7th Circuit Affirms FERC's Decision on Multi-Value Projects, Relying Heavily on Policy of Promoting Wind Development
From my colleague, Andrew Moratzka:
On June 7th, 2013, the United States Court of Appeals for the Seventh Circuit issued an opinion in Illinois Commerce Commission, et al., v. Federal Energy Regulatory Commission, affirming the Federal Energy Regulatory Commission’s approval of the Midcontinent Independent System Operator, Inc. (MISO) Multi-Value Project (MVP) tariff for financing new high-voltage power lines that largely serve remote wind farms.
Six issues were before the court: (i) the proportionality of benefits to costs for MVPs; (ii) the procedural adequacy of the previous proceedings; (iii) the propriety of an energy-cost allocator for MVPs; (iv) whether MISO should be allowed to add an MVP fee to utilities belonging to the PJM Interconnection, LLC (“PJM”); (v) whether MISO should be permitted to assess some costs associated with MVPs; and (vi) whether the Commission’s approval of the MVP tariff violates the Tenth Amendment to the Constitution by invading state rights. The fourth and fifth issues were remanded. And the court quickly dismissed the sixth issue at the outset of the opinion, stating that the arguments amounted to an assertion that the MVP tariff “provides a carrot that states won’t be able to resist eating.” This entry therefore focuses on issues (i) – (iii).
The court addressed issues (i) and (ii) together. There are two important takeaways in this section of the opinion. First, MISO’s burden of establishing rough proportionality of costs to benefits under the Federal Power Act arguably changed in the name of policy. The court stated that “The promotion of wind power by the MVP program deserves emphasis” and that wind power will probably “grow fast and confer substantial benefits on the region.” The court determined there was “no reason to think these benefits will be denied to particular subregions of MISO” and found that other benefits (e.g., reliability) were real, even though they couldn’t be calculated in advance. The court then went on to find that MISO’s and FERC’s efforts to match cost and benefits, even if crude, were sufficient. It is not entirely clear how this aspect of the opinion can be reconciled with the court’s previous opinion in Illinois Commerce Commission v. FERC. But it appears the policy of promoting wind power influenced the decision in this case. Moreover, the court rejected requests for an evidentiary hearing on this issue, on the basis that requiring such proceedings after two years of appeal “would create unconscionable regulatory delay.”
The second takeaway is a comment made by the court in response to a criticism raised by the State of Michigan, which claimed it would not benefit from out-of-state MVPs because a provision in Michigan law forbids Michigan utilities from counting renewable energy generated out of the state to satisfy requirements under the state’s Clean, Renewable, and Efficiency Act of 2008. The court stated that Michigan cannot discriminate against out-of-state renewable energy without violating the commerce clause of Article I of the Constitution. This statement could have significant ripple effects on similar laws around the country that give preference to in-state renewable resources or impose limits on imported generation.
The policy of promoting wind development also seemed to influence issue (iii). The court found that the objection to an energy allocator was refuted by the fact that a primary goal of the MVPs is to increase the supply of renewable energy. It acknowledged that wind production is intermittent and not a reliable source of energy to meet peak demand. But the court concluded that MVP lines will enable plants to serve off-peak demand and stated that “MISO and FERC were entitled to conclude that the benefits of more and cheaper wind power predominate over the benefits of greater reliability brought about by improvement in meeting peak demand.”
My California colleague Kristen Castaños has written an alert about a recent Fresno County Superior Court decision that denied a challenge to Fresno County's cancellation of a Williamson Act contract to accommodate a solar generating project.
The decision is the first time a court has considered the interplay between the Williamson Act, a California statute that seeks to protect agricultural land, and California’s directive to increase reliance on renewable energy in the state. In rejecting the challenge, the court gave the County substantial deference to determine whether the public interest in developing solar projects outweighs the public interest in protecting agriculture.
Southwestern Public Service Company (“SPS”), a subsidiary of Xcel, has issued a request for proposals to diversify its existing renewable energy portfolio in New Mexico. SPS is seeking, on an annual basis, approximately 88,705 MWh of “Other” renewable energy generation as defined by the New Mexico Public Regulation Commission Rule 572 NMAC (i.e., other than solar and wind) or an equivalent amount of biogas of approximately 665,300 MMBtu to be in commercial operation no later than January 1st, 2015.
