Intermittent resources create unique challenges for 21st Century Utilities, RTO's and System Operators. The now infamous "Duck Chart" highlights a key element of the problem -- central station thermal plants cannot ramp efficiently, leading to "worst of all" scenarios where the benefits of renewables are not fully utilized and central station plants operate inefficiently for extended periods.
By contrast, fast-ramping distributed generation creates a path to the opposite result. With fast-ramping support, central station plants remain at an efficient "steady state" while intermittent renewables operate at maximum output, providing emission-free generation with no variable fuel costs. These efficiencies result in substantial and quantifiable economic benefits.
The U.S. Defense Department (DOD) seeks to procure renewable energy at or below market prices, and is not considering fast ramping generation in its current procurement plans. Because there is no economic incentive for DOD to invest in such resources, and because markets for fast-ramping generation and ancillary services are largely non-existent, the current policy framework lacks a vehicle for attracting investment in fast-ramping distributed energy and related technologies.
Manufacturers of fast-ramping generation equipment are studying issues relating to intermittent energy resources. Among other initiatives, they have developed economic models that demonstrate system-wide efficiencies produced by fast-ramping technologies. The models have been vetted by credible public and private sector organizations and found to be both accurate and insightful.
With their policy expertise and purchasing power, the Department of Energy and DOD can play a role in developing policies and markets that allow such technologies to take hold and proliferate.
Xcel Energy, Minnesota Power, Center for Energy and Environment, George Washington University, and other stakeholders participated in the first e21 Initiative meeting on February 28. The e21 Initiative aims to develop a new or adapted regulatory framework that addresses the challenges of the evolving energy economy and shifting technological landscape. There will be three phases for this effort. The first will be stakeholder meetings where participants will discuss specific and practical steps to accomplish the objectives summarized here. In the second phase, participants will focus on developing recommendations for modifying the statutory and regulatory framework in Minnesota, with a focus on the utility business model. In the third phase, participants will address implementing the action steps identified in the second phase. The e21 Initiative will be moderated by the Great Plains Institute. Stay tuned for additional blog posts and monitor the Great Plains Institute’s website for additional information.
This morning, Xcel Energy announced plans to issue a Request for Proposals (RFP) for up to 150 MW of solar energy generation. Xcel included its RFP plans in a filing submitted to the Minnesota Public Utilities Commission (Commission) outlining its strategy for complying with Minnesota’s new solar energy standard. The standard requires that public utilities like Xcel obtain 1.5 percent of their retail sales from solar energy resources. Xcel expects to obtain about 1/3 of its Minnesota solar requirement from distributed solar resources (including community solar gardens and small projects eligible for certain incentives). The other 2/3 of the mandate would be met via large-scale solar projects, which are the focus of the RFP.
Xcel anticipates issuing the RFP on April 15, 2014 with proposals due June 1, 2014. Following contract negotiations, selected projects would be submitted to the Commission in October 2014.
In other Minnesota solar news, the Commission conditionally approved Xcel’s community solar garden plan yesterday, including the interim rates we wrote about last week. A compliance filing will be due within 30 days of the Commission’s written order. Then, Xcel is required to open the program within 90 days of the Commission’s approval of the compliance filing.
Democratic legislators in Wisconsin plan to unveil a plan this week that would require investor-owned utilities, municipal utilities, and rural electric cooperatives (“electric providers”) to increase their renewable electricity portfolios to 30% by 2030. Wisconsin’s current renewable portfolio mandates that electric providers obtain 10% of their retails sales from electricity generated from renewable resources by 2015.
In addition to the increased mandate, the bill would create for the first time a requirement that electric providers secure a certain amount of power from waste-to-energy digester projects. Meanwhile, an alternative proposal introduced by Republican legislators would allow nuclear power to qualify as an eligible renewable technology.
While the Democratic bill faces an uphill battle to become law, many commentators predict Wisconsin will eventually need to act on this issue as a result of the U.S. Environmental Protection Agency’s plans to regulate greenhouse gas emissions from coal-fired power plants.
