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.
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.
On July 28, 2010, the Colorado Public Utilities Commission (the "Commission") issued a Notice of Proposed Rulemaking ("NOPR") regarding rules related to electric transmission facilities planning (the "Proposed Rules"). The Proposed Rules are based, in large part, on the input provided by all interested parties in the workshops and written comments in connection with Docket Nos. 08I-227E and 09M-616E and in response to certain legislative and policy changes impacting transmission planning significantly. In response to these legislative and policy changes, some of the key issues that need to be addressed in transmission planning include transmission-related challenges to satisfying State of Colorado's renewable energy portfolio standard for electricity generation, distributed generation set-asides, and requirements that the Commission give the fullest possible consideration to cost-effective implementation of new clean energy and energy efficient technologies. In implementing the Proposed Rules, the Commission recognizes that "both state-wide coordinated transmission planning and a meaningful involvement in such planning by stakeholders and the Commission are essential." NOPR at 2-3. In addition, the Commission concluded that "an effective transmission planning approach needs to be long-term and pro-active rather than just-in-time and reactive."
Under the Proposed Rules, the Commission will rely on the Colorado Coordinated Planning Group ("CCPG") as the primary means by which jurisdictional electric utilities will develop the ten-year transmission plans and the twenty-year conceptual plans contemplated under the rules, in consultation with other CCPG members and stakeholders. Overall, the Proposed Rules set forth the general objectives associated with the biennial filing of the following:
- ten-year transmission plans;
- twenty-year conceptual plans;
- associated economic studies that jurisdictional electric utilities will develop through CCPG.
At its core, a ten-year transmission plan is required to be:
- consistent with the single-system planning concept, defined as a collective use of the existing transmission system and making the appropriate additions, upgrades and enhancements to the system as if the transmission system were owned by a single entity;
- coordinated with all transmission providers in Colorado; and
- developed in conjunction with the CCPG, a formal subregional transmission planning organization recognized by the Western Electricity Coordinating Council ("WECC"), in a manner consistent with its charter and with the Federal Energy Regulatory Commission ("FERC") regulations regarding transmission planning.
Under the Proposed Rules, it is expected that the jurisdictional utilities will file their first transmission plan in February 2011. In addition, it is anticipated that there will be an interaction between the biennial tranmission planning process, the "Certificate of Public Convenience and Necessity" ("CPCN") proceedings, electric resource planning and the Senate Bill 100 processes. One specific intent of the Proposed Rules is to provide useful information to stakeholders and the Commission in CPCN proceedings in terms of identifying how a proposed transmission facility fits into a larger state-wide transmission plan -- this is particularly important in facilitating the integration of location-constrained renewable energy resources.
Finally, the Commission found that the state-wide coordinated transmission planning must be open to all stakeholders and address both reliability and economic considerations in order for the process to be effective. The Commission noted that while the CCPG charter provides that CCPG meetings and membership are open to all interested stakeholders, the Proposed Rules also provide that in connection with the biennial filings, the utilities are required to demonstrate the outreach to interested stakeholders that occurred in the development of the ten and twenty year transmission plans.
For those interested in commenting on the Proposed Rules, here is an overview of dates/deadlines set forth in the NOPR:
- Pre-filed comments must be submitted by August 25, 2010
- Reply comments must be submitted by September 1, 2010
- A hearing on the Proposed Rules will be held before Hearing Commissioner James Tarpey on Thursday, September 9, 2010 at 9:00 a.m. in Commission Hearing Room A, 1560 Broadway, Suite 250, Denver, Colorado.
From our colleague Adam Walters:
In February we blogged about Colorado HB-10 1001, a bill then pending in the Colorado legislature that would increase Colorado’s Renewable Energy Standard (RES) from 20% to 30% by 2020. The Democrat-sponsored bill was passed by the legislature on March 11 on a party line vote and yesterday it was signed into law by Colorado Governor Bill Ritter with great fanfare.
With the passage of this law Colorado now has one of the most ambitious RES’s in the country, and second only to California’s 30% requirement.
In addition to increasing the State’s RES, the law attempts to assist in job creation in the solar installation industry by placing greater emphasis on distributed generation (DG). For instance, the law requires Colorado utilities to spend 3% of its power purchases on distributed solar installations. The law also allows a utility to develop and own, as part of its rate base, up to 50% of the DG capacity it acquires from power purchase agreements and new construction if the cost is reasonably comparable to current market cost. The Public Utility Commission must also allow utilities the same cost recovery for the construction of new DG systems as allowed for new coal-fired facilities.