. CCX emitting members make a voluntary but legally binding
commitment to meet annual GHG emission reduction targets. Those who reduce below the
targets have surplus allowances to sell or bank; those who emit above the targets comply by
purchasing CCX Carbon Financial Instrument® (CFI®) contracts.250 CFI contracts are
comprised of Exchange Allowances and Exchange Offsets. Exchange Allowances are issued to
emitting members in accordance with their emission baseline and the CCX Emission Reduction
Schedule. Exchange Offsets are generated by qualifying offset projects.
CCX first started trading CFIs on December 12, 2003 at a price of $0.98 for 2003 vintage CFIs.
CFIs reached a high price of $7.40 for all vintages in May 2008 before dropping to a current
price of $1.50. The low for CFIs was at $0.71 for 2005 vintage from February 26 through March
12, 2004.
In 2008, the average price for CFIs was $3.89 for all vintages except 2003, which had an average
price of $3.90. The CFI 2008 high price was $7.40 on May 30 and June 1. The CFI 2008 low
price was $0.95 for 2010 vintage on November 17-19, 2008.
According to a report published by Ecosystem Marketplace and New Energy Finance, in 2007,
CFI prices ranged from $1.62 to $4.20 with a weighted average of $3.15 per ton.251In 2007, the
CFI market saw a record breaking trading volume of 23 MtCO2e and a value of $72 million or
€53 million, approximately doubling the volume and values of 2006.252
Voluntary Emissions Reductions
Point Carbon estimated total voluntary market volume to be 75 Mt in 2007, which includes
VERs as well as CFIs traded through the Chicago Climate Exchange. The majority of the
voluntary market transaction volume took place in the United States split evenly between the
Chicago Climate Exchange and the corporate and consumer retail market. In 2007, carbon credit
prices ranged between $2 per ton and $15 per ton.253 According to a survey conducted by
Ecosystem Marketplace and New Energy Finance, prices for voluntary carbon prices ranged
from $1.80 to $50 with one project priced at $300 per ton and with a weighted average of $6.10
per ton. The difference in price depended primarily on type of verification standard and type of
project.254
88
Appendix
E. Carbon Price Forecasts
Forecasts from S.3036 legislation
One analysis determined that the Lieberman-Warner Climate Security Act (S. 3036), which was
the only bill of the eight introduced in the U.S. Senate during the 110th Congress to make it out
of committee, would result in carbon prices between $15 and $40 per ton. The LiebermanWarner Climate Security Act was written to bar trade of a major volume of credits generated by
international greenhouse gas offset projects, such as solar and wind farms in China and India. If
the United States, the world's largest energy consumer, bars trade of such credits, the price of
greenhouse gas emissions will hit $35 to $40 per ton as soon as 2015, according to New Carbon
Finance. That should boost consumer power bills 20 percent, gasoline 12 percent, and natural gas
10 percent, it said.255Opening up the market would cut U.S. emissions prices down to $15 a ton
and cut costs for the average American about $480 per year. That is because emissions
reductions associated with global clean development projects trade for much less than $40 per
ton.
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101
Endnotes
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21
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23
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26
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27
Wiser, Ryan, and Mark Bolinger. "Surpassing expectations: State of the US wind power
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28
Wiser, Ryan, and Mark Bolinger. "Surpassing expectations: State of the US wind power
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29
American Wind Energy Association - Directory Search. 23 Mar. 2009
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30
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31 Coldham, Anna, Evan Croen, Brian Katzman, and Theo Ludwick. "PPA vs. Ownership of
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32
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33
Tseng, Phillip. "Modeling Regional Electricity Generation." Apr. 2007. Energy Information
Agency. 26 Mar. 2009.
<http://www.eia.doe.gov/smg/asa_meeting_2007/spring/files/modelingelect.ppt>.
34
20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. July 2008. U.S. Department of Energy.
35
A balancing area refers to the area across which load must be matched with generation.
Source: 20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. July 2008. U.S. Department of Energy.
36
American Wind Energy Association and Solar Energy Industries Association. Green Power
Superhighways: Building a Path to America’s Clean Energy Future. Feb. 2009.
<http://www.awea.org/GreenPowerSuperhighways.pdf>.
37
The duration curve illustrates the availability of resources compared to time. Flattening the
duration curve increases the availability of a resource.
38
Porter, Kevin. New Transmission Initiatives for Renewable Energy and Some Thoughts on
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w%2520Transmission%2520Initiatives%2520for%2520Renewable%2520Energy%2520and%25
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39
Joint Coordinated System Plan ‘08. Rep. MISO, SPP, PJM, TVA, MAPP, SERC. New
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40
Joint Coordinated System Plan ‘O8. Rep. MISO, SPP, PJM, TVA, MAPP, SERC, New
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41
20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity
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42
An Environmentally Friendly Investment. Lifecycle Assessment of a V80-2.0 MW onshore
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103
Endnotes
43
Erickson et al. Summary of Anthropogenic Causes of Bird Mortality. 2002. American Wind
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44
Audubon's Position on Wind Power Audobon Society. Audubon Society. 27 Mar. 2009
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45
Utility Scale Wind Energy and Sound. American Wind Energy Association. 27 Mar. 2009
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46
How is natural gas used? June 2008. Energy Information Administration. 6 Jan. 2009
<http://www.eia.doe.gov/kids/energyfacts/sources/nonrenewable/naturalgas.html#WHATITISUSEDFOR>.
47
Natural Gas Consumption by End Use (MCF). 26 Feb. 2009 U.S. Department of Energy
Office of Electricity Delivery & Energy Reliability. 26 Mar. 2009
<http://tonto.eia.doe.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm>.
48
Natural Gas Basic Statistics. Sept. 2008. Energy Information Administration. 30 Jan. 2009
<http://www.eia.doe.gov/basics/quickgas.html>.
49
Natural Gas Supply. NaturalGas.org. Natural Gas Supply Association. 11 Jan. 2009
<http://www.naturalgas.org/business/supply.asp>.