Bidders that intend to submit a proposal are REQUIRED to submit a Notice of Intent to Bid no later than Friday August 31st, 2012. The submission deadline is 5:00 P.M. Mountain Time on Monday, October 1st, 2012. More information can be found here on Xcel Energy's web site.
On December 15, 2011, the California Public Utilities Commission adopted Decision 11-12-052, implementing Portfolio Content Categories for the 33% Renewables Portfolio Standard (RPS) Program in California. The Decision implements portions of Senate Bill (S.B.) x1-2, which created the 33% RPS Program. S.B. x1-2 established three categories of RPS-eligible electricity, applicable to RPS contracts executed after June 1, 2010:
- Category One includes electricity from RPS-eligible resources that have their first point of interconnection with a California balancing authority, RPS-eligible resources with a dynamic transfer arrangement with a California balancing authority, and RPS-eligible resources scheduling their electricity directly into a California balancing authority without substituting electricity from another source.
- Category Two includes firmed and shaped RPS-eligible electricity.
- Category Three includes transactions that do not meet the criteria of Category One or Two, including unbundled renewable energy credit (REC) transactions.
A Legal News Alert from Seth Hilton and the Stoel Rives Renewable Energy Law Group:
California’s Governor Jerry Brown signed Senate Bill ("SB") X1-2 on Tuesday requiring California's electric utilities to procure 33% of their energy from renewable resources by 2020. Upon signing the bill, Governor Brown stated the "bill will bring many important benefits to California, including stimulating investment in green technologies in the state, creating tens of thousands of new jobs, improving air quality, promoting energy independence and reducing greenhouse gas emissions."
Details concerning the implementation of the new legislation will have to be worked out at various California regulatory agencies, including the California Public Utilities Commission and the California Energy Commission. The legislation will likely spawn numerous regulatory proceedings as the various regulatory agencies struggle to come to grips with the new RPS mandate.
Stoel Rives partner Bev Pearman reviewed the complaint filed Monday in American Tradition Institute, et al., v. Colorado and prepared this analysis:
On April 4, 2011, the American Tradition Institute (“ATI”), the American Tradition Partnership (“ATP”), and Rod Lueck filed suit in the U.S. District Court for the District of Colorado arguing that Colorado is unconstitutionally discriminating against out-of-state renewable energy producers. ATI is a nonprofit organization “dedicated to the advancement of rational, free-market solutions to America’s land, energy, and environmental challenges,” and ATP is a lobbying organization “dedicated to fighting environmental extremism and promoting responsible development and management of land, water, and natural resources in the Rocky Mountain West and across the United States.” Rod Lueck is a member of ATI and ATP.
Colorado’s renewable energy standard (“RES”) states that by 2020 the state’s two major investor-owned utilities must get 30 percent of electricity sold from recycled or renewable resources. Renewable energy resources are “solar, wind, geothermal, biomass, new hydroelectricity with a nameplate rating of ten megawatts or less, and hydroelectricity in existence on January 1, 2005, with a nameplate rating of thirty megawatts or less.” “Fossil and nuclear fuels and their derivatives” are not “eligible energy resources” for complying with the RES. Additionally, each kilowatt of electricity generated in Colorado from certain recycled or renewable sources is given an enhanced value of one and one-quarter kilowatt-hours for purposes of meeting the mandated standards.
Plaintiffs raise both a sweeping Commerce Clause claim and a more focused Commerce Clause claim. The sweeping claim is that the statutory scheme is unconstitutional because it discriminates against non-renewable generation resources, both in-state and out-of-state, with plaintiffs alleging that such non-renewable generation is “legal, safer, less costly, less polluting and more reliable than renewable generation. A more focused claim is that the statutory preference given to in-state renewable electricity establishes a “market-bias against otherwise qualifying renewable sources located outside of Colorado and an inflated cost of complying with the RES requirements.”
