PacifiCorp argues length of QF contracts at Utah commission

PacifiCorp d/b/a Rocky Mountain Power told the Utah Public Service Commission in Oct. 14 testimony that it is not trying to get rid of its must-purchase obligations for qualifying facility (QF) contracts, just trying to minimize the durations of those contracts.

PacifiCorp had applied on May 11 with the commission for permission to a put a three-year cap on the length of its QF contracts, as opposed to the current 20 years, due in part to the sheer number of QF requests it has gotten lately, mostly for solar projects. These are QF contracts that the company must enter into under the Public Utility Regulatory Policies Act of 1978 (PURPA).

Various parties have filed opposing testimony in the case, with PacifiCorp official Paul Clements on Oct. 14 supplying the company response. “The Company is requesting an order from the Public Service Commission of Utah (‘Commission’) directing implementation of a reduction of the maximum contract term for PURPA contracts from 20 years to three years, to be consistent with the Company’s hedging and trading policies and practices for non-PURPA energy contracts and more aligned with the Integrated Resource Plan (‘IRP’) cycle,” Clements wrote. “The Company is seeking a modification to the maximum contract term of QF contracts executed under both Schedules 37 and 38.”

He was responding specifically to the direct testimony of: Utah Clean Energy (UCE) witness Sarah Wright; Sierra Club witness R. Thomas Beach; Rocky Mountain Coalition for Renewable Energy witnesses Kevin Higgins, Bryan L. Harris, and Hans Isern; Renewable Energy Coalition witness John Lowe; Utah Office of Consumer Services (OCS) witness Bela Vastag; and Utah Division of Public Utilities (DPU) witness Charles E. Peterson.

Wrote Clements: “In seeking to maintain the ‘ratepayer indifference’ standard required by PURPA, the Company’s direct testimony explains and illustrates how the required 20-year contract term is: (1) inconsistent with the Company’s hedging practices implemented after careful review by stakeholders in a recent collaborative, (2) inconsistent with resource acquisition policies and practices for non-PURPA energy purchases, and (3) not aligned with the Company’s IRP planning cycle and action plan. Additionally, the Company’s direct testimony describes how, without the requested modification to contract term, PacifiCorp will be forced to continue to acquire long-term, fixed-price PURPA contracts even though PacifiCorp’s 2015 IRP, which was filed in March 2015, shows no new resource is required until 2028.

“The direct testimony of three intervenors, namely UCE, the Coalition, and Sierra Club, carry common themes in response to the Company’s application. These parties suggest PacifiCorp is trying to eliminate the PURPA must-purchase obligation, even though my direct testimony is clear that the must-purchase obligation remains. These parties are more concerned with ensuring continued QF development under any scenario, despite the lack of an identified need for new generation, than they are with balancing customer rate and risk impacts with QF rights under PURPA.

“These parties suggest a QF contract is not similar to commodity hedges, which are currently limited to three years or less under the Company’s trading policies, even though the current QF contract is clearly a fixed-price purchase of unit-contingent non-dispatchable energy for a 20-year term. These parties suggest a QF contract is similar to a Company resource, even though procurement of a Company resource is driven by need; and a Company resource can be dispatched and backed down when more economic alternatives are available, passing through to customers the savings from lower fuel and other operating costs because the total cost of the energy is not locked-in for 20 years like it is in a QF contract.

“Lastly, these parties suggest QFs are able to meet future environmental compliance obligations, even though those obligations are not currently known and measurable. Importantly, these parties ignore the critical fact that the QF retains the renewable energy credits (‘RECs’) for their own economic benefit, and those RECs represent the environmental attributes that these parties are touting as beneficial to the Company.

“The OCS submitted a short piece of testimony in which it raises two critical issues with which I agree: 1) there is a risk to customers associated with carrying long-term fixed-price contracts for power, and 2) there is a disconnect between new QF contracts and PacifiCorp’s IRP. Notwithstanding these important concerns, the OCS recommends the Commission not approve the Company’s application.”

Clements said the DPU agrees with PacifiCorp on many key issues and shares the company’s concerns related to the large number of existing and potential QFs. The DPU agrees that:

  • A 20-year contract is inconsistent with the hedging principles agreed upon in the hedging collaborative;
  • A 20-year contract term is a clear benefit to QF developers;
  • It is not the regulator’s place to ensure economic viability of a QF project; and 
  • It is time to reconsider the previous positions related to QF contracts in light of recent events.