50
Ibid.
51
Ibid.
52
Natural Gas Consumption by End Use (MCF). 26 Feb. 2009 U.S. Department of Energy
Office of Electricity Delivery & Energy Reliability. 26 Mar. 2009
<http://tonto.eia.doe.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm>.
53
Ibid.
54
Electric Power Industry 2007: Year in Review. Rep. U.S. Department of Energy: Energy
Efficiency and Renewable Energy. 21 Jan. 2009
<http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html>.
55
Natural Gas Consumption by End Use (MCF). 26 Feb. 2009 U.S. Department of Energy
Office of Electricity Delivery & Energy Reliability. 26 Mar. 2009
<http://tonto.eia.doe.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm>.
56
U.S. Electric Power Industry Net Summer Capacity. 22 Oct. 2007. Department of Energy
Energy Information Administration. 11 Jan. 2009
<http://www.eia.doe.gov/cneaf/electricity/epa/figes2.html>.
57
U.S. Electric Power Industry Net Summer Capacity. 1 Jan. 2009. Department of Energy
Energy Information Administration. 21 Nov. 2009 <
http://www.eia.doe.gov/cneaf/electricity/epa/figes2.html>.
58
Natural Gas Information Toolkit. National Association of Regulatory Utility Commissioners.
11 Jan. 2009 <http://www.naruc.org/Publications/gas%20toolkit%20final.pdf>.
59
Short-Term Energy Outlook. Rep. 10 Mar. 2009. U.S. Department of Energy Energy
Information Administration. 1 Apr. 2009
<http://www.eia.doe.gov/emeu/steo/pub/contents.html>.
60 Electric Power Monthly, March 2009; Table 4.9.A and 4.13A
<http://www.eia.doe.gov/emeu/steo/pub/contents.html>.
61
Industry and Market Structure. NaturalGas.org. Natural Gas Supply Association. 26 Mar. 2009
<http://www.naturalgas.org/business/industry.asp>.
62
Franolic, Peter. "Supply Chain Components of Natural Gas Cost 1 - IV." Supply
104
Endnotes
Chain Management Review (2008). 27 Mar. 2009
<http://www.scmr.com/blog/500000450/post/940028294.html>.
63
Ibid.
64
Ibid.
65
Ibid.
66
Franolic, Peter. "Supply Chain Components of Natural Gas Cost 1 - IV." Supply
Chain Management Review (2008). 27 Mar. 2009
<http://www.scmr.com/blog/500000450/post/940028294.html>.
67
History. NaturalGas.org. Natural Gas Supply Association. 11 Jan. 2009
<http://www.naturalgas.org/overview/history.asp>.
68
Nersesian, Roy L. "Energy for the 21st Century: A Comprehensive Guide to Conventional and
Alternative Sources." M.E. Sharpe 2007.
69
Ibid.
70
Electric Power Industry 2007: Year in Review. Rep. U.S. Department of Energy: Energy
Efficiency and Renewable Energy. 21 Jan. 2009
<http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html>.
71
Electric Generation Using Natural Gas. NaturalGas.org. Natural Gas Supply Association. 11
Jan. 2009 <http://www.naturalgas.org/overview/uses_eletrical.asp.>.
72
Nersesian, Roy L. "Energy for the 21st Century: A Comprehensive Guide to Conventional and
Alternative Sources." M.E. Sharpe 2007.
73
The thermal efficiency of a combined cycle power plant is the net power output of the plant
divided by the heating value of the fuel.
74
Electric Generation Using Natural Gas. NaturalGas.org. Natural Gas Supply Association. 11
Jan. 2009 <http://www.naturalgas.org/overview/uses_eletrical.asp.>.
75
Electric Power Industry 2007: Year in Review. Rep. U.S. Department of Energy: Energy
Efficiency and Renewable Energy. 21 Jan. 2009
<http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html>.
76
Nersesian, Roy L. "Energy for the 21st Century: A Comprehensive Guide to Conventional and
Alternative Sources." M.E. Sharpe 2007.
77
How Does Natural Gas Impact the Environment? June 2008. Department of Energy Energy
Information Administration. 6 Jan. 2009 <http://www.eia.doe.gov/kids/energyfacts/sources/nonrenewable/naturalgas.html#NGANDTHEENVIRONMENT>.
78
Ibid.
79
Ibid.
80
"Natural Gas 1998: Issues and Trends." U.S. Department of Energy Office of Electricity
Delivery & Energy Reliability. 27 Aug. 1999. U.S. Department of Energy Energy Efficiency and
Renewable Energy. 27 Mar. 2009.
<http://www.eia.doe.gov/oil_gas/natural_gas/analysis_publications/natural_gas_1998_issues_an
d_trends/it98.html>.
81
Electricity from Natural Gas. 28 Dec. 2007. Environmental Protection Agency. 11 Jan. 2009
<http://epa.gov/cleanenergy/energy-and-you/affect/natural-gas.html>.
82
How Does Natural Gas Impact the Environment? June 2008. Department of Energy Energy
Information Administration. 6 Jan. 2009
105
Endnotes
83
Spath, Pamela L., and Margaret K. Mann. "Life Cycle Assessment of a Natural Gas
Combined-Cycle Power Generation System." NREL Life Cycle Assessment (2000): n. pag. Web.
8 Dec 2009. <http://www.nrel.gov/docs/fy00osti/27715.pdf>.
84
Bolinger, Mark and Ryan Wiser. "Surpassing expectations: State of the U.S. wind power
market - Renewable Energy World." Renewable Energy World 4 Sep. 2008. 26 Mar. 2009
<http://www.renewableenergyworld.com/rea/news/article/2008/09/surpassing-expectations-stateof-the-us-wind-power-market-53498>.
Form EIA-861, Annual Electric Power Industry Report. Rep. Energy Information
Administration. 26 Feb. 2009
<http://www.eia.doe.gov/cneaf/electricity/wholesale/wholesalet2.xls>.
