Entergy seeks okay of extended power purchase deal with Occidental’s Taft cogen

The Louisiana Public Service Commission on Dec. 7 named an administrative law judge to handle the Nov. 15 application by Entergy Louisiana LLC (ELL) for approval to amend and extend a power purchase agreement (PPA) with Occidental Chemical Corp., which was approved by the PSC in 2008.

This PPA extension was negotiated following an unsolicited offer from Oxy in September 2016. This application requests certication that ELL’s purchase of up to 520 MW (winter rating) of capacity and associated energy for a ten-year term beginning in 2018 from Oxy’s Taft Cogeneration Facility in Taft, Louisiana, serves the public convenience and necessity.

ELL noted that it has a substantial overall long-term need for base load and core load-following generation capacity. This need persists notwithstanding its completion of the Ninemile 6 combined cycle gas turbine (CCGT) facility, acquisition of Union Power Station Power Blocks 3 and 4 in Arkansas, and anticipated construction of the proposed St. Charles Power Station and Lake Charles Power Station CCGT projects.

ELL also needs base load and core load-following resources to satisfy a projected energy deciency. Without such resources, the Company will be in the position of having a larger percentage of its Midcontinent ISO energy purchases unhedged by offsetting energy margins that can be obtained by resources such as Oxy’s Taft Facility. Tithout its supply plan additions, ELL projects that by 2020 it will have a need for approximately 2,500 MW of base load and core load-following generation. With its commercially-proven technology and a relatively efficient heat rate, Oxy’s Taft Facility is projected to produce energy at a cost lower than the expected market clearing prices for energy required to serve ELL’s load, and customers will benefit from the cost/price difference.

Entering into the Amended PPA also keeps the Taft Facility committed to serve load in the supply-constrained Amite South planning region through 2028. Amite South contains concentrated electric loads represented by the greater New Orleans area and the petrochemical industry located along the Mississippi River. The Amite South region is referred to as a “load pocket” because it is an area of the transmission system that, due to concentrated loads and geographic features that limit transmission imports, must be served, at least in part, by local generation.

The Amended PPA would extend the term of the Existing PPA with Oxy by ten years to 2028. Under the Amended PPA, ELL will purchase between 480 MW (summer) and 520 MW (winter) of capacity, energy, and other products from Oxy’s Taft Facility. ELL will purchase three capacity and energy products under the Amended PPA — Product A, Product B, and Product C. Product A will supply base load capacity and energy, Product B will supply core load-following capacity, and Product C will supply peaking capacity.

The terms of the Amended PPA are essentially the same as the Existing PPA, except for pricing and certain other items negotiated between the parties. The Amended PPA was negotiated following an unsolicited written offer from Oxy in September 2016. The Unsolicited Offer was received after completion of the 2015 RFP for Long-Terrn Developmental and Existing Capacity and Energy Resources (“2015 ELL RFP”) conducted by Entergy Services on behalf of ELL. The two proposals that were selected in that RFP were ELL’s self-build proposal for the Lake Charles Power Station (certication for which is currently pending at the PSC) and a PPA for capacity from a third-party generating facility.

The Dec. 7 order said this case has been assigned to Administrative Law Judge Joy Guillot. A status conference in this proceeding has been scheduled for Dec. 19.

This retained capacity helps compensate for three unit shutdowns

John P. Hurstell, employed by Entergy Services as Vice President of System Planning, supplied supporting testimony for the Nov. 15 application that outlined plans to shut some existing capacity on the ELL system, which helped drive the need for the extended Taft PPA. He explained the analyses undertaken that support recent determinations that deactivation of Willow Glen Units 2 and 4 and Sterlington Unit 7B were the lower cost option for customers.

ELL’s generation fleet includes a number of gas-fired steam units ranging in age from 37 to 65 years of service, commonly referred to as “legacy gas generation.” These units cannot stay in service in perpetuity and assumptions must be made regarding when those units will no longer be available for service, Hurstell noted.

Willow Glen Unit 2 is a 179 MW (installed capacity or “lCAP”) unit that has operated for over 50 years, and Willow Glen Unit 4 is a 483 MW (ICAP) unit that has operated for over 40 years. As of 2008, the deactivation date assumption for both Willow Glen units was 2017. A Plant Condition Assessment completed by URS, an independent engineering firm, 2010 estimated that Willow Glen Units 2 and 4 would, at that time, require investments of approximately $60 million and $50 million, respectively (excluding investment in common facilities) to continue to operate another 10 years.

In 2013. an economic screening analysis indicated that continued investment in Willow Glen Units 2 and 4 at levels reflected in the 2010 URS report was comparable to other market alternatives for capacity, and the assumed deactivation date was extended to 2027 for planning purposes pending further development of preliminary estimates of projected spend to sustain the units beyond 2017. The company thereafter developed a comprehensive Reliability/Sustainability (“R/S”) program to sustain the availability of Willow Glen Units 2 and 4 through 2027 based on the projects identified in the 2010 URS feasibility study updated to reflect then-current unit condition, then-current estimates of work scope and costs, and a contingency to account for unknown or higher than expected costs.

By 2015, that detailed assessment of projected R/S spending determined that the condition of each unit would require significant spending over the next three years to keep the two units in service through 2027. The cost estimate for total R/S spend ranged from approximately $222 million to $334 million, with the higher end of the range dependent on whether the scope of R/S projects would include environmental compliance costs of roughly $100 million. A new analysis indicated that deactivation in 2017 was more economic. Based on this analysis, the Entergy Operating Committee approved deactivation of Willow Glen Units 2 and 4 effective June 1, 2016, and submission of an Attachment Y Notice to MISO. The decision to deactivate Willow Glen Units 2 and 4 is pending review in another commission docket.

Sterlington Unit 7B is a 44-MW (ICAP) unit located in Sterlington, Louisiana, that has operated over 40 years. Sterlington Unit 7B experienced a forced outage caused by damage to several components and went out of service in March 2014. It has been reported as being in forced outage to both the North American Electric Reliability Corp. (“NERC”) and MISO since that time and, beginning with the MISO Planning Year (“PY”) 2015/16 Planning Resource Auction, the rating of Sterlington 7 (Units 7A and 7C) reflected the forced outage of Unit 7B. The unit had a then-assumed deactivation target in 2022. The Entergy Operating Committee approved a recommendation to deactivate Sterlington Unit 7B and place it in a “mothballed” status effective Jan. 1, 2016. Putting the unit in “mothballed” status allowed the company to suspend for economic reasons the operation of Unit 7B for up to 36 cumulative months and preserve transmission interconnection service during this period.

Because Sterlington Units 7A and 7C remain operable (effectively rendering the Sterlington 7 resource a 1×1 CCGT), the decision was made to preserve the optionality to repair Unit 7B through the use of a suspension of service for up to three years. Preserving transmission service offers an option during the suspension period to repair and return Unit 7B to active status and operate Sterlington Unit 7 in a 2×1 configuration if it is determined to be economic to do so. However, there are no plans to repair Unit 7B, Hurstell added.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.