In a proposed decision issued today 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.
On Thursday, March 27, 2014, the California Public Utilities Commission established rules for transitioning distributed generation renewable energy systems from the current net energy metering (NEM) arrangement to the successor tariff which will be adopted by the CPUC in 2015.
The decision, D.14-03-041, was mandated by last year’s passage of AB 327, requiring implementation of changes to California’s NEM program by 2017. AB 327 specifically directed the CPUC to establish a transition period for “pre-existing” systems based on a “reasonable expected payback period” and other factors consistent with California’s policy to promote the use of renewable energy. Under the legislation, systems installed prior to the earlier of July 1, 2017, or the date upon which the customer’s utility reaches the 5% cap on its capacity subject to the net metering tariff, would be eligible for the transition period.
The CPUC decided that 20 years from the date of installation (interconnection) would be the transition period for pre-existing systems. The adopted period is longer than advocated by the utilities and certain ratepayer organizations and shorter than urged by some members of the solar industry and local governments. The Commission also rejected arguments that customers installing systems after adoption of the transition rule should have shorter transition periods on the theory that they had notice of the coming change in tariffs and therefore could not have had reasonable expectations of more lengthy “payback” periods.Continue Reading...
Fake Punt! Minnesota Commission Immediately Reevaluates Motion, Advances Solar Plus One (or more) Gas Plants
In a follow up to our prior post, we now report that the Minnesota Commission subsequently modified its initial decision to clarify that Xcel Energy is directed to negotiate a power purchase agreement with the solar bidder, which will be reviewed by the Commission to ensure the terms are consistent with the public interest. Xcel is also directed to negotiate with the natural gas project bidders and develop pricing terms for its own natural gas project. Here is the text from the revised motion.
Although all terms will be reviewed by the Commission, Xcel Energy's Minnesota ratepayers will likely have a utility-scale solar project and at least one natural gas project to meet capacity needs in the 2017-2019 timeframe. And it's fair to state the Commission's decision puts solar in the red-zone, first and goal.
After the years of inconclusive resource planning, months of contested case proceedings, and days of oral argument, discussion and review that led to today’s deliberations, the Minnesota Public Utilities Commission (“Commission”) unanimously decided not to decide. The ultimate question before the Commission was what capacity needs had been determined in the record and what should be done to fill that need on Xcel Energy’s system. At the turn of the new year, the Administrative Law Judge’s (“ALJ”) answers to these questions made national news by finding that the solar bid provided the best value for ratepayers (see our blog on that here). The ALJ made his determination, in part, based on new modeling done at the request of the Commission given the significant changes in circumstances that had occurred since docket was opened (e.g., Xcel Energy acquired 750MW of new wind and Minnesota passed a Solar Energy Standard). In light of the changed circumstances and uncertain need, the ALJ recommended selection of the solar resource that was independently “needed” by statute, a capacity bid that could be added as necessary to bridge for any further shortfall, and then conduct a more thorough analysis for the longer-term needs. Today the Commission instead chose to rely primarily on the original need determination that opened the docket, accept the ALJ’s findings only to the extent they were consistent with their own findings, and direct Xcel to negotiate with everyone proposing to build something and report back.
Despite the above, the decision is a significant step forward for solar. This was the first time a solar proposal had competed directly with natural gas in a resource acquisition process and, despite significant pressure from the Department of Commerce to shuffle the solar bid off into a separate, solar-only proceeding, the Commission confirmed today that the solar bid was welcome at the big kids table.
Look for a forthcoming Order that includes something like this:
In order to meet reliability and adequacy requirements and to comply with MN energy policy statutes, direct Xcel to separately negotiate power purchase agreements with Geronimo Energy, Calpine, Invenergy and develop pricing terms for Black Dog 6 to address the overall Xcel system needs identified in this record and the March 5, 2013 Integrated Resource Plan Order and determine which resources best meet system needs and are in ratepayers’ best interests.
Find that negotiated terms that shift risk or unknown costs to ratepayers are not likely to be reasonable. Find that bidders shall be held to the prices and terms used to evaluate each bid for purposes of cost recovery from Xcel ratepayers. Ratepayers will not be at risk for costs that are higher than bid or for benefits assumed in bids that do not materialize. If actual costs are lower than bid, the bidders should be allowed to keep those savings.
Require that power purchase agreement provide terms that sufficiently protect ratepayers from risks associated with the non-deliverability of accredited capacity or energy from the projects as proposed.
"Don't mess with Texas." Apparently the slogan even applies to liquidated damages clauses.
