This special interest group is for professionals to connect and discuss all types of carbon-free power alternatives, including nuclear, renewable, tidal and more.

Post

Market design was never meant to be easy: PJM’s infamous MOPR

image credit: Adobe Stock
Kent Knutson's picture
Energy Market Specialist Hitachi Energy USA Inc.

Kent Knutson is a market specialist focusing on energy industry intelligence for Hitachi Energy.  He has more than 30 years of experience designing and developing intelligence products for some...

  • Member since 2018
  • 192 items added with 140,717 views
  • May 12, 2020
  • 1364 views

PJM Interconnection, LLC. (PJM) is the largest organized power market in America, representing roughly one-fifth of all power demand delivered across the United States. As an Independent System Operator and Regional Transmission Organization (ISO/RTO), PJM is tasked with managing the interests of a wide array of stakeholders across 13 eastern and midwestern states and the District of Columbia, an area comprised of more than 65 million people.  Driven by a plethora of ever-expanding state and local renewable energy goals and programs, planning for generating capacity and grid projects in the PJM region has become an increasingly complicated process.

U.S. ISO/RTO footprint map

Some background

PJM operates three primary markets to maintain reliability and provide market pricing signals to loads and generators. The energy and ancillary services markets have load requirements and resource commitments that are both determined and compensated on a daily and even sub-hourly basis. Unlike those markets, PJM uses the Reliability Pricing Model (RPM) to conduct an annual Base Residual Auction (BRA) which provides forward commitments based on clearing a pre-determined demand-curve.  The auction, which includes both existing and new resources, provides commitments that require the resources to be available to deliver energy three years into the future.  Since the first auction was held in 2007, the capacity market has constantly been evolving to optimize the market singles necessary to stimulate investment in new capacity.

The MOPR

The Minimum Offer Price Rule (MOPR) has undergone several revisions since 2011.  Still, in June 2018, the Federal Energy Regulatory Commission (FERC) decided the current MOPR was potentially unjust and unreasonable given it did not apply to enough resources and opened a paper hearing process.  During the past two years, PJM has submitted three compliance filings to jumpstart the auction, but the FERC rejected two of those filings in 2018, and after a long review period, in June of 2019 declared that PJM’s existing MOPR is unjust and unreasonable.  In December 2019, FERC issued its Order which modifies the existing MOPR to include all existing and new resources eligible to receive state-subsidies regardless of resource-ownership, with some limited exceptions. 

In March 2020, PJM filed a 536-page compliance filing to meet FERC’s December 2019 request to retool the MOPR.  FERC’s April 16, 2020 Order on Rehearing rejected most of the rehearing requests, which triggered groups, including publicly-owned utilities and environmental groups, to step up their resistance to the MOPR as defined.

One of their concerns centers on the increased cost to customers due to having to participate in the auction to satisfy capacity obligations, but also continue to support the development of renewable energy projects, which are capacity resources but unlikely to clear the auction given the high offer floor prices.  Public Power concerns cite that the MOPR undercuts their business model and will increase the cost of capacity procurement. With that backdrop, consider that most (74%) of the generating capacity operated in PJM is owned by merchant companies, with investor-owned utilities accounting for 19% and power derived from public utilities (3%) and cooperatives (4%) rounding out the rest.

The states that have adopted rate-payer funded uplift programs for existing nuclear plants known as Zero-Emissions Credits (3) and those states (10) that have adopted Renewable Portfolio Standards (RPS) are concerned the new MOPR will undercut state clean energy goals by pricing the resources out of the market.  The state governments in New Jersey and Illinois have petitioned their respective public service commissions to evaluate the feasibility to exit the PJM market to avoid compliance with the MOPR. 

State policy and incentives

The MOPR raises the offer floor price for capacity resources entitled to receive state subsidies, including planned development projects in states with RPS goals and public power entities that receive tax benefits and other state and local economic support.         

State policies and incentives cover an array of programs supporting clean-energy including renewable energy portfolio standards (RPS), grant programs, tax credits, efficiency goals, rebate programs, green contracts, loan programs, building codes, net metering policies and a myriad of technical resources to name only some of the incentive types.

To place this in a better perspective, consider the large array of clean energy standards and support programs within every state. The North Carolina Clean Energy Technology Center maintains a Database of State Incentives for Renewable Energy (DSIRE).  The database was originally funded through a contract with the U.S. Department of Energy (DOE) and is considered the most comprehensive repository of state and local goals and programs supporting renewable energy available. 