20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity Supply.
Rep. Jul. 2008. U.S. Department of Energy.
Natural Gas Supply. NaturalGas.org. Natural Gas Supply Association. 11 Jan. 2009
<http://www.naturalgas.org/business/supply.asp>.
How Does Natural Gas Impact the Environment? Jun. 2008. Department of Energy Energy
Information Administration. 6 Jan. 2009 <http://www.eia.doe.gov/kids/energyfacts/sources/nonrenewable/naturalgas.html#NGANDTHEENVIRONMENT>.
85
Nersesian, Roy L. "Energy for the 21st Century: A Comprehensive Guide to Conventional and
Alternative Sources." M.E. Sharpe 2007.
86
20% Wind Energy by 2030. Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. July 2008. U.S. Department of Energy.
87
20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. Jul. 2008. U.S. Department of Energy.
88
Ibid.
89
Ibid.
90
Ibid.
91
Armistead, Thomas. "Technologies for Grid Reliability Receive More of Transmission
Investment Funds - ENR McGraw Hill Construction." Engineering News-Record. 27 Aug.
2007. Engineering News-Record. 18 Apr. 2009
<http://enr.construction.com/features/powerIndus/archives/070829-1.asp>.
92
According to DOE, currently there are 230,000 miles of transmission lines above the 230kv
capacity level.
93
20% Wind Energy by 2030. Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. July 2008. U.S. Department of Energy.
94
20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. Jul. 2008. U.S. Department of Energy.
95
Ibid.
96
Ibid.
97
$0/kW is estimated for projects that add wind resources to the grid without requiring
transmission investment.
98
Mills, Andrew, Ryan Wiser, and Kevin Porter. The Cost of Transmission for Wind Energy: A
Review of Transmission Planning Studies. Rep. Feb. 2009. Ernest Orlando Lawrence Berkeley
National Laboratory. 7 Mar. 2009 <http://eetd.lbl.gov/EA/EMP>.
106
Endnotes
99
$50 million of 6.63% Senior Secured Notes due 2014 on December 18, 2008, $40 million of
7.12% First Mortgage Bonds due 2017, and $35 million of 7.27% First Mortgage Bonds due
2020.
100
Dotten, Michael, Steve Jones, and Alyssa Moir. “Battle Over Transmission Siting: Congress
Considers Federalizing Permit Process, While Fourth Circuit Upholds States’ Right to Control
It.” 10 Mar 2009. Marten Law Group. <http://www.martenlaw.com/news/?20090310transmission-siting-battle>.
101
EEI - Electricity Transmission. Edison Electric Institute. 27 Mar. 2009
<http://www.eei.org/ourissues/ElectricityTransmission/Pages/default.aspx>.
102
FERC: About FERC. Federal Energy Regulatory Commission. 23 Mar. 2009
<http://www.ferc.gov/about/about.asp>.
About NERC. NERC North American Electric Reliability Corporation. 26 Mar. 2009
<http://www.nerc.com/page.php?cid=1>.
103
FERC: About FERC. Federal Energy Regulatory Commission. 23 Mar. 2009
<http://www.ferc.gov/about/about.asp>. And About NERC. NERC North American Electric
Reliability Corporation. 26 Mar. 2009 <http://www.nerc.com/page.php?cid=1>.
104
Porter, K., S. Fink, C. Mudd, and J. DeCesaro. Generation Interconnection Policies and Wind
Power: A Discussion of Issues, Problems, and Potential Solutions. Rep. Columbia: National
Renewable Energy Laboratory, 2009.
105
Porter, K., S. Fink, C. Mudd, and J. DeCesaro. Generation Interconnection Policies and Wind
Power: A Discussion of Issues, Problems, and Potential Solutions. Rep. Columbia: National
Renewable Energy Laboratory, 2009.
106
FERC Approves MISO Queue Reforms. National Renewable Energy Laboratory. 27 Mar.
2009 <http://www.nrel.gov/wind/news/2008/632.html>.
107
Porter, K., S. Fink, C. Mudd, and J. DeCesaro. Generation Interconnection Policies and Wind
Power: A Discussion of Issues, Problems, and Potential Solutions. Rep. Columbia: National
Renewable Energy Laboratory, 2009.
108
Ibid.
109
Environmental Sector Comments: MISO Advisory Committee Hot Topic Questions on Cost
Allocation." Midwest Independent System Operator 2 Apr 2009
<http://www.misostates.org/11ItemB1aEnvironmentalCostAllocHotTopic12-08%20(2).pdf>.
110
Green Power Superhighways: Building a Path to America’s Clean Energy Future. February
2009. American Wind Energy Association and Solar Energy Industries Association.
<http://www.awea.org/GreenPowerSuperhighways.pdf>.
111
Ibid.
112
Environmental Sector Comments: MISO Advisory Committee Hot Topic Questions on Cost
Allocation." Midwest Independent System Operator 2 Apr 2009
<http://www.misostates.org/11ItemB1aEnvironmentalCostAllocHotTopic12-08%20(2).pdf>.
113
Baldick, Ross, Ashley Brown, James Bushnell, Susan Tierney, and Terry Winter A National
Perspective On Allocating the Costs of New Transmission Investment: Practice and Principles."
Sep 2007 The Blue Ribbon Panel on Cost Allocation.
<http://www.wiresgroup.com/images/Blue_Ribbon_Panel_-_Final_Report.pdf>.
114
20% Wind Energy by 2030. Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. July 2008. U.S. Department of Energy
107
Endnotes
20% Wind Energy by 2030. Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. July 2008. U.S. Department of Energy
116
Baldick, Ross, Ashley Brown, James Bushnell, Susan Tierney, and Terry Winter A National
Perspective On Allocating the Costs of New Transmission Investment: Practice and Principles."
Sep 2007 The Blue Ribbon Panel on Cost Allocation.
<http://www.wiresgroup.com/images/Blue_Ribbon_Panel_-_Final_Report.pdf>.
