Non-Profit Groups Challenge Colorado's RES and Question Public Policy Favoring Wind Energy
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.
Colorado Signs MOU for Small Hydro Development with FERC
On August 25, 2010, the Federal Energy Regulatory Commission ("FERC") and the State of Colorado signed a Memorandum of Understanding ("MOU") which could lead to simplified procedures and regulations for authorizing small-scale hydropower development in Colorado. Although traditional hydropower has not seen significant new development in recent years, interest in small, low-impact projects is on the rise across the country.
In Colorado, federal surveys have identified several hundred potential small-scale hydropower projects under five megawatts (5 MW), which could have a combined capacity of more than 1,400 MW. These new projects, if developed, could provide a needed boost for the state: on March 22, 2010, Colorado again increased its Renewable Energy Standard, requiring investor-owned utilities to procure 30% of their total retail sales from renewable resources by 2020.
Under the MOU, "Colorado proposes to implement a pilot program to identify and test opportunities to simplify and streamline procedures and regulations for authorizing small scale hydropower projects in an environmentally sound manner." The pilot process would require the State to prescreen projects to ensure that they qualify for either of the two exemptions from FERC's licensing provisions under Part I of the Federal Power Act: (1) the conduit exemption and (2) the 5 MW exemption. While only facilities being added to existing infrastructure will qualify for the pilot program, the benefits for those projects are marked. So long as Colorado state and federal resource agencies and any affected Indian tribe waive compliance with the consultation requirements of 18 CFR section 4.38(e) for a project prescreened by the State, FERC will waive the first and second stages of consultation in 18 CFR sections 4.38(b) and (c). The pilot program will continue until 20 projects have gone through the program.
While FERC's offer to waive consultation may be considered a symbolic gesture because it is conditioned on a "first move" by the State and other federal agencies, the MOU still represents an effort by the agency to develop innovative ways to streamline new, small-scale hydropower development in Colorado.
NOTE: Nothing in the MOU prevents a developer from proceeding through the traditional FERC licensing and exclusion process outside of the pilot program.
Colorado Public Utilities Commission Proposes New Rules Governing Transmission Planning
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.
Colorado Increases its Renewable Energy Standard to 30% by 2020
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.
Colorado Division of Property Taxation Considers Proposed Tax Treatment of Transmission Lines
The Colorado Division of Property Taxation will hold an important open public meeting Thursday, January 14, 2010, to discuss the "tax treatment of transmission lines". Details of the proposed options will be posted on the Division's website under the "state assessed tab." In the notice provided by the Division, the agenda for the meeting will include addressing the following questions:
- Is the value of the transmission lines accounted for anywhere using the current valuation methodology?
- If not, how should this be accounted for?
- Pick up locally.
- Add to the value of the renewable energy facility determined by the state.
- Increase the capital cost threshold to account for the transmission line.
While the details of the proposed tax treatment have not been disclosed publicly, it is currently unclear how this will impact new and existing transmission lines, including gen-tie lines from renewable energy projects. The Division has provided a remote access opportunity to participate in the meeting. For those interested in attending in person, the meeting will be held at the Division of Property Taxation Office, 1313 Sherman Street, Room 419, Denver, Colorado 80203. It is anticipated that key parties involved in the development of renewable energy projects will be in attendance, along with representatives from the Interwest Energy Alliance.
To the degree that the proposed change in tax treatment increases the taxes borne by existing facilities--most of which have already entered into power purchase agreements--the experience underscores a topic that developers ought to consider when negotiating long term PPA's: if a tax or other charge imposed after the PPA's effective date materially increases a project's cost burden, does the developer have the right under the PPA to pass any or all of the costs onto the buyer? If not, does the developer have any right to renegotiate or terminate the PPA so as to reprice it to account for the unexpected tax burden? Or must the developer absorb the cost for its own account?
Utility pro forma PPAs rarely allow the developer to pass such "change of cost" risks through to the buyer, but the Seller should nonetheless carefully consider such risks (e.g., changes in taxes or integration charges) and its willingness to absorb all of those risks over the life of a long term PPA--it is sometimes possible to negotiate a sharing of unexpected costs that arise after the effective date of the PPA, especially if the utility offtaker is in a position to resist the imposition of such costs.
