Earlier this year, a group of Stoel Rives attorneys traveled to Mexico to assess existing opportunities and pending developments in the Mexican power markets. Some of the reforms and key trends identified during that trip are now taking shape. See also my blog post “Let the Market Decide: The Third Wave of Energy Investment in Latin America and Caribbean.”
Our work in Mexico included meetings with existing clients, senior partners of a major Mexican law firm, a briefing with a senior Mexican policymaker regarding implementation of the reforms and attendance at the Mexican International Renewable Energy Conference. Here are some key "take-aways" from these meetings:
- A Mexican renewable energy market has been successfully launched, with more wind than solar developed to date.
- A package of "secondary" laws implementing Mexico's energy reform legislation are pending in the Mexican Congress.
- The secondary laws will include some form of renewable portfolio standard (e.g., 30% by 2024) that relies on (among other elements) renewable energy certificates.
- The secondary laws are also expected to launch a wholesale electricity market, a demand response market and other provisions designed to encourage distributed generation.
- Solar module manufacturers and other stakeholders are concerned about the government's decision to apply a 15% import tax on electrical "generators" to non-NAFTA solar modules.
Supreme Court Rolls Back EPA's Regulation of Greenhouse Gases in Utility Air Regulatory Group Decision
The U.S. Supreme Court has delivered a stunner with its decision this morning in Utility Air Regulatory Group v. Environmental Protection Agency. The Supreme Court has curtailed the U.S. Environmental Protection Agency’s (EPA) regulation of stationary source greenhouse gas (GHG) emissions under two Clean Air Act permitting programs - New Source Review Prevention of Significant Deterioration (PSD) and Title V. EPA can no longer require PSD or Title V permits for stationary sources based on a source’s GHG emissions, unless a source is already subject to the permitting programs. However, if a source triggers PSD permitting for another pollutant, the Court has left the door open for EPA to require the source to undergo a Best Available Control Technology determination for GHGs. Today’s decision in Utility Air Regulatory Group has significant ramifications for industrial source permitting. See our alert for more details.
During today's open meeting, the Federal Energy Regulatory Commission (FERC) issued a proposed rulemaking that impacts the owners of gen-tie lines, particularly those owners who are developing multi-phase projects that require priority to interconnection capacity to support future phases. The proposed rule would ease existing FERC policies that treated gen-tie lines just like any other transmission facility and required owners to make interconnection capacity available to third parties if the owner could not provide enough documentation proving its planned use of the gen-tie lines.
FERC has proposed the following:
- Gen-tie line owners will be granted a blanket waiver from the requirement to (x) maintain a transmission tariff and OASIS and (y) comply with the standards of conduct. FERC will revoke that blanket waiver only when it is in the public interest to do so, and not simply when a third party requests transmission service over a gen-tie line.
- Third parties seeking to interconnect with existing gen-tie lines will be required to do so using the rules and regulations applicable to service requests under sections 210 and 211 of the Federal Power Act.
- Gen-tie owners who are eligible for the blanket waiver from maintaining a tariff, etc., will be granted a 5-year safe harbor period giving the owner the benefit of a rebuttable presumption that (1) the owner has plans to use the gen-tie line's capacity, and (2) the owner should not be required to expand its facilities. Third parties would have an opportunity to rebut that presumption, but those third parties would have the burden of proof. FERC proposes that the 5-year period would begin on the gen-tie energization date. Gen-tie owners would also be required to make an informational filing with FERC in order to take advantage of the safe harbor rights.
- Lastly, FERC has asked whether the affiliates of public utility transmission provider should receive the benefit of the proposed rules.
The proposed rulemaking is available here: Gen-Tie Rulemaking
Comments are due by 60 days after publication of the proposed rule in the Federal Register. Please let us know if you have questions about the proposed rulemaking and/or would like to submit comments to FERC.
The East Kern Wind Resource Area (EKWRA)--it's a mouthful--and it's also a hotbed for renewable energy development and the location of a fight over millions of dollars among Southern California Edison (SCE), the California ISO, and independent power developers (IPPs). Late last week, the Federal Energy Regulatory Commission (FERC) scored that fight in favor of SCE and the California ISO.
For the past few years, SCE has been working to reconfigure the transmission system in the EKWRA region in order to address a reliability issue occurring there. But the reconfiguration would have another impact--it would modify the transmission system in the area so that it became a distribution system under SCE, rather than CAISO, control. To IPPs, that modification came with significant cost consequences: in the interconnection process, IPPs funding network upgrades on the transmission system receive a full reimbursement for the cost of those upgrades; distribution upgrades, on the other hand, result in no reimbursement. For IPPs who had assumed they would be reimbursed the network upgrade costs that appeared in their interconnection agreements (which often cost a single project millions of dollars), it came as something of a surprise when they learned that the reconfiguration might cause their reimbursements to dry up.
And so the IPPs challenged SCE and the California ISO. In its decision, FERC determined that the reconfigured EKWRA facilities are distribution, or non-integrated facilities, and that the California ISO correctly transferred control over the facilities to SCE's tariff. As a result, no further reimbursements to the IPPs will occur. "Despite being informed of the possibility of reclassification, [the IPPs] made a business decision to proceed with interconnection." For some IPPs, this could have a very costly impact.
You can read the entire order here: EKWRA Order.
In a proposed decision issued yesterday from the California Public Utilities Commission, an administrative law judge (ALJ) determined that energy storage devices (i) that are paired with net energy metering- (NEM) eligible generation facilities, and (ii) that meet the Renewables Portfolio Standard Eligibility Guidebook requirements to be considered an "addition or enhancement" to NEM-eligible systems are "exempt from interconnection application fees, supplemental review fees, costs for distribution upgrades, and standby charges when interconnecting under current NEM tariffs.
The issue of whether solar PV-integrated energy storage could interconnect through NEM tariffs heated up in recent months as utilities in California determined that such systems were not NEM-eligible and therefore imposed additional requirements (and costs) in order for a paired solar PV system itself to be NEM-eligible. These requirements and costs acted as a barrier to using energy storage technologies with distributed generation. But in this proposed decision, the ALJ encouraged the state's utilities to take a "more proactive and collaborative approach to avoid creating barriers," and found that energy storage should be exempt from these additional requirements when certain conditions are met.
Sizing. The proposed decision states that NEM-paired storage systems with storage devices sized at 10 kW or smaller are not required to be sized to a customer's demand or the NEM generator. For NEM-paired storage systems with storage larger than 10 kW, (x) the discharge capacity of the storage system may not exceed the NEM generator's maximum capacity, and (y) the maximum energy discharged by the storage device shall not exceed 12.5 hours of storage per kW.
Metering. With respect to metering requirements, the proposed decision again draws distinctions between storage systems above 10 kW discharge and those at 10 kW and below discharge capability, although the decision proposes to impose certain requirements on both categories in order to "preserve the integrity of NEM." For systems at 10 kW and below, the decision proposes using a de-rate factor to measure the AC energy that flows into, and out of, the NEM generator. NEM-paired systems larger than 10 kW will be required to adhere to metering requirements similar to those under the NEM Multiple Tariff Facilities provision of utilities' NEM tariffs, although the costs of metering will be capped at $500. In either category, the proposed requirements aim to ensure that only NEM-eligible generation receives NEM credit.
