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State legislatures across the country have been active this spring debating ambitious new targets and renewable energy market reforms, following the successful passage of multiple renewable energy mandates in certain states.  Last year California passed SB 100, which sets the target of 100% carbon-free electricity by 2045.  At least other three states—Hawaii, New Mexico, and Washington—have also adopted 100% renewable energy targets and, according to Inside Climate News, several other states debated 100% renewable energy legislation this spring including Minnesota, Illinois, Nevada, Maine, and Massachusetts.

Like other states adopting renewable energy mandates, the Washington legislature specifically concluded “that Washington must address the impacts of climate change by leading the transition to a clean energy economy … by transforming its energy supply.”  To support this goal, the Act mandates 100% renewable electricity generation by 2045.  To help achieve this, section six of the Washington law mandates that utilities must file a
“four-year clean energy implementation plan” by 2022 and every four years after that.  Each action plan must include “specific actions to be taken by investor-owned utility[ies] over the next four years … that demonstrate progress toward meeting the standards … of [the] act.”  By requiring the utilities to provide relatively frequent updates, the Washington legislature appears to indicate a desire for strong oversight of the transition to 100% renewable electricity generation.

In other states, such as Minnesota, 100% carbon-free targets were the subject of substantial attention and debate but were not ultimately adopted.  The Minnesota legislature ultimately passed a jobs and energy omnibus bill in a special session this year with more limited ambition—including provisions for energy storage pilot programs, which will allow public utilities to pursue and recover costs for such programs.  The pilot program petitions, at a minimum, must provide: (1) the storage technology utilized; (2) the energy storage capacity and the duration of the output at the capacity; (3) the proposed location; (4) the cost of purchase and installation; (5) the interplay between the storage facility and existing distributed generation resources; and (6) the overall goals of the project. 
Continue Reading Renewable Energy Trending in State Legislative Sessions

On April 25, the California Public Utilities Commission (“CPUC”) adopted a decision (“Decision”) in its Integrated Resource Plan (“IRP”) proceeding, R.16-02-007.

The Decision examined the first round of integrated resource plans filed by each of the load-serving entities subject to CPUC jurisdiction. The Decision approved the plans filed by 20 load-serving entities, found that another eight load-serving entities were not required to file integrated resource plans, and found that 19 plans were insufficient as they failed to address criteria pollutant issues. One load-serving entity—Commercial Energy of California, an energy service provider—failed to file an integrated resource plan at all. The Decision also provides specific guidance for plan development for each load-serving entity for the next IRP cycle.

CPUC staff also aggregated all of the resource plans into a single portfolio—after certain adjustments to render it feasible—defined as the Hybrid Conforming Portfolio, or HCP. Adjustments were necessary to ensure that the consolidated new resource procurement proposals did not exceed resource potential in a geographic area or existing transmission availability. Commission staff identified four regions where the proposed new wind resources exceeded assumed resource potential (Northern California, Solano, Southern California Desert, and Riverside East Palm Springs). Where resource potential was exceeded, staff adjusted the resources to come from nearby regions. There were also five regions where the proposed renewable buildout appeared to exceed assumed available transmission capacity (Central Valley North Los Banos, Greater Carrizo, Southern California Desert, Northern California, and Solano). Adjustments were made in these regions by converting the proposed projects to energy-only, or moving resources to nearby locations when transmission assumptions were exceeded. No resource selections for out-of-state resources that required transmission upgrades, however, were adjusted based on transmission limitations. The Decision requires load-serving entities to disclose the contractual and development status of their resource selections in future IRPs, in order to help avoid adjustment issues in the future, and to provide an updated filing with that information to the CPUC by August 16, 2019.
Continue Reading Recent California Public Utilities Commission Decision Charts Path Forward for its IRP Proceeding

The Federal Energy Regulatory Commission (“FERC” or the “Commission”) issued an order on May 1, 2019 denying rehearing of its orders asserting concurrent jurisdiction with a bankruptcy court over wholesale power contracts.

