DOE to Fund Long-Duration Energy Storage

On Tuesday, DOE announced that it will be providing up to $30 million dollars through its Advanced Energy Research Projects Agency-Energy (ARPA-E) program to support the development of grid-connected long-duration energy storage.  The Duration Addition to electricitY Storage (DAYS) project will support the development of storage systems that will provide power to the grid for between 10 to 100 hours.  According to the project website, extended storage options will help to “prevent blackouts and smooth overall grid operation, improving resilience and enhancing grid security”; will “enable greater integration of intermittent renewable energy sources, greatly reducing emissions in the power sector”; and “could help improve grid efficiency and promote the growth of domestic energy sources.”

Notices of Intent to apply for funding under the program are due on June 15, 2018 with full applications due by July 2, 2018.

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PJM and NYISO take Steps to Address State Policy Objectives

PJM and the New York Independent System Operator (NYISO) both recently issued proposals to address the interplay of state policy objectives and wholesale electric market pricing.  PJM presented two alternative proposals to FERC, Docket No. ER18-1314, for authorization to amend PJM’s capacity market rules, and NY-ISO released a Carbon Pricing Straw Proposal.

PJM’s proposed tariff revisions target the capacity market price impact of resources receiving out-of-market state subsidies. The filing states that PJM is proposing these changes because “the PJM Region is seeing increased ‘participation of resources receiving out-of-market state revenues,’ which . . . threaten[] to ‘undermine[] [the first] principles [of capacity markets] in the PJM Region.”  The filing comes on the heels of the Commission’s recent contested order on ISO-New England’s (ISO-NE) Competitive Auction with Sponsored Policy Resources (CASPR) in which the Commission stated that the first principles of capacity markets are that:

[a] capacity market should facilitate robust competition for capacity supply obligations, provide price signals that guide the orderly entry and exit of capacity resources, result in the selection of the least-cost set of resources that possess the attributes sought by the markets, provide price transparency, shift risk as appropriate from customers to private capital, and mitigate market power.

PJM claims that its filing does not address “whether states have the right to act but instead how the wholesale market should respond to such actions.”  PJM presents FERC with two alternative options, neither of which received a large enough sector vote in PJM’s stakeholder process for endorsement:

  • Under Option A, the Capacity Pricing Approach, PJM would “accommodate” state subsidies by running the market twice.  The first run would be used to determine resource commitment. In this run, subsidized offers would bid at their subsidized level.  The second run would then determine the clearing price.  During this run, only those offers that cleared the first run would participate, but subsidized offers would be repriced at a competitive price.  This proposal is preferred by PJM and would replace PJM’s current Minimum Offer Price Rule (MOPR).
  • Under Option B, the MOPR-Ex proposal, PJM would “mitigate” the impacts of state subsidies by repricing subsidized offers before the market is run.  This proposal would apply a revised and expanded form of the current Minimum Offer Price Rule (MOPR-Ex) to both new and existing resources.  This approach is preferred by PJM’s Independent Market Monitor and received a higher portion of the sector-based vote in PJM’s stakeholder process.

Over 55 parties have intervened in this closely watched docket, including trade associations, environmental organizations, industrial customers, public utilities, rural electric cooperatives, independent power producers, and state attorney general, public service commission, and consumer advocate offices.  Responses to the filing are due by May 7, 2018.

NYISO’s Carbon Pricing Straw Proposal proposes to “harmonize” the State of New York’s decarbonization goals with NYISO’s wholesale electricity market prices by incorporating the price of carbon dioxide emissions into the market.  Under the proposal, each energy supplier participating in the market will be assessed a carbon charge for its carbon emissions.  For internal suppliers, the charge will be calculated based on the supplier’s point-of-production carbon emissions multiplied by a carbon price that will depend on whether the supplier is or is not covered by the Regional Greenhouse Gas Initiative.  The proposal states that it expects suppliers to incorporate these charges into their energy offers. Resources that clear the market will receive the full locational based marginal price (LBMP), but the carbon charge will be debited as part of the settlement process.  The proposal states it expects that the carbon charges should cause market prices to rise whenever high emitters are on the margin.  The straw proposal also addresses external transactions stating that to prevent production from shifting to resources outside of New York (which may be costlier and higher-emitting), external resources will be expected to “compete with internal resources on a status quo basis, as if there were no incremental carbon charge applied within the NYISO.”  As such, “NYISO would treat imports and exports similar to today (with imported energy being paid the full LBMP and exports buying energy at the full LBMP), but then apply a carbon charge to imports and a credit to exports.”  Under the proposal, load will be expected to continue to pay the full LBMP including the carbon effect on the market price, but will be credited the carbon charges collected from suppliers based on a cost levelizing allocation.

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FERC Gives Increasing Attention to Distributed Energy Resources

A number of recent FERC actions highlight the Commission’s growing focus on distributed energy resources (DERs).  Although there is no standard definition of DERs, the term generally refers to small resources that are located on the distribution system (typically below 100kV) and are geographically decentralized.  They can include generation resources such as solar and combined heat and power, and broader definitions of DER also encompass energy storage, energy efficiency, and demand response resources.

In February 2018, FERC issued a Staff Report entitled Distributed Energy Resources: Technical Considerations for the Bulk Power System.  This was followed by a two-day technical conference in mid-April that focused on the participation of DER aggregations in Regional Transmission Organization and Independent System Operator markets.  FERC has invited post-technical conference comments, but has separated the issues into two separate dockets.  Comments on available data on DER installations and DER modeling, planning, and operational studies are to be addressed in the new docket focused on DERs.  All other comments (such as those addressing DER aggregations’ participation in wholesale markets and the implications of such participation for state and local regulation) will remain in the docket FERC established when it proposed its rule on electric storage resources.

