MINNESOTA PAVES THE WAY FOR MORE EV TRAFFIC ON THE ROADS

On May 9, 2018 the Minnesota Public Utilities Commission issued an order approving Xcel Energy’s residential electric vehicle (“EV”) pilot program (the “Pilot”), designed as an alternative to Xcel’s existing EV tariff, concluding that the Pilot will “benefit all ratepayers by aiding Xcel in its efforts to integrate EV load as cost-effectively as possible.” A full copy of the Commission’s order is available by clicking here.

By way of background, Xcel petitioned the Commission for approval of the Pilot after receiving consumer feedback on Xcel’s initial residential EV tariff filed in January 2015 pursuant to Minn. Stat. § 216B.1614. Under the initial EV tariff, the typical residential customer paid approximately $1,725 to $3,525 to enroll due to various costs including: wiring, installation of additional meters, and electric vehicle supply equipment (“EVSE”). Consumer feedback to Xcel that these costs were simply too high.

Under the Pilot, consumers’ barrier to entry complaints are addressed by employing the use of EVSE that sends usage data to the utility via the customer’s home wireless network, removing the need for an additional meter. Because EVSE transmits customer data through a wireless connection, customers may be wary of data privacy issues. In an attempt to remedy these concerns, the Commission requires that Xcel immediately notify customers of any unauthorized access to data obtained through this Pilot.

As an additional attempt to make the Pilot more accessible, Customers now have the option to pay for the EVSE over a period of time which also reduces initial costs. participants may elect to pay for EVSE through either a monthly customer charge included in a “bundled service” rate option, or under a “prepay” option. Under the “bundled service” option the monthly customer charge will be no higher than $19 and the “prepay” monthly customer charge no higher than $8. Xcel also negotiated with several vendors to supply and install EVSE to further ease the cost of entry. Lastly, like Xcel’s existing EV tariff, the Pilot offers a lower per-kilowatt-hour (“kWh”) rate during off peak hours.

As for accounting treatment, Xcel requested and received Commission approval for it to own all EVSE during the term of the pilot program, to capitalize the EVSE costs as distribution plant, and to earn a return upon the capitalized amounts. Xcel also received approval for recovering a carrying charge on the unpaid balance of the EVSE purchase price in the case of bundled service. These costs, as well as the costs of customer-outreach initiatives, will be recovered in the communications-cost tracker account under Xcel’s existing EV tariff.

Xcel will submit compliance filings by June 1, 2019, providing the Commission with data related to the Pilot. In other words, more to come.  But not just in this docket.

Also issued by the Commission on May 9 was a Notice of Comment Period in Commission Docket No. CI-17-879, which is the miscellaneous docket where the Commission seeks to gain more understanding of: (1) the possible impacts of EVs on the electric system, utilities, and utility customers, including the potential electric system benefits; (2) the degree to which utilities and utility regulatory policy can impact the extent and pace of EV penetration in Minnesota; and (3) possible EV tariff options to facilitate wider availability of EV charging infrastructure. The Commission’s Notice of Comment Period may be accessed here.

Arbitration Clauses in Solar Contracts

This month, a panel of the New Jersey Superior Court, Appellate Division, ruled that a proposed class action brought by customers of a solar energy company was subject to arbitration. The case, Brian and Ananis Griffoul v. NRG Residential Solar Solutions, LLC, Dkt. No. A-5536-16T1, alleged fraudulent marketing under the New Jersey Consumer Fraud Act as well as violations of the state’s Truth-In-Consumer Contract Warranty and Notice Act.

The defendant, NRG Residential Solar Solutions, LLC, responded to the lawsuit with a motion to compel arbitration and to dismiss the claims with prejudice. The trial court judge originally sided with the plaintiffs, finding the case analogous to Atalese v. U.S. Legal Services Group, L.P., 219 N.J. 430, 435 (2014), which found an arbitration clause unenforceable because it failed to clearly and unambiguously state that consumers were waiving their right to seek relief in court. Specifically, in Atalese, the court held the arbitration clause failed to state that consumers were waiving their right to seek relief in court by agreeing to the arbitration clause.

But the appellate court in Griffoul reversed, premising its holding on the arbitration clause’s clear and unambiguous language. It found the arbitration clause expressly “announced” that any dispute was subject to arbitration; that arbitration was the “sole and exclusive remedy”; and “clearly stated the parties were waiving the right to a jury trial.” Importantly, the appellate court also found–unlike the trial court–that the arbitration clause “clearly” limited claims brought in arbitration to individual claims, therefore barring a class action in arbitration.

