Minnesota Commission Punts on Resource Decision: Keeps Solar in the Game

After the years of inconclusive resource planning, months of contested case proceedings, and days of oral argument, discussion and review that led to today’s deliberations, the Minnesota Public Utilities Commission (“Commission”) unanimously decided not to decide. The ultimate question before the Commission was what capacity needs had been determined in the record and what should be done to fill that need on Xcel Energy’s system. At the turn of the new year, the Administrative Law Judge’s (“ALJ”) answers to these questions made national news by finding that the solar bid provided the best value for ratepayers (see our blog on that here). The ALJ made his determination, in part, based on new modeling done at the request of the Commission given the significant changes in circumstances that had occurred since docket was opened (e.g., Xcel Energy acquired 750MW of new wind and Minnesota passed a Solar Energy Standard). In light of the changed circumstances and uncertain need, the ALJ recommended selection of the solar resource that was independently “needed” by statute, a capacity bid that could be added as necessary to bridge for any further shortfall, and then conduct a more thorough analysis for the longer-term needs. Today the Commission instead chose to rely primarily on the original need determination that opened the docket, accept the ALJ’s findings only to the extent they were consistent with their own findings, and direct Xcel to negotiate with everyone proposing to build something and report back. 

Despite the above, the decision is a significant step forward for solar. This was the first time a solar proposal had competed directly with natural gas in a resource acquisition process and, despite significant pressure from the Department of Commerce to shuffle the solar bid off into a separate, solar-only proceeding, the Commission confirmed today that the solar bid was welcome at the big kids table.

Look for a forthcoming Order that includes something like this:

In order to meet reliability and adequacy requirements and to comply with MN energy policy statutes, direct Xcel to separately negotiate power purchase agreements with Geronimo Energy, Calpine, Invenergy and develop pricing terms for Black Dog 6 to address the overall Xcel system needs identified in this record and the March 5, 2013 Integrated Resource Plan Order and determine which resources best meet system needs and are in ratepayers’ best interests.

Find that negotiated terms that shift risk or unknown costs to ratepayers are not likely to be reasonable. Find that bidders shall be held to the prices and terms used to evaluate each bid for purposes of cost recovery from Xcel ratepayers. Ratepayers will not be at risk for costs that are higher than bid or for benefits assumed in bids that do not materialize. If actual costs are lower than bid, the bidders should be allowed to keep those savings.

Require that power purchase agreement provide terms that sufficiently protect ratepayers from risks associated with the non-deliverability of accredited capacity or energy from the projects as proposed.

For more information, please contact Drew Moratzka or Sara Bergan.

Post-Conference Report: Solar Power International 2013

Thousands of solar industry participants gathered in Chicago for the Solar Power International expo in Chicago, Illinois on October 21-24 to discuss the state of the solar industry. Participatnts included banks, investors, developers and equipment suppliers, and also several Stoel Rives attorneys.

Many themes emerged during the week-long event, and a common thread running through these themes was “change.” The solar industry is undergoing significant changes, as demonstrated by the following:

  • Stoel Rives announced that Federal Energy Regulatory Commission Chairman Jon Wellinghoff will join the firm later this year following his impending resignation from the Commission;
  • The regulatory environment continues to morph as the 1603 cash grant phases out while the ITC reemerges pending its expiration, net-metering battles rage on in multiple states, and California has required investor owner utilities to procure and invest in significant amounts of energy storage;
  • Companies continue to search for investment grade projects while developers continue to hunt for PPAs with sustainable pricing;
  • Chinese equipment manufacturers continue to factor in the space, and several companies from mainland China attended the expo for the first time, now also joined by a growing number of Taiwanese and Korean companies;
  • As utility scale development opportunities in the United States continue to stagnate, many companies are turning their focus to Latin America where new and potentially lucrative opportunities are emerging;
  • The industry seems ripe for consolidation and the remainder of 2013 and 2014 may witness several significant mergers.

In this time of significant change, Stoel Rives will continue to serve the solar industry by providing high quality legal services and innovative solutions for the issues of today and the issues of the future.

#PTC Extension: Scarcity of Utility-Scale PPAs a Big Challenge for Wind Energy in 2013

In the wake of the extension of the production tax credit, my colleague Ed Einowski has analyzed a key challenge – the relative scarcity of available utility-scale power purchase agreement RFPs. Having a PUC-approved PPA in place is generally a prerequisite for securing financing for utility-scale wind projects. Here’s what he has to say:

The extension of the production tax credit (PTC) allows the wind energy industry to move forward with projects in 2013. But the last few years – especially 2012 – have seen relatively few utility-scale wind power purchase agreements executed. Without the assured revenue source of a power purchase agreement (PPA), wind projects will generally find third-party financing – whether debt, tax equity or cash equity – unavailable. And few developers – even those with the financial resources to do so – will likely be willing to risk proceeding with project construction in the absence of a financeable PPA. As a consequence, for most developers the PTC extension presents the immediate challenge of securing a financeable PPA to enable the PTCs to be secured. Given the time it generally takes to negotiate and finalize a utility-scale wind PPA as well as pursue other key items such as turbine supply agreements and engineering, procurement and construction contracts, it will be necessary to move expeditiously.