This morning, the Supreme Court of Texas issued a decision in a drawn-out fight between wind developer FPL Energy and the power marketer TXU Portfolio Management. The dispute originates from power purchase agreements (PPAs) in which FPL failed to deliver enough electricity and renewable energy credits (RECs) to cover its performance guaranty over a period of four years, in large part because of congestion and resulting curtailment orders by ERCOT. TXU initially brought suit for the shortfall, and FPL countered by claiming that the shortfalls were due to curtailments by ERCOT, and that TXU caused those curtailments to occur by failing to ensure that transmission capacity would be available away from the project delivery point. In any event, FPL argued that the liquidated damages for the shortfall amounted to an unenforceable penalty.
At the time of negotiating the PPAs, TXU and FPL agreed by contract that a shortfall in RECs would trigger liquidated damages in the amount of $50 per REC. There was no market for RECs at the time, and so the parties had settled on this damages amount by using the $50 per REC penalty that the Public Utility Commission of Texas could impose on utilities for not acquiring enough RECs. (The parties also agreed to an alternative price of twice the market value of RECs as determined by the Public Utilities Commission of Texas, if any such determination occurred.)
But today the Supreme Court of Texas ruled that the parties' agreed-upon liquidated damages provision amounts to an unenforceable penalty. Although the clause may have been a reasonable estimate of TXU's damages at the time of negotiation--particularly given that the clause mirrored the regulatory penalty for REC shortfalls--the provision failed to reflect actual damages at the time it was applied. The parties' powers of divination had failed them!
In the court's words: "When the liquidated damages provisions operate with no rational relationship to actual damages, thus rendering the provisions unreasonable in light of actual damages, they are unenforceable." In other words, it does not matter that the liquidated provision in the PPA was a reasonable estimate of damages at the time it was negotiated. Instead, what matters is whether the liquidated damages provision at the time it is applied reflects actual damages. As a result, a provision that was once reasonable became invalidated when market values later created a significant difference between the past estimate and actual damages.
To put this in a broader context, not all states approach a liquidated damages provision in this way. In its decision, the Supreme Court of Texas applied the "second-look" doctrine to the liquidated damages clause (despite seemingly starting toward a different doctrine), meaning that the court considered whether the liquidated damages provision was reasonable at the time it was negotiated, and also whether it is reasonable at the time it is applied. A "one-look" state considers only whether a liquidated damages clause was reasonable at the time it was negotiated. If FPL and TXU had chosen in the PPA to apply the laws of a "one-look" state, then the result may have had many differences--tens of millions of differences.
As to how FPL wound up in the shortfall position to begin with, FPL argued that TXU had failed in its contractual duty to provide transmission capacity to deliver electricity away from the delivery point. That failure resulted in higher than expected congestion and resulting curtailment orders from ERCOT. TXU countered that its transmission service obligations were limited to transmission for “Net Energy” - i.e. energy that was first delivered to the Delivery Point. The court agreed with TXU, holding that TXU’s transmission obligations arose only when the FPL-generated electricity actually reached the Delivery Point. The court reached this holding notwithstanding its recognition of FPL’s argument that transmission congestion and ERCOT's related curtailment orders had prevented electricity from reaching the delivery point in the first place.
You may read the court's opinion here: TXU v. FPL.
NV Energy is in the market for solar. On March 10, 2014, the utility issued a Request for Information (“Solar Site RFI”), asking developers to help identify potential sites for solar projects that would be 20 MW AC or greater in size and are sufficiently developed to meet a 2016 commercial operation date.
The Solar Site RFI comes in the wake of SB 123’s passage in June 2013. The law requires electric utilities to issue RFPs for at least 300 MW of generating capacity from new renewable energy resources by December 31, 2016. Click here for more information. Responses are due March 21, 2014.
Yesterday afternoon, the Minnesota Public Utilities Commission approved the methodology for calculating value of solar (VOS) tariffs in Minnesota as developed by the Department of Commerce. In doing so, Minnesota became the first in the nation to adopt a VOS tariff methodology.
The Commission was required by statute to take action on the VOS calculation methodology by the end of the month. It had three options: to approve it as proposed, reject it, or approve it with modifications and with the consent of the Department. For background on the Department's January 31st recommendation, see our blog posts here and here. The Department subsequently included several modifications affecting the fuel price escalation factor, the avoided distribution capacity cost, and the environmental cost categories.
In its ruling, the Commission approved the Department’s methodology, as amended, by a 3-2 vote.Continue Reading...
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).