117
Electric Power Industry 2007: Year in Review. Rep. U.S. Department of Energy: Energy
Efficiency and Renewable Energy. 21 Jan. 2009
<http://www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html>.
118
Nashville, TN and New Orleans, LA Assumptions and Capacity Expansion Workshops. Joint
Coordinated System Plan. 11-12 Dec 2007. http://www.jcspstudy.org/>.
119
Wiser, Ryan, Mark Bolinger, and Galen Barbose. Using the Federal Production Tax Credit to
Build a Durable Market for Wind Power in the United States. Rep. Nov. 2007. Ernest Orlando
Lawrence Berkeley National Laboratory. 20 Dec. 2008
<http://eetd.lbl.gov/ea/emp/reports/63583.pdf>.
120
Legislative Priorities. American Wind Energy Association. 20 Dec. 2008
<http://www.awea.org/legislative>.
121
Production Tax Credit for Renewable Energy. Union of Concerned Scientists. 14 Nov. 2008
<http://www.ucsusa.org/clean_energy/solutions/big_picture_solutions/production-tax-creditfor.html>.
122
Form 8835: Renewable Electricity, Refned Coal and Indian Coal Production Credit. Rep.
2007. U.S. Department of Treasury Internal Revenue Service. 20 Dec. 2008
<http://www.irs.gov/pub/irs-pdf/f8835.pdf>.
123
Tiegerman, Philip. "Credit for Renewable Electricity Production, Refined Coal Production,
and Indian Coal Production, and Publication of Inflation Adjustment Factors and Reference
Prices for Calendar Year 2008." Federal Register 73 (2008). 20 Dec. 2008.
124
" Production Tax Credit for Renewable Energy. Union of Concerned Scientists. 14 Nov. 2008
<http://www.ucsusa.org/clean_energy/solutions/big_picture_solutions/production-tax-creditfor.html>.
125
Production Tax Credit for Renewable Energy. Union of Concerned Scientists. 14 Nov. 2008
<http://www.ucsusa.org/clean_energy/solutions/big_picture_solutions/production-tax-creditfor.html>.
126
Baratoff, Michael C., Ian Black, Bodhi Burgess, Justin E. Felt, Matthew Garratt, & Christian
Guenther. Renewable Power, Policy, and the Cost of Capital Improving Capital Market
Efficiency to Support Renewable Power Generation Projects. Apr 2007
<http://deepblue.lib.umich.edu/bitstream/2027.42/50488/4/070419%20RPPCC%20FINAL.pdf>.
127
Production Tax Credit for Renewable Energy. Union of Concerned Scientists. 14 Nov. 2008
<http://www.ucsusa.org/clean_energy/solutions/big_picture_solutions/production-tax-creditfor.html>.
128
H.R.1424: To provide authority for the Federal Government to purchase and insure certain
types of troubled assets for the purposes of providing stability to and preventing disruption in the
economy... (Enrolled as Agreed to or Passed by Both House and Senate). Oct 2008. Library of
Congress. <http://thomas.loc.gov/cgi-bin/query/F?c110:1:./temp/~c110GuFX29:e137874:>.
115
108
Endnotes
129
Renewable Electricity Production Tax Credit (PTC). DSIRE: Database of State Incentives for
Renewables and Efficiency. 18 Nov. 2008
<http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=US13F>.
130
Production Tax Credit for Renewable Energy. Union of Concerned Scientists. 14 Nov. 2008
<http://www.ucsusa.org/clean_energy/solutions/big_picture_solutions/production-tax-creditfor.html>.
131
Ibid.
132
Ibid.
133
Wiser, Ryan, Mark Bolinger, and Galen Barbose. Using the Federal Production Tax Credit to
Build a Durable Market for Wind Power in the United States. Rep. Nov. 2007. Ernest Orlando
Lawrence Berkeley National Laboratory. 20 Dec. 2008
<http://eetd.lbl.gov/ea/emp/reports/63583.pdf>.
134
Short, Walter, Nate Blair, Paul Denholm, and Donna Heimiller. "Modeling the Penetration of
Wind Energy Into the U.S. Electric Marke." CNLS 26th Annual Conference. 16 Aug. 2006.
135
Ibid. And 20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S.
Electricity Supply. Rep. July 2008. U.S. Department of Energy.
136
"The National Energy Modeling System: An Overview 2003." Energy Information
Administration. Mar 2003. Department of Energy Energy Information Administration. 16 Mar
2009 <http://www.eia.doe.gov/oiaf/aeo/overview/introduction.html>.
137
Short, Walter, Nate Blair, Paul Denholm, and Donna Heimiller. "Modeling the Penetration of
Wind Energy Into the U.S. Electric Marke." CNLS 26th Annual Conference. 16 Aug. 2006.
138
Baratoff, Michael C., Ian Black, Bodhi Burgess, Justin E. Felt, Matthew Garratt, & Christian
Guenther. Renewable Power, Policy, and the Cost of Capital Improving Capital Market
Efficiency to Support Renewable Power Generation Projects. Apr 2007
<http://deepblue.lib.umich.edu/bitstream/2027.42/50488/4/070419%20RPPCC%20FINAL.pdf>.
139
Wiser, Ryan, Mark Bolinger, and Galen Barbose. Using the Federal Production Tax Credit to
Build a Durable Market for Wind Power in the United States. Rep. Nov. 2007. Ernest Orlando
Lawrence Berkeley National Laboratory. 20 Dec. 2008
<http://eetd.lbl.gov/ea/emp/reports/63583.pdf>.
140
"Summary of Final Provisions in H.R. 1, the American Recovery and Reinvestment Act
(ARRA) of 2009, of Interest to the Wind Energy Industry." American Wind Energy Association.
Mar. 2009. American Wind Energy Association. 14 Mar. 2009
<http://www.awea.org/legislative/pdf/ARRA_Provisions_of_Interest_to_Wind_Energy_Industry
.pdf>.