The DPU introduced an alternative to PacifiCorp’s proposal. The DPU proposal consists of a five-year contract term but allows the capacity payment to be based on a 20-year avoided cost calculation. Energy prices would be calculated as they are now, but only for the next five years. Under the DPU proposal, the QF will have the option every five years to seek alternate off-takers elsewhere.

Said Clements about the idea from DPU: “While this proposal is an improvement in that it only fixes energy prices for up to five years, paying a capacity payment based on 20 years but allowing the QF the option to cease sales to the Company after only five years is similar to the issue that arises with levelized pricing where capacity and energy values are brought forward for the QF’s benefit in early years and returned to customers in the later years of the long-term contract. In the DPU proposal, customers over-pay for the capacity value in the early years as capacity values is brought forward but bear the risk of the overpayment if the QF leaves after five years. This exposure does not meet the ratepayer indifference standard. I continue to recommend the implementation of a three-year contract term for all QF contracts.”

Developer reps says long-term QF contracts needed for project financing

Filing Oct. 14 rebuttal testimony for the coalition was Hans Isern, the Senior Vice President of Origination for power project developer Sustainable Power Group (sPower). He responded to the prefiled direct testimony of Division of Public Utilities witness Charles E. Peterson. “Specifically, I will explain why none of the ‘new financing vehicles’ suggested in Mr. Peterson’s testimony will alleviate or affect the need for long term PPAs, and why the Division’s suggestion for a five-year PPA term will make financing of renewable energy projects virtually impossible,” Isern wrote.

None of the “vehicles” suggested reduce the need for long-term price to finance a renewable energy project. Isern said that with respect to a “yieldco,” it is true that this is a relatively new financing mechanism for sponsor equity placement into renewable energy projects. However, the existence of a yieldco does nothing to reduce the requirement for long-term pricing certainty to finance a renewable energy project. No reasonable source of equity, tax equity, or debt will be available for such a project absent long-term PPA price certainty, he said. Almost all publicly-traded yieldcos disclose remaining contract length, which is analyzed by the financial community as a metric of safety of long-term cash flows and distributions. Of the major yieldcos the average remaining contract life is typically in the 15 to 20 year range, and this includes projects that already have an operational history.

Isern said he is also unaware of any “crowdfunding” mechanism for financing power projects and is not aware of a single utility-scale renewable project that has previously utilized crowdfunding. “Mr. Peterson’s testimony describes crowdfunding as ‘… a developer solicits funds directly from large numbers of people, typically over the internet.’ This is not a viable option for a large power plant costing tens or hundreds of millions of dollars. Furthermore, the inability to pass tax equity through individuals would rule out crowdfunding for a significant portion of the project capital. For these reasons, I do not believe that crowdfunding is viable or able to alleviate the need for price certainty via a long-term PPA.”

Isern added: “Mr. Peterson’s suggestion for the use of ‘traditional bond and stock issuances’ based on a company’s assets rather than a project is not viable. Most renewable projects are held in special purpose entities and use a variety of types of non-recourse financing, including tax equity and debt.”

Making some of the same points in his own Oct. 14 testimony on behalf of the coalition was Bryan L. Harris, a Senior Development Manager for SunEdison. He also responded to a Peterson contention that SunEdison doesn’t need long-term PPAs in order to develop renewable energy projects.

“I do not know precisely what Mr. Peterson is suggesting by referencing SunEdison’s asset base, but it is extremely unlikely SunEdison can or will develop new QF renewable energy projects in Utah if the maximum term of QF PPAs is reduced to three years or five years,” Harris wrote. “Neither SunEdison nor any other company that must survive in a competitive environment, regardless of the magnitude of their assets, can develop or finance a renewable energy project with a PPA with such a short term.”

Harris said any limit on contract length will almost certainly result in an almost complete cessation of development of any new significant renewable energy resources in Utah by anyone other than a utility with a captive customer base to serve as security for financing.

“To my knowledge, none of the developers is asking for an assurance of economic viability for any project,” Harris said. “Economic viability will depend upon a project’s costs and returns relative to other competitors and opportunities. Developers are used to competing with others for economic viability. Our need for pricing certainty to attract capital has little to do with economic viability. Rather, it has to do with maintaining a structure that can facilitate and encourage the development of non-utility, non-traditional renewable energy projects when a project’s costs and returns make it economically viable. That, as I understand it, is the intent and purpose of existing federal and state laws and policies. In my opinion, any failure to retain such a structure will frustrate the intent and purpose of those laws.”

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.