In New Jersey, similar to neighboring states, larger electricity users (with a peak demand of over 500 kW) are classified as Commercial Industrial Energy Price (CIEP) customers. For these customers, the default utility price is an hourly rate that is an average of hourly prices over the course of a given month. Since these prices change every 15 minutes, there can be a tremendous amount of price risk and volatility with this structure.  However, over the last five years, there has not been a significant amount of hourly price volatility. Figure 1 shows the average monthly real-time (hourly) price in the Public Service Enterprise Group (PSEG) zone for each month of the year beginning in January 2015.  In New Jersey, and throughout the Northeast, the most volatile times of the year are the winter months of December through March. This is reflected in the chart below with price spikes in January 2018, February 2015, March 2015 and December 2017. It is interesting to note that hourly prices for this winter’s months of January and February are at their five-year lows. 

Wholesale electricity prices in New York have been falling for the past several years.  Figure 1 shows how the price of electricity in New York City, for the period March 2020 to April 2021, has traded over the last six years.  This chart shows that prices have fallen from a high of $80/MWh in the summer of 2014 to current all-time lows of $32.56/MWh.  One might assume that these low wholesale electricity prices would translate into lower retail electricity prices.  Wholesale electricity is only one of several other pricing components that make up a retail electricity price.  After electricity, the next largest price component is Capacity and, unfortunately, Capacity prices have risen dramatically in New York City. 

Last week, Williams Company and its partners announced that they have cancelled plans for the construction of the Constitution Pipeline.  This new 124-mile natural gas pipeline, shown in Figure 1,  would bring 650 Dth of gas per day from the Marcellus Shale to the Southern Tier of New York State.  While public opposition to this project was strong, recent favorable legal and regulatory developments suggested that the construction of the pipeline would proceed as planned.  However, Williams stated the economics of this project have recently changed in a way that there would not be a strong enough return on the company’s investment.  The unfavorable economics associated with the pipeline project are driven by a bearish natural gas market. 

We are excited to have you join us for one of our upcoming regional market webinars.

In early 2019, Con Edison (Consolidated Edison, Inc.) filed for a substantial rate increase for both electric and gas service. The original proposal (“Original Filing” in Table 1) called for electric delivery rates to increase by 7.2% over 3 years, and gas to increase by 12.2% over the same period.  Overall bill increases would have been even larger. In dollar terms, the Company’s original proposal would have increased electric revenues by $2.42 billion over 3 years and gas revenues by over $1.06 billion.

There has been a lot of news lately regarding capacity throughout PJM.  As we have reported in the past, the Federal Energy Regulatory Commission (FERC) and PJM have been at odds over the mechanism by which the price for capacity is set.  In December, the FERC issued a ruling that prescribed new rules and requirements around the auctions that establish capacity prices.  Before getting into those details, we wanted to offer a quick review of what capacity is and why this issue is important.

As you have likely heard, national, and even global, natural gas prices have been falling.  In fact, NYMEX futures prices for the rest of this winter are all trading below $2.00/MMBtu and as shown in Figure 1, the balance of 2020 (Feb – Dec) is trading at $2.10/MMBtu.   These are the lowest prices we have seen since late winter/early spring of 2016.  Prices in the calendar year 2021 haven’t decreased as much, but are trading at all-time lows of $2.35/MMBtu.

ACTUALIZACIONES DEL MERCADO

• "Avalan venta de luz de vecino a vecino", La CRE aprobó que los residenciales que generen energía a través de paneles solares puedan comercializar los excedentes.
  
• "Sener da pie a cumplir de forma irreal meta de energía limpia" Los cambios a los lineamientos de CELs permiten un “cumplimiento artificial” de las obligaciones de generación eléctrica y desincentivan la inversión privada al disminuir el precio de los CELs.

Two weeks ago, ERCOT released its initial reserve margin estimates for the summer of 2020.  The reserve margin is the difference between the peak forecasted load and the amount of installed generating capacity available to meet the grid’s electricity demand. This summer, ERCOT estimates that 82,403 MWs of installed generating capacity will meet a forecasted peak demand of 76,696 MWs. This equates to an estimated reserve margin of 10.6%, which is 2% more than the reserve margin that ERCOT reported going into the summer of 2019. ERCOT expects that an additional 7,633 MWs of generating capacity will be added to the grid in the next six months. Most of this new generation will be from renewable power sources and natural gas fired generating assets. 

Despite essentially flat growth in demand, the electricity generating capacity in PJM has grown by more than 15,000 MWs from 2009 to 2017.   Almost all of this additional capacity has been in the form of new natural gas plants.  As a result, the reserve margin (the amount of excess capacity above peak demand) in PJM has soared. In 2018, the expected summer reserve margin was 16.1%. The actual reserve margin was more than double what was forecasted, coming in at 32.8%. This reserve margin has been increasing with time.  According to the North American Electric Reliability Corporation, the anticipated reserve margin in 2021 is 45%.