Griffoul brings more certainty and clarification to the law. When considered alongside Atalese, it underscores the critical importance of using clear language, which unambiguously announces to consumers that any potential claim is subject to arbitration and that they are waiving their right to seek relief in court.

Helping the Hook-Up: FERC’s Generator Interconnection Procedures Reform Seeks to Improve Information Flow, Recognizes Changing Technology and Opens Further Opportunities for Storage

The Federal Energy Regulatory Commission’s (“FERC”) long-awaited Order 845 (Reform of Generator Interconnection Procedures and Agreements) was issued on April 19 after over two years of consideration of the issues. Order 845 is the first grid-wide major reform of FERC’s Generator Interconnection Procedures and Agreements since Order 2003 was issued 15 years ago.  Order 845 adopts reforms that are designed to address three goals: (1) improving certainty for interconnection customers, (2) promoting more informed interconnection decisions, and (3) enhancing the interconnection process.

Order 845 revises FERC’s pro forma Large Generator Interconnection Procedures (“LGIP”) and Large Generator Interconnection Agreement (“LGIA”) to recognize the changing landscape of technology and is intended to provide interconnection customers with new opportunities to interconnect their projects faster and more cost-effectively.  For example, transmission providers must now allow interconnection customers (at the interconnection customer’s option) to build the needed transmission owner interconnection facilities and stand-alone network upgrades in all cases. Previously, interconnection customers only had this option if the transmission owner could not meet the dates proposed by the interconnection customer.  Thus, an interconnection customer has newly granted flexibility in the construction of the transmission owner interconnection facilities and stand-alone network upgrades. If the transmission owner returns a high cost estimate, then the interconnection customer can manage the construction of the transmission owner interconnection facilities. On the other hand, if the transmission owner cost estimate is reasonable, the interconnection customer can choose to leave the construction responsibilities for the transmission owner interconnection facilities and stand-alone network upgrade with the transmission owner. Interconnection customers can now make these decisions based on both timing and cost considerations.

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Updates to Energy-Related Bills in the 2017-2018 California Legislative Session

Stoel Rives’ Energy Team has been monitoring and providing summaries of key energy-related bills introduced by California legislators since the beginning of the 2017-2018 legislative session. Legislators have been busy moving bills through the legislative process since reconvening from the spring recess. Below is a summary and status of bills we have been following.

An enrolled bill is one that has been through the proofreading process and is sent to the Governor to take action. A two-year bill is a bill taken out of consideration during the first year of a regular legislative session, with the intent of taking it up again during the second half of the session.

  • Since our last update, the Governor has vetoed one bill and signed the others that were sent for approval earlier this session.
  • Several bills we previously reported on have become two-year bills, but without much movement in this second half of the session.
  • Several new bills have been introduced that are currently going through the process of amendments and hearings. 

 

Bills Passed Since Last Update

 

SB 549 (Bradford, D): Public utilities: reports: moneys for maintenance, safety and reliability.
STATUS: Approved by Governor September 25, 2017.

  • Existing law places various responsibilities upon the CPUC to ensure that public utility services are provided in a manner that protects the public safety and the safety of utility employees.
    • SB 549 requires an electrical or gas corporation to annually notify the CPUC each time that capital or expense revenue authorized by the CPUC for maintenance, safety or reliability is redirected for other purposes, and requires the CPUC to make the notification available to the Office of Safety Advocate, Office of Ratepayer Advocates, and to the service list of any relevant proceeding.

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5 Key Takeaways from FERC’s Recent Energy Storage Order

In February, FERC issued Order 841, Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators (the “Order”), requiring RTOs and ISOs to establish new market participation rules for energy storage that recognize the physical and operational characteristics of these resources. While the Order set forth some minimal requirements that each RTO/ISO must meet when proposing market rules, the Commission also left considerable flexibility for each RTO/ISO in implementation.