Plaintiffs’ Commerce Clause claim is grounded in a U.S. Court of Appeals for the Tenth Circuit’s decision in KT&G Corp. v. Attorney General of the State of Oklahoma, 535 F.3d 1114, 1143 (10th Cir. 2008), which says a state may violate the dormant Commerce Clause by:
· Discriminating against interstate commerce in favor of intrastate commerce, unless “the discrimination is demonstrably justified by a valid factor unrelated to economic protectionism;” or
· Imposing “a burden on interstate commerce incommensurate with the local benefits secured;” or
· Creating mandates with the “practical effect of extraterritorial control of commerce occurring entirely outside the boundaries of the state in question.”
We expect that Colorado will vigorously defend the RES as being constitutional because its interest in promoting renewable energy generation is an important policy choice. Plaintiffs are attacking that position head-on, however, by challenging the policy of favoring renewable resources, particularly wind energy. They allege that wind energy is not reliable, causes more pollution due to the cycling of coal and natural gas plants during times when wind generation is not possible, and drives up utility costs for consumers. They do not attack other forms of renewable energy as vociferously, but still argue that any scheme favoring renewable resources over other energy sources burdens interstate commerce and violates the Commerce Clause.
The more focused claim (based on the preference given in-state renewable resources) is similar to a Commerce Clause challenge was brought nearly a year ago in Massachusetts by TransCanada Power Marketing, Ltd. (“TransCanada”). The Massachusetts suit did not challenge the policy of promoting renewable energy over non-renewable energy sources. It instead focused on renewable energy mandates and incentives favoring in-state generation. We do not know what arguments Massachusetts would have raised in defense of its program because the case was stayed after the state suspended the regulation underlying the statute in question. It issued emergency regulations, which were later adopted as final regulations, but the statute that establishes the challenged policy has not been amended. On April 1, 2011, the Alliance to Protect Nantucket Sound, an advocacy group that is leading the opposition to the Cape Wind project, filed a motion to intervene in that proceeding. It argued that TransCanada does not represent the interests of Massachusetts ratepayers. Their economic interests are allegedly harmed because the program at issue discourages utilities from entering long-term contracts with out-of-state generators, which has the effect of reducing out-of-state competition and increasing the cost of renewable energy for ratepayers.
The outcome of both of these cases could have far-reaching effects on other state’s RESs and renewable portfolio goals (RPGs). If the plaintiffs are successful with their claims, then the states with RESs and RPGs may have to modify their standards so they are not discriminating against out-of-state renewable energy generators. As we have noted before, the RESs with regional preferences may not be as much at risk. A key question that the courts have yet to answer are whether the RESs and RPGs create protectionist barriers to interstate trade. Check here for regular updates as these groundbreaking cases moves forward.
Legal News Alert from Stoel Rives Renewable Energy Law Group
The California Legislature has passed Senate Bill (“SB”) X1-2, which requires California’s electric utilities to increase their renewable generation to 33% by 2020. Passage of the legislation is the culmination of years of effort to increase California’s Renewable Portfolio Standard (“RPS”) from its current 20%. In 2009, the Legislature passed SB 14, which also would have increased California’s RPS to 33%, but the bill was vetoed by Governor Schwarzenegger on the ground that it imposed too many restrictions on the use of out-of-state generation to meet California’s RPS requirement. Governor Schwarzenegger then issued an executive order directing the California Air Resources Board to develop its own 33% Renewable Energy Standard under the Board’s authority pursuant to Assembly Bill 32, the Global Warming Solutions Act of 2006. Last year, the Legislature again tried to pass another 33% RPS bill, SB 722, but the session expired before the legislation could reach a final vote. Two bills were introduced in this session: SB 23 and SBX1-2. SBX1-2 was identical to SB 23, but it was introduced in special session in an attempt to speed passage of the legislation. SBX1-2 now goes to Governor Brown for signature, and he is expected to sign the legislation into law.