My colleague, Daniel Lee, followed oral argument yesterday in the U.S. Supreme Court's consideration of federal greenhouse gas (GHG) regulation in Utility Air Regulatory Group v. EPA, and provides this analysis:
During oral argument for Utility Air Regulatory Group v. EPA this Monday, the Supreme Court conflicted over a number of issues including the application of Chevron deference, the scope of the Court’s holding in Massachusetts v. EPA, and the nature of the Prevention of Significant Deterioration (PSD) program under the Clean Air Act (CAA). At the broadest level, the Court will decide whether the EPA’s PSD program regulating emissions from stationary sources will apply to greenhouse gas emissions. Much of the Justices’ questioning focused on whether EPA’s interpretation, that the PSD statute required regulation of GHGs, was reasonable and would receive Chevron deference. Pointing out that the parties had advanced four separate interpretations of the statute, Justice Sotomayor suggested the statute’s “quintessential ambiguity” implicated Chevron. Justice Kagan went further to suggest that EPA’s interpretation was “most reasonable” in light of its longstanding adherence to the position and that there is “nothing that gets more deference than this Agency with respect to this complicated a statute.”
To overcome the Chevron hurdle, petitioners emphasized the incongruence between the local focus of the PSD program and the broader, global effects of GHGs. However, Justice Ginsburg countered that GHGs had “severe effects at the local level” according to EPA’s endangerment finding. In contrast, Justice Alito emphasized that GHGs are nevertheless distinguishable from other substances regulated under the PSD program because of the large quantity of GHGs emitted.
Less aggressive was the questioning from Justice Kennedy, whose vote has often been the deciding factor for the Court. Justice Kennedy reaffirmed that the Court must abide by Massachusetts v. EPA, but nevertheless indicated that he “couldn’t find a single precedent that strongly supports” the EPA’s position. Yet he also opined that Brown & Williamson, a case relied on by the industry petitioners, was also distinguishable.
If EPA’s interpretation is upheld, PSD and Title V permitting programs will continue to apply broadly to industrial emitters of GHGs. If EPA’s interpretation is not upheld EPA could continue to regulate GHGs through the New Source Performance Standards program but would presumably need to withdraw the PSD and Title V permits issued for GHGs and many sources currently undergoing PSD and/or Title V permitting would see their permitting burdens greatly reduced. Additionally, Utility Air Regulatory Group v. EPA will likely add further contour to the sprawling case law on Chevron deference in the context of environmental regulation.
See our previous report on the Supreme Court's grant of certiorari in Utility Air Regulatory Group and its related cases for additional background on the controversy's road to the Supreme Court.
After a full day of hearing arguments on Xcel’s proposed Community Solar Garden (CSG) program (see more on that here), the Minnesota Public Utilities Commission deliberated in public on the issue yesterday and made some important modifications to Xcel’s proposal. The program would allow Xcel customers to invest in off-site solar facilities and receive bill credit for their portion of generation. Ultimately that credit would be at the Value of Solar rate, but as parties await a decision on the Value of Solar (VOS) methodology (more on the VOS here), the Commission settled on an interim rate for the program (though its final vote on the matter is still forthcoming). It is largely based on average retail rates but importantly includes a placeholder value of any transferred Solar Renewable Energy Certificates (SRECs). A CSG developer could transfer the S-RECs to Xcel at a compensation rate of $.02/kWh for facilities with a capacity greater than 250 kW and at $.03/kWh for those with a capacity of 250 kW or less. The S-REC value is not intended to reflect a market rate and is intended and is intended to be strictly temporary, expiring upon the approval of Xcel’s VOS tariff. Furthermore the rate and S-REC value are to be reviewed annually and adjusted if necessary.
The illustrative range of rates (assuming the SREC is transferred) is as follows:
Residential: $.14033 or $.15033
Small General: $.13738 or $.143738
General Service: $.11456 or $.12456
In addition, Xcel’s proposed 2.5 MW quarterly cap on the program was removed given the statute precludes a cap. While a final decision has not yet been issued by the Commission, newsmedia have already begun to report on it (see Star Tribune article here).
Converting a qualifying facility's legacy PURPA interconnection agreement to a FERC-jurisdictional agreement can be an effective way to bypass the numbing headache that often accompanies taking a new power generation project through the interconnection queue. One may even be able to throw in a repower and, voila!, you have a refreshed facility that can operate for decades more in broader bilateral power markets without having years of interconnection delay.
But there are ins-and-outs to these conversions, and today FERC addressed the question of whether a qualifying facility owner may necessarily convert the capacity that's stated in its PURPA interconnection agreement. For qualifying facility owners--it isn't the answer you wanted.
See FERC's order by following this link: CalWind Order.
Final comments were filed yesterday on the proposed methodology for calculating a value of solar (VOS) rate for utilities in Minnesota (more on the proposed methodology is here). With the Commission required to make a decision within 60 days of January 31, 2014, parties remain in fairly wide disagreement about what is required by statute, particularly what values are truly “known and measurable” and whether the value calculation or proposition applies to the particular utility or more broadly to society. Depending on the interpretation of these factors among others, the estimated VOS rate could vary from half of that suggested by the Department’s original $0.135/kWh example to something considerably higher. The rate would eventually apply to Xcel’s Community Solar Garden (CSG) Program and potentially as an alternative to net-metering arrangements for projects under 1MW. In a separate proceeding yesterday, the Commission set interim rates for the CSG program that could be even higher with a placeholder SREC value included (more on that in a separate blog).Continue Reading...