A number of ISOs/RTOs submitted motions for clarification and requests for rehearing in March, and last Friday, April 13 FERC issued a tolling order to allow for more time to consider these motions and requests. As we await FERC’s response, here are our five key takeaways from the Order as it currently stands:

  1. New Revenue Opportunities for Storage. With the Order, there is now a pathway for energy storage to be able to participate in wholesale markets on something like a level playing field with other resources. Market rules, for example, will now need to include storage-specific bidding parameters such as state of charge and allow for market participation of storage assets as both supply and demand resources. For the storage industry, this can open up new opportunities for multiple revenue streams in the Capacity, Energy, and Ancillary Services markets. At the same time, storage resources will not be precluded from participating in existing programs, such as demand response. The end result is that, in markets with existing programs, storage resources will now have more options for participation.
  2. Market Access Does Not Always Lead to More Storage Projects. Opening the door for storage participation is not the same as saying more storage will be built. Like any energy project, it can be hard to finance storage in the absence of fixed revenue contracts. Today, state procurement mandates are largely driving the storage market and how much more storage will be built on the basis of wholesale market access is hard to predict. This will depend in part on how energy storage companies choose to compete in wholesale markets, and whether accessing multiple revenue streams is possible. This will especially be true if wholesale energy prices alone do not make a project cost-effective.
  3. The ISOs/RTOs Are Generally Supportive of the Order, But Have Sought Further Guidance. A number of the ISOs/RTOs submitted motions for clarification on certain implementation issues. These were generally supportive of the overall direction of the Order, and asked for clarifications related to applicability in their specific markets and their role in implementation when there could be overlap with state authority. Reading the tea leaves suggests that while the ISOs/RTOs have already begun to consider these issues in the context of their unique regions, the interaction with state jurisdiction at the distribution level and the opportunity to participate at both wholesale and distribution level will be key to driving more storage procurement. Following the Order, we can also expect new voices in ISO/RTO stakeholder proceedings that will address the technical capabilities of new technologies.
  4. Compliance Filings Are Due in December, But Expect Some Delays. Compliance filings are due December 3rd of this year. While FERC stated that the Order’s allowance for as much regional flexibility as possible is intended to assist in meeting the compliance and implementation deadlines, it is unclear whether RTO/ISOs will have enough time to initiate robust stakeholder initiatives. Especially in markets with no existing programs, unforeseen stakeholder issues could slow down the process. MISO has already requested a 6 month extension in consideration of this time crunch as it relates to the distributed energy resource technical conference held last week.
  5. Individual ISO/RTO Stakeholder Processes Will Be More Important to Track. Once FERC responds to the motions for clarification, the ISOs/RTOs will be working on implementation details. It will be important to follow each one to see how unique details play out in each ISO/RTO region. For example, in light of MISO’s motion, we anticipate new storage market participation rules that go beyond FERC’s Order to address issues specific to distributed energy resources. The CAISO will be another one to watch, though their filings have stated that they already largely comply with the requirements of the Order, because of their recently identified operational issues associated with high levels of renewable integration and the opportunities storage can provide to solve them.

Check back here for updates as implementation of the Order progresses over the rest of the year.

California May Need up to 2,000 MW of New Battery Energy Storage Resources by 2030, Commission Finds

On February 8, 2018, the California Public Utilities Commission (“CPUC”) adopted a new procurement process in a decision which suggested that 2,000 MW of new battery energy storage resources may be needed in California by 2030. This means an additional 2,000 MW of storage on top of the existing 1,325 MW that is already required.

The new integrated resource planning process included modelling to explore the optimal energy resource portfolio designed to meet a greenhouse gas emissions planning target at the lowest possible cost while maintaining system reliability. This portfolio will be updated every two years. Each utility will need to file a procurement plan that either aligns with the optimal portfolio or explains the reasons for deviating from the optimal portfolio.

Here is an illustration of the new resources called for by the decision:

Here are the key things to keep in mind:

First, this calls for additional resources, on top of what is required by existing programs. This means grid planners see the need for an additional 2,000 MW of new battery energy by 2030 to allow the state to meet its policy goals. As shown, this also anticipates the need for substantial quantities of new utility-scale solar resources (9,000 MW) and in-state wind resources (1,100 MW).

Second, this refers to the need for battery energy storage resources, as distinguished from other types of energy storage technologies. In California, the largest source of energy storage other than batteries is in the form of pumped hydroelectric energy storage.

Third, this portfolio will change over time, as each two year cycle will revisit the models and adjust the optimal resource mix. However, the portfolio shown here represents a snapshot of what resource planners see as the future of California’s energy mix as of today. And as you can see, this points to a future that is heavily reliant on new battery storage resources.

