Eastern Interconnection studies natural gas/electric system interface
Phase II of transmission study finds that a combined policy scenario would result in $978 billion of capital investment in 2030
The U.S. Department of Energy (DOE) has asked the Eastern Interconnection Planning Collaborative (EIPC) to undertake a study of the natural gas/electric system interface to supplement the transmission analysis it recently completed, EIPC Executive Director David Whitely told TransmissionHub on March 20.
"In terms of the interface between the gas and electric systems, I think it's just now becoming a key issue, and that is because of the projections on demand in terms of electric resources for natural gas," Whitely said. "There is a fundamental shift that gas is now projected to be one of the most dominant — if not the dominant — fuel sources of the future."
EIPC stakeholders are still determining the parameters for the natural gas/electric interface study, but it will have more of a fuel than a generation focus, Whitely said. EIPC expects to have developed the new study's parameters in the next month, he said. At that time, EIPC will issue a request for proposals for consulting services to do the analysis.
"In Phase I, we made a simplifying assumption that natural gas would be available," Whitely said. "What we didn't say was in one of those scenario ... was there really enough fuel or pipeline capacity out there, and how would it respond to generation demand?"
EIPC at the end of 2012 completed Phase II of its study to determine what transmission would be needed under three different future scenarios. It completed the first phase of the study at the end of 2011.
Unlike Phases I and II of the EIPC analysis, the natural gas/electric interface study will not focus on the infrastructure needs that may be driven by potential policy scenarios.
"I think it'll be much more focused on what we know at this point [projecting] into the future and how the gas system will interact with the electric system, rather than looking at different policy alternatives, which are much more hypothetical," Whitely said.
Today, the natural gas pipeline system is structured such that pipeline capacity will expand in response to demand from firm customers willing to pay for firm service. In contrast, the nature of the electric system is to respond to fluctuating consumer demand.
"Part of what goes on and the reason why this is so interesting is because the traditional model right now is that the pipelines are expanding for firm service, whereas electric generators will be calling on the natural gas system for non-firm service," Whitely said.
The study is expected to take up to a year and a half, Whitely said. No additional funding, which has been provided by DOE under the American Recovery and Reinvestment Act, will be needed for this third leg of the study, Whitely said.
The Phase II analysis, which was sent to DOE in December 2012, will remain in draft form until the natural gas/electric interface portion of the analysis is complete, Whitely said.
For Phase II of the EIPC study, EIPC studied transmission and production cost analyses for the Eastern Interconnection for three future scenarios: a nationally implemented federal carbon policy, combined with increased energy efficiency and demand response initiatives (Scenario 1); a regionally implemented national renewable portfolio standard (RPS) (Scenario 2); and business as usual (Scenario 3).
For all three scenarios, EIPC assumed that new natural gas plants would be placed at the sites of deactivated coal plants, reducing the need for transmission, but did not take into account the locations and capacities of natural gas pipelines.
"We thought we were going to get a bigger build-out for Scenario 1 than 3, but what's interesting is how much bigger and what the costs are ... to develop the transmission," Whitely said.
In 2010 dollars, Scenario 1, which required the largest transmission buildout, was estimated to cost about $978 billion; Scenario 2, which required a moderate transmission build-out, was estimated to cost about $772 billion; and Scenario 3, which required the smallest amount of change, nearly $285 billion. These costs represent "overnight" capital investments that would need to be made in the single year of 2030.
"The transmission planning analysis is a strategic snapshot in time, utilizing year 2030," EIPC said in the study. "Traditional transmission planning is much more incremental and an analysis would typically be done for five and ten years out rather than twenty years out into the future."
The estimates include costs for production, carbon dioxide, energy efficiency, demand response, generation and transmission voltage support, constraint relief and generation interconnection, among others.
"The constraints identified were eliminated with the addition of transmission elements," EIPC said in the study. "These elements range from transformers to high voltage direct current HVDC ... and extra high voltage alternating current (AC) transmission lines that are hundreds of miles long."
Scenario 1 eliminated virtually all coal plants, and included 152 MW of demand response and over 215 GW of wind generation in Nebraska, the Midwest ISO (MISO) and Southwest Power Pool (SPP) regions.
"Scenario 1 was the most challenging from a transmission planning perspective because of the large amount of additional transfers that needed to occur in the scenario, particularly from MISO-West to [PJM Interconnection] and from Southwest Power Pool to PJM," EIPC said in the study.
Building out the AC system was found to be insufficient, resulting in the need to add more transmission until the identified constraints eased.
"Six 500 kV HVDC lines, each capable of carrying 3,500 MW, were needed to reliably achieve the required transfers," according to the study. "In addition, there were still significant amounts of 765 kV, 500 kV and 345 kV AC lines that were needed to maintain reliability."
More than 4,300 miles of existing transmission would also need to be reconductored or upgraded under Scenario 1.
For Scenario 1, the largest amount — 64 percent — of installed capacity was from wind, natural gas combined cycle plants and demand response, while the largest amount of generation — 87 percent — came from nuclear power plants, combined cycle and wind.
For Scenario 2, the nationally implemented RPS under which 30 percent of the nation's demand would be met with renewable generation, EIPC determined the most significant need was for a 765-kV line running east from Illinois to Ohio and Pennsylvania, to move renewable generation from the western to eastern part of PJM Interconnection. In addition, more than 2,600 miles of lines needed to be upgraded.
"In Scenario 2, the bulk of the constraints occur in the MISO and SPP regions due to the amount of wind being sited in those areas," EIPC said, adding that there were also some constraints in the southeast states.
The largest amount of installed capacity, or 57 percent, was from wind, natural gas peaking plants and coal plants, while the largest amount of generation, or 70 percent, came from coal, nuclear and wind.
This was article originally published by TransmissionHub. It was republished by permission.