For a more detailed discussion of the issues involved, read the full article.

Georgia Power Files for Advanced Solar Initiative

On September 26, 2012, Georgia Power filed with the Georgia Public Service Commission a proposal for the creation of the Georgia Power Advanced Solar Initiative, a program that would result in the procurement of up to 210 megawatts of solar generation through power purchase agreements. Of the 210 MWs, 180 will come from utility scale projects while 30 MW will come from distributed projects.

Utility Scale Projects.  The proposal calls for Georgia Power to issue RFPs in 2013, 2014, and 2015 for utility scale solar projects up to 20 MWs in size and to be located in Georgia.  The PPAs would have twenty year terms and with pricing not to exceed 12 cents per kWh. 

Distributed Projects.  Georgia Power will also enter PPAs with Small-Scale projects (up to 100 kW) and Medium-Scale projects (greater than 100kW and smaller than 1 MW).  In each of 2013, 2014 and 215, Georgia Power will enter 10 MW worth of PPAs with Small/Medium-Scale projects until anoverall cap of 30 MW is reached.

More information and a copy of Georgia Power's filing is available here.

Minnesota PUC clarifies that "other credits" include RECs

Last year, we reported on the resolution of a longstanding dispute between Xcel Energy and 46 renewable energy generators about the ownership of Renewable Energy Credits (RECs) when the Power Purchase Agreement (PPA) is silent. In an Order released September 9, 2010, the Minnesota Public Utilities Commission decided that 1) generators own the RECs produced under PPAs signed under the 1978 federal Public Utilities Regulatory Policy Act (PURPA) and 2) Xcel owns the RECs produced under PPAs signed under Minnesota’s 1994 wind and biomass mandates, unless the generator could demonstrate that the PPA was not silent. Today, the Commission released an Order offering more clarity to PPAs in the latter category.

Following the September 2010 Order, two generators (St. Paul Cogeneration LLC and Mission Funding Zeta) with contracts under the wind and biomass mandates sought to demonstrate to the Commission that their PPAs were not silent on REC ownership. Both PPAs at issue contained language allocating to the generator the benefit of “any tax credits, allowances or other credits” related to the generation facility. In today’s order, the Commission determined that this language unambiguously includes RECs. As a result, the Commission found that St. Paul Cogeneration and Mission Funding Zeta own the RECs under the terms of their PPAs.  The Commission also found that Xcel owns the RECs under any remaining unsettled wind and biomass mandate PPAs, unless the generator demonstrates that the PPA is not silent within 30 days.

Renewable Energy Projects: Keys to Drafting Power Purchase Agreements

Renewable Energy Projects: Keys to Drafting Power Purchase Agreements
Thursday, March 31, 2011
1:00 – 2:00 p.m. (Eastern)

Join Stoel Rives Partner, Bill Holmes, as he presents this exclusive, 60-minute webinar on Thursday, March 31.

The power purchase agreement (PPA) is the most critical component of a renewable energy project, and essential to project finance. Knowing how to properly draft and negotiate PPAs will not only alleviate tension between buyer and seller, but will protect your client by equitably allocating future risks that can arise in this ever-changing business and legal environment. This webinar also features a live Q&A session, where you can get expert answers to your specific PPA questions.

Key highlights and learning objectives:

• How to draft and negotiate PPAs: critical terms and provisions for the buyer and seller
• Keys to allocating risks of RPS compliance, curtailment, change of law, and more
• Strategies to proactively address common disputes between developers and purchasers
• Key considerations for drafting dispute resolution clauses for PPAs

This crucial webinar is not to be missed. Click here to register.

Idaho PUC Issues Proposal to Revise Prices Paid to QF Wind Generators Under PURPA

The Idaho Public Utilities Commission (PUC) has issued a straw man proposal that lays out plans to revise the surrogate avoided resource (SAR) methodology used to calculate avoided cost rates for wind generators.  The "avoided cost" is the price paid to Qualifying Facilities that are selling power to Idaho utilities under the Public Utility Regulatory Policies Act (PURPA).   

The PUC included six cost categories in the wind SAR:  capital costs; fixed and variable O&M costs, transmission costs; tax credits; wind integration; and forecasting costs.  The PUC assumed transmission costs of $1.90/kw-month, production tax credits at $0.021/kWh, a $0.00 REC premium, and wind integration at $6.50/MWh.  With those inputs and others, the PUC arrived at 20-year levelized wind rates for a 2010 project as follows:

Wind and Gas SARs
Utility Wind SAR Gas SAR
Avista $86.31/MWh $79.17/MWh
Idaho Power $84.72/MWh $79.19/MWh
PacifiCorp $85.06/MWh $79.31/MWh

The PUC proposed that where the Wind SAR is higher than the Gas SAR, a wind developer may choose whether to sell power at the wind or gas rate.  If the wind developer opts for the latter, it retains ownership of RECs.  If the wind developer opts for the former, RECs go to the utility.  However, when the Gas SAR is higher than the wind SAR, wind developers would only be eligible for the wind SAR, meaning that the utility would automatically receive RECs under a PPA.  Non-wind projects would be entitled to the gas SAR when the gas rate is higher, and RECs would remain with developers.