In January, prior to Pacific Gas & Electric (“PG&E”) filing for bankruptcy, NextEra Energy, Inc. and Exelon Corporation both filed complaints and petitions for declaratory orders from FERC, requesting that the Commission find that PG&E could not abrogate, amend, or reject in a bankruptcy proceeding any rates, terms, and conditions of its FERC-jurisdictional wholesale power contracts without first obtaining approval from the Commission.  The Commission quickly issued a brief order holding that a party to a FERC-jurisdictional wholesale power contract must obtain approval from both the bankruptcy court and the Commission  to reject a contract and modify the filed rate, respectively.  PG&E then filed its petition for bankruptcy and initiated an adversarial proceeding against FERC, requesting preliminary and injunctive relief.  That matter has continued to play out in the Northern District of California and there has not yet been a resolution by the bankruptcy court.  Meanwhile, PG&E requested rehearing of the Commission’s decision.  The Commission’s order on rehearing offers a more in-depth analysis of its jurisdiction.

The order first highlights the distinct roles that FERC and a bankruptcy court play in evaluating wholesale power contracts.  While FERC’s role is to protect the public interest, the bankruptcy court’s role is to provide a path to rehabilitate debtors.  The Commission held that the existence of bankruptcy proceedings does not alter its obligation, and exclusive authorization, to consider whether wholesale rates are just and reasonable. 
Continue Reading FERC Reaffirms Concurrent Jurisdiction Over PPAs in Bankruptcy

At its March 14, 2019 voting meeting, the California Public Utilities Commission (“CPUC”) voted out an Order Instituting Rulemaking (“OIR”) to Implement Senate Bill 237 (“SB 237”) Regarding Direct Access and to Consider Changes to Existing Direct Access Procedures.  The Rulemaking will address the expansion of Direct Access, as required by SB 237.

Direct Access permits customers of a California investor-owned utility (“IOU”) (e.g., Pacific Gas and Electric, San Diego Gas and Electric, Southern California Edison) to obtain their electricity from an electric service provider registered with the CPUC.  The IOU continues to provide transmission and distribution service to the customer.  Direct access was instituted in 1998 as part of California’s efforts to deregulate the electric sector.

As part of California’s efforts to recover from the energy crisis in 2000-2001, the California legislature passed Assembly Bill 1X (“AB1X”), which authorized the Department of Water Resources (“DWR”) to begin procuring electricity on behalf of IOU customers, and required the CPUC to allow DWR to recover the costs of such procurement from IOU ratepayers.  AB1X also authorized the CPUC to suspend Direct Access, motivated by a concern that IOU ratepayers would flee to Direct Access to avoid paying the cost of DWR procurement.Continue Reading California Public Utilities Commission Opens Rulemaking to Consider Expansion of Direct Access

The 2019-2020 California Legislative Session has reached its first deadline.  February 22, 2019 marked the deadline by which bills could be introduced for the first half of the Legislative Session. Lawmakers will begin Spring Recess April 12 and reconvene April 22.  The last day for bills to be passed out of the house of origin is May 31, 2019.

Below is a list of some of the key bills Stoel Rives’ Energy Team will be monitoring throughout the Legislative Session.  We note that some bills do not contain language beyond the “intent of the Legislature.”  However, we will continue to monitor these bills in case of substantive amendments.  These bills are set forth separately below under the heading “Legislative Intent.”

The majority of the bills introduced this Legislative Session relate in some way to California’s efforts to reduce greenhouse gas emissions and move to cleaner sources of generation, including legislation governing electric vehicles, energy storage, and renewable energy.  A number of bills introduced in February also attempt to address the impacts of wildfires, or to reduce wildfire risk.


ASSEMBLY BILLS

AB 40 (Ting, D)   Zero-emission vehicles: comprehensive strategy.

Status: Introduced December 3, 2018; referred to Committees on Transportation and Natural Resources January 24, 2019.

AB 40 would require by no later than January 1, 2021, the State Air Resources Board to develop a comprehensive strategy to ensure that the sales of new motor vehicles and new light-duty trucks in the state have transitioned fully to zero-emission vehicles, as defined, by 2040, as specified.
Continue Reading Key Energy Related Bills Introduced in the 2019-2020 Legislative Session

The Federal Energy Regulatory Commission (“FERC”) issued a Notice of Proposed Rulemaking (“NOPR”) on December 20 proposing changes to its regulations regarding the horizontal market power analysis required for market-based rate (“MBR”) sellers.  The proposed rulemaking picks up on an earlier effort in Order No. 816 to ease the regulatory burden on MBR sellers in RTO/ISO markets.  The current proposal would eliminate the need for certain MBR sellers to submit indicative screens with their initial MBR application, triennial updates, and change in status notices.  The exemption would apply to all MBR sellers in RTO/ISO markets with RTO/ISO-administered energy, ancillary service, and capacity markets subject to FERC-approved RTO/ISO market monitoring and mitigation.  For RTO/ISO markets that lack an RTO/ISO-administered capacity market (that would be CAISO and SPP), MBR sellers would be exempt from the requirement to submit indicative screens if their MBR authority is limited to sales of energy and/or ancillary services.  FERC also proposed eliminating the rebuttable presumption that FERC-approved RTO/ISO market monitoring and mitigation is sufficient to address horizontal market power concerns for capacity sales in CAISO and SPP.