My partner Seth Hilton attended last Friday's all-party meeting on California's 2011 RPS procurement and prepared the following update:
On February 11, 2011, California Public Utilities Commission (CPUC) Administrative Law Judge Burton Mattson issued a Proposed Decision (PD) conditionally accepting the 2011 Renewables Portfolio Standard (RPS) Procurement Plans for Southern California Edison (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas and Electric Company (SDG&E). If adopted, the Decision would set a schedule for the utilities’ 2011 RPS solicitation. The PD was on the agenda for the CPUC’s March 24, 2011 business meeting, but was held at Commissioner Florio’s request until the April 14 meeting.
On March 25, Commissioner Florio held a well-attended all-party meeting on the PD. Among the issues raised by Commissioner Florio was where California’s investor-owned utilities stood relative to the current RPS procurement targets and the targets contained in pending legislation (SBX1-2), and whether a 2011 RPS solicitation was necessary.
All three investor-owned utilities—PG&E, SCE and SDG&E—stated that holding a 2011 RPS solicitation would be prudent. PG&E stated that it was on track to meet the current 20% RPS this year and through 2013. However, future compliance, especially with the higher procurement targets under SBX1-2, is dependent on several large projects that are scheduled to come online in the next few years. Any delay or failure of those projects would require PG&E to procure additional resources to get to the 2016 target under SBX1-2, and therefore holding a solicitation this year made sense.
According to SCE, a 2011 solicitation would be prudent for a number of reasons, not only to assist SCE to reach the goals in SBX1-2. SCE noted that a solicitation would be beneficial for current contract administration by setting the price for any replacement power and that annual RPS solicitations were important for maintaining a vigorous RPS market.
SDG&E stated that it too was not done with procurement and would need further procurement to comply with the 2016 goal under SBX1-2.
Other parties also advocated in favor of a 2011 solicitation, with TURN noting that there may be some bargains available to the utilities due to the fact that no RPS solicitation was held last year and that competition would be fairly robust for RPS contracts.
The Division of Ratepayer Advocates was one of the few dissenters (along with CARE), arguing that because a new cost containment mechanism would apply under SBX1-2, the CPUC should consider waiting until it had addressed cost containment before commencing a new RPS solicitation.
The parties also discussed various issues to be resolved by the PD, including how economic curtailment should be handled in the pro forma RPS contract, congestion adders and integration cost adders. As currently drafted, the PD would require all three utilities to amend their pro forma agreements to use the economic curtailment provisions proposed by PG&E, which would allow utilities to economically curtail projects up to five percent of the project’s expected annual generation, for which PG&E would pay the project the full contract price but would not reimburse the project for any lost production tax credits. The California Wind Energy Association noted that although it supported PG&E’s proposal, the proposal should be amended to make it clear that the cap applies to any economic curtailment caused by the utility, even if the curtailment was in fact ordered by the California Independent System Operator, and to provide for the payment of any lost production tax credits as well.
As for congestion adders, the PD would require the utilities to consider congestion costs when evaluating projects and order the utilities to release congestion cost information in their 2012 and future plans, so that project developers will be fully informed when making siting decisions.
Finally, the PD declined to allow the use of integration cost adders when evaluating bids, despite both SCE’s and SDG&E’s requests that they be permitted to do so.
If you have any further questions on this all-party meeting or any other California energy regulatory issue, please contact:
COMMISSIONER FLORIO NOTICES ALL-PARTY MEETING CONCERNING 2011 RENEWABLE PORTFOLIO STANDARD PROCUREMENT
On February 11, 2011, California Public Utilities Commission (CPUC) Administrative Law Judge Burton Mattson issued a Proposed Decision conditionally accepting the 2011 Renewables Portfolio Standard (RPS) Procurement Plans for Southern California Edison, Pacific Gas and Electric Company, and San Diego Gas and Electric Company. If adopted, the Decision would set a schedule for the utilities’ 2011 RPS solicitation. The Decision was on the agenda for the CPUC’s March 24, 2011 business meeting, but was held at Commissioner Florio’s request until the April 14 meeting.
On March 17, 2011, Commissioner Florio noticed an all-party meeting on the Proposed Decision for March 25, 2011. Yesterday, Commission Florio circulated an agenda for the meeting. Among the issues raised by the agenda is whether an RPS solicitation in 2011 is necessary and prudent.