The full proposed decision may be viewed here: CPUC Proposed Decision re Energy Storage
Ameren Should LOSE the Latest Battle Over Option 1 Network Upgrade Funding in the Midcontinent ISO Region
Ameren is at it yet again--perpetuating a method for funding generator interconnection network upgrades in MISO that the Federal Energy Regulatory Commission (FERC) found to be unjust, unreasonable, and discriminatory over three years ago. Ameren has already won two cases that allowed it to continue using Option 1 funding for certain interconnection customers. But Ameren should lose this one. Here's why:
A Brief History. Prior to March 22, 2011, the MISO tariff provided three methods for funding interconnection network upgrades. Option 1 required an interconnection customer to upfront fund the cost of network upgrades (post security and pay monthly construction costs); when those upgrades became commercially operational, the transmission owner would reimburse the full amount paid by the customer and then establish a transmission rate to charge the customer for using the upgrade on an ongoing basis. Option 2 funding also required the customer to pay upfront construction costs, but then the customer was reimbursed a portion of those costs following commercial operation. Option 2 did not include an ongoing rate. As a result, over time Option 1 funding could result in multiples of the actual cost that a customer might pay under Option 2. (The third option--"self-fund"--allowed a transmission owner to pay upfront costs itself and then charge a usage rate.)
On March 22, 2011, FERC responded to a complaint about Option 1 funding by independent power producers, determining that the method was "unjust, unreasonable, and discriminatory." FERC ordered MISO to remove Option 1 funding from its tariff. That order is found here: E.ON Climate & Renewables.
However, in the past couple of years, Ameren has successfully won the right to continue using Option 1 funding in interconnection agreements that were signed prior to FERC's decision in E.ON. After FERC issued its decision in E.ON, certain customers attempted to obtain the benefit of that decision by having FERC alter their agreements where they had agreed to Option 1 funding. But FERC denied the attempts, primarily on the basis that those prior agreements expressly provided for Option 1 funding and that it would not be in the public interest to unilaterally modify the contracts. In other words, those customers who sought to benefit from the E.ON decision had express notice that Option 1 funding would apply and they failed to raise a timely dispute; FERC would not reset the contracts they had agreed to. Those decisions are available here: Rail Splitter (agreed to Option 1 funding by signing a Facilities Service Agreement) and Hoopeston (agreed to Option 1 funding in its interconnection agreement).
Now we come to the current dispute over Option 1 funding. This docket focuses on an interconnection agreement that Ameren signed with White Oak Energy in 2007. At that time, Option 1 funding existed under the MISO tariff, but White Oak's interconnection agreement said nothing expressly about Option 1 funding. In addition, Ameren was not required to select the funding method until the network upgrades reached commercial operation. At the time of signing its interconnection agreement, if White Oak had disputed the potential application of Option 1, FERC would have likely dismissed the dispute for being unripe. It wasn't a real issue yet.
Fast forward four years. Ameren completed construction of White Oak's network upgrades in 2011 and notified White Oak at that time that Option 1 would apply. White Oak disagreed repeatedly, leaving Ameren forced to file White Oak's Facilities Service Agreement unexecuted with FERC. Under the proposed funding method, White Oak's network upgrades (actual cost $2,399,128) will cost $8,292,180 over 20 years under the ongoing rate. You can see Ameren's application to FERC here: White Oak FSA Application.
So why should White Oak receive a different result than the customers in Rail Splitter and Hoopeston? White Oak should be treated differently because, until now, it had no prior opportunity to complain to FERC about this method for funding network upgrades that we know to be discriminatory. Unlike the customers in Rail Splitter and Hoopeston, who waived their opportunity to complain and consequently needed FERC to undo contracts they'd agreed to, White Oak has never agreed to Option 1 funding--there is no contract to undo As a result, White Oak should now be afforded the chance to argue against Option 1 funding on the merits (see E.ON), rather than being hung up by procedural technicalities and the Mobile-Sierra doctrine.
If FERC were to rule in White Oak's favor, then the decision would help to restrict the application of this discriminatory method of funding network upgrades to a limited group of interconnection customers (i.e., those who expressly agreed to Option 1 in a contract) and to insulate those who are just now receiving notice of Option 1 funding from the absurd results that accompany it. But we'll need to wait and see if those at FERC who call balls and strikes see it the same way.
The Minnesota State Legislature is currently debating a bill that would ease the regulatory burden on independent power producers looking to export wind and solar energy generated in Minnesota.
Minnesota law currently prohibits the construction of a large energy facility without the issuance of a certificate of need by the Minnesota Public Utilities Commission. This Certificate of Need requirement ensures that consumer demand, rather than potential revenue, drives construction. The new proposal would change this regulatory scheme by creating an exception for independent power producers who build a wind or solar project and export the power or sell into a wholesale market operated by a federally recognized regional transmission organization or independent system operator.
The new proposal, if enacted, will greatly reduce the initial cost and time required to develop a project and put Minnesota on par with neighboring states that do not require a Certificate of Need for projects that sell out-of-state. The Minnesota Public Utilities Commission estimates that it takes, on average, 12 months to secure a Certificate of Need.
At this time the proposal looks to be progressing smoothly, as it unanimously cleared committee votes in both the House and Senate and was incorporated into the House omnibus energy bill. Read more about the proposed legislation here.
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.
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.
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...
With the holidays behind us and the cheer and reverie of the New Year trailing off, wind developers in Idaho may be realizing that the Federal Energy Regulatory Commission (FERC) left a lump of coal in their stockings on Christmas Eve. On December 24, FERC agreed to dismiss an historic legal action that it had taken to enforce the Public Utility Regulatory Policies Act of 1978 (PURPA) against the Idaho Public Utilities Commission (IPUC) on behalf of Qualifying Facility (QF) wind developers who have been beaten up by numerous decisions coming out of the state agency over the past several years. FERC had never before sought to enforce PURPA against a state agency, but the IPUC apparently found FERC’s tipping point.
In exchange for its agreement to dismiss this first-of-its-kind action, FERC extracted a simple acknowledgement of questionable value from the IPUC: “The Idaho PUC acknowledges that a legally enforceable obligation may be incurred prior to the formal memorialization of a contract to writing.” And that is as far as their substantive agreement goes. In other words, the IPUC acknowledges that a hypothetical situation may occur, without agreeing to the all-important question of when that situation does occur. The agreement signals an apparent policy change at FERC, and it also leaves QF wind developers on their own, once again, to enforce PURPA in protracted litigation in federal court, i.e., without a viable option.
For those keeping score, there was none in this dispute: FERC threw in the towel before the first bell.
This week the California Air Resources Board (ARB) released a draft of its AB 32 Climate Change Scoping Plan Update. The original Scoping Plan was adopted in 2008 and must be updated every five years. The Scoping Plan serves as a blueprint for achieving AB 32’s goal of reducing greenhouse gas (GHG) emissions to 1990 levels by 2020.
The draft Update summarizes programs implemented over the last five years under AB 32 and outlines actions necessary to continue California’s progress toward the 2020 emissions reduction goal. The draft Update shows that California is on track to meet the 2020 emissions reduction goal and inventories the progress made across different economic sectors and programs like cap and trade. With the Update, ARB continues its strategy of achieving AB 32 goals through a mix of emissions reduction measures, including regulatory programs, incentives, and market-based approaches.Continue Reading...
Minnesota Supreme Court Affirms Minnesota Public Utilities Commission's Interpretation and Application of State Law and Distinguishes Bluefield
On November 2, 2009, just one day after the Minnesota Public Utilities Commission's (the "Commission's") final order in Minnesota Power's 2008 rate case, Minnesota Power filed its largest petition ever to increase electric rates. As part of its petition, and consistent with Minnesota law, Minnesota Power sought to impose interim rates - the rates Minnesota utilities are permitted to collect while a petition to increase rates is pending. The size of any interim rate increase is generally dictated by Minnesota law. A number of parties opposed Minnesota Power's interim rate increase, claiming exigent circumstances justified deviation from the statutory formula.
