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Study estimates low-carbon future would be costly


From the May 3, 2013 issue of Public Power Daily

Originally published May 3, 2013

By Robert Varela
Editorial Director

The infrastructure needed for a low-carbon future would be costly, according to a new study of the Eastern Interconnection by the Eastern Interconnection Planning Collaborative (EIPC) for the Department of Energy. The study of the costs of three different public policy scenarios through 2030 estimated that the greenest (with reduced carbon emissions and a 30 percent renewable portfolio standard) would entail capital costs of $978 billion, compared with $285 billion for a "business as usual" scenario. Capital costs for a scenario with a 30 percent RPS but no carbon limits would be $772 billion, the study estimated.

The EIPC study did not attempt to study the impact on retail electricity rates, nor did it analyze any societal or economic benefits that would be derived from the clean energy scenario.

For scenario one (the greenest), EIPC assumed an economy-wide reduction in carbon emissions of 42 percent from 2005 levels by 2030 and 80 percent by 2050; a 30 percent RPS; and "significant deployment of energy efficiency measures, demand response, distributed generation, smart grid and other low-carbon technologies." 

Coal-fired generation would be virtually eliminated under scenario one, with most of that loss being offset by wind (272 gigawatts), demand response (152 GW) and nuclear (140 GW), the study said. Combined-cycle natural gas plants would account for 208 GW of capacity. Peak demand was estimated to be 565,012 MW and total energy to be 2,979 terrawatt-hours.

In solving the significant constraints that occurred in scenario one, the planning authorities found that building a larger AC system would not be sufficient, the study said. Six 500-kV HVDC lines, each capable of carrying 3,500 MW, would be needed to achieve the required transfers, in addition to significant amounts of 765-kV, 500-kV and 345-kV AC lines. Over 4,300 miles of existing transmission lines, ranging from 115-kV to 345-kV, would need to be reconductored or upgraded, the study said.

The major capital costs for scenario one would be $868 billion for generation; $50 billion for transmission to interconnect generation; $48 billion for transmission to relieve constraints; and $7 billion for pollution retrofit.

Scenario two (30 percent RPS) would require a new 765-kV transmission line from Illinois to Pennsylvania, plus new lines to connect wind power, EIPC said. Wind would account for the most capacity, 203 GW, followed by peakers, 192 GW; coal, 186 GW; combined-cycle gas, 158 GW; and nuclear, 112 GW. Demand response would contribute 69 GW of capacity. Estimated peak demand would be 673,108 MW and total energy, 3,261 TWh.

The major capital costs under scenario two would be $679 billion for generation; $54 billion for transmission to interconnect generation; $13 billion for transmission to relieve constraints; and $20 billion for pollution retrofit.

For the third scenario (business as usual), the study assumed continuation of forecasted load growth, existing RPS requirements and Environmental Protection Agency regulations as proposed and understood in the summer of 2011. An additional 765-kV line would be needed in Virginia/West Virginia and 345-kV lines would be needed in a few regions, the study said. Peak demand would be an estimated 690,492 MW and total energy would be 3,687 TWh.

Under this scenario, coal would be the major source of generation capacity at 208 GW, followed by combined-cycle gas, 197 GW; peakers, 191 GW; nuclear, 113 GW; and wind, 79 GW. 

Capital costs for the business-as-usual scenario included $242 billion for generation, $7 billion for transmission to interconnect generation; $8 billion for transmission to relieve constraints; and $20 billion for pollution retrofit.

Estimated operating and maintenance costs for the three scenarios in 2030 were relatively close: $150 billion for scenario one, $146 billion for scenario two and $155 billion for scenario three. The major O&M cost for scenario one was $45 billion for carbon dioxide costs, which offset lower fuel costs for that scenario.

The study is available on EIPC’s website.

EIPC to look at gas-electricity interface
"DOE has requested that we continue the project to investigate if sufficient natural gas infrastructure exists to support the growing use of natural gas for power production as well as the associated impacts on electric transmission planning," said Stephen Whitley, president and CEO of the New York Independent System Operator and chair of the EIPC Executive Committee. 

The effort to analyze the interface between the natural gas delivery system and the electric transmission system has just begun and supplements its ongoing work, EIPC said. The collaborative said it will continue its Eastern Interconnection-wide transmission planning activities in 2013, beginning with a comprehensive update of its Eastern Interconnection power flow model for the years 2018 and 2023 based upon the regional plans of its members. The natural gas study contemplates investigating the increasing reliance on natural gas for generating electricity, EIPC said. There are concerns regarding the future ability of the natural gas infrastructure to meet the coincidental requirements of gas utilities and generators under various conditions, especially during the winter heating season. The study will focus on regions of particular concern, including the Northeast and Midwest regions of the Eastern Interconnection, EIPC said. 

EIPC, formed in 2009, represents two dozen planning authorities and utilities from 39 states in the Eastern United States and two provinces in Canada. 


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Senior Vice President, Publishing 
Jeanne Wickline LaBella
202/467-2948
JLaBella@publicpower.org

Editorial Director
Robert Varela
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RVarela@publicpower.org

Editor, Public Power Daily
Jeannine Anderson
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JAnderson@publicpower.org

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