Entergy Louisiana LLC (ELL) has been working lately to meet a gaping long-term capacity need, including the 2011 acquisition of the gas-fired Power Block Two of the Acadia Energy Center and the ongoing construction of a new combined-cycle gas turbine facility at the Ninemile Point Station in Jefferson Parish.
Several ELL officials, including President and CEO Phillip May, provided Feb. 15 testimony to the Louisiana Public Service Commission in a new rate case. ELL is a unit of Entergy Corp. (NYSE: ETR).
The company in April 2011 purchased the 580-MW combined-cycle gas-turbine (CCGT)-equipped Power Block Two from Acadia Power Partners LLC, an independent power producer, for approximately $300m.
ELL expects that it will need to construct a new unit about every five years between 2012 and 2031 in the Amite South Region and a new unit about every three years between 2019 and 2031 in the Central Region, May noted in the Feb. 15 rate testimony. The capital requirements to build this capacity range from $4.7bn to $7.1bn, depending on actual load growth in Amite South. This need is largely driven by the replacement of existing, aged capacity that will need to be retired, and system load growth. Amite South, due to technical considerations, tends to need a high level of locally-sited generating capacity.
A gas-fired, $721m Ninemile Point addition, called Ninemile 6, is due to meet the need in Amite South out to about 2020. This is a 550-MW combined-cycle gas turbine facility, which last year got a commission approval and is expected to enter service by April 2015.
Entergy told the commission, in the Ninemile 6 approval proceeding, that the new unit was proposed to provide generation needed in the Amite South planning region, identified as the area east of the Baton Rouge metropolitan area to the Mississippi state line and south to the Gulf of Mexico, and particularly within the Downstream of Gypsy (DSG) sub-region within Amite South. They said the project was needed to provide an efficient generating unit to meet reliability needs within Amite South and particularly DSG and to reduce reliance on existing aging gas-fired generation, in addition to adding a resource to meet long-term needs for load-following capacity.
The Feb. 15 testimony from May noted that the average age of the existing Amite South capacity is 42 years and that those aging units are: Buras 8, Little Gypsy 1-3, Michoud 2-3, Ninemile 3-5 and Waterford 1-4. Notable is that Waterford 1-4 are by far the youngest of these units, with the oldest less than 40 years old and the newest, Waterford 4, a little over 20 years of age. The oldest of these Amite South units is Ninemile 3 at nearly 60 years, with Ninemile 4 and 5 at around 40 years of age or slightly older.
The range of the ELL resource need over the next 20 years is 2,100 MW to 4,600 MW of new capacity, with a reference case need of 2,660 MW, May wrote. The assumption is that the need would be met with about a 50-50 combination of combined-cycle and simple-cycle gas turbine additions.
The Central Region is assumed to be good until about 2019 in terms of existing capacity, but then a new generator about the size of Ninemile 6 would be needed in that region every three years after that out to 2031.
Buying at least some of this needed new capacity via power purchase agreements is feasible, though that does raise some issues with debt rating agencies that count PPAs as a form of long-term financial obligation, May noted.
In supporting Feb. 15 testimony filed by ELL, Michael Tennican of NERA Economic Consulting said it may be better for the utility to build much of this new capacity itself.
“Power purchases have in the past and might in the future reduce the need for ELL to invest in its own power plants,” Tennican wrote. “Nonetheless, I think it is prudent for ELL to be prepared to build the generation capacity needed to meet the requirements stemming from load growth, reliability standards and plant retirements. It is not certain that ELL will be able to renew existing power purchase agreements, much less contract for power from new sources. I note that, given the sub-investment grade credit ratings of many merchant generators and prospects for further downgrades, any new capacity might be more costly for merchant generators to finance than ELL itself.”
Tennican noted that given the dominance of gas-fired and nuclear power plants in the ELL generation mix, the utility isn’t as vulnerable to new environmental regulations as utilities with more coal-fired capacity, but significant environmental spending by the utility is still likely.