Solar PPA Provider That Only “Arranges” Installation of System It Owns Is Not a “Contractor” in California

In the recently issued but unpublished decision Reed v. SunRun, Inc. (Los Angeles County Super. Ct. No. BC498002, Feb. 2, 2018), the Second District Court of Appeal ruled that a solar power purchase agreement (“PPA”) provider that only sells solar energy to homeowners is not required to be a licensed California contractor under certain circumstances. Specifically, the court held that where the PPA provider “arranges” installation by a licensed contractor of the solar energy system (“system”) installed on the homeowner’s house but the PPA provider retains ownership of the system and sells the electrical output from the system to the homeowner, the PPA provider does not need to be a licensed contractor.

This ruling is good news for PPA providers in the state, whether they are marketing PPAs for residential or commercial property owners. Further, the ruling does not harm homeowners or other property owners or otherwise run afoul of the regulatory purpose of the Business and Professions Code (“BPC”) where the actual physical installation of the system must still be performed by qualified licensed contractors. This decision, if published, would also benefit the state by the further refinement of several California decisions that otherwise seem to restrict “arrangers” unless they carefully craft their contracts and actual activities within a narrow aspect of non-construction services.

The facts leading to the SunRun decision are familiar to lawyers involved with clients in both the energy sector and the heavily regulated licensing scheme under California law: SunRun sought to facilitate the use of solar in California through a PPA structure that enables homeowners to purchase energy from SunRun-owned solar systems installed on the homeowners’ rooftops. SunRun itself was not a licensed contractor prior to February 2012, but worked with a number of licensed contractors for the installation of the systems. SunRun and a licensed contractor would 1) visit the home and evaluate what was optimally required for the system, 2) the contractor would present a design to the homeowner for approval, 3) the contractor would install the system (using SunRun’s “best practices” and SunRun’s modular parts), 4) SunRun would retain ownership of the system (including maintenance and insurance obligations), 5) the homeowner would agree to buy energy from SunRun for 20 years, with an option to buy the system during that time, and 6) if the homeowner breached the agreement, SunRun had reserved its right to remove the system (which would take about one day). SunRun’s agreement with the homeowner provided that SunRun would “arrange for the design, permitting, construction, installation and testing of the” system, but specified that a separate contractor would “furnish all installation and construction services” and that separate contractor was to be “solely responsible” for all aspects of the installation related to construction. Although SunRun could refuse to pay a contractor if the installation was not satisfactory, the approval was fairly superficial and cursory, taking “15 seconds to two minutes.” SunRun did not oversee installation nor was it physically present at the installation sites.

In August 2011, Reed contracted to purchase power from SunRun pursuant to a PPA styled as a “Solar Power Service Agreement.” Reed made only four of the monthly payments under the PPA and then sold his home. The new owner assumed the SunRun agreement. Later in January 2013, Reed sued SunRun and sought to certify a class on the grounds that SunRun was an unlicensed contractor and engaged in unfair competition. Although abandoning the “solar energy claims” and not pursuing the subclass he originally asserted, Reed still sought to pursue the contractor license violation allegations. Motions for summary adjudication/judgment followed by SunRun in 2014 and 2016. Relevant to the license analysis, in April 2016 after further discovery, the trial court ruled that SunRun was not a “contractor” under BPC 7026 because 1) it “did not direct or supervise its licensed installers’ work at any job site” and any approval was limited “exclusively to ensur[ing] the local designer and installer’s design matched the agreement,” and (2) even if SunRun were a contractor, it fell within the exception under BPC 7045 for a finished product that was not a fixed part of the home. An appeal by Reed followed.

On appeal of that aspect of the ruling, the appellate court affirmed in full the trial court’s determination. Importantly for those navigating California’s licensing regulations was the court’s reiteration of the public policy undergirding the BPC, while yet noting that the penalties that Reed sought to enforce hinged on whether or not SunRun was a “contractor” under BPC 7026. The court emphasized that a “contractor” historically had to 1) actually perform construction services, 2) supervise the performance of services, or 3) agree by contract to be “solely responsible” for construction services. Citing The Fifth Day, LLC v. Bolotin (2009) 172 Cal.App.4th 939, 947-950, the court stated that “[h]owever, a license is not required if a person merely coordinates construction services performed by others.” Rejecting Reed’s counter arguments outright, the court did not find it necessary to reach the alternative ground ruled upon by the trial court: whether SunRun’s system was within the non-fixture exception to licensing under BPC 7045.