The Commission agreed. It determined that the confluence of the following three circumstances justified a finding of exigent circumstances: (i) the size of Minnesota Power's request, (ii) the state of the economy, and (iii) the fact that the 2009 rate case was filed on the heels of the 2008 rate case. As a result, the Commission set interim rates at approximately 60% of Minnesota Power's overall request - $25 million less than Minnesota Power's interim rate request. Minnesota Power appealed the Commission's decision to the Minnesota Supreme Court, which affirmed the Commission's decision in an opinion issued on September 18.
In large part, the Minnesota Supreme Court deferred to the Commission's interpretation of Minnesota's interim rate statute, finding of exigent circumstances, and revised calculation for setting interim rates. Of particular note is the part of the court's opinion distinguishing Bluefield Water Works & Improvement Co. v. Public Service Commission of West Virginia, 262 U.S. 679 (1923). Minnesota Power cited Bluefield for the proposition that the constitutional due process requirement that rates be sufficient to recover cost of service must inform the Commission's decision in finding exigent circumstances. The court disagreed. It found that Bluefield and other similar State decisions "do not address the issue of the recovery of cost of service by interim rates set temporarily as part of a larger administrative process designed to determine final rate levels." The court affirmed the Commission's decision.
Over 40 percent of the lands in Malheur County have been designated as core habitat for sage grouse by the Oregon Department of Fish and Wildlife ("ODFW"). Other counties in southeastern Oregon are also heavily affected. ODFW's approach was to simply recommend against any development in core habitat, without consideration whether off-site mitigation could result in net benefit. For energy and mining developments in particular, it seemed likely that the Energy Facility Siting Council ("EFSC") and the Department of Geology and Mineral Industries ("DOGAMI") would defer to ODFW's recommendation. This approach threatened the economic vitality of southeastern Oregon.
To read the entire article, please click here.
A tentative ruling was issued yesterday in the related cases California Chamber of Commerce v. California Air Resources Board (ARB) and Morning Star Packing Co. v. ARB, pending before the Sacramento County Superior Court. The cases challenge the legality of ARB's cap and trade auctions under two theories: (1) the cap and trade auctions exceed ARB's authority under AB 32, and (2) the auctions amount to an illegal tax adopted without the requisite two-thirds approval of the California Legislature. The Court tentatively ruled in ARB's favor that the agency's implementation of a cap and trade auction system is within the scope of AB 32, which delegated ARB authority to design the distribution of emissions allowances. The Court did not rule on whether the allowance auctions constitute an illegal tax. The tentative ruling outlined questions on this topic for oral argument, which was heard yesterday. A ruling on the tax challenge is expected in the next 90 days.
ARB held its most recent quarterly auction on August 4, 2013. 2013 vintage allowances sold for $12.22. In the advance auction of 2016 vintage allowances, held concurrently, allowances sold for $11.10.
As we discussed in this alert, the U.S. Fish and Wildlife Service (FWS) released its final Eagle Conservation Plan Guidance (ECP Guidance) on April 26, 2013. Intended to promote compliance with the Bald and Golden Eagle Protection Act (BGEPA) for wind development projects that have the potential to affect bald and golden eagles, the ECP Guidance provides specific in-depth guidance for conserving eagles in the course of siting, constructing, and operating wind energy facilities.
The industry norm prior to the FWS’s release of the ECP Guidance was to not pursue Eagle Take Permits (due, in part, to the 5-year term limitation in the 2009 final rule and in anticipation of the 30-year permit rule). Now that the ECP Guidance is in place, however, there is increased scrutiny on BGEPA compliance issues and the FWS has become more assertive in its efforts to persuade wind developers to apply for Eagle Take Permits. Meanwhile, the prediction that the FWS’s 30-year permit rule is imminent seems less likely. As such, we are now advising our clients to reassess their BGEPA compliance strategies to account for what appears to be a “new normal” in BGEPA compliance. If you would like more information on this issue, please contact Barb Craig at (503) 294-9166 or Sarah Stauffer Curtiss at (503) 294-9829.
On July 8, 2013, Xcel Energy Inc., submitted a filing with the SEC detailing an Administrative Law Judge’s decision in a pending electric rate case in Minnesota and calculating the decision’s impact on one of its subsidiaries. In November 2012, Northern States Power Company (NSP), a wholly owned subsidiary of Xcel Energy Inc., petitioned the Minnesota Public Utilities Commission (MPUC) for authority to increase electric rates by $285 million, or 10.7 %. This request was referred to the Minnesota Office of Administrative Hearings for review as a contested case. Government agencies, business and industry representatives, and low income advocates intervened in the case to contest NSP’s request. These intervenors raised a number of concerns with NSP’s request, including NSP’s proposed level of recovery for investments in nuclear facilities, depreciation expense, sales forecast, incentive compensation, property taxes, and rate of return. After reviewing multiple rounds of written testimony and overseeing an evidentiary hearing, the ALJ concluded in a written opinion dated July 3, 2013, that NSP’s request should be reduced, based largely on a lower return on equity of 9.83%, reduced recovery for nuclear plants, and increased sales forecast. According the SEC filing, the ALJ’s decision limits NSP’s request to $127 million, or 4.7%. This revised increase is based on an equity ratio of 52.56% and an electric rate base of $6.233 billion. The ALJ’s decision will be reviewed by the MPUC, which will reach a final decision in early September 2013.
Last November, the Minnesota Public Utilities Commission approved Xcel Energy’s 2011-2025 Integrated Resource Plan and established various compliance filing requirements and deadlines. Pursuant to that November 2012 Order, the Commission directed Xcel to conduct a Life Cycle Management Study (“LCM Study”) examining the feasibility and cost-effectiveness of continuing to operate, retrofitting, or retiring Sherburne County (Sherco) Generating Station Units 1 and 2, two coal-fired units each having a production capability of 750 MW. The Commission’s November 2012 Order also outlined a number of study components, including the parameters for a base case and various modeling sensitivities, and ordered Xcel to file the results with the Commission on July 1.
At the conclusion of that study, Xcel proposes a wait and see approach. Low natural gas prices, higher CO2 prices, higher coal prices, or higher costs at Sherco favor retirement of Units 1 and 2. Conversely, higher natural gas prices, lower or later implementation of CO2 costs, or higher construction costs for replacement generation favor retrofitting the units with selective catalytic reduction (“SCR”) instead. In light of these uncertainties, Xcel believes that the most prudent course of action is to continue operating Sherco 1 and 2 until more is known regarding environmental regulation, particularly as it pertains to CO2. Xcel believes keeping the status quo leaves both continuing operation and Sherco-replacement options open until there is greater clarity on environmental regulations, timing, and cost. To provide guidance to subsequent resource plan proceedings, Xcel suggests the Commission order a re-evaluation of how to proceed with Sherco 1 and 2 if (1) air quality regulations establish a need for SCRs or (2) carbon regulation becomes clear.
The Commission has not established a timeframe for interested parties to comment. But given the number of parties participating in the stakeholder process, including the North Dakota and South Dakota Public Service Commissions, City of Becker, environmental groups, and business representatives, there will likely be at least one (if not many) alternative suggestions. As a prophylactic measure, Xcel emphasized no decisions should be made in response to the LCM Study. Instead, Xcel asserts “It is in the context of the next Resource Plan, and not this study, that the size, type, and timing of future resources will be decided.” If the Commission follows its precedent from a similar docket involving another Minnesota utility, Minnesota Power, it will wait to act until Xcel’s next resource plan, which is due February 1, 2014. Replacing 1,500 MW of coal-fired generation would require extensive analysis and, if ordered by the Commission, significantly alter Xcel’s generation portfolio. Stay tuned.