Stoel Rives’ Partner Seth Hilton will be present at the all-party meeting, and will provide an update afterwards.
The second of two bills that would drastically impact the Washington State Renewable Portfolio Standard (RPS) was recently introduced in the Washington State Legislature. HB 1890 would cut in half the amount of energy utilities are required to obtain from new renewable resources, and also allow them to offset renewable energy requirements with energy from fresh water sources and sources that predate March 31, 1999.
Currently, electric utilities in Washington that serve more than 25,000 customers are required to obtain the following percentages of their electricity from new renewable resources:
- At least 3% by January 1, 2012
- At least 9% by January 1, 2015
- At least 15% by January 1, 2020
This has been the case since the passage of the Washington Energy Independence Act (EIA) in 2006. HB 1890 would cut these percentages in half -- requiring eligible utilities to acquire only 1.5% of their energy from renewable sources by 2012, only 4.5% by 2015, and only 7.5% by 2020.
In addition, the EIA treats as eligible only incremental electricity produced as a result of efficiency improvements completed after March 31, 1999 and excludes energy from fresh water resources. HB 1890, however, would count as eligible all electricity from an existing generation facility powered by a fresh water renewable resource that commenced operation before March 31, 1999. In other words, fresh water energy resources that have been operating since before March 31, 1999 -- and are unchanged and unimproved since that time -- would count toward the RPS.
Washington HB 1890 is sponsored by Rep. Brad Klippert (R-8th Dist.), Rep. Jan Angel (R-26th Dist.), Rep. Dan Kristiansen (R-39th Dist.), Rep. Shelley Short (R-7th Dist.), Rep. Larry Haler (R-8th Dist.), Rep. Barbara Bailey (R-10th Dist.), and Rep. Jim McCune (R-2nd Dist.). It was introduced and referred to the Environment Committee on February 8, 2011.
Another bill that would essentially wipe out the Washington State RPS altogether was introduced earlier this session. The blog post on that bill, SB 5563, is available here.
Currently, electric utilities in Washington that serve more than 25,000 customers are required to obtain the following percentages of their electricity from new renewable resources:
- At least 3% by January 1, 2012
- At least 9% by January 1, 2015
- At least 15% by January 1, 2020
This has been the case since the passage of the Washington Energy Independence Act in 2006. The current Legislature has introduced a bill which, if passed, would essentially wipe out these RPS requirements. SB 5563 -- which was introduced in the Washington State Legislature on January 31, 2011 -- plainly states its intention of “temporarily suspending provisions of the energy independence act during periods of economic downturn.” If SB 5563 passes, qualifying utilities would be deemed to have met the 2012 target and, from 2015, the target for any year in which the the Washington unemployment rate goes above six percent. Furthermore, utilities would be deemed to have met their renewable target not only for that year but for four subsequent years, regardless of the unemployment rate during the look back period.
A historical look at Washington’s unemployment rate shows that a look back period for four years would be able to eliminate the RPS standards in even the most prosperous economic times. For example, Washington state’s unemployment rate for the past 20 years was below 6% during only five calendar years (1998, 1999, 2000, 2006, 2007) and never for more than three consecutive years. That means if SB 5563 had been in effect for the past two decades -- decades that included some of the most robust economic times this generation has known -- at no time would utilities have been required to meet the renewable energy requirements of the EIA. Given where the U.S. economy currently stands, it’s highly unlikely SB 5563 would play out any differently for the next 20 years, much less between now and 2020.
Washington SB 5563 is sponsored by Sen. Jerome Delvin (R-8th Dist.), Sen. Mark Schoesler (R-9th Dist.), Sen. Mike Hewitt (R-16th Dist.), Sen. Jim Honeyford (R-15th Dist.), and Sen. Tim Sheldon (D-35th Dist.) and was referred to the Environment, Water & Energy Committee on January 31, 2011.
 Not seasonally adjusted.