FERC also recently issued a unanimous order reaffirming an earlier declaratory order on its jurisdiction over energy efficiency resources.  FERC held that it has exclusive jurisdiction over the participation of energy efficiency resources in the organized wholesale electricity markets, including the terms that establish the eligibility for such resources’ participation.  It rejected the argument that this would interfere with state and local regulators’ jurisdiction to regulate retail electric service, and disagreed with the argument that “state and local restrictions on [energy efficiency resources] participation in wholesale markets is a valid exercise of state and local authority over electric retail service.”  Although this decision was limited to energy efficiency resources, it could foreshadow FERC’s future interpretation of its jurisdiction over DERs more broadly.

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Hawai‘i PUC Directed to Modify Rate Structure and Decouple Utility Revenues from Capital Investments

Earlier this week the Hawai‘i Governor David Ige signed into law the Hawai‘i Ratepayer Protection Act, SB 2939 SD 2, requiring the Hawai‘i Public Utility Commission (“PUC”) to develop a performance based regulation model that will “break the direct link between allowed revenues and investment levels.”

In enacting the legislation, the Hawai‘ian Legislature recognized that integrating more renewable resources into the grid and reducing carbon emissions affects the traditional utility business model.  Under the traditional cost-of-service model, a regulated distribution utility’s earnings are based on its revenue requirement and the size of its load from which it recovers that requirement. The revenue requirement, in turn, is based on a combination of:

  • The utility’s operating costs (e.g. more consumption = more fuel = higher costs);
  • A return on its rate base which is largely derived from the level of prudent capital investment that the utility had made, or was expecting to make, in plant and other assets (higher investment = higher return); and
  • The recovery of depreciation expenses on those capital investments.

The Hawai‘ian Legislature expressed concern that in transitioning energy generation to renewable energy, utilities are reducing their fossil fuel purchases, but will be spending more on capital projects.  The bill states that “[t]he legislature is concerned that the existing regulatory compact misaligns the interests of customers and utilities because it may result in a bias toward expending utility capital on utility-owned projects that may displace more efficient or cost-effective options, such as distributed energy resources owned by customers or projects implemented by independent third parties.” The Legislature “concludes that it must ensure a change to the regulatory compact to promote decisions and strategies that will maximize public benefit, reduce ratepayer risk, and meet Hawaii’s energy goals.”

While other states and public service commissions have adopted various performance based regulation mechanisms, this law earns Hawai‘i the distinction of becoming the first state to enact legislation to decouple a utility’s revenues from its capital investments.

The Act directs the Hawai‘i PUC to establish by January 1, 2020 “performance incentives and penalty mechanisms that directly tie an electric utility revenues to that utility’s achievement on performance metrics.” These metrics are to include, but not be limited to:

  • Certain economic incentives or cost-recovery mechanisms;
  • Volatility and affordability of electric rates and customer electric bills;
  • Electric service reliability;
  • Customer engagement and satisfaction, including customer options for managing electricity costs;
  • Access to utility system information, including, but not limited to, public access to electric system planning data and aggregated customer energy use data and individual access to granular information about an individual customer’s own energy use data;
  • Rapid integration of renewable energy sources, including quality interconnection of customer-sited resources; and
  •  Timely execution of competitive procurement, third-party interconnection, and other business processes.

The Act does not apply to member-owned cooperative electric utilities.

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FERC Approves Cybersecurity Reliability Standard

In its April Open Meeting, FERC issued a final rule approving a cybersecurity Critical Infrastructure Protection (CIP) Reliability Standard.  The rule focuses on low impact Bulk Electric System (BES) Cyber Systems and transient electronic devices.  “Low impact” is the default classification for all Cyber Systems not rated as High or Medium Impact, and transient electronic devices include thumb drives, laptops, and other portable electronics that can connect to a Cyber System.

In response to a FERC directive, the North American Electric Reliability Corporation (NERC) sought approval in March 2017 of a Reliability Standard on “Cyber Security—Security Management Controls.”  This Reliability Standard would (1) clarify obligations related to electronic access control for low impact BES Cyber Systems; and (2) adopt mandatory security controls for transient electronic devices.  Although FERC had not directed it to do so, NERC also proposed to require responsible entities to have a policy for declaring and responding to CIP Exceptional Circumstances related to low impact BES Cyber Systems.

In October 2017, FERC proposed adopting this Reliability Standard.  However, it proposed two modifications to what NERC had submitted.  First, it proposed requiring that the standard “provide clear, objective criteria for electronic access controls for low impact BES Cyber Systems.”  Second, it proposed that the standard “address the need to mitigate the risk of malicious code that could result from third-party transient electronic devices.”

In its final rule, FERC adopted the Reliability Standard proposed by NERC, including the modification to mitigate the risk of malicious code from transient electronic devices.  Although commenters agreed that there was already an implicit obligation to guard against such risks, FERC concluded that an explicit requirement was needed to ensure that entities develop and implement adequate compliance plans.

Although FERC had proposed to direct NERC to develop objective criteria for electronic access controls for low impact BES Cyber Systems, it declined to do so in its final rule.  NERC and other commenters argued that existing standards provided a sufficiently clear security objective while at the same time providing responsible entities with the flexibility required to address the wide range of low impact BES Cyber Systems.  FERC stated that it was satisfied with this explanation, although it did direct NERC to conduct a study of what electronic access controls entities choose to implement and whether they are effective.  NERC must file this study by October 25, 2019.

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