For those companies owning generation on the Bonneville Power Administration system, mark your calendars for March 15, 2014. That's the day by which you must submit your facility displacement costs for Bonneville's implementation of its Oversupply Management Protocol (aka Environmental Redispatch) that provides compensation for certain generator curtailments. The failure to submit facility displacement costs will result in a displacement cost of $0.00 per MWh.
So begin registering your facility with Bonneville now at https://oversupply.accionpower.com so that you are prepared for when Bonneville begins accepting displacement cost information on February 28.
Ralls Corp., a privately-held company owned by executives of the China-based heavy machinery manufacturing conglomerate Sany Group, recently filed an appeal in its ongoing effort to avoid President Obama’s order requiring the company to divest itself of its interest in four wind farms in Oregon. We have previously reported on the order, which was issued by the president on the recommendation of the Committee on Foreign Investment in the U.S. (CFIUS) and followed a similar CFIUS order. The CFIUS order was withdrawn following issuance of the executive order. Our earlier articles can be found at http://www.lawofrenewableenergy.com/tags/ralls-corp/.
On February 7, Ralls Corp. filed an appeal of the D.C. Circuit Court’s October ruling that Ralls Corp. was not deprived of due process and that it was not entitled to know the specific basis for the executive order. The appeal asserts, among other things, that the district court erred in finding that Ralls Corp. has no constitutionally protected interest in the wind projects and in granting undue discretion to the president to prohibit a transaction on national security grounds. Ralls Corp. takes particular issue with the federal government’s failure to state with specificity the factual basis for the orders and to give Ralls Corp. an opportunity to address and rebut such a statement.
Separately, the US government has initiated a civil action to force the sale of the wind projects, which are located adjacent to a US Naval facility that is believed to be used to test unmanned drones and other electronic warfare equipment, as required by the executive order.
A successful outcome for Ralls Corp. seems unlikely, given the deference the judicial branch has historically given the executive branch with respect to matters of national security. The ongoing dispute continues to serve as a reminder of the extensive authority of CFIUS and the president to intervene in transactions to protect national security interests and, therefore, the importance of notifying CFIUS of transactions that may concern national security.
In May 2013, the Minnesota Legislature passed legislation that, among other things, set a solar standard, directed Xcel Energy to develop a community solar garden program, and provided for the development of an alternative tariff mechanism to net metering that would also serve as the rate for community solar garden programs. Under this new scenario and instead of traditional net-metering arrangements, customers would potentially buy all of their electricity from their local distribution utility and then sell all of their PV generation under that utility's Value of Solar (VOS) tariff which would be designed to capture the societal value of PV-generated electricity.
The legislation directed the Department of Commerce to work with stakeholders to develop a VOS methodology and to deliver its recommendations to the Minnesota Public Utilities Commission (Commission) on Friday, January 31, 2014. The Department’s filing today includes its recommendation, with a more in-depth document addressing the methodology. The Department’s recommendations do not set a rate, but rather propose the methodology for calculating a utility-specific rate for distributed PV solar (1 MW and smaller). If the Department’s sample calculation is any indicator of what’s to come, however, the value went from $0.126/kWh in its initial draft to $0.135/kWh in the documents filed this morning.Continue Reading...
Like other Independent System Operators have done before it, the Southwest Power Pool (SPP) is back at the drawing board in an effort to further refine its generator interconnection procedures and improve on queue reforms initially put in place in 2009. And also like other ISOs that have continued to tinker with queue reform, SPP is looking to make the interconnection process more demanding so that only the "viable" projects get through.
Among the various proposed changes, there are a few that generation developers should key in on.
- SPP proposes to allow later-queued customers pass by higher-queued customers in terms of queue priority, provided that the later-queued customer is the first to reach the Facilities Study phase. Previously, customers who reached the DISIS queue could not lose their queue priority and be passed by. But now priority goes to customers who reach the Facilities Study first. This change, of course, will impact customers' cost responsibilities, as priority to unused transmission capacity will be subject to the race to the top.
- To enter the Facilities Study phase (and lock in queue priority), customers must complete a financial milestone by providing security equal to $3,000 per megawatt of the generator size. SPP has proposed removing other choices that customers previously used for entering this phase of the study process. But watch out--customers who later withdraw from the queue may forfeit this deposit.
