On November 29, 2018, the Pennsylvania General Assembly’s Nuclear Energy Caucus (“NEC”) released the “Bicameral Nuclear Energy Caucus Report” (“Report”) that details the NEC’s findings on nuclear energy issues during the 2017-2018 Legislative Session.  The Report finds that Pennsylvania’s five nuclear plants provide numerous benefits, including supporting jobs, providing zero-emissions energy, moderating electricity prices, and ensuring grid resilience and reliability.[1]  As a result, to avoid adverse “employment, economic, and environmental impacts associated with the premature closures” of Pennsylvania’s nuclear facilities, the Report suggests that Pennsylvania has four options to determine the future of its nuclear industry:[2]

  1. Do nothing and leave Pennsylvania’s clean energy resources, including its nuclear plants, on a trajectory to early retirement – effectively allowing PJM to dictate the mix of resources serving Pennsylvania.
  2. Modify AEPS (or establish a ZEC program) to put nuclear generation on equal footing with other zero-emission electric generation resources in Pennsylvania.
  3. Modify AEPS (or establish a ZEC program) with a “safety valve” mechanism that (depending on the outcome of the FERC proceeding) would allow Pennsylvania to adopt a new capacity construct proposed by FERC that is designed to accommodate state programs to support preferred generation resources.
  4. Establish a Pennsylvania carbon pricing program.

Despite the detail in the report, several questions remain unanswered and issues remain unaddressed:

  1. The Report does not specify the amount of subsidies that nuclear generators should receive. Any policy decision must include an analysis of the costs to consumers and the potential impact on employment and investment in Pennsylvania.
  2. The Report discusses testimony from a portion of the stakeholders (e.g., the nuclear industry, environmental advocates, and organized labor coalitions), but groups that serve as “watchdogs” to ensure that consumers’ costs and interests are considered by the legislature (e.g., the Pennsylvania Energy Consumer Alliance, the Pennsylvania Manufacturers Association, AARP, etc.) were not invited to testify before the NEC. By doing so, the NEC omitted a key stakeholder group that has a different perspective about the potential costs and pitfalls of “saving” the nuclear industry.
  3. The Report relies on a Brattle Group study to support the assertion that nuclear generators moderate electricity prices, thus providing $788 million in reductions to the energy costs of Pennsylvania’s consumers. However, that study assumes that there is no replacement of the retiring nuclear capacity with new generation.  Within the last three years, sufficient natural gas generation has been constructed (or is under construction) to match the entire Pennsylvania nuclear fleet, including those facilities that are not retiring (Susquehanna, Peach Bottom, and Limerick).  In December 2018 alone, Tenaska is scheduled to begin operation of a 925 MW plant in Westmoreland County.
  4. The Report summarily dismisses the fact that consumers paid $10 billion for stranded cost to the generation owners, without recognizing that those subsidies were calculated over the expected lifetime of the project. Once those payments were made, ratepayers were not expected to bear the financial risk that the plants could close.  Providing additional ratepayer subsidies is reneging on the bargain.
  5. Nuclear plants are not “prematurely” retiring – they are retiring because they cannot compete in the market. This is a natural effect of competitive market forces.  Non-competitive fuel sources (e.g., coal, inefficient gas, etc.) should retire from the market while stronger resources prevail.  Any attempt to interfere with these natural market sources will interfere with price signals and thus impact current and future investment in replacement generation.
  6. The Report makes errant assumptions (e.g., assuming that all Pennsylvania nuclear generators will retire) and misstates PJM’s conclusion in its fuel security study, which is still ongoing.

 

We are continuing to review the Report and will provide further updates.  In the interim, if you have any questions, please do not hesitate to contact David Kleppinger (dkleppinger@mcneeslaw.com), Pam Polacek (ppolacek@mcneeslaw.com), Kathy Pape (kpape@mcneeslaw.com), Kathy Bruder (kbruder@mcneeslaw.com), or Aly Hylander (ahylander@mcneeslaw.com).

[1] https://nuclearenergy.pasenategop.com/pennsylvanias-bipartisan-nuclear-energy-caucus-releases-report-detailing-impacts-of-losing-the-states-nuclear-industry-and-provides-options-for-taking-action-in-2019/

[2] Report, p. 30.