In a public workshop held yesterday, the California Air Resource Board discussed its proposed new regulations for alternative diesel fuels as well as conventional diesel fuels. There are a wide range of issues on the table which can best be reviewed on the CARB website for the proceeding. Of particular interest to the advanced biofuels community, CARB is proposing a phased process for introducing alternative diesel fuels to the California market. Prior to supplying any alternative diesel fuel to market, a producer would need to obtain a Memorandum of Exemption (MOE) granted by CARB. I raised the issue that the language was sweeping and would perhaps be more restrictive than the federal standard established by the Fuels and Fuel Additive Registration system found in 40 CFR Part 79 (FFARs). FFARs authorizes producers to provide some pre-commercial supply which can be highly valuable to companies testing and proving out new fuels for the marketplace. CARB officials who attended were receptive to further input on this issue during the public comment period. CARB encouraged public comments by June 24th if possible though the formal period is longer than that.
In a development that will increase liquidity and transparency in the RIN market, two major providers are making RIN future contracts available to be traded. Both CME Group and the IntercontinentalExchange (ICE) will have RIN products available to be traded by mid May. CME Group and ICE will enable over the counter trading (OTC) of D4 RINs, D5 RINs, and D6 RINs. D6 RINs are the most common RINs, typically fulfilled by corn ethanol production. D5 RINs are the most flexible premium RINs, representing advanced biofuel that may consist of biogas, advanced drop in fuels, or other fuel types that meet the 50% GHG reduction standard. D4 RINs are biomass-based diesel RINs, fulfilled primarily by biodiesel and renewable diesel fuels. The development of a futures market could provide a substantial boost to the development of advanced biofuel facilities by enabling their financing. Many financial market participants have in the past regarded RIN revenue as too speculative to include in a plant's pro forma but are likely to be reassured by the presence of RINs in the OTC market. We speculated in our recent white paper that the EPA's rulemaking on Quality Assurance Programs (QAPs) could facilitate the establishment of a RIN futures market. See http://www.stoel.com/showarticle.aspx?Show=10180
On April 19, 2013, the California Air Resources Board (CARB) voted to link the California cap and trade program to Québec’s cap and trade system. CARB approved changes to the California cap and trade regulation on Friday to allow for the linkage, which is effective January 1, 2014. In practical terms, the linkage opens a new market for greenhouse gas allowances and offsets for California’s regulated entities and offset generators. As Québec’s cap and trade participants enter the California market, regulated entities in California could face tighter competition in bidding for allowances at CARB’s quarterly auctions.
CARB is also planning for additional amendments to the California cap and trade regulation this year. Many of the potential changes were teed up for consideration in CARB Resolutions 12-33, 12-51, and 11-32. Topics up for potential amendment include:
- Refining the definition of resource shuffling and clarifying how CARB will deal with the problem. CARB will base proposed amendments to resource shuffling provisions on the recommended actions presented by staff in October 2012.
- Providing transition assistance to electrical generating facilities with legacy power purchase agreements that do not provide for recovery of the cost of compliance with the cap and trade program.
- Exemption for steam and waste heat emissions from combined heat and power.
- Exemption for emissions from waste-to-energy facilities during the first compliance period (2013-2014).
There has been a new development in the effort by Ralls Corporation, a company owned by two Chinese nationals, to challenge President Obama’s September 2012 order requiring it to divest its interests in four wind projects in Oregon and to remove any equipment and infrastructure it had placed on the sites of the proposed projects. The President’s order, issued pursuant to section 721 of the Defense Production Act of 1950 (“Section 721”), had cited unspecified national security risks as the reason for blocking Ralls Corporation’s acquisition of the wind projects, but the sites of the four proposed projects are near or within restricted airspace of U.S. Naval Weapons System Training Facility Boardman.
On Friday, U.S. District Judge Amy Berman Jackson ruled that she could not overturn President Obama’s order. In her opinion, Judge Jackson said that the law "is not the least bit ambiguous about the role of the courts: 'The actions of the president . . . and the findings of the president . . . shall not be subject to judicial review.'" Therefore, the judge declined to review the President’s findings on the merits. However, she did determine that the court has jurisdiction to determine whether the President followed proper procedures in implementing Section 721. The judge will rule on that due process issue following further briefing by the parties. If Ralls Corporation wins on the merits of the due process claim, it may be entitled to hear the reasons for the President’s decision to block the acquisition of the wind projects.
*Update: Ralls Corp reacted to Judge Jackson's ruling by insisting they would "persist in the lawsuit to the end and will appeal to the circuit court or the supreme court [sic] of the United States if necessary." See here for more of the company's reaction.
We are pleased to announce that we have opened a satellite office in Washington, D.C. Our new address, effective immediately:
Stoel Rives LLP
1020 19th Street NW, Suite 375
Washington, DC 20036
Phone: (202) 398-1795 / Fax: (202) 621-6394
The new office is headed by firm partner Greg Jenner, a former Deputy Assistant Secretary of the U.S. Treasury for Tax Policy and Tax Counsel to the U.S. Senate Committee on Finance.
Click here to read the press release.
The Committee on Foreign Investment in the United States (CFIUS) recently issued its 2012 Annual Report to Congress. My colleague CJ Voss has summarized some of the report's key findings.
CFIUS is charged with reviewing acquisitions of U.S. businesses for national security implications. As we reported last fall, President Obama blocked Chinese-owned Ralls Corporation’s acquisition of wind farm projects in Oregon following intervention by CFIUS in the deal.
According to CJ, the report provides important insights for foreign companies considering investment and M&A transactions that could raise national security considerations, including:
- CFIUS believes foreign governments or companies likely have a “coordinated strategy” to acquire U.S. companies involved in research, development and production of critical technologies
- Filings with CFIUS have increased 70% since 2009
- Filings involving Chinese buyers have increased
- CFIUS has imposed various mitigation measures on transactions
- Certain industry sub-sectors accounted for more than half of all filings between 2009-2011
Congress yesterday passed the American Taxpayer Relief Act of 2012 (the Act), which averted the so-called “fiscal cliff.” The President is expected to sign the Act shortly.
The Act includes a number of energy-related tax provisions, including a one-year extension and modification of the production tax credit under Section 45 of the Internal Revenue Code (the PTC) for certain renewable energy facilities. The energy-related provisions in the Act include:
- PTC Extensions and Modifications – The PTC is extended and modified for certain types of facilities. These extensions and modifications include:
- In the case of wind, geothermal, landfill gas, trash, marine, and hydrokinetic facilities and certain closed-loop biomass, open-loop biomass, and qualified hydropower facilities, the PTC will apply if construction begins before January 1, 2014 (rather than if the facilities are placed in service before January 1, 2014). The Act does not specify what it means to begin construction for this purpose, although there are analogous authorities that have been adopted for other purposes that may be applied. Note, however, that a facility to which this extension applies may qualify for the PTC even if it is not placed in service before January 1, 2014.
- The PTC for municipal solid waste facilities is modified to exclude from the definition of municipal solid waste certain paper that is commonly recycled and that has been segregated from other solid waste.
- The election to claim the investment tax credit rather than the PTC for certain facilities is extended to apply to certain facilities with respect to which construction begins prior to January 1, 2014.
- The PTC for Indian coal production facilities is extended for one year, to apply to sales of qualified production during the eight-year period (rather than the previous seven-year period) beginning on January 1, 2006.
- In the case of wind, geothermal, landfill gas, trash, marine, and hydrokinetic facilities and certain closed-loop biomass, open-loop biomass, and qualified hydropower facilities, the PTC will apply if construction begins before January 1, 2014 (rather than if the facilities are placed in service before January 1, 2014). The Act does not specify what it means to begin construction for this purpose, although there are analogous authorities that have been adopted for other purposes that may be applied. Note, however, that a facility to which this extension applies may qualify for the PTC even if it is not placed in service before January 1, 2014.
We are pleased to report that the California Third District Court of Appeal recently granted our request to publish its decision in a California Environmental Quality Act (CEQA) case in which we were lead counsel. In a challenge to the certification of an environmental impact report (EIR), plaintiffs had argued that the EIR failed to include an adequate range of alternatives to the project. The Court rejected this argument.