Background

MBR sellers are currently required to submit two indicative screens, a pivotal supplier screen and a wholesale market share screen, in their initial MBR applications, change in status notices, and any updated market power analyses. Passage of both screens creates a rebuttable presumption that the seller does not have horizontal market power.  If a seller fails either screen, it is presumed to have horizontal market power.  To rebut the presumption of market power, the seller must present evidence through a delivered price test or other means to show that it does not possess market power.  However, sellers in an RTO/ISO market who fail the screens have an alternative.  They may instead rely on FERC-approved RTO/ISO market monitoring and mitigation to address market power concerns.  In 2014, FERC issued a NOPR proposing to eliminate the indicative screen requirement for those RTO/ISO sellers because it yielded little practical benefit due to their ability to rely on RTO/ISO market monitoring and mitigation.  FERC decided not to act on that proposal in Order No. 816 but stated that it may consider the issue in the future.

The Current NOPR

In the current NOPR, FERC states that the indicative screens provide marginal additional market power protections given that FERC has found that RTO/ISO market monitoring and mitigation adequately mitigate a seller’s market power and FERC has access to other data regarding horizontal market power. FERC notes that all RTOs/ISOs have mitigation provisions for energy offers.  While not all RTOs/ISOs have market power mitigation provisions for ancillary services, concerns about market power in ancillary service offers are mitigated through the mitigation of energy offers, since ancillary service prices are based on the opportunity cost of not generating energy.  Finally, ISO-NE, NYISO, PJM, and MISO all have capacity markets with FERC-approved market power mitigation.
Continue Reading FERC Issues NOPR to Eliminate Horizontal Market Screens for Certain MBR Sellers

In a recent order from the Minnesota Public Utilities Commission (the “Commission”), Minnesota took a big step to update the state’s interconnection process and standard interconnection agreement for distributed energy resources or “DERs.” This ongoing process relates to Minn. Stat. § 216B.1611 which directs the Commission to establish generic standards for utilities’ tariffs that govern…

On June 21, 2018, the United States District Court, District of Minnesota issued an order and memorandum rejecting a challenge to the constitutionality of Minn. Stat. § 216B.246 and granting defendants’ motions to dismiss. The statute, which was enacted after FERC Order 1000 (and eliminating the federal right of first refusal or “ROFR”), provides incumbent…

On June 1, 2018, only two days after the completion of 12th SNEC International Photovoltaic Power Generation Conference, the world’s biggest solar conference and a central gathering of all the Chinese PV manufacturers, the Chinese central government announced a nation-wide solar subsidy cut that resulted in the Chinese solar stocks tumbling with the falling range from 7% to 31%.[1]  Specifically, the National Development and Reform Commission, the Ministry of Finance and the National Energy Administration of China issued the “2018 Solar PV Generation Notice” (the “Notice”)[2], imposing caps and reducing the feed-in tariff (“FiT”) mechanism in connection with China’s domestic PV projects[3], and at the same time setting rules at the central government level to urge marketization of China’s solar industry.[4]

Overview of the Notice

Imposition of Project Cap

Firstly, the Notice imposed a 10 GW cap on capacity for distributed generation projects and stopped utility-scale project for 2018. This is a steep drop from last year’s installation of 19 GW distributed generation projects (out of 53 GW of all PV projects in China).[5] Also, the Notice provided that only those distributed generation projects that are connected to the grid no later than May 31, 2018 would be covered by central government’s budget, whereas the financial responsibility for other distributed generation projects would be shifted to local governments.[6]  In addition, the Notice encouraged the local governments to come up with more solar supportive policies, to reduce non-technological costs, and as a result to reduce the needs for central and local governments’ solar subsidies.[7]  Separately, the Notice abolished the utility-scale projects and instructed local governments not to approve any utility-scale projects until central government’s further notice.[8]
Continue Reading China’s Renewable Policy Shift and its Global Implications

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…