141
Wiser, Ryan, Mark Bolinger, and Galen Barbose. "Using the Federal Production Tax Credit
to Build a Durable Market for Wind Power in the United States." Ernest Orlando Lawrence
Berkeley National Laboratory LBNL-63583NOV 2007 20 Dec 2008
<http://eetd.lbl.gov/ea/emp/reports/63583.pdf>.
142 Bolinger, Mark, Ryan Wiser, Karlynn Cory, and Ted James. "PTC, ITC, or Cash Grant? An
Analysis of the Choice Facing Renewable Power Projects in the United States." Lawrence
Berkeley National Laboratory. Mar 2009. Web. 8 Dec 2009.
<http://eetd.lbl.gov/EA/EMP/reports/lbnl-1642e.pdf>.
143
20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity
Supply. Rep. July 2008. U.S. Department of Energy.
144
Ibid.
109
Endnotes
145
Ibid.
Ibid.
147
Ibid.
148
Ibid.
149
Ibid.
150
Ibid.
151
Series Compensation: Boosting Transmission Capacity. ABB. 21 Apr. 2009 <
http://library.abb.com/global/scot/scot221.nsf/veritydisplay/837c056a6167747fc1256fda003b4d0
3/$File/SC%20050926copy.pdf >.
152
Competitive Renewable Energy Zones (CREZ) Transmission Optimization Study. Rep. 2
Apr. 2008. ERCOT. 7 Mar. 2009 <http://www.ercot.com/news/presentations/2008/index>.
153
Transmission Projects: At a Glance. Jan. 2008. Edison Electric Institute. 22 Apr. 2009
<http://www.eei.org/OURISSUES/ELECTRICITYTRANSMISSION/Pages/TransmissionProjec
tsAt.aspx>.
154
High voltage (765 kV) projects accessing renewable energy as outlined by EEI are AEP’s
High Voltage Superhighway includes multiple 765 kV segments in the Mid-Atlantic, South and
Midwest regions; AEP, MidAmerican Energy and Westar Energy’s Prairie Wind project in
Kansas; AEP, MidAmerican Energy and OG&E’s Tallgrass Transmission Project in Oklahoma;
ITC’s KETA project from Kansas to Nebraska; and the multi-party Kansas V-Plan in Kansas.
155
HVDC lines (500 kV and 800 kV DC) in progress include National Grid’s Northeast Energy
Link from Maine to Massachusetts; Avista Corp., British Columbia Transmission Corp., and
PacifiCorp’s Canada-Pacific Northwest-California Transmission Project (CNC Project) in
Northern California; and the purchase of the existing Square Butte Electric Cooperative’s HVDC
line between North Dakota and Minnesota by Minnesota Power.
156
Transmission Projects Supporting Renewable Resources. Feb. 2009. Edison Electric Institute.
26 Mar. 2009
<http://www.eei.org/ourissues/ElectricityTransmission/Documents/TransprojRenew_web.pdf>.
157
Interstate Transmission Vision for Wind Integration. American Electric Power. 9 Jan. 2009
<http://www.aep.com/about/i765project/docs/windtransmissionvisionwhitepaper.pdf>.
158
AEP Interstate Project: 765 kV or 345 kV Transmission. 24 Apr. 2007. American Electric
Power. 10 Jan. 2009 <http://www.aep.com/about/i765project/docs/AEPInterstateProject765kVor345kV.pdf>.
159
Osborn, Dale. Remarks at The Joint Coordinated System Planning Process with Results
Transmission Infrastructure. 18 Mar 2009. Midwest ISO. 26 Mar 2009
<http://www.awea.org/events/transmission09/pres/Dale_Osborn_Laptop.pdf>.
160
Federal Energy Regulatory Commission Order 679. Promoting Transmission Investment
through Pricing Reform. 20 Jul. 2006. FERC.
161
“FERC approves incentives for major transmission projects in the West, New England”
Electric Light and Power. 17 Oct. 2008.
<http://uaelp.pennnet.com/display_article/342907/22/ARCHI/none/BUSIN/1/FERC-approvesincentives-for-major-transmission-projects-in-the-West,-New-England>.
162
Ibid.
163
Lyon, Thomas. "Why Rate-of-Return Adders Are Unlikely to Increase Transmission
Investment." The Electricity Journal; 2007: 48-55.
146
110
Endnotes
164
It should be noted that the relationship is not fully linear and therefore further cost adder
increases leads to greater increases in the cost of wind power.
165
Federal Energy Regulatory Commission Order 679. Promoting Transmission Investment
through Pricing Reform. 20 Jul. 2006. FERC.
166
"U.S. Natural Gas Wellhead Price (Dollars per Thousand Cubic Feet)." U.S. Department of
Energy, Energy Information Administration. Aug. 2008. U.S. Department of Energy, Energy
Information Administration. 1 Apr. 2009.
<http://tonto.eia.doe.gov/dnav/pet/hist/n9190us3m.htm>.
167
As one can see in Figure 35, wellhead prices differ from Henry Hub spot prices. Wellhead
prices should always be less than Henry Hub spot prices due to their earlier place in the natural
gas value chain.
168
"U.S. Natural Gas Wellhead Price (Dollars per Thousand Cubic Feet)." U.S. Department of
Energy, Energy Information Administration. Aug. 2008. U.S. Department of Energy, Energy
Information Administration. 1 Apr. 2009.
<http://tonto.eia.doe.gov/dnav/pet/hist/n9190us3m.htm>.
169
"Natural Gas Prices: Definitions, Sources and Explanatory Notes." U.S. Department of
Energy Office of Electricity Delivery & Energy Reliability. U.S. Department of Energy Energy
Efficiency and Renewable Energy. 20 Apr. 2009
<http://tonto.eia.doe.gov/dnav/ng/TblDefs/ng_pri_sum_tbldef2.asp>.
170
"Annual U.S. Natural Gas Electric Power Price." Department of Energy Energy Information
Administration. 24 Dec. 2008. Department of Energy Energy Information Administration. 6 Jan.