The case is significant for two reasons. First, it provides precedent for a lead agency and project proponent to reject alternatives that are not feasible, thus avoiding the time and cost of analyzing an infeasible alternative for fear of a CEQA suit. Second, the Court upheld the rule of reason in its finding that the analysis of the project and the No Project alternative amounted to a reasonable range of alternatives. CEQA practitioners often advise clients to identify at least one alternative that is potentially feasible. Based on this determination, a record clearly showing there is no feasible project alternative can be upheld.
From my partner Michael O’Connell:
Occasionally, we receive inquires regarding federal policies relating to actual, potential or alleged impacts of projects on bald and golden eagles and other migratory birds.
On October 12, 2012, Attorney General Holder issued a policy regarding Possession or Use of the Feathers or Other Parts of Federally Protected Birds for Tribal Cultural and Religious Purposes. The policy “formalizes and memorializes” the U.S. Department of Justice longstanding prosecutorial discretion policy regarding possession or use of feathers and parts of eagles and other migratory birds by members of federally recognized Indian tribes for religious and cultural purposes. The policy does not alter requirements that Indians obtain a permit from U.S. Fish and Wildlife Service to “take” eagles in the wild for religious or cultural reasons or to salvage eagle carcasses or parts that may have been killed by collision with project structures or vehicles or other causes.
This new policy reflects a deliberate federal efforts to accommodate tribal cultural and religious interests in eagles and other migratory birds. While the policy does not directly affect project developers or operations of energy, agriculture, infrastructure and other projects, it may be of interest to project developers and operators. Deliberate federal accommodation of tribal interests in possession and use of eagle and other migratory bird feathers and parts may lead federal agencies to give greater attention under NEPA and other laws affecting permits and project authorizations and in enforcement initiatives to potential project impacts on eagles and other migratory birds.
California's Pacific Gas and Electric Company (“PG&E”) announced today that it plans to issue an Energy Storage Request for Information (“RFI”) to obtain information on utility-scale, dispatchable, and operationally flexible storage resources through a solicitation of interest from technology providers, owners, and developers of energy storage resources. PG&E said that it plans to issue the RFI and to ask for responses from RFI participants this year.
PG&E explained that the RFI will help it to learn about different storage technologies and their costs, to understand which storage technologies could bid into a future RFO, and to identify and value the various attributes of those technologies. The company plans to open up its Energy Storage RFI website later this week--the new website will list the types of questions that PG&E plans to ask in the RFI. PG&E invites feedback on its proposed questions in the form of comments or questions to EnergyStorage@pge.com.
Persons who want to to subscribe to PG&E's general RFO distribution list should go to www.pge.com/rfo to fill out theregistration form and submit the Excel form as an attachment to the Renewable RFO mailbox. Registrants will receive notices about this energy storage RFI and other PG&E long-term procurement solicitations.
A law alert from our colleague Cherise Oram:
On August 24, 2012, the U.S. Fish and Wildlife Service and the National Marine Fisheries Service (collectively, the "Services") issued a proposed rule that would modify when and how the Services analyze economic impacts in critical habitat designations under the Endangered Species Act ("ESA"). Critical habitat designation is intended to provide special protection of essential habitat for species listed as endangered or threatened under the ESA. The ESA prohibits federal agencies from taking actions that are likely to destroy or adversely modify that critical habitat. Critical habitat designations are often controversial because they may discourage or impair private activities on private lands by requiring federal permits or otherwise devaluing the lands located within a designation.Continue Reading...
The Pacific Northwest Economic Region (PNWER) Energy Storage Coaliation (ESC) will be holding an important energy storage conference at the Portland Convention Center on October 8, 2012. ESC has worked with the Oregon and Washington public utility commissions to bring together a diverse mix of developers, utilities and regulators to share their perspectives on opportunities and barriers to deploying energy storage in the Pacific Northwest. You can find the draft agenda for the event here and register for the conference here.
Following the PNWER event, Pivotal Leaders will hold an Energy Storage Panel from 4-6 PM at the Portland offices of Perkins Coie, 1120 NW Couch Avenue, 10th Floor. I will be joinging the panel with Dave Curry of Demand Energy, Praveen Kathpal of AES Corporation, and Lee Kosla of SAFT . Guests are welcome, but an RSVP is required. Contact email@example.com. I hope to see you at both of these events.
For those interested in energy storage, I regularly follow the topic on Twitter, @BillHolmesStoel. The PNWER Energy Storage Coalition can also be found on Twitter, @PNWERESC. Finally, www.stationarystoragenews.com is an excellent energy storage news aggregator that offers daily news and a weekly newsletter on the topic.
Last week the White House issued an Executive Order calling for 40 GW of new CHP capacity by 2020:
The Executive Order on Accelerating Investment in Industrial Energy Efficiency (also known as combined heat and power (CHP) or cogeneration) calls for federal agencies (including the Departments of Energy, Commerce and Agriculture), States, industrial companies and utilities to coordinate policies to encourage investment in CHP facilities with a goal of achieving 40,000 MW of new CHP generating capacity in the U.S. by 2020. Among other provisions, the Order calls for (i) set asides for CHP under emissions allowance trading program state implementation plans, grants, and loans and (ii) recognition of the emissions benefits of highly efficient energy generation technologies like CHP to provide compliance options under power and industrial sector regulations. By one estimate, this could create $40 billion to $80 billion in new capital investment in U.S. manufacturing facilities.
*Combined heat and power (CHP), also known as cogeneration, is an efficient, clean and reliable means of generating power and thermal energy (such as steam) from a single fuel source, including natural gas, coal, biogas and biomass.
At today's open meeting, the Federal Energy Regulatory Commission (FERC) adopted a new rule that may be particularly helpful for variable energy resources (wind and solar) that, in the past, have been hit with pricey imbalance penalties, and for the transmission providers who have struggled to integrate those resources. The new rule adopted today requires transmission providers to provide generators with the option of scheduling transmission service on 15-minute intervals, rather than the typical 60-minute interval. With the shorter scheduling interval, generators will be able to better mitigate imbalance penalties, and transmission providers should be able to maintain reserves that more closely match the variable generation that is expected to be online. The bottom line--cost savings!
FERC also issued a Notice of Proposed Rulemaking (NOPR) in which FERC proposes to revise its policies governing the sale of ancillary services at market-based rates. FERC also proposes to require transmission providers outside of organized markets (e.g. WECC) to take into account resource speed and accuracy in determining regulation and frequency response reserve requirements. That consideration may help to establish a stated need for fast-acting resources, such as certain energy storage technologies. The NOPR also suggests other regulatory changes that, in part, aim to provide energy storage technologies with better access to providing ancillary services.
We will soon issue full clients alerts on the results of today's open meeting at FERC. If you would like to receive an electronic copy of our Energy Law Alerts, please follow this link: Sign Up - Stoel Rives Energy Law Alerts
FERC Confirms That Its "One-Mile" Rule is a Safe Harbor for Establishing Separate Qualifying Facilities
The Federal Energy Regulatory Commission's (FERC) regulations provide that, for purposes of calculating a qualifying facility's net capacity, generating facilities are considered together as a single qualifying facility if they are located within one mile of each other, use the same energy resource, and are owned by the same persons or their affiliates. In recent years, landowners and energy purchasers have disputed whether the location of generating facilities more than one mile apart is a "safe harbor," ensuring that the facilities will be treated as separate qualifying facilities, or is instead a rebuttable presumption that may be challenged. In its Order Denying Rehearing, issued June 8, 2012 in Docket Nos. EL11-51-001, QF10-649-002, and QF10-687-001, FERC reaffirmed that the one-mile separation standard provides a safe harbor for establishing separate qualifying facilities.Continue Reading...