The California Public Utilities Commission Lifts Moratorium on Approval of Tradable Renewable Energy Credit Transactions; Limits Use of Out-of-State Generation for California RPS Compliance
A legal update from our colleague Seth Hilton:
Ten months after initially authorizing the use of tradable renewable energy credits (TRECs), the California Public Utilities Commission (CPUC) today lifted its moratorium on approval of TREC transactions. CPUC Dec. 11-01-025. Today’s decision, however, retains restrictions on TREC transactions that could limit the amount of out-of-state generation that the three major investor-owned utilities can use to meet their California Renewable Portfolio Standard (RPS) obligations.
At its March 11, 2010 meeting, the CPUC authorized the use of TRECs for compliance with the RPS, subject to certain limitations. CPUC Dec. 10-03-021 (March Decision). Among the limitations that the March Decision imposed was a cap limiting the use of TRECs for RPS compliance for the largest investor-owned utilities (Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric) to 25% of their annual RPS compliance obligations. That cap was to remain in place until December 31, 2011, when the CPUC would consider modifying or removing that limitation. The March Decision also imposed a price cap of $50 per TREC. The price cap was also set to expire on December 31, 2011.
An alert written by Stoel Rives partner Seth Hilton:
Last night, the California legislature failed to pass Senate Bill 722—the 33% Renewable Portfolio Standard (RPS) legislation—by the close of the legislative session. The bill would have increased California’s RPS to 33% for both investor-owned and publicly owned utilities. It would also have placed limits on the use of renewable resources located out-of-state to meet California’s RPS—utilities would have been required to meet a certain percentage of their RPS obligations through resources whose first point of interconnection was a California balancing authority, or whose power is transmitted to California through a dynamic transfer arrangement or scheduled hourly or inter-hourly into California. The proposed legislation also would have authorized the use of renewable energy credits (RECs)—the environmental attributes of renewable power separated from the power itself—for RPS compliance, but would have imposed limits on the amount of RECs that could be used to meet the utilities’ RPS obligation.
Last year, California also failed to enact a 33% RPS bill, similar to SB 722, although the process proceeded farther than this year. Last year, the legislature passed the bill, but it was vetoed by Governor Schwarzenegger due to concerns about the limits placed on the use of out-of-state generation. Like SB 722, last year’s bill would have limited the extent to which California could rely on out-of-state renewable resources to meet California’s RPS. Part of the failure of SB 722 to pass this year can be attributed to disagreements between the legislature and the Governor regarding what limits would be appropriate for out-of-state generation.
Despite his concern about limits on out-of-state generation, Governor Schwarzenegger supports increasing California’s RPS to 33%. Following his veto of the legislation last year, he issued an executive order directing the California Air Resources Board (ARB) to develop regulations to implement a 33% RPS under authority the ARB had under AB 32, California’s Global Warming Solutions Act. Pursuant to the executive order, the ARB was to enact those regulations by July 2010. Shortly before the ARB considered those regulations, the Governor requested via letter to the ARB that it postpone consideration of those regulations while the legislature attempted to pass a 33% RPS bill. ARB therefore moved the hearing on those regulations to September 22, 2010. With the failure of SB 722, ARB may now move forward with those regulations, although there are questions regarding the extent to which those regulations would be implemented by the new Governor.
In March, the California Public Utilities Commission (CPUC), which is responsible for administering portions of California’s current 20% RPS for investor-owned utilities, adopted a decision that would have authorized the use of RECs to meet the 20% RPS, subject to certain caps. In May, the CPUC stayed that decision. If SB 722 were enacted, it would have preempted the CPUC’s efforts to set standards for the use of RECs. Just last week, the CPUC issued a proposed decision that, if adopted, will lift the stay. The proposed decision was seen by many as an effort to encourage the legislature to act on SB 722 and adopt standards for the use of RECs. Now that the legislation has failed, the CPUC is free to move forward with its proposed decision allowing the use of RECs, and to lift the stay of the March decision.