- Prior to signing an interconnection agreement, an interconnection customer may extend its commercial operation date by no more than three years. Anything longer will be considered a material modification and will result in a loss of queue position.
- Under proposed revisions to the interconnection agreement, a customer would have three years following its designated Commercial Operation Date to complete its generating facility. A customer who fails to do so will have its interconnection agreement terminated. In addition, customers who fail to bring their full generation capacity online within that timeframe will lose rights to any capacity that remains unused at the three-year mark.
- Lastly, customers who sign an interconnection agreement must post 20% of the costs of their network upgrades within 30 days of execution. This deposit may be non-refundable under certain circumstances.
Given the queue reforms that FERC has accepted in other regions, it's likely that much of what SPP has proposed will make it into the tariff.
SPP has asked that these latest reforms be made effective March 1, 2014, and applicable to any customer who does not have an interconnection agreement with an earlier effective date. For those customers currently negotiating an interconnection agreement: the race is on.
At the close of last year, Minnesota Administrative Law Judge Eric Lipman determined that the single solar proposal in a competitive resource acquisition process would provide the best value to Xcel ratepayers (see more here). Key to his decision was his conclusion that Xcel's capacity needs in the timeframe considered were uncertain and potentially declining substantially. Yesterday Xcel and the natural gas bidders (Calpine and Invenergy) in the process filed exceptions to his findings and took sharp aim at the Judge's determination that Xcel's capacity needs appeared to be declining from what had earlier been predicted. In a related news article, Bill Grant, the Deputy Commissioner for Energy Programs at the Department of Commerce, voiced concern that the Judge had relied on an "untested and unusually low forecast for future sales" and suggested that ratepayers would be better served by Xcel's procurement of solar resources through a solar-specific process. The parties with the selected solar (Geronimo) and capacity (GRE) bids, perhaps unsuprisingly, do not agree with these voiced concerns and largely applauded the Judge'sselection of scalable resources in light of uncertain need . Reply comments are due at the end of this month and ultimately the matter will soon be taken up by the Minnesota Public Utilities Commission.
We last reported to you about Committee on Foreign Investment in the United States (CFIUS) activities in connection with the Ralls Corporation case. CFIUS is a multi-agency U.S. government committee charged with reviewing foreign acquisitions of U.S. businesses for national security implications
The committee recently released its unclassified Annual Report to Congress for 2013 regarding its activity during calendar year 2012. My colleague CJ Voss and myself have prepared an analysis of the report, available on our firm’s website. As we explain in our analysis, the report offers important insights for foreign companies that are considering investment and M&A transactions that could raise U.S. national security considerations.
Nebraska filed suit against the U.S. Environmental Protection Agency (EPA) in federal court on Wednesday, challenging the agency’s newly proposed standards for greenhouse gas emissions from new power plants. Nebraska argues that EPA’s proposed regulation, officially released last week, violates the Energy Policy Act of 2005. The Act prohibits EPA from considering new technology or a level of emissions reduction to be “adequately demonstrated” under the Clean Air Act where the emissions reduction is achieved ‘solely by reason of the use of the technology’ by one or more facilities receiving funding under the Act. Under the Clean Air Act, any new source performance standard (NSPS) must be based on the “best system of emissions reduction” that EPA determines has been “adequately demonstrated.”
EPA has proposed a greenhouse gas NSPS for new fossil fuel-fired boilers, including coal-fired power plants, based on the partial implementation of carbon capture and storage (CCS). EPA’s notice of the proposed NSPS cites to various facilities that have successfully implemented CCS, adequately demonstrating the commercial viability of the technology as a basis for the stringent greenhouse gas emissions standard of 1,000 to 1,100 lb CO2/MWh. The flaw, Nebraska argues, is that the very CCS projects that support EPA’s determination have all received significant funding under the Energy Policy Act, which prohibits EPA from considering such technology as “adequately demonstrated.” Nebraska, and other critics of the proposed standard, argue that the proposed NSPS would severely limit the construction of any new coal-fired plants in the U.S.
Nebraska’s lawsuit may be more of a political statement than anything, however. The suit challenges the proposed rule under the Administrative Procedure Act as a “final” action of EPA. The “proposed” NSPS was just released, however. The proposed rule is open for public comment until March 10, 2014 and may not be finalized by EPA until mid-2015. The Nebraska suit is wide open to challenge on the basis that the case is not ripe for judicial review until a final NSPS has been issued by EPA.
For more details on the proposed NSPS, including the standards proposed for natural gas-fired facilities,Continue Reading...