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.

Legislation to reform Ohio’s energy efficiency, peak demand reduction, and renewable energy mandates is again before the Ohio General Assembly.  House Bill (“HB”) 114 was introduced in the Ohio House on March 7, 2017.  The bill has 55 co-sponsors.

As a bit of background, in 2008 Ohio adopted mandates that require each electric utility in the state to reduce energy consumption measured as a reduction in kilowatt-hours (“kWh”) of sales as well as a peak kilowatt (“kW”) demand reduction relative to a historic baseline.  The 2008 legislation also required each utility and each competitive supplier to source a percentage of its generation supply from renewable energy sources.

Since 2008, there have been several legislative changes to the mandates, including a provision that permits businesses served above primary voltage and those that self-assess the kWh tax to opt-out of the energy efficiency and peak demand reduction mandates beginning January 1, 2017.

If adopted, HB 114 would extend the opt-out opportunity of the energy efficiency and peak demand reduction mandates to businesses that qualify as mercantile customers under Ohio law (businesses that consume 700,000 kWh per year or are part of a national account involving multiple facilities in one or more states) effective January 1, 2019.

HB 114 also contains a provision that would reduce the energy efficiency mandate from 22.5% to 17.3% and would provide for counting reform as to what the Public Utilities Commission of Ohio (“PUCO”) may count towards the electric utilities’ compliance obligation.

HB 114 also proposes changes to the renewable mandates.  If adopted, the legislation would transform the renewable mandate to a non-mandatory provision and would provide all customers of electric utilities the opportunity to opt-out of the renewable mandates beginning January 1, 2019.

HB 114 further proposes a firm end-date to the energy efficiency, peak demand reduction, and renewable mandates in 2027.  Current law provides that at the end of the year-after-year escalation in the mandates that the final tier of compliance continue indefinitely thereafter.

The bill is similar to legislation that passed the Ohio House and Senate last year but was vetoed by the Governor late in 2016.

The full text of HB 114 is available at:

https://www.legislature.ohio.gov/legislation/legislation-summary?id=GA132-HB-114

Each month, electric bills arrive like clockwork.  For large commercial and industrial businesses, especially those that are energy-intensive, these electric bills can represent a sizeable portion of a business’s monthly expenses.   Given the broad revenue collection ability of regulated utilities, businesses continue to see their electric bills increase to fund things beyond just the supply and delivery of electricity.  Compliance costs associated with things like energy efficiency and renewable energy mandates, economic development, payment assistance programs, and many more programs are often baked into the “price” of electricity that appears on a business’s electric bill.  Such is the case for businesses in Ohio and Pennsylvania.

Given the pressure on large energy-intensive businesses to not only manage the true cost of the supply and delivery of the electricity they consume but also to fund these additional programs through their electric bills, large energy-intensive businesses are constantly searching out tools to help control the magnitude of their bills.  One such tool, that goes by many names, is demand response (other names include interruptible capabilities, load shedding, and active load management).

Demand response represents the ability of a business to actively reduce the amount of electricity the business draws from the electric grid at specific times.  This typically occurs through the use of an on-site backup generator, shutting down or scaling back an energy-intensive business practice, or rescheduling an energy-intensive business practice to an off-peak time, typically the morning or evening.  Businesses with demand response capabilities can capitalize on those capabilities by avoiding certain costs and receiving compensation from both state and federal programs.

One significant challenge to the ability of businesses with demand response capabilities was recently resolved in favor of businesses. In February 2016, the United States Supreme Court, in F.E.R.C. v. Electric Power Supply Association (EPSA), upheld rules that provided compensation to businesses for committing their demand response capabilities to a regional grid operator.

Still, vital questions remain unresolved by the Supreme Court’s EPSA decision.  First, will states block businesses from participating in the federal programs? As things currently stand, the Federal Energy Regulatory Commission (FERC) has authorized states to block businesses in their states from participating in the federal programs.  Having lost their fight in the federal courts, electricity generators may turn to the states in an effort to block businesses from participating in the wholesale markets regulated by FERC.

Second, will FERC and the regional grid operators continue to rely on demand response resources?  While the Supreme Court has upheld FERC’s authority over demand response, PJM Interconnection (PJM), which is a regional transmission organization that serves 13 states, including Ohio, Pennsylvania and the District of Columbia, and other regional grid operators have taken and are taking actions to limit the scope of available federal demand response programs.

Third, how much compensation can demand response participants expect? Currently, demand response resources are generally paid the same amount as generators.  And we are talking big money:  PJM paid over $800 million to demand response resources in 2015 (these payments included all types of demand response in PJM, not just the specific demand response program at issue in EPSA).  As the ink was still drying on the Supreme Court’s decision in EPSA, FERC Commissioner Tony Clark encouraged the conversation to turn to whether the compensation that businesses receive for their demand response capabilities should be reduced.  So the question endures:  will customers continue to receive the same compensation as generators?

Getting help with energy costs

While the Supreme Court decision in EPSA is certainly good news for businesses, it is likely not the last word on the issue, and staying abreast of the varying state and federal electricity rates and programs applicable to businesses with demand response capabilities can be a daunting task.  McNees Wallace and Nurick’s Energy and Environmental Law Group frequently works with large energy consumers, state and federal regulators, and others in this dynamic area.

Matthew R. Pritchard practices in the Energy and Environmental Law Practice Group in the Columbus, Ohio office of McNees Wallace & Nurick LLC.  Joseph G. Bowser, a technical specialist in the Energy and Environmental Law Practice Group, assists clients of the firm with their participation in demand response programs. They can be reached at 614.469.8000 or mpritchard@mcneeslaw.com or jbowser@mcneeslaw.com