The list below highlights the number of programs and the key RPS goals in each PJM state presented in the DSIRE database:

  • Delaware (32 programs and policies) – 25% RPS with 3.5% from solar PV by 2025-26  
  • Illinois (91) – 25% by 2025-26
  • Indiana (79) – 7% 2019-24, 10% in 2025
  • Kentucky (76) – No RPS
  • Maryland (83) – 50% by 2030
  • Michigan (68) – 15% by 2021
  • New Jersey (58) – 52.5% target in 2030, with a 2.5% increase each year after
  • North Carolina (96) – 12.5% for IOUs by 2021
  • Ohio (74) – 12.5% and solar 0.5% by 2026
  • Pennsylvania (68) – Tier One 8%, Tier Two 10%, solar PV 0.5% by 2020-21
  • Tennessee (50) – No RPS
  • Virginia (52) – 41% by 2030, 100% by 2045
  • West Virginia (13) – No RPS
  • District of Columbia (68) – 100% by 2032

With the assumption that the commission moves forward and approves the MOPR in its present form, the most important question becomes, what will it mean to the long-term costs and the overall fuel portfolio in the region as future auctions are undertaken?

New ABB study 

ABB’s Energy Market Advisors team recently completed a study assessing the long-term impact on PJM Base Residual Auction clearing prices due to the MOPR under three scenarios; the “Status Quo,” the Resource-Specific Exception (RSE), and the MOPR as written.  The “Status Quo” involved an evaluation under which both existing and new capacity resources with state-subsidy participate in the auction absent an offer floor price.  The study also looked at the MOPR, as it is presented by PJM in their March filing.  And finally, the study developed the “Resource-Specific Exception” with built-in assumptions for wind and solar costs, industry-based learning curve cost reductions, and a longer financing life than PJM’s default assumption.  Between 2022 and 2029, under the “Status Quo,” prices would be about 32% below the “Resource-Specific Exception” average clearing price, and about 44% below the MOPR.

Average PJM capacity clearing prices, 2022-2030, 2019$/MW-Day

The report found that the average “Status-Quo” market-clearing price between 2022-23 and 2029-30 will land at $93/MW-Day in 2019 dollars.  The MOPR in full force would result in market-clearing prices of roughly $165/MW-Day, and under the Resource-Specific Exception scenario would land at $137/MW-Day.  The Resource-Specific Exception represents a middle of the road that assumes the market stays intact without state exits.

The study goes on to show that the immediate (2022/2023) auction impacts are minimal given the market is long on capacity, and the initial tranche of planned renewables are mostly exempt from the MOPR.  By 2029/30, with at least 13 GW of added solar, the results indicate 86% of the solar that offers into the market based on the Resource-Specific Exception (RSE) will achieve commitment, and under the MOPR, 65% will achieve commitment – making the RSE possibly less controversial and easier to implement.  Most importantly, in the long-term 10-yr horizon, renewables, particularly solar, clear the market at a high rate in the absence of subsidies.

Solar PV “New Capacity Resource with State-Subsidy” RPM commitment

For nuclear, during the 2022/23 auction, 77% is committed, while further out, by the mid-2020s, over 90% of nuclear receives commitment.  This is mostly driven by the assumption of higher natural gas prices. 

Natural gas maintains a high commitment (90%) through every year in the simulation, but without the MOPR could struggle to compete with the more heavily state-subsidized resources under the Status-Quo scenario. 

The study goes on to evaluate state exit strategies for both load and supply and load only, as well as a limited Fixed Resource Requirement (FRR) option.   The limited FRR showed very little variation from the standard MOPR.  The state-by-state load exit analysis showed significant downward movement of the market-clearing price, given the remaining supply would be chasing less demand.  It is important to note that lower prices may not be able to support long-term generation asset maintenance and other reliability enhancing grid investments. 

Most of the states considering a market exit strategy, except for Illinois, are located along the eastern seaboard and are heavily promoting and supporting offshore wind projects. These projects will have a hard time earning a commitment to future auctions given the high cost of development.  

If states opt for exiting the PJM Reliability Pricing Model to adopt a Fixed Resource Requirement (FRR) alternative, utilities would become responsible for contracting with in-state generating companies to avoid the complexities of permitting and financing long-haul interstate high-voltage transmission projects that will take a long time to move through permitting and get built.  In the near-term, most states entertaining the exit strategy that have a supply shortage would likely need to bridge energy and capacity requirements with resources (e.g., natural gas) to retain necessary reliability while individual state markets develop renewables.

Some observations

The whole concept of operating a fair and competitive capacity market across multiple resource alternatives is complex by itself, but then add state goals driven by ever-increasing renewable energy standards, and the undertaking becomes extremely complex.

The capacity market model (RPM) is designed to send price signals to attract new resources but also to allow owners of existing resources to decide whether to continue to invest in their generation fleet or retire their resources. Sustained market-clearing prices that are artificially low because generators that receive out-of-market compensation are bidding low into the auction, could create a reliability risk.  Asset value needs to be high enough to cover maintenance and operational expenses, keeping projects active on the grid, and avoiding early retirement or operational challenges.

As time evolves, renewable technology costs will decline further, and the cost of natural gas will likely increase.  This makes renewables more affordable and ultimately makes nuclear and coal more cost-competitive, leading to lower, but adequate, market prices.  This enables all resources to better compete without the support of subsidies. 