2009. <http://tonto.eia.doe.gov/dnav/ng/hist/n3045us3A.htm>.
"Natural Gas Futures Prices (NYMEX)." Energy Information Administration. 11 Mar. 2009.
Department of Energy Energy Information Administration. 12 Mar. 2009
<http://tonto.eia.doe.gov/dnav/ng/ng_pri_fut_s1_d.htm>.
171
EIA - Annual Energy Outlook 2009 Early Release Summary Presentation. U.S. Energy
Information Agency. 17 Dec. 2008
<http://www.eia.doe.gov/oiaf/aeo/aeo2009_presentation.html>.
172
"Annual Energy Outlook 2009 Early Release ." Department of Energy Energy Efficiency and
Renewable Energy. Dec. 2008. U.S. Department of Energy Energy Efficiency and Renewable
Energy. 27 Mar. 2009 <http://www.eia.doe.gov/oiaf/aeo/index.html>.
173
The AEO was published in December 2008 and looks at long-term energy forecasts through
2030. The Short Term Energy Outlook is published monthly, the most recent being March 2009,
and is focused on near-term forecasting.
174
"Short-Term Energy Outlook." U.S. Department of Energy Energy Information
Administration. 10 Mar. 2009. U.S. Department of Energy Energy Information Administration. 1
Apr. 2009 <http://www.eia.doe.gov/emeu/steo/pub/contents.html>.
175
"Short Term Energy Outlook." Department of Energy Energy Efficiency and Renewable
Energy. 10 Mar. 2009. Department of Energy Energy Information Administration. 14 Mar. 2009
<http://www.eia.doe.gov/emeu/steo/pub/contents.html#Natural_Gas_Markets>.
176
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006. U.S. Environmental
Protection Agency USEPA #430-R-08-00515 Apr. 2008 18 Dec. 2008
<http://www.epa.gov/climatechange/emissions/usinventoryreport.html>.
177
Ibid.
111
Endnotes
178
Biddle, Jo. "Obama calls for carbon cap legislation." Yahoo News. 25 Feb. 2009. 16 Mar.
2009 <http://news.yahoo.com/s/afp/20090225/sc_afp/uspoliticsobamaclimate>.
179
Hamilton, Katherine, and Milo Sjardin, Thomas Marcell and Gordon Xu. Forging a Frontier:
State of the Voluntary Carbon Markets 2008. New York, NY: Ecosystem Marketplace and New
Carbon Finance, 2008.
Carbon 2008: Post-2012 is now. Washington DC: Point Carbon, 2008.
Capoor, Karan, and Philippe Ambrosi. State and Trends for the Carbon Market 2008.
Washington DC: The World Bank, 2008.
"Overview." Chicago Climate Exchange. 18 Dec. 2008
<http://www.chicagoclimatex.com/content.jsf?id=821>.
180
The price at the busbar includes generation but not transmission. The busbar is located
between the generator and transformers that are necessary to transfer electricity to the grid.
181
Wiser, Ryan, and Mark Bolinger. Annual Report on U.S. Wind Power Installation, Cost, and
Performance Trends: 2007. Rep. U.S. DOE Energy Efficiency and Renewable Energy. 26 Mar.
2009 <http://eetd.lbl.gov/EA/EMP/reports/lbnl-275e.pdf>.
182
LBNL reports wind electricity prices were $0.045/kWh on average and ranged from $0.030 to
$0.065/kWh in 2007 dollars. Escalating at 3%/year results in an average price of $0.046/kWh
and a range of $0.031 to $0.067/kWh in 2008 dollars.
183
Many transmission planning studies are not comparable to our analysis and therefore will not
be discussed in depth in this section. The DOE 20% by 2030 study examines the transmission
investment necessary to meet a goal of 20% renewables. It does not analyze the benefits of this
scenario or compare to a natural gas or fossil fuel-based reference scenario.
184
Kirby, Brendan. “Direct Testimony of Brendan Kirby for the Wind Coalition and Electric
Transmission Texas, LLC.” Public Utility Commission of Texas, PUC Docket No. 33672. 24
April 2007.
185
More Wind Power and Transmission are Good for Texas. The Wind Coalition.
186
"Executive Summary: Joint Coordinated System Plan 2008 Overview." Joint Coordinated
System Plan. 26 Mar. 2009 <http://www.jcspstudy.org/>.
187
"Executive Summary: Joint Coordinated System Plan 2008 Overview." Joint Coordinated
System Plan. 26 Mar. 2009 <http://www.jcspstudy.org/>.
188
Mills, Andrew, Ryan Wiser, and Kevin Porter. The Cost of Transmission for Wind Energy: A
Review of Transmission Planning Studies. Rep. Feb. 2009. Ernest Orlando Lawrence Berkeley
National Laboratory. 7 Mar. 2009 <http://eetd.lbl.gov/EA/EMP>.
189
Ibid.
190
Mills, Andrew, Ryan Wiser, and Kevin Porter. The Cost of Transmission for Wind Energy: A
Review of Transmission Planning Studies. Rep. Feb. 2009. Ernest Orlando Lawrence Berkeley
National Laboratory. 7 Mar. 2009 <http://eetd.lbl.gov/EA/EMP>.
191
Mills, Andrew, Ryan Wiser, and Kevin Porter. The Cost of Transmission for Wind Energy: A
Review of Transmission Planning Studies. Rep. Feb. 2009. Ernest Orlando Lawrence Berkeley
National Laboratory. 7 Mar. 2009 <http://eetd.lbl.gov/EA/EMP>.
192
Ibid.
193
Ibid.
194
Olsen, David. "Renewables-First Generation/Transmission Projects." Center for Energy
Efficiency and Renewable Technologies. 6 Jun. 2007. Center for Energy Efficiency and
Renewable Technologies. 10 Jan. 2009
112
Endnotes
<http://www.nwenergy.org/publications/reports/miscellaneous-reports-and-studies/OlsenWindTrans.pdf>.
