Midcontinent Indep. Sys. Operator, Inc., 154 FERC ¶ 61,059, at P 14 (2016); Calpine Energy Serv., Inc., 154 FERC ¶ 61,082, at P 12 (2016); New York Power Auth., 152 FERC ¶ 61,058, at P 22 (2015). The Xxxxxxxxx Xxxxxx-Xxxx A. Xxxxx Xxxxx 4, 2024
Midcontinent Indep. Sys. Operator, Inc., 155 FERC ¶ 61,211, at P 18 (2016). 38 Order No. 827, 155 FERC ¶ 61,277 at P 1. 39 Order No. 827, 155 FERC ¶ 61,277 at P 39 (“measuring the reactive power requirements at the high-side of the generator substation reasonably balances the need for PSCo’s statement that its interconnection studies indicate that the reactive support upgrades are needed for reliability does not, in and of itself, establish that it is necessary to allocate the costs of the upgrades to transmission customers. Additionally, XXXx cites to a paragraph in Order No. 807 indicating that where the generation function of the public utility transmission provider is the owner of an interconnection customer’s interconnection facility, it is appropriate, in the event of a third-party request, for the request to be processed pursuant to its affiliated public utility transmission provider’s OATT.40 However, PSCo has not explained how its provision of interconnection service over the Rush Creek Gen-Tie Line, as required by Order No. 807, creates a unique case that warrants treating upgrades to interconnection facilities as network upgrades. Accordingly, for these reasons, we reject the Xxxxx LGIA. The Commission orders: The proposed Xxxxx LGIA is hereby rejected, as discussed in the body of this order. By the Commission. ( S E A L ) Xxxxxxxx X. Xxxx, Secretary. reactive power for the transmission system with the costs to non-synchronous generators of providing reactive power” (emphasis added)).
Midcontinent Indep. Sys. Operator, Inc., 148 FERC ¶ 61,057 at P 9 (2014) (finding MISO’s Tariff unjust and unreasonable because it did not allow MISO to compensate System Support Resources for their full cost of service) (“Ameren”). 63 See Xxxxx Testimony at 16-17. 64 See Xxxxxx Testimony at 16-17. 65 See, e.g., GenOn, 149 FERC ¶ 61,218 at PP 35-36. See also Xxxxxx Testimony at 16-17; 18 CFR Parts 35, 101 and 141 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, 139 FERC ¶ 61,245 at P 33(2012) (citing Central Maine Power Company, 56 FERC ¶ 61,200, at 61,818-19 (1991) (“[T]he Commission has long permitted cost-of- service sellers to propose cost-justified ceiling rates….”)).
Midcontinent Indep. Sys. Operator, Inc., 148 FERC ¶ 61,136 (August 21, 2014) (“August Order”). Xxx. Xxxxxxxx X. Bose April 20, 2015 following the expiration of the Original SSR Agreement, subject to review of feasible alternatives to the continued SSR designation.7 Following the stakeholder discussions described below, XXXX worked with WPEP and the MISO Independent Market Monitor (“IMM”) to negotiate and develop an appropriate SSR Agreement. The terms of the Original SSR Agreement, as adjusted in the compliance filing on August 27, 2014, formed the starting point for negotiation of the terms and conditions for the Restated SSR Agreement. WPEP agreed to a twelve (12) month SSR Agreement for the period between April 16, 2015 and April 15, 2016. WPEP has agreed to continue operating White Pine 1 on and after April 16, 2015.
Midcontinent Indep. Sys. Operator, Inc., 148 FERC ¶ 61,136 (August 21, 2014) (White Pine 1 SSR agreement) at P 31. 14 Tariff Section 38.2.7 (“Evaluation of SS Unit Application”). 15 SSR Order at P 80; see attached exhibit, Attachment Y Study Report, Section VII Xxx. Xxxxxxxx X. Bose December 30, 2014 In the course of reviewing feasible alternatives, MISO held a West Technical Study Task Force stakeholder meeting regarding White Pine 2 on June 23, 2014. The reliability issues raised by retirement of White Pine 2 were reviewed, and stakeholders were asked to provide input regarding feasible alternatives that could address the reliability issues. The end result of this meeting was the absence of any significant debate over the near-term need for the SSR status for White Pine 2. Stakeholders at the West Technical Studies Task Force (WTSTF) meeting in June considered generation re-dispatch, available reconfiguration options, and demand response requirements. ATC has submitted a proposed MTEP15 Project 8089 to rebuild the Lakota – Mass 69 kV transmission facilities, with an expected in-service date of December 1, 2020.16 No further significant feedback from stakeholders was received to help resolve these matters regarding substitutes for an SSR arrangement for White Pine 2. In review of the generation alternatives, XXXX explained that the only other generation that was available to be committed to support the load pocket was the Portage CT Unit that is designated “Emergency” and cannot be used to support ATC planned outages. In previous SSR alternatives discussions for White Pine 1, XXXX had discussed with the owner of Portage whether that unit could be made available as an alternative to the designation of White Pine Unit No. 1 as an SSR Unit. The owner of Portage declined due to the uncertainty in usage requirements without more definite outage schedules from ATC. The owner of Portage contacted MISO on October 3, 2014 with an interest in making the Portage CT available for economic commitment. In a call on November 12, 2014, the owner provided additional information on the capability and limitations of the Portage unit. To preserve the remaining life of the equipment, XXXX proposed an agreement for limited use of the unit. That proposal, or a modification of such an agreement that would make Portage more available, remains under discussion. Without such a firm commitment for use of Portage, MISO is proceeding to with the White Pine 2 SSR Agreement while continuing to consider the...