California Judicial Council Announces Expedited CEQA Litigation Court Rules for Qualifying Development Projects
From our colleague Wayne Rosenbaum:
As Juliet Cho blogged about in our California Environmental Law blog, California Governor Jerry Brown signed the Jobs and Economic Development through Environmental Leadership Act of 2011 (also known as AB 900) into law last September. The law aims to provide an incentive for applicants to move forward with their development projects by requiring that any challenge to a “leadership project” Environmental Impact Report (“EIR”) under the California Environmental Quality Act (“CEQA”) will be venued immediately in the Court of Appeal. The court will then have a maximum of 175 days to issue its decision on the challenged EIR. For a description of the qualifying criteria of a “leadership project” see Juliet’s blog post.
AB 900 also required the Judicial Council to adopt rules of court to implement the new law. Recently, the Council announced its proposed rules. These rules, which are to be adopted no later than July 1, 2012, impose a highly expedited briefing schedule and require payment of a special $100,000 fee to the Court to reimburse for costs related to the expedited handling of the case. Currently, at least one Solar PV project has applied for special handling under AB 900.
It remains a question whether the added costs for this expedited process are worth it for Solar PV and other developers. While no project has actually gone through the process as of this date, utility scale Solar PV projects should carefully consider the possible benefits. One benefit of immediate appellate review would be a dramatic reduction of the judicial review period by twelve to eighteen months. Having the Governor certify the project as an environmentally superior major job creator would also likely expedite the administrative review process before the land use agency.
Yesterday the EPA released the third major Notice of Violation ("NOV") against a biofuel producer in the past six months under the Renewable Fuel Standard ("RFS"). The NOV states that EPA has determined that Green Diesel, LLC of Houston, Texas, generated 60,034,033 invalid Renewable Identification Numbers (“RINs’) with a current market value of perhaps $85 million. Coming on the heels of 31 settlement agreements relating to the Clean Green Diesel and Absolute Fuels RINs, this NOV is likely to trigger immediate market reaction. The EPA has been enforcing invalid RIN cases first against the RIN generator then subsequently against the obligated party, i.e., the company that uses the RINs for compliance with RFS. Obligated parties under the RFS are petroleum refiners and importers in the U.S. About a month after the Clean Green Fuel filing, the EPA filed NOVs against the obligated parties. It remains to be seen whether EPA will do so again. The agency may instead rely upon its past actions and its recently released Interim Enforcement Response Policy to motivate corrections by obligated parties.
Some market participants have criticized the EPA for their managing of the RFS program and questioned the RFS program itself. In response, the biofuel industry and particularly the National Biodiesel Board have taken significant steps to address the validity issues. While there is significant time delay as many of the alleged activities date back to 2010, it appears that the EPA enforcement activities have motivated substantial due diligence activities that will serve the RFS program participants well in future years. The immediate challenge is in addressing the new Green Diesel NOV and the resulting contractual implications for market participants who transacted in these RINs. The rapid growth in the value of the RIN market has certainly presented substantial challenges. Nonetheless, private market responses to date suggest that the resourceful biofuel and petroleum industries can weather these storms and ultimately make the RFS program more effective toward its goals of reducing U.S. dependence on foreign oil imports and reducing GHG emissions.
In October 2011, the Federal Energy Regulatory Commission (FERC) issued Order No. 755, which requires regional transmission organizations (RTOs) and independent system operators (ISOs) to pay for frequency regulation services based on the actual amount of service provided in response to actual or expected frequency deviations or interchange power imbalances. The order directs RTOs and ISOs to implement a two-part payment for frequency regulation services consisting of (1) a capacity payment that includes the marginal unit's opportunity costs, and (2) a performance payment that reflects the quantity of frequency regulation service that a resource provides when it is accurately following the dispatch signal. In February 2012, FERC issued Order 755-A, denying a motion for rehearing filed by Southern California Edison.
On Tuesday April 10, 2012, 11 am to 12:30 pm Eastern time (8 am to 9:30 am Pacific), I'll be moderating a Webinar produced by that Infocast to discuss the implications and effect of Order No. 755. We'll review the Order itself, the process that is underway in the RTOs and ISOs to implement the Order, and the Order's implications for energy storage, demand response and other aspects of the frequency regulation market.
Infocast has assembled an excellent panel for this Webinar. Jacqueline DeRosa, Director of Regulatory Affairs, California, Customized Energy Solutions and Rahul Walawalkar, PhD, CEM, CDSM, Vice President, Emerging Technologies Markets, Customized Energy Solutions, will jointly provide a cross-market overview of the current approaches and proposed responses to Order No. 755 in key ISOs and RTOs (i.e., PJM, NYISO and CAISO) . Eric Hsieh, Regulatory Affairs Manager, A123 Systems, Inc., (which participated actively in the Order No. 755 docket) will offer a technology provider's perspective on the order and the ongoing process. Praveen Kathpal, Director of Marketing and Regulatory Affairs, The AES Corporation, will provide the perspective of a technology-neutral independent energy storage developer.
You can register for the Order No. 755 conference here. Use the Stoel Rives discount code (“128505”) to reduce the tuition to $150.
Oregon Governor John Kitzhaber announced today that he has named Margi Hoffman to serve as his Energy Policy Advisor. She will join the Governor's office on April 2.
Ms. Hoffman has served as Senior Vice President and Director of Oregon Operations with Strategies360, a strategic consulting firm, and has also worked closely with Renewable Northwest Project (RNP) . The news release from the Governor's office can be found here.
I'll be moderating Energy Storage for the Grid: Watchful Waiting or the Perfect Storm? at the MIT Enterprise Forum Northwest's May 8, 2012 program at Seattle's Museum of History and Industry (MOHAI) , 2700 24th Ave East. The event, which includes a networking reception, will be held from 5:00 to 8:30 pm.
The evening's panelists will be:
- Terry Oliver, Chief Technology Innovations Officer, Bonneville Power
- Alexander H. Slocum, Professor, Massachusetts Institute of Technology
- Chris Wheaton, Chief Operating & Financial Officer, EnerG2
- Nathan Adams, Manager of Development and Emerging Technologies, Puget Sound Energy
Among other topics, the panel will address:
- The most promising energy storage strategies
- How different storage methods could work together with the grid in the Northwest and nationally
- How entrepreneurs, the changing energy marketplace, grid operators, and utilities are responding to the call to build the foundation for a clean energy economy
For more information about this event, visit MITEF Northwest's web site.
I hope to see you there! In the meantime, for those who are following energy storage, I'm "tweeting" regularly on that topic as well as Department of Defense renewables procurement at @BillHolmesStoel (#energystorage).
Update: California Energy Commission Postpones Action on Proposed Decision Allowing PV Projects to Opt-In to CEC Permitting Process
In a previous blog, we reported on a proposed decision pending consideration by the California Energy Commission (CEC), which would allow solar photovoltaic project developers to opt-in to the CEC's permitting process. The CEC has announced that its decision on this matter has been postponed to an as-yet undetermined date.
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.
On November 30, the California Independent System Operator Corporation ("CAISO") announced that it would not push for changes to the Participating Intermittent Resources Program ("PIRP") at the December 15-16 Board of Governors meeting. The announcement came as welcome news to intermittent renewables advocates as the CAISO and stakholders have spent the past year negotiating issues set out in one Straw Proposal, five Revised Straw Proposals, and a Draft Final Proposal on changes to PIRP eligibility requirements and cost allocation, bid cost recovery ("BCR"), and a lowering of the energy bid floor. Instead of making changes to PIRP now, the CAISO will revisit the discussions in the second quarter of 2012- when it is scheduled to begin a stakeholder process to review decremental bidding options for participating intermittent resources in the Renewable Integration- Market and Product Review, Phase 2 initiative. Changes to the BCR netting methodology and the incremental lowering of the energy bid floor are still scheduled for review by the CAISO Board this month.