195
Pattanariyankool, Sompop, and Lester B. Lave. "Optimizing Transmission from Distant
Wind Farms." Carnegie Mellon University. 21 Apr. 2009
<http://wpweb2.tepper.cmu.edu/ceic/papers/ceic-08-05.asp>
196
0.056 tCO2/MWh is comparable to integrated gasification with combined cycle (IGCC) coal
plant. This emissions rate is significantly lower than for a combined cycle natural gas plant
(0.361 tCO2/MWh) or a pulverized coal plant (0.830 tCO2/MWh).
197 "Emissions for Coal-Fired Power Plants." Small Business Pollution Prevention Center. Sep
2006. Iowa Waste Reduction Center, Web. 8 Dec 2009.
<http://www.iwrc.org/downloads/pdf/CoalPowerPlantsEmissionsFacts.pdf>.
198
Phadke, Amol. Advanced Coal Wind Hybrid: Economic Analysis. Dec. 2008. Lawrence
Berkeley National Laboratory. 7 Mar. 2009 <http://eetd.lbl.gov/ea/EMS/reports/lbnl-1248e.pdf>.
199
DOE’s “20% by 2030” report has found that the United States has enough spare capacity to
meet the demand for 20 percent of electricity from wind using current spare capacity.
200
Joint Coordinated System Plan 2008. Rep. MISO, SPP, PJM, TVA, MAPP, SERC. New
England ISO, New York ISO.
<http://www.midwestmarket.org/publish/Document/20b78d_11ef44fc9c0_7bad0a48324a/JCSP_Report_Volume_1.pdf?action=download&_property=Attachment>.
201
Milligan, M., and B. Kirby. "Impact of Balancing Areas Size, Obligation Sharing, and
Ramping Capability on Wind Integration." Proc. of WindPower 2007 Conference & Exhibition,
California, Los Angeles.
202
Milligan, M., and B. Kirby. "Impact of Balancing Areas Size, Obligation Sharing, and
Ramping Capability on Wind Integration." 3-5 Jun 2007, Procedures of WindPower 2007
Conference & Exhibition; Los Angeles, CA 22 Apr 2009.
<http://www.nrel.gov/docs/fy07osti/41809.pdf>.
203
Informational Filing to FERC. 03 Apr 2006. Midwest Independent System Operator. 17 Mar
2009.
204
Callaway, Duncan. Meeting. School of Natural Resources and Environment. University of
Michigan. Ann Arbor. 4 March 2009.
205
American Wind Energy Association and Solar Energy Industries Association. Green Power
Superhighways: Building a Path to America’s Clean Energy Future. February 2009.
<http://www.awea.org/GreenPowerSuperhighways.pdf>.
206
Milligan, M., and B. Kirby. "Impact of Balancing Areas Size, Obligation Sharing, and
Ramping Capability on Wind Integration." Proc. of WindPower 2007 Conference & Exhibition,
California, Los Angeles.
207
Bai, Xinggang, et al. Intermittency Analysis Project: Appendix B. Impact of Intermittent
Generation on Operation of California Power Grid. Jul 2007.
GE Energy Consulting. 23 Mar 2009 <http://www.uwig.org/CEC-500-2007-081-APB.pdf>.
208
Bolinger, Mark, Ryan Wiser, and William Golove. Quantifying the Value that Wind Power
provides as a Hedge against Volatile Natural Gas Prices. June 2002. Ernest Orlando Lawrence
Berkeley National Laboratory.
209
Ibid.
210
Berry, David. “Renewable energy as a natural gas price hedge: the case of wind.” The
Electricity Journal 33 (2005).
113
Endnotes
EIA Forecasts and Analysis of Energy Data. U.S. Energy Information Agency. 20 Dec.
2008 <http://www.eia.doe.gov/oiaf/forecasting.html>.
212 Electric Power Annual – Capacity Additions, Retirements, and Changes by Energy
Source. 21 Jan. 2009. U. S. Energy Information Agency. 26 Mar. 2009
<http://www.eia.doe.gov/cneaf/electricity/epa/epat2p6.html>.
213
Data is drawn from JCSP, “Joint Coordinated System Planning: Workshop to Address
Resource Forecasting and Siting,” December 11-12, 2007, Nashville, TN.
<http://www.jcspstudy.org/>. Overnight capital costs are based on EIA 2007 assumptions
<http://www.eia.doe.gov/oiaf/archive/aeo07/assumption/pdf/electricity.pdf> escalated by 30%
and adjusted for inflation based on JCSP stakeholder comments. For the interest rate (R), we
estimated a nominal discount rate of 10% for project developers. This is primarily based on an
informal review of planning studies.
214
Data is drawn from JCSP, “Joint Coordinated System Planning: Workshop to Address
Resource Forecasting and Siting,” December 11-12, 2007, Nashville, TN.
<http://www.jcspstudy.org/>. O&M costs are based on EIA 2007 assumptions
<http://www.eia.doe.gov/oiaf/archive/aeo07/assumption/pdf/electricity.pdf> escalated by 30%
and adjusted for inflation based on JCSP stakeholder comments.
215
Capacity factor data is from JCSP, for the natural gas CC and CT. “Joint Coordinated System
Planning: Workshop to Address Resource Forecasting and Siting,” December 11-12, 2007,
Nashville, TN. <http://www.jcspstudy.org/>. For wind, we analyzed a range of capacity factors
from 25% to 40%.
216
Heat Rates from JCSP, “Joint Coordinated System Planning: Workshop to Address Resource
Forecasting and Siting,” December 11-12, 2007, Nashville, TN. <http://www.jcspstudy.org/>.
Data is drawn from current prices for natural gas in the electricity markets and NYMEX future
markets. Forecasts are drawn from information provided in the EIA’s Annual Energy Outlook
["Annual Energy Outlook 2009 Early Release ." Department of Energy Energy Efficiency and
Renewable Energy. Dec. 2008. U.S. Department of Energy Energy Efficiency and Renewable
Energy. 27 Mar. 2009 <http://www.eia.doe.gov/oiaf/aeo/index.html>] and Monthly Energy
Outlook.
