The Colorado Public Utilities Commission, in an April 24 decision, approved a settlement proposed by Xcel Energy‘s (NYSE:XEL) Public Service Company of Colorado and others regarding the company’s Cheyenne Ridge Wind Project, and granted a certificate of public convenience and necessity (CPCN) for the project.
The commission said that it also approves the proposed customer protection mechanism (CPM), generation performance metric, and cost recovery proposal, as well as makes noise and magnetic field reasonableness findings.
As noted in the decision, Public Service in December 2018 filed an application for approval of two CPCNs for the project, which includes 500 MW of wind generation facilities and a 345-kV generation tie line. Public Service in March filed the unopposed comprehensive settlement agreement seeking approval of the project. The commission also said that the settlement was proposed by the company, commission staff, Office of Consumer Counsel, Colorado Energy Office, Colorado Energy Consumers Group, Western Resource Advocates, Climax Molybdenum Company, International Brotherhood of Electrical Workers Local No. 111, and Tradewind Energy, Inc.
The commission noted that it approved company ownership of the 500-MW wind project in the company’s most recent electric resource plan (ERP) application (Proceeding No. 16A-0396E). The commission said that in that proceeding, it also approved the company’s Preferred Colorado Energy Plan Portfolio (CEPP) by a decision issued in September 2018 (ERP Phase II Decision).
Commission approval included retirement of 660 MW of coal-fired generation, as well as the acquisition of 1,131 MW of new wind resources – 500 MW of which will be company owned – 707 MW of new solar resources, 275 MW of new battery storage, and 383 MW of existing gas assets. The commission added that the wind project is the 500 MW of new utility owned wind approved in the ERP Phase II Decision. As part of the ERP Phase II Decision, the commission required Public Service to file a CPCN application for the 500 MW of utility owned wind, and required the company to propose a ratepayer protection mechanism as a part of that application as well as the details of the generation performance metric and cost recovery proposals.
The wind farm would be located on the eastern plains of Colorado and comprised of 225 Vestas V116 turbines and 25 Vestas V110 turbines, the commission added, noting that through the approximately 65-mile, 345-kV generation tie line, the wind farm would interconnect at the new Shortgrass switching station approved in a separate proceeding.
In its application, the company requested that the commission issue a decision by May 1 in order to allow the company time to ensure that it gets the full value of the federal production tax credit (PTC). The commission also said that the estimated cost of construction of the wind project, including the wind farm and generation tie line, is $707m in capital costs, plus an allowance for funds used during construction (AFUDC) of about $38m, for a total of $745m.
The anticipated construction start date begins in July, and the construction period is estimated to be about 18 months, the commission said, adding that the commercial operation date is anticipated by Dec. 31, 2020.
The wind project was bid into the company’s 2017 All-Source Solicitation as a build-own-transfer (BOT) project whereby Tradewind Energy, Inc., would develop and build the project ahead of its commercial operation date. The commission also said that upon commercial operation of the project, the proposal included that Tradewind would sell the project to the company to operate the facility as a utility owned asset. However, during the course of negotiations with Tradewind regarding the terms of the BOT structure, Tradewind and Public Service mutually agreed to pursue a “develop-transfer” structure as an alternative to the BOT structure.
The commission also said that consistent with the directives in the ERP Phase II Decision, Public Service proposes a customer protection mechanism that ensures customers receive the value from the project. The company would track the costs and generation from the wind project on a $/MWh basis to allow comparison with the costs included in the modeling of the wind project in the Phase II bid evaluation process in the ERP Proceeding No. 16A-0396E.
Under the terms of the settlement, the commission added, the point cost for capital costs establishing a presumption of prudence in this proceeding for the project would be $743m, including an AFUDC. Public Service would bring forward the actual point cost for evaluation in the first electric base rate proceeding following the commercial operation of the project.
PTCs related to the actual output generated by the project would be passed to customers through the electric commodity adjustment (ECA) as generated by the project, the commission added, noting that Public Service would credit customers with 100% of the PTC based on the actual output generated by the entire project, at the federal PTC level in effect at the time they are generated.
For purposes of cost recovery and evaluation related to the project, Public Service would lock the deferred tax asset (DTA) carrying costs associated with the project consistent with the annual amounts shown in the “highly confidential settlement exhibit A.” In any year that there is a DTA, the company would not recover more than the lower of the DTA annual cap amount reflected in “exhibit A” or the actual DTA carrying cost amount, the commission added.
The customer protection mechanism represents the cumulative $/MWh on a net present value basis back to 2016 consistent with the modeling in the ERP Proceeding No. 16A-0396E. The commission also said that the standard is $20.61/MWh, based on a return on equity of 9.83%, capital structure of 56% equity and 44% long-term debt, as well as 6.78% discount rate as modeled in the ERP.
The settlement prescribes reporting and rate recovery requirements for “Timeframe 1,” which represents commission approval to commercial operation; “Timeframe 2,” which represents commercial operation to the effective date of new rates from base rate proceeding, and “Timeframe 3,” which represents from the effective date of new rates through the end of the project’s useful life.
The commission added that during Timeframe 1, for instance, the settlement proposes that Public Service would provide quarterly construction reports. The company would forgo cost recovery, as well as a current return on CWIP, until the project is in commercial operation, and would instead accrue interest at the AFUDC rate.
The commission also said that there are many provisions in the settlement that provide significant protections to customers and result in a reasonable overall balance, including that the settling parties agree that the point cost for capital costs for the project would be $743m, inclusive of AFUDC. The commission further noted that the settlement provides that PTCs related to the full actual output generated by the wind project would be passed to customers through the ECA, effectively placing the risk on Public Service for failure to qualify for credits at the 100% level due to construction delays.
Among other things, the commission said that it approves the settlement without modification.