On June 21, 2018, PJM Member GreenHat Energy, LLC, defaulted on a $1.7 million weekly invoice for an FTR position payable to PJM.  PJM does not absorb the cost of market defaults; rather, PJM Members cover the cost of market defaults through a “default allocation assessment” charged to all PJM Members.  The value of the weekly invoice that was the basis of GreenHat’s original default translates to a default allocation assessment to PJM Members totaling approximately $1.2 million.  However, this weekly invoice unfortunately represents just the tip of the iceberg with respect to the impact of the GreenHat default on PJM Members and the PJM market.  Below is more information to help understand the far-reaching ramifications of this significant event.

GreenHat was a participant in PJM markets for Financial Transmission Rights or “FTRs.”  GreenHat started acquiring so-called “long-term FTRs” in 2015 and held FTR positions in its portfolio through 2021 before its PJM Membership was terminated due to the default.  The value of GreenHat’s portfolio has declined since the FTRs were acquired.  Existing PJM Tariff rules call for PJM to liquidate the entire position at the next available auction in the event of a default.  Approaching the liquidation this way for the GreenHat default could result in significant risk premiums and ultimately raise the default allocation costs for all PJM Members.  With this concern, PJM filed a request with FERC on July 26 for a waiver of the tariff obligation and to allow for liquidation of the FTR positions for one-month forward in each of the FTR auctions conducted from July to October 2018 to allow time for consideration of alternate approaches to handle the GreenHat default.

PJM has quantified the actual net losses on the FTR portfolio for the months of June and July 2018 and the costs to liquidate the August 2018 positions utilizing the approach set forth in the waiver request to be $42.5 million.  Because GreenHat held positions into the future, PJM is unable to determine the full value of the final default allocation because the price of the future market is unclear.  As such, given the remaining GreenHat positions, the actual amount of the default could far exceed $42.5 million.

At the August 23rd PJM Markets and Reliability Committee and Members Committee, PJM Members undertook two actions.

First, upon the motion of Exelon and Old Dominion Electric Cooperative, PJM Members approved PJM requesting FERC approval to allow PJM to suspend liquidating GreenHat’s August 24 through November 30 positions in favor of allowing these positions to “go to settlement.”  Those market participants speaking in favor of this approach indicated it would allow PJM Members, if interested, to hedge the costs associated with the GreenHat FTR positions.  This approach is also a reaction to information that the August 2018 FTR auction resulted in liquidation prices that were as much as six times higher than the actual portfolio losses for the first half of August.

Second, PJM Members voted to continue stakeholder deliberations of alternatives to PJM Tariff’s current liquidation process for FTR positions held by a member that defaults, which could also potentially apply to the GreenHat default.

Customers purchasing power or selling generation directly or indirectly in the PJM wholesale market will be impacted by the GreenHat default, treatment of the GreenHat FTR positions, and default allocation assessment.  It’s important to keep in mind that a PJM Member default is handled through both a membership and a market activity allocation.  The membership portion (10%) of allocation is capped at $10,000 annually.  The activity allocation (90%) is based on a pro rata share of market activity in the prior three months from the event of default.  From a retail customer perspective, PJM charges a default allocation assessment to PJM Members, including those that serve as retail customers’ suppliers (known as Load-Serving Entities at PJM).

If a customer purchases energy under a fixed-priced or other structured energy contract, the customer’s supplier may seek to pass along the costs incurred due to this default allocation.  As such, the customer’s contract language should be closely reviewed to determine whether such costs can be collected from the retail customer.  Also, those market participants, including customers, with access to FTRs may want to consider the benefits of pursuing strategies to minimize their own default allocation assessment.

McNees is available to assist in reviewing energy supply contracts to assess risks of being charged a portion of the GreenHat default and help understand the impact of the GreenHat default on your company.   Please contact Susan Bruce, sbruce@mcneeslaw.com or Amy York, ayork@mcneeslaw.com for more information or with any questions.

Capacity prices cleared PJM Interconnection LLC’s (PJM) most recent auction for the “rest of RTO” region at $140.00 per megawatt-day (MW-day) for the PJM delivery year June 1, 2021 through May 31, 2022.  The rest of RTO region represents all of the unconstrained zones of PJM and makes up the majority of the PJM footprint.  The clearing price of this auction is roughly double the result for the rest of RTO region for the prior delivery year which cleared at $76.53/MW-day.