Another helpful element of this lengthy litigation, although not at issue on appeal, was the initial motion for summary adjudication by SunRun in February 2014 where the trial court ruled that the applicable statute of limitations under BPC 7031 was one year. As the trial court succinctly stated:

This statute imposes forfeitures. The contractor’s work can be perfect and the client delighted. Then there would be neither damages nor any equitable basis for compensation or a remedy. Yet the legislature put in this provision to get contractors’ attention: get your license, or else. It is the financial equivalent of flogging. That is simple and harsh by design, and it is to drive home a point. A simple and harsh punishment serves “the clear statutory policy of deterring unlicensed contract work.” (Hydrotech Systems, Ltd. v. Oasis Waterpark (1991) 52 Cal.3d 988, 992; see also id. 995, 996, 997, and 998.) SunRun’s analysis is correct.

While neither the statute of limitations analysis nor the licensing ruling is published, both still serve as very good guidance using common sense in their application under California law. Nevertheless, entities looking to walk that line should be very mindful of the underlying facts and the points highlighted by the appellate court in this case, and ensure that neither their contract language nor their actual activities move them across the line and therefore potentially under the California contractor regulatory scheme found in the BPC.

FERC Brushes Away Secretary Perry’s “Resiliency” NOPR, Finding It Legally Deficient

In a move that was widely anticipated across the energy industry, the Federal Energy Regulatory Commission (FERC) today issued an order that terminated a notice of proposed rulemaking that had been initiated in October 2017 in response to a demand by Energy Secretary Rick Perry that FERC enact rules to compensate certain resources for what he then termed “grid resiliency.”   Today’s order punts the issue of grid resiliency to the organized energy market operators, who now have 60 days to provide FERC with specific information about how those operators are addressing grid resiliency on their respective systems and whether there remain any gaps to address.  FERC has thus effectively washed its hands of the Secretary’s proposal, leaving it for the market operators to put an end to (or reshape) the issue of “resiliency.”  FERC will consider the information submitted by the market operators, including the public’s response thereto, in taking a more “holistic” look at what “grid resiliency” means and whether anything more must be done about it.  The short of it, though, is that FERC seems intent on not arbitrarily tinkering with market forces, refusing in this instance to prop up uneconomic coal and nuclear facilities using payments for loosely-defined and controversial characteristics.  Instead, FERC reaffirmed its support for markets and market-based solutions, acknowledging that sometimes the market compels retirements simply because a technology has become uneconomic.

And so while the term “grid resiliency” may not yet leave our lexicon and will be given additional consideration in the months or years to come, I think it’s safe to say that what comes of compensating resources for “grid resiliency”, to the extent it occurs, will look little or nothing like what Secretary Perry had intended.

 

House Bill Would Extend the ITC to Standalone Energy Storage Systems

The investment tax credit (“ITC”) plays a major role in driving investment in the U.S. solar energy market. Earlier this month, two members of Congress introduced a bill in the U.S. House of Representatives to provide a similar ITC for energy storage systems.

The bill, called the Energy Storage Tax Incentive and Deployment Act of 2017 (H.R. 4649) (the “Act”), would extend the ITC to energy storage systems with a capacity of at least 5 kilowatt-hours (“kWh”).  The legislation is a companion to an identical bill introduced in the U.S. Senate earlier this year (S. 1868).

The Act is modeled on the existing ITC for solar energy, which enables the owner of a solar energy system to receive a tax credit equal to thirty percent (30%) of the cost of the system. The solar ITC, along with other tax incentives like accelerated depreciation, have been a significant driver of growth in the solar industry over the last decade.

However, under current law, the ITC cannot be claimed for an energy storage system unless it meets certain requirements (primarily, that it is installed and operated in connection with a solar energy system). This contemplates the use of energy storage as a component of a solar energy system. But energy storage systems are capable of functioning as standalone systems entirely separate from solar energy systems. The Act would enable such systems to be eligible for the ITC, thus greatly expanding the universe of eligible energy storage projects. In addition, many industry participants believe the Act would serve an important role in clarifying the complex rules governing the ITC for energy storage, which would provide greater certainty to investors.

