PacifiCorp d/b/a Rocky Mountain Power applied May 11 at the Public Service Commission of Utah for approval to cut, from 20 years to only three years, the maximum contract term of prospective power purchase agreements (PPAs) with qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA).
The company wrote: “Congress enacted PURPA in response to the nationwide energy crisis of the 1970s. Its goal was to reduce the country’s dependence on imported fuels by encouraging the addition of cogeneration and small power production facilities to the nation’s electrical generating system. PURPA requires electric utilities to purchase all electric energy made available by QFs at rates that (a) are just and reasonable to electric consumers, (b) do not discriminate against QFs, and (c) do not exceed ‘the incremental cost to the electric utility of alternative electric energy.’ The incremental cost to the utility means the amount it would cost the utility to generate or purchase the electric energy but for the purchase from the QF.
“The incremental cost standard is intended to leave customers economically indifferent to the source of a utility’s energy by ensuring that the cost to the utility of purchasing power from a QF does not exceed the cost the utility would incur in the absence of the QF purchase. FERC issued rules implementing PURPA in which it adopted what it called a utility’s ‘avoided costs’ as the standard for implementation of the incremental cost requirement. While the applicable statutes and rules are matters of federal law, PURPA gives state commissions the responsibility of determining a utility’s avoided costs as well as the terms and conditions of PURPA contracts.
“A critical element of the utility’s must-purchase requirement under PURPA is the contract term. The term is critical because FERC generally requires a utility to lock in forecasted avoided cost rates for the entire contract term. FERC has explained that it believes imperfections found in the avoided cost methodology should, if set correctly, balance out between overestimation and underestimations. However, PURPA and FERC regulations are silent as to the length of QF contracts and, with a few exceptions not relevant here, FERC has not spoken directly to the issue of setting an appropriate contract length.
“Under PURPA, states are tasked with assessing the needs of the state, the idiosyncrasies of the local utility systems, and the reliability and quality of potential power sources. And it is the states that are implementing standards within FERC’s PURPA framework in a manner consistent with the public interest. This Commission has recognized that the term of a PURPA contract and the rates to be paid under that contract are interrelated. Indeed, both avoided costs and other terms and conditions of PURPA contracts affect whether retail customers remain indifferent to the purchase of QF power. The modification of contract term requested by the Company in this application is necessary to maintain ratepayer indifference and is a means by which the Company and the Commission can protect customers from unnecessary long-term, fixed-price risk.”
Number of QF requests has jumped lately
Said the May 11 PacifiCorp application: “The Company has experienced a dramatic increase in QF pricing requests in recent years. In Utah, of the Company’s current 1,041 MW of QF contracts, contracts for projects totaling 896 MW (86 percent of the total PURPA MW under contract) have been executed in the last two years. System-wide, of the Company’s 1,991 MW of QF contracts, projects totaling 1,145 MW (58 percent of the total PURPA MWs under contract) have online dates of 2014 or later.
“The magnitude and potential impact of this increased PURPA activity may also be illustrated by comparing the total amount of existing and proposed Utah PURPA projects to the Company’s Utah retail load. The Company currently has 2,253 MW of proposed PURPA contracts in Utah. This, combined with its 1,041 MW of existing PURPA contracts, totals 3,294 MW of nameplate capacity. In 2014, the Company’s average Utah retail load was 2,959 MW and its minimum Utah retail load was 2,033 MW. The 3,294 MW of existing and proposed PURPA contracts in Utah at their nameplate capacity would be enough to supply 111 percent of the Company’s average Utah retail load and 162 percent of the Company’s minimum Utah retail load.
“Expanding the foregoing analysis to the Company’s six-state system, the Company currently has requests for 3,692 MW of new PURPA contracts system-wide, in addition to the 1,991 MW of QF contracts that are already executed. In 2014, the Company’s average system-wide retail load was 6,844 MW and its minimum system-wide retail load was 4,967 MW. The 5,683 MW of existing and proposed PURPA contracts at their nameplate capacity would be enough to supply 83 percent of the Company’s average retail load and 114 percent of the Company’s minimum retail load.
“The Company’s long-term planning and resource decisions are thoroughly evaluated through the Company’s Integrated Resource Plan (‘IRP’) process. The Company’s IRP is developed with participation from public stakeholders, including the Commission and its staff, the Division of Public Utilities (‘Division’), the Office of Consumer Services (‘Office’), advocacy groups, and other interested parties. The planning process entails: (1) developing an assessment of resource need via a load and resource balance, reflecting current load growth forecasts and existing resources and contracts over a 20-year planning horizon; (2) producing a range of different resource portfolios that could be used to meet the projected resource need; and (3) evaluating the comparative cost and risks of each resource portfolio, taking into consideration a wide range of planning uncertainties, in order to identify the least-cost and least-risk preferred portfolio. Once a preferred portfolio is selected, an action plan is developed that identifies the specific resource actions the Company will take over the next two to four years to implement its resource plan.
“The Company would not plan to enter into long-term transactions unless a long-term resource need is identified in the IRP preferred portfolio. Long-term resource needs are typically identified in the IRP only after lower-cost, lower-risk short-term resource opportunities are exhausted such that a long-term resource is required to meet customer load requirements. If the IRP identifies the need for a long-term resource in the near-term, an IRP action item would specify the Company’s plans to acquire the resource.The Company’s 2013 IRP, which until the recent filing of the 2015 IRP, was the reference for avoided costs in Utah, included a combined cycle combustion turbine (‘CCCT’) gas plant in 2024. Due to the timing of the identified need for this resource, the 2013 IRP action plan did not include any action items to procure this long-term resource. The 2013 IRP Update filed with the Commission in March 2014, pushed the CCCT out to 2027. Again, due to the timing of this identified need, the Company did not develop an action item to procure this long-term resource. The Company’s 2015 IRP has now been filed with the Commission. The 2015 IRP preferred portfolio pushes the CCCT out even further to 2028. As in the 2013 IRP and the 2013 IRP Update, the 2015 IRP draft action plan does not include any action items to procure this long-term resource.
“Thus, while the Company has had a sharp increase in pricing requests for new PPAs with QF’s under PURPA equal to 3,693 MW system-wide and 2,253 MW in Utah, the 2015 IRP indicates that the Company has no need for any system resource until at least 2028.”
Paul H. Clements, Senior Originator/Power Marketer for Rocky Mountain Power, said in May 11 supporting testimony: “Given the magnitude of new QF requests, and considering the inherent uncertainties in projecting avoided cost rates out 20 years or more, current Utah avoided cost rates expose customers to unreasonable fixed-price risk for 20 years. To protect customers from this risk on an on-going basis, the Company requests approval of a reduction in the maximum contract term for PURPA contracts, from 20 years to three years. Such a term would be more consistent with the Company’s hedging and trading policies and practices for non-PURPA energy contracts and more aligned with the IRP cycle.”
This is not the only PacifiCorp-served state facing this issue. The Idaho Public Utilities Commission said March 19 that it will conduct both technical and public hearings in late June to consider requests by three electric utilities to reduce the duration of sales agreements they must enter into with large renewable energy developers.
The Idaho commission on Feb. 5 granted an Idaho Power request to reduce the duration of sales agreements with solar and wind PURPA projects that are larger than 100 kiW and other PURPA projects – such as geothermal, industrial cogeneration and hydro – that generate more than 10 average megawatts. Idaho Power originally sought to reduce the contract length from 20 years to two years. The commission approved five-year contract lengths while it further examines the case. Since that decision, Avista Utilities and PacifiCorp d/b/a Rocky Mountain Power requested similar treatment.