Dual-fuel capability "has a much lower cost for a new combined-cycle plant” than firm natural gas transportation for power generators in the Eastern Connection, and for simple-cycle plants the difference is even more pronounced, according to a study summarized in the last of eight Gas-Electric Coordination Quarterly Update reports issued by FERC Thursday.
With few exceptions, the incremental cost of dual-fuel capability for individual generators appears to be much less than the incremental cost of firm transportation on natural gas pipelines as a direct cost strategy to achieve fuel assistance for electric reliability within the Eastern Connection, according to preliminary results in a recently released Eastern Interconnection Planning Collaborative (EIPC) final Target 4 draft report. The primary reasons for those conclusions are:
Existing pipelines in constrained locations are typically fully subscribed, thereby requiring a pipeline to add expensive new facilities to serve gas-fired generation plants;
Generators behind local distribution company gate stations would be expected to bear the cost of local facility improvements to ensure year-round service in addition to mainline improvements from the producing basin in the local system;
The avoided cost of non-firm transportation is not sufficiently high in most constrained locations to significantly reduce the net cost of incremental firm transportation service;
The capital charges, inventory carrying charges and incremental fixed operations and maintenance associated with dual-fuel capability are comparatively low; and
Structural change in the distillate oil market has and will continue to simplify the logistics of ultra-low sulfur diesel replenishment during cold snaps or outages or other contingencies.
The report concludes that despite the ostensible economic superiority of the dual-fuel capable solution to the challenge of maintaining fuel assurance, there may be other commercial reasons that would induce power generators to invest in firm pipeline transportation, including different operating characteristics, margin recoupment from the redeployment of firm capacity rights, and the ability to source gas at a lower price and more stable trading point under firm pipeline service.
EIPC's final Target 2 draft report, which evaluates the adequacy of natural gas infrastructure in 2018 and 2023 to meet expected core load and non-core gas-fired generation requirements on Winter Peak Days and Summer Peak Days, was due to be released in October, but it has been delayed. Target 3 -- a contingency analysis -- is scheduled to be completed in the first quarter of 2015, according to Federal Energy Regulatory Commission staff.
The six participating planning authorities of EIPC -- ISO New England, New York ISO, Ontario's Independent Electric System Operator, Midcontinent ISO, PJM Interconnection and the Tennessee Valley Authority -- issued a request for proposals (RFP) to conduct the Gas-Electric System Interface Study in August 2013 (see Daily GPI, Aug. 5, 2013).
The RFP came three months after EIPC said it had completed a transmission analysis as part of an electric system transmission planning effort funded by the U.S. Department of Energy, and the government agency asked EIPC to look into whether the country's natural gas infrastructure is up to the challenges posed by increased gas-fired power generation (see Daily GPI, April 30). Study results, due to be completed by mid-2015, are expected to help improve gas-electric coordination to ensure electric system reliability.
A separate study, released earlier this month by the Eastern Connection States Planning Council and the National Association of Regulatory Utility Commissioners, concluded that investment in mainline natural gas pipelines is the largest component of infrastructure expenditures in the natural gas sector, followed by lateral pipelines, processing and storage equipment.
"The majority of the infrastructure buildout is driven by rapidly expanding production plays in the Northeast (Marcellus and Utica shales) and the Southwest (Eagle Ford and Haynesville shales), with the largest concentration of infrastructure investment needed in Pennsylvania and Louisiana," FERC staff said.
The study found that total infrastructure costs for the natural gas and power sectors could be about 1.5% lower if they co-optimize on siting and fuel infrastructure expansion.
FERC commissioners directed staff to compile the quarterly gas-electric coordination reports two years ago as part of a response to concerns aired during a series of regional conferences on coordination issues in the Mid-Atlantic, New England, Southeast, West and Midwest regions (see Daily GPI, Nov. 19, 2012).