On August 15, 2011, Great River Energy (GRE) issued a request for proposals (RFP) for community-based energy development (C-BED) renewable energy resources. Eligible energy technologies include: wind, solar, hydroelectric of less than 100 megawatts, biomass, municipal solid waste, landfill gas and anaerobic digesters, and hydrogen produced from any of the previous resources.
In announcing the RFP, GRE noted that it already has enough renewable resources in its energy portfolio to meet Minnesota's Renewable Energy Standard. Minnesota's RES requires electric utilities to supply an increasing percentage of their energy sales from renewable energy sources, reaching 25 percent by 2025. Nevertheless, GRE issued the RFP to "evaluate if additional C-BED renewable resources can provide value to our member cooperatives in the future," according to Jon Brekke, Great River Energy vice president of member services. GRE plans to evaluate proposals based on their impact to wholesale power rates and other factors.
Proposals are due before 4pm Central Prevailing Time on Sept. 9, 2011. GRE plans to notify short listed bidders by September 30 and has targeted November 1, 2011 as the execution date for a power purchase agreement (PPA). GRE is clearly looking for bargains from developers who can take advantage of the Section 1603 cash grant, a program that expires on December 31, 2011, and who can place a project in service by December 31, 2012. Since projects seeking the cash grant will need to "begin construction" (as that concept is defined in Section 1603) by December 31, 2011, the November 1 target execution date will likely be critical for developers seeking to arrange project financing before year end.
GRE is interested in entering into a PPA rather than a build-transfer or other ownership arrangement. GRE's form of PPA can be found here. The RFP itself can be found here. For more information about the RFP, contact Mark Rathbun at 763-445-6104 or email@example.com.
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.
The Oklahoma legislature passed three bills (H.B. 2973, S.B. 1787, and H.B. 3028) in 2010 that affect the renewable energy industry. Two have already gone into effect and the third will go into effect on January 1, 2011. A summary of each bill is included below.
The Oklahoma Wind Energy Development Act (the “Act”), H.B. 2973, becomes effective on January 1, 2011 and will be codified in Okla. Stat. tit. 17 §§160.11-17 (2010). The Act includes the following:
- Decommissioning: Decommissioning requirements apply to any wind energy facility entering into or renewing a power purchase agreement (PPA) on or after January 1, 2011. If energy is not being sold under a PPA, the requirements apply to wind energy facilities which commence construction on or after January 1, 2011. The requirements include:
- Restoration: Owners of a wind energy facility must remove wind energy equipment (to a depth of 30”) and restore land surfaces to substantially the same pre-construction condition (excluding roads) within 12 months of abandonment of a project or the end of the useful life of the equipment.
- Cost Estimate and Posting of Financial Security: After the 15th year of operation, facility owners must file a professional estimate of the decommissioning costs together with a financial security (either a surety bond, collateral bond, parent guaranty or letter of credit) to cover such costs. Those failing to so file may incur an administrative penalty of up to $1,500/day.
- Payment Statements and Access to Records: Any owner or operator making payments to landowners based on the amount of electrical energy produced is required to deliver a statement to the landowner, within 10 business days of payment, explaining the payment calculation and a means for the landowner to confirm its accuracy. Landowners have the right to inspect owner/operator records to confirm the accuracy of payments for up to 24 months following payment. Records must be made available for review within the state of Oklahoma.
- Insurance: Owners or operators are required to obtain commercial general liability insurance policy with limits consistent with prevailing industry standards (or a combination of self insurance and excess liability insurance policy), which name the landowner as an additional insured and certificates of insurance must be delivered to landowner prior to commencing construction of the facility.
No Severance of Wind and Solar Rights. Wind and solar right severance was restricted in another Senate bill out of the same session, Oklahoma S.B. 1787. The bill restricts the permanent severing of rights to the airspace above the surface estate for the purpose of developing and operating commercial wind and solar energy conversion systems. Thus wind and solar resource leasing arrangements (broadly defined to include easement and option arrangements) must be made with the legal owner of the surface estate. The bill confirms that wind and solar agreements run with the land and outlines provisions for recording the interest. The bill will be codified in the Okla. Stat. tit. 60 §820.1 (2010) and became effective July 1, 2010 .
15% Renewable Generation Capacity by 2015. The Oklahoma Energy Security Act (the “OES Act”), H.B. 3028, sets a goal that 15% of all installed electric generation capacity within the state be generated from renewable energy sources by 2015. Qualifying renewable energy resources include: wind, solar, photovoltaic, hydropower, hydrogen, geothermal and biomass (including crops, residues, animal waste, MSW and landfill gas). Demand side management can be used to meet up to 25% of the overall 15% goal. Notably the OES Act does not include any provision for the use of renewable energy certificates (RECs) to meet the goal.
Expand Transmission in SW. To better facilitate wind-energy development, the OES Act also directs the legislature to work with the Southwest Power Pool to develop a plan to expand transmission capacity in Oklahoma.