In addition to extending the ITC to standalone energy storage systems, the Act would also expand the tax credit for residential energy efficiency property to include the costs of an eligible energy storage system. This will provide the same credit as currently available for solar energy systems. The credit will be limited to battery energy storage technologies and system sizes of at least 3 kWh.

California IOUs Request Approval of 175 MW of New Energy Storage Resources

On December 1, 2017, two of the three major California investor-owned utilities (“IOUs”), Pacific Gas & Electricity (“PG&E”) and Southern California Edison (“SCE”), submitted applications for approval of the results of their 2016-2017 energy storage request for offers.

Background on the Energy Storage Mandate in California

In September 2010, the Governor of California signed AB 2514, which required the California Public Utility Commission (“CPUC”) to determine, by October 21, 2013, appropriate targets, if any, for each load-serving entity to procure viable and cost effective energy storage resources.  Consistent with AB 2514, the CPUC issued D.13-10-040 on October 21, 2013, which adopted the Energy Storage Procurement Framework and Design Program, providing biennial storage procurement targets for each of the three large California IOUs – SCE, San Diego Gas & Electric Company, and PG&E. Overall, the mandate called for the IOUs to procure a total of 1,325 MW of storage capacity by 2020.

The IOUs held their first biennial solicitation for energy storage contracts on December 1, 2014. As a result of those solicitations, SCE executed two contracts totaling 16.3 MW of distribution connected energy storage resources, and PG&E contracted for 74 MW new energy storage resources. Subsequently, the CPUC issued two decisions addressing the results of PG&E’s 2014 Energy Storage Request for Offers (“2014 ES RFO”). In D.16-09-004 the CPUC approved four Energy Storage Agreements proposed by PG&E, and rejected two Purchase and Sale Agreements associated with distribution reliability projects. In D.16-12-004 the CPUC rejected a 4 MW behind-the-retail-meter Energy Storage Agreement proposed by PG&E, determined that PG&E had not met its 2014 energy storage target, and directed that PG&E’s 2016 energy storage target should be increased to account for the identified shortfall.

Results of 2016 Requests for Offer

PG&E issued its 2016-2017 ES RFO on December 1, 2016 to seek new energy storage offers to reach its 2016 goal and cover the shortfall of the 2014 ES RFO.

Following receipt of offers, PG&E has executed six energy storage agreements totaling 165 MW of new energy storage capacity. Five of these agreements (totaling 145 MW) call for the delivery of resource adequacy capacity and one agreement is a purchase and sale agreement for a 20 MW / 80 MWh distribution-connected storage project designed to provide distribution deferral benefits. These projects are summarized below:

Counterparty
(Project Name)
Storage Technology On-Line Date Discharge Duration
(Hours)
Size
(MW)
Connection Level
Calstor, LLC (EDF BTM) Lithium Ion Batteries 11/01/2020 4 10 Customer
Cascade Energy Storage, LLC (Cascade Energy Storage) Lithium Ion Batteries 12/01/2022 4 25 Transmission
Kingston Energy Storage, LLC (Kingston Energy Storage) Lithium Ion Batteries 12/01/2023 4 50 Transmission
Sierra Energy Storage, LLC (Sierra Energy Storage) Lithium Ion Batteries 12/01/2023 4 10 Transmission
Diablo Energy Storage, LLC (Diablo Energy Storage) Lithium Ion Batteries 12/01/2021 4 50 Transmission
Tesla, Inc. (Llagas Energy Storage) (PG&E owned distribution deferral project) Lithium Ion Batteries 11/01/2021 4 20 Distribution

SCE issued its energy storage and distribution deferral request for offers on December 1, 2016 (“ES&DD RFO”). The ES&DD RFO sought offers for up to 20 MW of resource adequacy-eligible energy storage projects in specified locations. This solicitation sought a lower amount of procurement because SCE had already satisfied its 2016 biennial storage procurement target.

In response to the bids, SCE selected one offer from Powin SBI, LLC for a 10 MW lithium iron phosphate battery storage project with a delivery period expected to begin on January 1, 2022 and end on December 31, 2031.

Next Steps

PG&E has sought CPUC approval of the agreements by August 2018, and SCE has sought approval by June 2018. Interested parties are encouraged to submit comments on the applications. Since the energy storage procurement is carried out biennially, the next round of IOU RFOs with regard to energy storage procurements should start around the end of 2018.

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