If you have any questions about the issues of this update, please contact:
Steven Hall at (503) 294-9434 or email@example.com
Seth Hilton at (916) 319-4749 or firstname.lastname@example.org
Jennifer Martin at (503) 294-9852 or email@example.com
Marcus Wood at (503) 294-9434 or firstname.lastname@example.org
On Thursday March 11, 2010, the California Public Utility Commission (the "CPUC") created a market for tradable renewable energy credits ("TRECs") in the state. That's big news. In its 149-page decision, the CPUC stated that investor-owned utilities ("IOUs"), energy service providers, and community choice aggregators may now use TRECs to comply with California's ambitious renewable portfolio standard ("RPS"). These entities are now permitted to purchase a portion of their RPS compliance from generation sources other than those they own (e.g., distributed solar generation facilities within the state and certain out-of-state facilities).
Think of a renewable energy credit as the "green" portion of a unit of electricity generated from an RPS-eligible facility (e.g., wind, solar, geothermal). Together, the "green" renewable energy credit and the unit of electricity that it came with are bundled; separate them, and they become unbundled. The CPUC's decision allows an RPS-eligible generator to unbundle the renewable energy credits and sell them separately from the electricity they were generated with. Thus, the renewable energy credits become tradable (i.e., TRECs).
The CPUC made its decision to allow the unbundling of renewable energy credits for two main reasons, both of which seem perfectly reasonable in light of California's push toward distributed solar generation and the conflict that is created when utilities need to meet ever-increasing RPS requirements in an atmosphere of stringent siting regulations for new projects under the California Environmental Quality Act.
- First, the CPUC created a market for TRECs to aid utilities with RPS compliance.
- Second, the TREC market is intended to incentivize development of more RPS-eligible generation, like rooftop solar modules.
A few highlights of the CPUC decision deserve particular attention:
25% Cap on TRECs: IOUs may only meet 25% of their RPS requirement with TRECs under the program. However, that 25% cap will be lifted in 2011 (unless the CPUC changes its mind).
Interim Price Cap: The CPUC set a price cap of $50 per TREC that is used for compliance by an IOU. However, that price cap will also be lifted in 2011 (unless the CPUC changes its mind).
3-Year Tradable Life: To count TRECs toward its RPS requirement, a participating utility must meet CPUC requirements for TREC-trading and Western Renewable Energy Generation Information System ("WREGIS") requirements for TREC-tracking. During the first 2-3 years of the program, the CPUC does not expect much activity in the market; so to ensure liquidity, new TRECs must be retired with WREGIS within 3 years from the date the TREC was created. "Retiring" a TREC means that the ultimate owner has applied the TREC's compliance value to the owner's California RPS requirement with WREGIS and the TREC is taken out of the market. However, once retired, a TREC's compliance value may be banked indefinitely.
TRECs Under Existing Contracts: TRECs generated in future years under existing RPS contracts (i.e., TRECs generated from this day forward) may be unbundled and sold separately under certain conditions set out in the CPUC's ruling.
Out-of-State Suppliers & Bundled Transactions: Bundled transactions must benefit California-customer load. Therefore, only electricity that comes from (1) California-connected generators and (2) out-of-state suppliers that can demonstrate that the bundled product that they deliver to California is not "shaped" using non-RPS-eligible resources, may qualify.
No Bundled Transactions for In-State Generators Selling Out-of-State: When an IOU purchases renewable energy credits (whether bundled or unbundled) from a generator located in California that sells its electricity outside of the state, the CPUC will consider that an unbundled purchase for purposes of reporting and retiring the credits. Therefore, renewable energy credits bought from an RPS-eligible generator serving out-of-state loads will count toward the IOU's 25% cap.
From an economic standpoint, the CPUC hopes that creating a market for TRECs will increase the overall efficiency of the RPS program. By allowing the market to set separate prices for TRECs and for the electricity associated with generating them, the CPUC believes that the public will benefit because the price of each will reflect its actual value.
Upcoming Webinar: Impact of State RPS's and the Prospect of a Federal RPS on What Utilities are Doing in Terms of Purchasing the Output of Wind Farms - January 27, 2010
With 3/5 of the States having Renewable Portfolio Standard in place and the prospect of a Federal RPS, many utilities are seeking to become first time purchasers of the output from wind projects. And utilities with a history of purchasing wind are seeking additional resources. In 2009, the presenters collectively worked on over 40 wind power purchase agreements for projects located throughout the United States, enabling them to present a comprehensive overview of the impact of these developments. A number of first time purchasers have been using the RFP process as a vehicle for educating themselves about wind, and often experience difficulty in translating PPA terms that are appropriate for base load resources into PPA terms that work for intermittent resources like wind. Through various PPA terms, utilities are increasingly seeking to place the risk of non-compliance with the RPS on the wind project developer. These developments can result in PPA terms that are very problematic for the financing of the project. This webinar will explore these recent developments, including issues related to output and availability guarantees, allocation of curtailment risk for long-distance transmission to load, wind integration charges, delay damages, conditions precedent, termination rights and the measure of damages.