Five local delivery areas were constrained and cleared at prices higher than the rest of RTO region:  ATSI $171.33/MW-day, BGE $200.30/MW-day, COMED $195.55/MW-day, EMAAC $165.73/MW-day, PSEG $204.29/MW-day.

The auction cleared a total of 163,627 MWs, representing a 21.5% reserve margin over PJM’s projected peak demand for the 2021/22 delivery year.  The prior auction cleared 165,109 MWs, representing a 23.3% reserve margin.

Notably, the amount of nuclear capacity that cleared in the auction was 7,473 MWs less than the prior auction.  FirstEnergy Solutions (FES) announced that it failed to clear 3,865 MW of nuclear capacity: Davis-Besse (875 MW), Perry (1,212 MW), and Beaver Valley Units 1 & 2 (1,778 MW).  Exelon announced that it failed to clear roughly 3,500 MW of nuclear capacity in the Dresden, Three Mile Island, and Byron plants, with Three Mile failing to clear for the second consecutive auction.  Exelon also announced that it cleared its Quad Cities nuclear plant in Illinois in the auction, a plant that had failed to clear in the prior auction.

There was also a significant increase from the prior auction in non-traditional capacity resources.  Demand response increased 42% (7,820 MW to 11,126 MW), energy efficiency increased 66% (1,710 MW to 2,832 MW), wind increased 60% (888 MW to 1,417 MW), solar increased 456% (125 MW to 570 MW), and seasonal capacity increased 80% (397 MW to 715 MW).

PJM will conduct up to 3 additional incremental capacity auctions for the delivery year beginning June 1, 2021.  However, in the past the incremental capacity auctions have had little impact on the overall capacity price.

Capacity prices cleared PJM Interconnection LLC’s (“PJM”) most recent auction for the “rest of RTO” region of PJM at $76.53 per megawatt-day (“MW-day”) for the PJM delivery year beginning June 1, 2020.  The “rest of RTO” region represents all of the unconstrained zones of PJM and makes up the majority of the PJM footprint.  This is the second consecutive auction where capacity prices have declined in the unconstrained PJM zones, while at the same time PJM was implementing more stringent capacity rules under the “capacity performance product.”  The clearing price for the 2018/19 and 2019/20 delivery years was $164.77/MW-day and $100/MW-day, respectively.

For the first time, the Duke Energy Ohio and Kentucky zone (“DEOK”) was constrained with capacity clearing at $130/MW-day.  The Mid-Atlantic Area Council (“MAAC”), Eastern MACC (“EMAAC”), and COMED Load Delivery Areas (“LDAs”) were also constrained with capacity clearing at $86.04, $187.87, and $188.12/MW-day in those LDAs, respectively.  The higher price in the EMAAC LDA was driven in part by 2,300 MW of generation retirements.  The MAAC LDA includes Potomac Electric Power Company, Baltimore Gas and Electric Company, Metropolitan Edison Company, Pennsylvania Electric Company and PPL Electric Utilities.  The EMAAC LDA is a subzone of MAAC and is comprised of Atlantic Electric Company, Delmarva Power and Light Company, Jersey Central Power and Light Company, PECO Energy, Public Service Electric and Gas Company, Rockland Electric Company.

In addition to decreased capacity prices, PJM cleared a record high reserve margin of 23.3%, representing a 6.7% increase over PJM’s target reserve margin of 16.6%.

Overall the supply and demand balance in PJM remained largely unchanged from the prior auction, with a 2,196.7 MW reduction of cleared capacity (165,109.2 MW vs. 167,305.9 MW) offset by a 2,800 MW decrease in PJM’s reliability requirement driven by lower forecasted peak demand (153,915 MW vs. 157,188 MW).  Notable changes for supply side resources clearing the auction included year-over-year increases in new generation (2,389.3 MW), capacity imports (121.3 MW), and energy efficiency (195.1 MW), and uprates to existing generation (434.5 MW).  Notable year-over-year decreases included a reduction of cleared demand responses (2,527.6 MW), wind (81.3 MW), and solar capacity resources (209.7 MW).

PJM will conduct up to three additional incremental capacity auctions for the delivery year beginning June 1, 2020.  However, in the past the incremental capacity auctions have had little impact on the overall capacity price.