Develop Natural Gas and Add Fueling Stations. Noting the opportunity to develop Oklahoma’s abundant natural gas resources, the OES Act sets natural gas as the preferred choice for any new fossil fuel based electric generation capacity until January 1, 2020. It also sets a goal to develop public CNG fueling stations every 100 miles along the interstate highway system by 2015 and every 50 miles by 2025. The OES Act became effective November 1, 2010 and will be codified in the Okla. Stat. tit. 17 §§801.1-7 (2010).
Air Resources Board Adopts 33% Renewable Energy Standard; Four California Energy Agencies Vow to Cooperate on Implementation
Last Thursday evening, the California Air Resources Board (ARB) unanimously adopted its Renewable Energy Standard (RES), mandating that California's electric utilities—both public and investor-owned—procure 33% of their electricity from renewable resources by 2020. The RES was adopted pursuant to the authority granted the ARB in AB 32, the California Global Warming Solutions Act of 2006, which vested the ARB with the authority to promulgate regulations to reduce California's greenhouse gas emissions. The RES requires utilities to submit plans by July 2012 on how they will comply with the new regulations. The regulation includes several multi-year compliance intervals—from 2012 to 2014 the RES is 20%, from 2015 through 2017 it is 24%, from 2018 to 2019 it is 28%, and from 2020 forward the RES remains at 33%. The RES is met through the retirement of Western Renewable Energy Generation Information System (WREGIS) certificates; unlike the current 20% Renewable Portfolio Standard (RPS) that applies to investor-owned utilities, there is no requirement that any energy be delivered to California. WREGIS certificates may be retained or traded for up to three years, utilities may also bank those certificates for RES compliance indefinitely. The RES also provides that ARB will conduct comprehensive reviews of the program by December 31, 2013, 2016, and 2018, and that those reviews may trigger modifications to the RES.
The proposed RES faced vigorous opposition from a variety of sources. On September 20, 2010, Senate President Pro Tempore Darrell Steinberg and Speaker of the California Assembly John Perez sent a joint letter to ARB Chair Mary Nichols, urging the ARB to set aside consideration of the RES, as the ARB's proposed action was "contrary to law, creates economic uncertainty and potential job losses…, and creates an inefficient and duplicative state bureaucracy." The letter noted that the Legislative Analysis Office had opined that the ARB lacked the authority to implement the RES, and recommended that the legislature de-fund those positions being used by the ARB to proceed with RES adoption.
The letter also noted that California also has two energy agencies already involved in implementing the legislative 20% RPS—the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC)—and that the ARB's efforts to regulate the increase from a 20% RPS to a 33% RES would lead to inefficiencies and wasteful spending.
Perhaps to address concerns about inefficiencies and duplications of effort, the following day, on September 21, 2010, the ARB, CPUC, CEC, the California Environmental Protection Agency and the California Independent System Operator released a report entitled "California's Clean Energy Future," an implementation plan and roadmap for reaching 33% renewables by 2020. In its resolution adopting the RES, the ARB also emphasized its intent to cooperate with the CPUC and CEC on implementation of the RES.
One area of potential conflict between the 20% RPS administered by the CEC and the CPUC and the RES is the lack of any delivery requirement under the RES—compliance is demonstrated through the surrender of renewable energy credits unbundled from the associated renewable energy. In contrast, the 20% RPS requires that energy be delivered to California. The CPUC is currently considering a proposed decision that would allow the use of unbundled or tradable renewable energy credits for compliance with the 20% RPS, but that would put caps on the amount of such credits that could be used for compliance.
However, the ARB resolution adopting the RES states that no later than 30 days after the CPUC adopts its decision regarding tradable renewable energy credits, the ARB will initiate a rulemaking to ensure "continued harmonization of the two programs, specifically incorporating provisions related to Tradable Renewable Energy Credits for all regulated parties under the RES regulation."
There remain significant questions as to whether the RES will ever be implemented. In addition to comments from the legislature concerning potential de-funding of any positions used to implement the regulations, the elections this November could also change the course of implementation. Depending on who is elected governor, the new governor may seek to suspend the ARB's implementation of the regulation, or to have it modified. Also on the November ballot is Proposition 23, which would suspend implementation of AB 32, the Global Warming Solutions Act. ARB's claimed authority to implement the RES is primarily based the grant of authority given it under AB 32. Continued efforts are also underway to have the legislature pass a 33% renewable statute that would preempt ARB's efforts. Finally, given the uncertainties concerning ARB's authority to implement the new regulation, a legal challenge to that authority is also a possibility.
If you have any questions about the issues of this update, please contact:
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.
In a January 8 letter to the Minnesota Public Service Commission, Xcel Energy informed the Commission that it intends to conduct competitive negotiations with wind projects that are able to interconnect at Xcel's Angus Anson generating station in Sioux Falls.
The Angus Anson plant is a gas-fired peaking facility that has firm transmission to deliver its output. Xcel wants to make better use of this transmission by looking at ways to locate wind generating capacity nearby and connect it to the transmission system at Anson. Over the next several months, Xcel plans to accept proposals and conduct competitive negotiations for wind projects that can interconnect at the Anson site. Xcel does not believe that transmission upgrades will be needed for the proposed interconnection.