The Public Service Co. of Colorado unit of Xcel Energy (NYSE: XEL) is improperly proposing to factor in coal plant cycle costs when it comes to whether it buys wind power for its system, said Randall Falkenberg, a utility regulatory consultant and President of RFI Consulting.
The Interwest Energy Alliance filed June 4 testimony from Falkenberg at the Colorado Public Utilities Commission in a proceeding that involves a review of PSCo’s 2011 Electric Resource Plan (ERP). The plan itself, which will result in a solicitation for new power suppliers, was first filed with the commission in October 2011. In that plan, the utility uses a Coal Cycling Study covered by a report entitled “Wind Induced Coal Plant Cycling Costs and the Implications of Wind Curtailment for Public Service Company of Colorado.”
The utility believes there are additional costs, not considered in its wind integration study, called coal cycling costs. Falkenberg said the company believes that if additional wind resources are added to its system, then there will be times when the amount of wind capacity on line will force output reductions from its coal plants. This will theoretically cause increased O&M expenses and capital expenditures which are not factored into its planning process in any other way. PSCo also includes costs related to curtailment of wind generation as part of the wind induced cycling costs in its modeling.
Coal plants are cycled routinely to respond to changes in system load, output levels of other plants, transmission constraints or for reserve purposes, Falkenberg noted. “There is nothing unique about wind generation that causes cycling costs to occur,” he added. “The Company recognizes this fact in the way in which it developed its study, by attempting to compute the cycling costs associated with wind as well as those resulting from the other system resources.”
PSCo clarified the ultimate purpose of the Coal Cycling Study in its response to an inquiry, with that response reading as follows: “Coal plant cycling costs will be added to wind bids and other must-take type resources…. As described for CPUC Staff in Discovery Request No. CPUC7-10, both the cycling and curtailment components from the Coal Plant Cycling study will be applied to wind resources (and other must-take type resources) during initial economic screening of bids.”
By the way, Falkenberg wrote that the use of the term “coal cycling costs” is a bit of a misnomer. The study really concerns what are often called “load following costs,” which are costs related to reducing the output of a coal unit, rather than cycling costs which result from taking it offline.
“If used at all, the coal cycling cost adders should be done in a more even handed manner than proposed by the Company,” Falkenberg testified. “No resources class should be singled out for a cost penalty while the contribution of other resource classes to the same problem is ignored. If the supporting analysis is sound, accurately implemented and based on reliable data it should be applied to all resource classes in future planning activities based on cost adders specific to each resource class. In the case of coal cycling costs, the Company’s own model shows that nearly any type of resource acquired, whether a new thermal plant or a wind project will increase coal cycling costs. Consequently, application of the study results to wind (or other ‘must take’) projects alone would be inappropriate.”
Falkenberg added that while combined cycle gas plants have become the “default” option for many utilities, even these plants bring their own set of unique problems. “For example, combined cycle plants may have to run at minimum loadings overnight or during low demand hours when they are otherwise not needed,” he explained. “Typically combined cycle plants have a six to eight hour minimum down time, and thus may not be shut down on demand if load drops or market prices dip for a few hours. This increases the likelihood of coal cycling and should be considered in planning as well. Further, gas plants frequently give rise to hedging costs and mismatches between the quantity of gas acquired, and the amount actually used. Finally, coal plants require a coal inventory be maintained, the cost of which would probably be reduced as wind energy increases on the system. The resulting costs and benefits of such issues are frequently ignored in the planning process. There is nothing to suggest that these issues are of less importance than coal cycling costs.”
Parties weigh in on utility’s resource planning process
Numerous other parties also filed June 4 testimony in this case, including PUC staff, Western Resource Advocates, SolarReserve LLC, the Colorado Independent Energy Association and Southwest Generation Operating Co. LLC. Generally speaking, parties representing possible bidders in the solicitation said they wanted to ensure a fair and open process.
Fiona Sigalla, an economist at the PUC, said in June 4 testimony: “The first thing the Commission will notice is that, unlike previous solicitations, Public Service’s 2011 ERP has no immediate need for additional generation capacity. Even towards the end of the proposed Resource Acquisition Period (RAP), the plan does not call for any large capacity additions. At the same time, stranded assets in Public Service’s territory far outnumber the proposed resource need. Some of the most important decisions that the Commission will entertain in this docket will be centered on process changes requested by Public Service, and how those changes will impact bidder response to the competitive solicitation. Staff believes that it is essential that all bids are evaluated in a fair, transparent and independent manner. Staff has examined the requested ERP process changes and found the proposed changes result in less transparency and additional uncertainty in the bid process, and thus a significant potential for increased cost.”
Sigalla said that as the commission decides this case, it should:
- Send a message to bidders that all contracts will be evaluated fairly to obtain the most cost-effective resources available.
- Direct Public Service to evaluate all bids equally, to not give a preference to short-term contracts and to evaluate alternatives for Arapahoe 4 and Cherokee 4 as part of the all-source process. Arapahoe 4 and Cherokee 4 are coal units of PSCo, with Arapahoe 4 to convert to natural gas in 2013 and Cherokee 4 to natural gas in 2017 under a commission-approved plan.
- Require that independent power producers be given timely access to modeling inputs and assumptions used to evaluate their bids.
- Approve standard contracts as part of the Phase I decision, after soliciting comments from interested parties, while retaining flexibility where appropriate. Then, authorize a limited window for contract negotiations, no longer than 90 days.
- Require Public Service to provide firm prices for any self-build proposals rather than allowing for the possibility of full cost recovery with no fixed limit.
- Remove self-build generation from the bid hierarchy for contingency resources.
- Direct Public Service to include the Independent Evaluator in all contract negotiations. The commission should also direct the Independent Evaluator to scrutinize and critique how the company self-build projects are represented in the bid evaluation, being careful to look for bias affecting the outcome and to protect the level playing field for all bidders.
- Not pre-authorize Public Service to engage in “opportunistic acquisition” outside the ERP process, allowing acquisition of resources only as permitted under current rules.
This is only Phase I of two-phase process
The Electric Resource Planning process is conducted in two phases. This proceeding is currently in Phase I, which prescribes the utility’s plan for evaluating and acquiring any major resource addition. At the end of Phase I, the commission approves the assumptions, criteria and models used to solicit and evaluate bids in a fair and reasonable manner thereby avoiding the necessity for a litigated docket in Phase II, Sigalla noted.
In Phase II of the ERP proceeding, the utility solicits bids for the capacity amount that is approved by the commission in its Phase I decision. The company evaluates both third-party bids and utility self-build proposals using a computerized optimization model. The process is referred to as an “all-source solicitation” because all technologies—i.e., coal, natural gas, solar and wind—are compared, Sigalla added. Within 120 days following the receipt of the bids, the company files a report of its findings presenting its preferred portfolio, and alternative portfolios, for commission approval, modification or denial.
The utility has proposed a seven-year RAP, obtaining resources through October 2018. Public Service has determined that it needs an additional 292 MW of generation during that period. The company needs additional capacity in 2019 but prefers to obtain that generation with a 2015 ERP.