Edward D. Einowski, Partner, STOEL RIVES LLP
To register: http://infocastinc.com/index.php/conference/255
The California Public Utilities Commission ("CPUC") issued a proposed decision on December 23, 2009 that would, if adopted, allow California investor-owned utilities, energy service providers, and community choice aggregators to purchase renewable energy credits alone, without the associated energy (sometimes referred to as "unbundled renewable energy credits ("RECs)" or "tradable RECs"), to satisfy their obligations under California's RPS. California's largest investor-owned utilities—Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric—would be limited to meeting no more than 40% of their annual procurement targets under the RPS with tradable RECs, and a price cap of $50 would be imposed. The CPUC will revisit both the percentage cap and the cost cap and whether those caps should be revised within 24 months of the decision.
Out-of-state renewable energy projects could be adversely impacted if the proposed order were adopted. The proposed decision would define all renewable generation purchased from out-of-state facilities1 as the purchase of unbundled or tradable RECs, making any out-of-state renewable energy sale subject to the cap that bars the large investor-owned utilities from using such sales to meet more than 40% of their overall RPS obligation. Although the proposed decision states that this classification would apply only to contracts signed on or after the effective date of the decision, contracts signed prior to the effective date would be considered REC-only contracts from the effective date forward, and would be "subject to the limits and rules applying to REC-only contracts" according to the proposed decision. Furthermore, although the purchase of tradable RECs from out-of-state facilities would be permitted, the delivery requirement in the RPS legislation would still have to be met, so a comparable amount of power would have to be imported into the state, along with the RECs. The jurisdiction to determine whether and how this delivery requirement is met, however, still remains with the California Energy Commission.
Comments on the proposed decision are due on January 19, 2010, and reply comments are due January 25, 2010.
For additional information about the history and effect of the proposed decision, see our Stoel Rives alert on the topic.
Activity is underway in Michigan to implement the state's recently-enacted renewable portfolio standard, which requires the state's electric utilities to serve 10 percent of their retail sales from renewable energy resources by 2015. In late December, Detroit Edison issued a Request for Proposals to purchase Michigan-based renewable energy credits that will help the utility meet the RPS requirements.
The RFP specifies that the renewable energy certificates must come from resources located in Michigan. Under the state's RPS, qualifying renewable technologies include energy produced from wind, solar, landfill gas, biomass, anaerobic digesters, geothermal, hydroelectric dams, industrial cogeneration and gasification facilities. Detroit Edison states that it is seeking long-term agreements with providers.
Bidder questions, which must be posted to the Power Advocate website, are due by Jan. 13, 2009. Responses to the RFP are due by Jan. 23, 2009.
On October 28, 2008, the Ohio Power Siting Board adopted rules implementing certification requirements for wind generating facilities in the state. The full text of the opinion and order approving the rules identifies the procedural background followed by the PSB and highlights comments received from all interested parties (including utilities, citizen groups, and AWEA). The The rules follow Ohio's passage in May 2008 of an RPS which requires that utilities provide 25% of their retail electricity supply from alternative energy resources by 2025, at least half of which must be generated by renewable resources such as wind.
The California Public Utility Commission issued a draft decision on October 29th authorizing the use of unbundled and tradable renewable energy certificates (“RECs” or “TRECs”) for compliance with California’s RPS.
The draft decision also outlines the structure and rules for a tradable REC market and for integrating these RECs into the RPS “flexible compliance system.” Comments are due on Nov. 18, 2008. The draft decision can be found here: http://docs.cpuc.ca.gov/efile/PD/92913.htm.