217
Ross, Marc H. “Chapter 5: U.S. Energy Use and Greenhouse Gas Emissions.” Sustainable
Energy Systems (Unpublished). University of Michigan.
218
AC 245kV and 765kV data is from AEP Interstate Project: 765 kV or 345 kV Transmission.
24 Apr. 2007. American Electric Power. 10 Jan. 2009
<http://www.aep.com/about/i765project/docs/AEPInterstateProject-765kVor345kV.pdf>. AC
500kV data is from Communication with Evan Wilcox, American Electric Power, 4 December
2008. DC data is from JCSP. Joint Coordinated System Plan ‘O8. Rep. MISO, SPP, PJM, TVA,
MAPP, SERC. New England ISO, New York ISO.
<http://www.midwestmarket.org/publish/Document/20b78d_11ef44fc9c0_7bad0a48324a/JCSP_Report_Volume_1.pdf?action=download&_property=Attachment>.
219
Joint Coordinated System Plan ‘O8. Rep. MISO, SPP, PJM, TVA, MAPP, SERC. New
England ISO, New York ISO.
<http://www.midwestmarket.org/publish/Document/20b78d_11ef44fc9c0_7bad0a48324a/JCSP_Report_Volume_1.pdf?action=download&_property=Attachment>.
220
Communication with Evan Wilcox, American Electric Power, 19 December 2008.
211
114
Endnotes
221
Olsen, David. "Renewables-First Generation/Transmission Projects." www.nwenergy.org. 06
June 2007. Center for Energy Efficiency and Renewable Technologies. 10 Jan 2009
<http://www.nwenergy.org/publications/reports/miscellaneous-reports-and-studies/OlsenWindTrans.pdf>.
222
Wilcox, Evan. Email communication. American Electric Power, 19 December 2008.
223
Developed based on Figure 1: St. Clair’s Curve in AEP Interstate Project: 765 kV or 345 kV
Transmission. 24 Apr. 2007. American Electric Power. 10 Jan. 2009
<http://www.aep.com/about/i765project/docs/AEPInterstateProject-765kVor345kV.pdf>.
Citing Dulop, Gutman and Marchenko.
224
Wilcox, Evan. “Approximate Loss Calculation” spreadsheet. American Electric Power, 4
December 2008.
225
FLL data courtesy of Evan Wilcox, American Electric Power, “Approximate Loss
Calculation” spreadsheet, 4 December 2008.
226
AC data is from "AEP Interstate Project: 765 kV or 345 kV Transmission." www.aep.com. 24
Apr 2007. American Electric Power. 10 Jan 2009
<http://www.aep.com/about/i765project/docs/AEPInterstateProject-765kVor345kV.pdf>. DC
data is from JCSP: Joint Coordinated System Plan ‘O8. Rep. MISO, SPP, PJM, TVA, MAPP,
SERC. New England ISO, New York ISO.
<http://www.midwestmarket.org/publish/Document/20b78d_11ef44fc9c0_7bad0a48324a/JCSP_Report_Volume_1.pdf?action=download&_property=Attachment>.
227
"Renewable Portfolio Standards." 08 Jan 2009. Pew Center on Global Climate Change. 21
Apr 2009 <http://www.pewclimate.org/what_s_being_done/in_the_states/rps.cfm>.
228
Policy Options for Reducing CO2 Emissions. Congressional Budget Office FEB 2008 18 Dec
2008 <http://www.cbo.gov/ftpdocs/89xx/doc8934/02-12-Carbon.pdf>.
229
"Essential Background." United Nations Framework Convention on Climate Change. United
Nations. 18 Dec 2008 <http://unfccc.int/essential_background/items/2877.php>.
230
"Kyoto Protocol." United Nations Framework Convention on Climate Change. United
Nations. 18 Dec 2008 <http://unfccc.int/kyoto_protocol/items/2830.php>.
231
"Emissions Trading." United Nations Framework Convention on Climate Change. United
Nations. 18 Dec 2008
<http://unfccc.int/kyoto_protocol/mechanisms/emissions_trading/items/2731.php>.
232
Carbon 2008: Post-2012 is now. Washington, DC: Point Carbon, 2008.
233
"Joint Implementation." United Nations Framework Convention on Climate Change. United
Nations. 18 Dec 2008
<http://unfccc.int/kyoto_protocol/mechanisms/joint_implementation/items/1674.php>.
234
"Clean Development Mechanism." United Nations Framework Convention on Climate
Change. United Nations. 18 Dec 2008
<http://unfccc.int/kyoto_protocol/mechanisms/clean_development_mechanism/items/2718.php>.
235 "Climate Security Action: Quick post-mortem on Lieberman-Warner." Grist.org. 07 Mar.
2009 <http://gristmill.grist.org/story/2008/6/6/12557/70075>.
236
Carbon 2008: Post-2012 is now. Washington, DC: Point Carbon, 2008.
237
Ibid.
238
Ibid.
115
Endnotes
239
Capoor, Karan and Philippe Ambrosi. State and Trends for the Carbon Market 2008.
Washington, DC: The World Bank, 2008.
240
Carbon 2008: Post-2012 is now. Washington, DC: Point Carbon, 2008.
241
Ibid.
242
Capoor, Karan and Philippe Ambrosi. State and Trends fo the Carbon Market 2008.
Washington, DC: The World Bank, 2008.
243
Carbon 2008: Post-2012 is now. Washington, DC: Point Carbon, 2008.
244
Ibid.
245
Ibid.
246
Ibid.
247
Ibid.
248
Ibid.
249
Based on total volume and value of the ERU and CER markets in 2007.
250
"Overview." Chicago Climate Exchange. Chicago Climate Exchange. 18 Dec 2008
<http://www.chicagoclimatex.com/content.jsf?id=821>.
251
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