The Environmental Protection Agency (EPA) is exercising its authority and enforcing the requirements of the Clean Air Act’s renewable fuel standard (RFS) program. The EPA issued twenty-four notices of violation on November 7, 2011, to petroleum refiners, importers and exporters of renewable fuel.
Following a filing last month of criminal charges of wire fraud, money laundering, and violations of the Clean Air Act (CAA) against an individual, Rodney R. Hailey, the EPA issued civil notices of violations (NOVs) to the entities that relied upon the allegedly invalid Renewable Identification Numbers (RINs) generated by Mr. Hailey. The companies involved are obligated parties under the RFS program and thereby, subject to Renewable Volume Obligations (RVOs) designed to demonstrate compliance with the renewable fuel standards set by Congress -- 36 billion gallons by 2022.
Stoel Rives issued a legal update on these matters, among the first enforcement actions initiated by the EPA under the RFS2 requirements. The entire update can be read here.
The CUB Policy Center, in partnership with the University of Oregon School of Law, will be holding its inaugural policy conference: Smart Grid: Today's Regulation and Tomorrow's Technology, on Friday, October 21, 2011, at the University of Oregon White Stag Block (70 NW Couch St., Portland, OR 97209). The luncheon keynote speaker will be former FERC Commissioner Nora Mead Brownell, who is the co-founder of ESPY Energy Solutions.
The conference is designed to educate utility analysts, policy analysts, attorneys, industry professionals, stakeholders and others on the current regulatory environment in Oregon and the region and to provide a forum for investigating the opportunities and challenges of integrating the Smart Grid into that environment. The CUB Policy Center notes that space for this conference, which promises to be well attended, is limited and encourages attendees to register early.
I'll be participating in the Closing Panel to recap and discuss lessons learned during the day, and I hope to see you there.
Governor Brown signed Senate Bill 267 and Senate Bill 618 this past weekend which resulted in California having two more laws in place to help facilitate development of renewable energy projects in California. For further information please see Kristen Castaños’ recent post entitled, “Governor Brown Signs Two More Bills to Streamline Renewable Energy Development in California: SB 267 and SB 618."
California’s AB 2514 directs the California Public Utility Commission (CPUC) to determine appropriate targets, if any, for load-serving entities to procure viable and cost-effective energy storage systems. If the CPUC decides that targets are appropriate, it is supposed to set dates for achieving those targets.
As a follow up to an AB 2514 workshop held on June 28, 2011, Administrative Law Judge Amy C. Yip-Kikugawa issued a ruling asking for comments on the presentations made at the workshop by the California Energy Commission, the California Independent System Operator, Southern California Edison, the California Energy Storage Alliance, AES Energy Storage, Beacon Power Corporation and KS Engineers, all of which were attached to the ruling. The ruling asks the parties to comment on whether they agree or disagree with the presentations.
In addition, the ruling seeks comments from parties on the following questions:
- Which barrier(s), either identified by the presenters or the CPUC, do you believe present the greatest impediment to more widespread usage of energy storage and development of ESS in California?
- Are there other barriers that were not identified during theworkshop? Please explain how these other barriers impede theusage or development of energy storage and whether they needto be resolved at the Commission or other forums.
- To whatextent can the Commission assist in removing these barriers?In your opinion, are there certain barriers that need to beresolved first, and therefore have higher priority?
The deadline for comments is August 29, 2011, and reply comments will be due September 16, 2011. Your can find a copy of the ruling and attachments here.
Yesterday, the Executive Director of the California Air Resources Board (CARB), Mary Nichols, announced that CARB is proposing to delay full implementation of California’s cap-and-trade program for a year. In testimony before the California Senate Select Committee on the Environment, the Economy, and Climate Change, Nichols stated that CARB is proposing to “initiate” the cap-and-trade program in 2012, but delay requirements for compliance until January 1, 2013. CARB adopted cap-and-trade in December 2010 and the program was set to go into effect on January 1, 2012, the statutory deadline for all greenhouse gas emissions reduction measures under A.B. 32 to become operative. CARB’s announcement comes despite an order from the California Court of Appeals last Friday that CARB can continue with implementation of cap-and-trade pending appeals related to the program in Association of Irritated Residents v. CARB. Earlier this month, CARB issued a revised analysis of alternatives to the cap-and-trade program, as ordered by the lower court in Association of Irritated Residents v. CARB. That supplemental environmental document is currently open for public comment until July 28 and CARB will consider adoption of the supplement on August 24, 2011. Nichols stated in her testimony that CARB will hold a public workshop in the next few weeks on its proposal to delay cap-and-trade compliance and other elements needed to finalize the cap-and-trade regulation. Look for CARB to issue an updated draft regulation in advance of the public workshop.
On Tuesday, June 28, 2011, the CPUC will hold an “Electric Energy Storage Workshop” as part of its R10-12-007 proceeding for AB 2514, which defines the process by which the CPUC will consider electric energy storage standards for California’s investor owned utilities. The workshop will be held at in the Golden Gate Room at CPUC’s headquarters from 9:30 am to 4:00 pm.
According to a draft agenda circulated by the CPUC, the theme of the workshop will be addressing barriers to entry facing Electric Energy Storage (EES). The workshops goals are to identify actions that the CPUC should consider, as well as whether and how it should participate in other forums.
The morning will feature presentations from several different perspectives, with each presentation to be followed by Q&A:
- Presentation from UC Berkeley and California Energy Commission (CEC) team on “2020 Vision Project”
- Presentation from CAISO about recent storage-related activities at the Independent System Operator, including findings from recent studies.
- Presentation from Southern California Edison (SCE) discussing a white paper entitled Moving Energy Storage from Concept to Reality.
- Presentation from California Energy Storage Alliance about developer’s perspectives
The afternoon will feature a facilitated presentation about a staff straw proposal concerning potential CPUC actions. The CPUC will allow parties to provide post-workshop comments on both the presentations and the staff straw proposal.
The CPUC is willing to accommodate short presentations (five minutes or less) or share prepared material pertinent to the workshop. Any party who wishes to do so may contact Michael Colvin at firstname.lastname@example.org. For reference (or inspiration), a series of energy storage presentations made to the CPUC as part of its 2011 IEPR process can be found here.
On June 16, 2011, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) seeking comments on what it described as two separate but related issues, both of which apply to electric energy storage (EES).
First, because FERC is interested in facilitating the development of robust competitive markets to provide ancillary services from all resources types, it seeks comment on “existing restrictions on third-party provision of ancillary services, irrespective of the technologies used for such provision.” In soliciting these comments, FERC noted the growing interest in rate flexibility among sellers of ancillary services, and a desire from those obligated to purchase those services to increase the available supply. Although a variety of resources can provide ancillary services, FERC believes that many are discouraged from doing so by the Commission’s restrictions on market-based pricing coupled with a lack of access to information that could help satisfy the requirements of those policies. Access to information is particularly difficult outside of areas served by RTOs/ISOs, which areas are often with the greatest need for an ancillary services market.
FERC pointedly invites comments on whether it should revise or replace the restriction set forth in Avista Corp., 87 FERC ¶ 61,223, order on reh’g, 89 FERC ¶ 61,136 (1999), which prohibits, absent a study showing lack of market power, third-party market-based sales of ancillary services to transmission providers seeking to meet their ancillary services obligations under the Open Access Transmission Tariff (OATT). Assuming that FERC revises or replaces the Avista restriction to facilitate the provision of ancillary services, it also seeks input on how it should contemporaneously ensure just and reasonable rates. In a related inquiry, the Commission is seeking comments on whether the various cost-based compensation methods for frequency regulation that exist in regions outside of organized markets can be adjusted to address the speed and accuracy issues identified in FERC’s recent Frequency Regulation Notice of Proposed Rulemaking for organized wholesale energy markets. See Frequency Regulation Compensation in the Organized Wholesale Power Markets, 76 FR 11177 (March 1, 2011), Notice of Proposed Rulemaking, FERC States & Regs ¶ 32,672 (2011). The June 16 NOI, when considered in context with this year’s NOPR on Frequency Regulation and last year’s NOI on EES, could signal that a broader rulemaking regarding EES is on the horizon.