The PUC is accepting written comments on the straw man proposal until November 23, 2010.

MPUC Issues Order on Renewable Energy Credit Ownership

Following our post from a couple weeks ago, the Minnesota Public Utilities Commission released its Order today regarding ownership of renewable energy credits in a group of "silent" power purchase agreements (Docket No. 08-440). The Order is available here and our previous post describing its substance is here.

Minnesota PUC Settles Longstanding Dispute over REC Ownership

Last week, the Minnesota Public Utilities Commission resolved a longstanding dispute over who owns Renewable Energy Credits (RECs) when the Power Purchase Agreement (PPA) is silent.  Following the establishment of an REC tracking system for Minnesota, Xcel Energy asked the Commission to clarify ownership of RECs associated with 46 wind, biomass, hydro, and landfill gas facilities totaling 467.5 MW.  These PPAs were written before the concept of RECs existed. 

On August 17, 2010, the Commission resolved the dispute partially in favor of Xcel and partially in favor of the generators.  The Commission divided the disputed PPAs into two categories: 1) PPAs signed under 1978 federal Public Utilities Regulatory Policy Act (PURPA) and 2) PPAs signed under Minnesota’s 1994 wind and biomass mandates (Minn. Stat. §§216B.2423 and 216B.2424).

For the PURPA contracts, the Commission decided that the generators are the rightful owners of RECs because they had only been paid avoided cost with no premium for the electricity being from renewable sources.

For the wind and biomass mandate PPAs, the Commission favored Xcel and decided that the utility had acquired ownership of the RECs, unless the generator can make a showing that the PPA is not silent on REC ownership.  For this category, the Commission reasoned that Xcel had contracted to buy electricity that would meet specific renewable mandates.  Without the RECs, the electricity would not satisfy the renewable mandates.

The Commission exempted two PPAs close to being privately settled from its decision as well as 13 PPAs that were already privately settled.

Filings related to the "silent PPAs" dispute can be found by searching for Docket No. E-002/08-440 in Minnesota’s eDocket system.

Rhode Island PUC Rejects Offshore Wind PPA

Last week, the Rhode Island Public Utilities Commission rejected a power purchase agreement (PPA) between Deepwater Wind and National Grid, the state's largest utility, stating that the deal’s projected cost of electricity did not qualify as “commercially reasonable” under a test required by state law.  Deepwater would have charged National Grid 24.4 cents per kilowatt-hour in 2013, the first year of the contract. Prices would increase 3.5 percent per year after that.

The state previously passed legislation requiring National Grid to purchase the energy output from an offshore wind project.  The PPA that was ultimately signed was for the output of a 28.8 MW project near Block Island. 

The news of the PUC rejection comes shortly after receipt of $23.3 million in stimulus funds by the Quonset Business Park to improve piers, roads and rails and to install a crane in preparation for offshore wind development.  Deepwater Wind has signed an agreement to lease 117 acres in the Quonset Business Park to store and assemble components, and ultimately create 800 jobs, as projected by Deepwater.

Public Service Commission of Utah Investigates Third-Party Power Purchase Agreements For Renewable Energy Generation

On October 12, 2009, the Public Service Commission of Utah ("PSC") joined the ranks of several other states in the west, including  Oregon, when it established a docket to investigate whether, and the extent to which, certain third-party arrangements for renewable energy generation are subject to the PSC's jurisdiction.   www.psc.utah.gov/utilities/misc/miscindx/0999912indx.html,  Pursuant to the notice, the PSC may consider the following issues:

  • Whether the third-party is a public utility under Utah law;
  • Whether the third-party is a public utility under Utah law when arrangements are entered into primarily as a financing mechanism for distributed renewable energy generation systems whereby a third-party owns the renewable generation equipment, which is installed on a utility customer's premises, there is a long-term contract with the customer to supply a portion of that customer's electricity use, and payments are based on kilowatt-hours;
  • Whether the third-party is a public utility under Utah law when (i) there is a single relationship between the third-party owner of the generation and a customer or (ii) there are multiple customers taking power from the same third party;
  • Whether the third-party is a public utility under Utah law when arrangements involve the leasing of distributed generation equipment from non-utility lessors to lessees that are also retail customers of utilities.

Comments and/or legal briefs regarding the above issues must be filed with the PSC by November 16, 2009.  A technical conference to discuss the specific terms and conditions surrounding third-party financing arrangements and other issues will be held on November 23, 2009, at 1:30 p.m. to 4:00 p.m., Fourth Floor Hearing Room Room 401, Heber M. Wells State Office Building, 160 East 300  South, Salt Lake City, Utah.