Evaluation of exit strategies is further complicated in states that are essentially deregulated.  Most of the power generated comes from merchant resources and retail customers can choose suppliers.  How could states exit if they lack supply in the short run?  They’ll need non-renewable resources to bridge the capacity gap until new clean power alternatives are developed and are generating. 

Since 2017, capacity prices in PJM represent about 20% of the total wholesale cost – energy, transmission services, and ancillary services account for the rest.  Getting the MOPR right is paramount since the percentage of revenue derived from the capacity market will likely remain high in the near-term as energy market prices have fallen steeply in recent years.  

Other concepts

Given the complications inherent in trying to satisfy all concerned with the MOPR, the question arises, are there any other solutions for creating a fair playing field where the market prices reflect both the competitive market and states clean-power goals.  The concept of ‘carbon pricing’ might fill the niche.  The New York ISO recently published a paper offering such a plan.  Setting a price on carbon as opposed to a carbon tax could work very well across a complex market, like PJM, where state renewable energy goals are so diverse. 

The unique features of an organized electricity market create an opportunity to integrate wide-region policies like direct ‘carbon pricing’ as a viable solution.  Implementing ‘carbon pricing’ would place the financial risk of building new clean power resources on investors rather than consumers.  Carbon pricing uses market-based incentives to reduce fossil emissions while strengthening investment economics for clean power, which in turn could reduce the need for ‘out of market’ subsidies.  The concept also provides policymakers the ability to adjust the carbon-price based on specific carbon reduction goals while at the same time keeping the interests of ratepayers satisfied.  Setting a consistent and fair carbon price might well be the neutral price signaling component necessary to value existing and future capacity as the market evolves in the years to come.

The MOPR timetable

May will be a busy month for PJM staff as they solicit additional input before the June 1, 2020 compliance filing deadline.  The May stakeholder meetings are being conducted in response to requests for clarification of elements of PJM’s March 18, 2020, MOPR compliance filing, which was largely affirmed in FERC’s April 16 Order on Rehearing Requests.

Additionally, PJM hopes to learn what the market and financial impacts of the newly designed MOPR will have on the market when approved.  On Wednesday (May 6) PJM held a special session of the Market Implementation Committee (MIC) to discuss the impacts of the MOPR, and on May 13, will hold a detailed session addressing some key issues including:

  • State default service procurements that are being captured by the definition of “state subsidy”
  • Public power self-supply entities engaging in voluntary, arms-length bilateral contracts with unaffiliated third parties that trigger the MOPR

PJM MOPR timeline

Source: PJM Interconnection

The discussions, according to PJM staff comments, target issues like MOPR floor prices, the classification of existing versus new capacity resources, and other transactions.  The PJM intends to run the 2022-23 auction approximately six to seven months after FERC approves the MOPR compliance filing, and after that, adopt a schedule that runs subsequent auctions on a six to seven-month schedule. 

What’s next?

The organized power market that was born out of federal policy in the late 1990s has saved companies and ratepayers billions of dollars over the years.  The MOPR component of the Reliability Pricing Model (RPM) is intended to balance the array of complex state goals within a market concept that creates a fair playing field for all resources with the intention to create a reliable power supply at a competitive price to consumers.       

Most of the states within PJM have ambitious RPS targets for 2030 that will require several strategies, including maintaining current zero-carbon generation like nuclear and hydro and building a significant amount of new solar and wind capacity.  To meet some of these state standards, companies will need to retire inefficient and high-cost fossil capacity and wisely plan for new transmission and upgrades that will bolster the state’s ability to import, and or, export clean power.

The bottom line, and the supporting argument behind the MOPR and PJM’s capacity market, is to provide the lowest cost power reliably while meeting the ever-evolving and complex clean energy standards mandated by the individual states that make up the PJM market.  The ABB Energy Market Advisor’s MOPR study sheds strategic light on the trade-offs under various scenarios and provides a quantitative understanding of the market impacts of adopting the MOPR.  One thing is for certain, the approval of PJM’s MOPR by FERC will be one of the most important market design structural changes in recent times.  We’ll be paying close attention throughout the upcoming months for what is sure to be a very hectic time of analysis, hopefully compromise, and rulemaking.

Kent Knutson's picture
Thank Kent for the Post!
Energy Central contributors share their experience and insights for the benefit of other Members (like you). Please show them your appreciation by leaving a comment, 'liking' this post, or following this Member.
More posts from this member
Discussions
Spell checking: Press the CTRL or COMMAND key then click on the underlined misspelled word.

No discussions yet. Start a discussion below.

Get Published - Build a Following

The Energy Central Power Industry Network is based on one core idea - power industry professionals helping each other and advancing the industry by sharing and learning from each other.

If you have an experience or insight to share or have learned something from a conference or seminar, your peers and colleagues on Energy Central want to hear about it. It's also easy to share a link to an article you've liked or an industry resource that you think would be helpful.

                 Learn more about posting on Energy Central »