Recognizing that “the role of electric storage and other new market entrants play in competitive markets is still evolving,” the Commission seeks comments on whether it should revise “current accounting and reporting requirements as they pertain to the oversight of jurisdictional entities using electric storage technologies” other than pumped storage hydro (for which FERC has established methods of accounting, reporting and rate recovery). Current utility accounting requirements do not appropriately fit EES due to the technology’s abilities to act like generation, transmission, and distribution assets. Accordingly, FERC is soliciting “specific details regarding whether and, if so, how to amend the current accounting and reporting requirements to specifically account for and report energy storage operations and activities.”
The NOI was published in the Federal Register on June 22, 2011, and comments are due sixty (60) days from that date.
Thanks to my colleague Jason Johns for his comments on this posting!
On June 3, the California Energy Commission (“CEC”) issued a Notice of Intent to Implement 33 Percent Renewables Portfolio Standard (“RPS”). The new 33% RPS was signed into law by Governor Brown on April 12, 2011. The legislation for the first time expanded the RPS to publicly-owned utilities (“POU”), and tasked the CEC with, among other things, monitoring POU compliance with, and developing regulations to enforce, the new 33% RPS.
The Notice also encourages all regulated entities, including POUs, to participate in the California Public Utilities Commission (“CPUC”) proceeding addressing the new RPS, Rulemaking 11-05-005, “so that, where appropriate, the [CEC] and CPUC may coordinate program development.”
The Notice states that the CEC will implement the new RPS through two processes: (1) amending the RPS Eligibility Guidebook through the existing amendment process so that it conforms with the new legislation, and (2) initiating a rulemaking proceeding to address POU compliance. Although the new RPS legislation set a target date of July 1, 2011 for the CEC to adopt regulations for POU compliance, pending legislation (Senate Bill 23) may extend that deadline to July 1, 2012.
On June 6, the CEC also noticed a staff workshop for June 17, 2011 to introduce the scope and a tentative schedule for the rulemaking proceeding concerning POU compliance, and to solicit comments from interested stakeholders. Written comments may also be submitted to the CEC by July 1, 2011.
The Oregon Department of Energy (ODOE) has issued new temporary BETC rules. The purpose of these rules, according to ODOE, is to clarify how the Section 1603 Grant will be deducted from BETC project costs. In an apparent reversal of ODOE’s recent position during the Tier Two and Tier Three application phases, the temporary rules appear to exclude from the definition of a “federal grant” any Section 1603 Grant that was obtained before April 18, 2011. However, the Section 1603 Grantwill be deducted from “certified” costs for projects that receive preliminary certification and that start construction after April 18, 2011 (the issuance date of these temporary rules). The temporary rules define certified costs to be the “costs certified in the final certification issued pursuant to ORS 469.215.” To see ODOE’s news release and a copy of the new temporary rules follow the links below.
http://www.oregon.gov/ENERGY/news/1133BETCFedGrant.shtml [news release]
California Public Utilities Commission Holds Prehearing Conference on Energy Storage Procurement Targets
As we’ve previously discussed, California’s AB 2514 requires the CPUC and municipal utilities in California to open proceedings by March 1, 2012 to determine appropriate targets, if any, for the procurement of viable and cost-effective energy storage systems by load-serving entities. Over a year before that deadline, the CPUC opened Rulemaking 10-12-007 in December of last year to both implement AB 2514 and “on [the CPUC’s] own motion to initiate policy for California utilities to consider the procurement of viable and cost effective storage systems.” In early March, the CPUC held an initial workshop on the scope of the rulemaking proceeding.
On April 21, the Commission held a prehearing conference to determine the scope and schedule for the proceeding. Stoel Rives partner Seth Hilton attended the conference. Among the issues discussed at the prehearing conference, led by Administrative Law Judge Yip-Kikugawa, was whether to conduct the proceeding in phases (e.g., first examining how storage might be applied, and then in a subsequent proceeding setting what the mandate will be for storage procurement), the issues to be covered in each phase , and whether evidentiary hearings would be necessary.
According to ALJ Yip-Kikugawa, a scoping memo should issue in the next two to three weeks. The scoping memo will set out the issues to be considered in the proceeding and a schedule for their resolution.
We'll be posting further information on Renewable + Law Blog when the scoping memo comes out, so stay tuned for further developments.
Having first reported to our readers in February that LexisNexis had nominated the Stoel Rives Renewable + Law Blog for its Top 50 Environmental Law & Climate Change Blogs for 2011 award, we are pleased to announce we made the list of winners! In publishing its Top 50 list, LexisNexis declared that our Renewable + Law bloggers’ “avowed passion for solar energy, wind energy, biofuels, ocean and hydrokinetic energy, biomass, waste-to-energy, geothermal and other clean technologies is evident in the care they take with this blog-the posts are frequent, the topics are interesting and cutting edge, and the writing is top notch.”
Thanks again to all our readers who make regular use of Renewable + Law Blog and those who wrote in to support us for this award. We're honored and inspired, and we plan to keep those Blogs and letters coming.
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 attorney Jay Eckhardt will give a presentation on April 21 addressing the proposed new FTC Green Guides. The presentation will focus on new FTC guidance and interpretations concerning renewable energy claims and carbon offset claims, as well as claims concerning renewable materials, and the use of green seals and certifications. Going beyond the Guides - the presentation will also review the broader enforcement environment. The program is sponsored by the Sustainble Future and Antitust & Trade Regulation Sections of the Oregon State Bar, and the Green Business Initiative at the University of Oregon School of Law.
For event details and logistics, click here. Admission to the live event in downtown Portland, Oregon is free. A telephone number and passcode will be provided for attendees unable to attend in person.
For more information on reguation of environmental marketing, see the Stoel Rives Green Guides Resource Page.
A report from Stoel Rives attorney Jake Storms (Sacramento):
The California Public Utility Commission (“CPUC”) recently announced that it will reopen the Rule 21 Working Group. Rule 21 governs the interconnection of distributed generation to a utility’s distribution system.
Each of the three largest investor-owned utilities—Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric—have a version of Rule 21 in their electric tariffs, which are subject to approval by the CPUC. The last Rule 21 workshop was held in 2008. The CPUC stated that, given the substantial changes in the technical and regulatory landscape in the past several years, Rule 21 is in need of reconsideration and has set forth a list of issues it believes should be addressed by the new Working Group. These include:
• The need for transparency in processing, queue information, and customer application information
• The need for review and potential reconsideration of technical screens within Rule 21 to ensure that the appropriate issues are being studied
• The need for articulation of cost-allocation methodology when network upgrades are required
• The need for review of utility tariffs for consistency with each other and with state law
• The need for additional standard interconnection agreements to accommodate the different types of distributed generation projects anticipated to come online
The first meeting of the Rule 21 Working Group will be Friday, April 29, 2011 from 10:00 a.m. to 3:00 p.m. at the Auditorium of the CPUC located at 500 Van Ness Avenue, San Francisco, CA.
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:
On the one hand, the FTC in the United States takes an enforcement approach, recently challenging a company that was marketing a sham certification program. In Europe and Canada, in contrast, regulators have done something different, appointing private firms to assess and certify "green" products and services.
Read the full column here.