Energy Procurement Insights for October 2019: See What's Driving Prices in Your Region

Energy markets are complex, and it can be difficult to find useful information to inform the energy procurement strategy for your organization. What you need is detailed information on the factors driving prices in the region where your facilities are located.

Every month, Enel X's Energy Intelligence team develops in-depth reports on activity in individual energy markets. Here you can read the highlights for this month and access the full report for each region. Just click on one of the tabs above to jump directly to a specific region.

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New England
2019 Summer Peak Load Third Lowest on Record

While ISO-NE won’t publish the official summer peak demand resuts until February 2020, preliminary data shows that the season’s peak demand of 23,973 MW (July 30, 2019 from 5 – 6PM) would be the third lowest on record.

A facility’s peak demand during that one-hour period will determine their share of capacity costs for the 2019/2020 planning year. The implications of the exact hour are significant for any electric customer with an upcoming renewal or on a capacity pass-through contract, as 1 MW of demand during the peak hour will translate to between ~$100,000 to $114,000 in annual capacity costs for the June 2020 – May 2021 period, depending on the load zone.

Weather and economic factors are the primary drivers of fluctuations in energy demand. While weather affects  demand in the near term, economic factors typically exert their influence over time. In the summer, peak demand tends to follow air conditioning systems as they battle periods of sustained heat and high humidity. The highest peak on record of over 28 GW occurred on August 2, 2006, when the temperature in Boston reached 97oF following six consecutive days of average temperatures near 90oF. This past summer’s preliminary peak of ~23.97 GW occurred on a day when the max temperature was 96oF following two consecutive days of 92oF heat.

The main determinants of capacity costs are the average facility demand at the time of the system peak and the Forward Capacity Auction zonal clearing price. A third, lesser-known component is known as the reserve margin. While the Forward Capacity Auction procures a certain number of MWs based on projected system demand, actual demand must be scaled up as a hedge against uncertainty and to ensure grid reliablity. The delta between forecasted and the upscaled capacity is referred to as the “reserve margin.” The higher the actual demand is relative to the number of MW procured in the auction, the lower the reserve margin. Following the lowest peak on record in the summer of 2017, reserve margins reached an all-time high near 52.5% in the 2018/19 delivery year. Reserve margins fell to roughly 42% in 2019/20, but are now expected to exceed 50% once again for 2020/21 due to the near-record-low demand this past summer. For customers with capacity pass-through contracts or those seeking fixed-price contracts spanning the 2020/2021 delivery year, a scheduled decline in capacity prices will more than offset the increased reserve margin.

For further updates on the power and natural gas markets, read our full report for this month.

New York
NYISO First: A Weekend Summer Peak

The New York Control Area (NYCA) saw system peak demand reach 30,397 megawatts (MW) on Saturday July 20, from 4 – 5 PM. This summer’s peak was relatively low, ranking 8th highest in the past 10 years and 15th in the past 20. Peak demand surpassed 30,000 MW only four times all summer, compared to 2018 when peak demand topped 31,000 MW six times.

The low magnitude of peaks contributed to two of the top-five demand days falling on the same weekend (July 20 – 21). Since 2014, only one other summer has had a top-five peak demand day (8/13/2016) fall on a weekend, and in that year it was only the 4th highest. Although New York City temperatures remained in the high 80s for much of the summer, there were few heat waves, which New York defines as three consecutive days with temperatures above 90 degrees. Peak demand in the NYCA is typically set when high temperatures and humidity drive increases in air-conditioning load across the state. For densely populated urban areas like New York City, heat waves sharply increase the likelihood of peak demand. As heat builds, particularly over multiple days, the amount of energy required to keep buildings cool increases.

In regions with capacity markets, customers typically pay for capacity based on their contribution to system peak demand. In NYISO, the charge allocation is based on a customer’s hourly demand coincident with the single highest system demand hour during the summer. Capacity payments to generators ensure that there is sufficient generation available to meet system peak demand. While daily peak demand averaged ~23,000 MW from July 1 – September 30 in the NYCA, all-time peak demand on the system reached 33,956 MW in the summer of 2013. This gap between typical demand and peak demand means that a significant portion of generation remains idle most hours; capacity payments provide compensation for their availability.

In New York, capacity pricing varies significantly by zone, because New York’s generation is mostly located upstate, far from its primary load-center, New York City. Capacity costs owed by consumers and paid to generators are therefore higher in New York City and the surrounding Lower Hudson Valley than the rest of state. A customer with 1 MW peak demand in Zone J (NYC) will pay roughly $110K for capacity from May 2020 to April 2021, based on current capacity swaps. Unlike some other regions, where capacity prices are known years in advance, New York is subject to prices set in monthly spot auctions. Although not as volatile as the energy market, spot capacity markets do change. Given that this year’s peak fell on a weekend, any organizations with muted demand during non-business days should seek advice on the opportunity presented by the lower-than-average capacity tag.

For further updates on the power and natural gas markets, read our full report for this month.

PJM Calls First Load Management Event in Five Years

On October 2, a late fall heat wave combined with scheduled generation outages and forced PJM to dispatch demand response (DR) resources.

Temperatures surpassed 90 degrees across the region and led to a shortage of generation reserve resources. To fill the gap, DR resources in the BGE, Pepco, and Dominion load zones were called between 2 pm and 3:45 pm, and resources in the AEP zone were dispatched from 2pm to 4pm. 

The last event called by PJM was during end of the 2014 Polar Vortex on March 4, 2014.

The unseasonable heat also led to hourly price spikes that may affect some customer bills. Buyers can utilize DR and purchasing strategies to minimize overall power costs. DR-capable customers can take advantage of high demand times, while a proper purchasing strategy can mitigate the risk of extreme price spikes.

For further updates on the power and natural gas markets, read our full report for this month.

For insights on important changes to PJM demand response in 2020, register for our upcoming webinar.

How Renewable Energy Growth in the Midwest Could Affect Energy Consumers

The Midwest is home to some of the richest resources available in the US; oil, gas, and coal are all abundant throughout the region. While these resources have spurred economic development in the region and beyond, the generation resource mix is rapidly moving away from coal and oil-fired power plants. The energy future is changing rapidly as aging coal generation continues to be retired and replaced with natural gas and renewable generation. Each year the cost of renewable technology continues to fall precipitously. Despite the improving economics incentives and regulations to encourage development in the Midwest fall short seem to be falling short at the state-level. Below is a table with current RPS targets for some Midwestern states:

The most aggressive renewable policy strategies continue to stem from the East and West coasts. Washington, California, and New York have each pledged to have a carbon-free grid by 2040 at the earliest. Interestingly enough, the renewable energy renaissance could be around the corner for the Midwest. In a recent article, Fitch Solutions forecasted 100 GW in solar power capacity additions in the Midwest over the next 10 years. The article focuses on the interconnection queues at the wholesale market level, and does not include investments in behind-the-meter (BTM) additions by corporate entities.

In the absence of strong federal mandates, state and local governments have taken initiative to set new renewables targets of their own. Chicago, IL, and Madison, WI, have pledged to transition from sourcing electricity from conventional generation to 100% renewable power over the coming years, a sign that the region is becoming more entrenched in the shift to a more sustainable energy future.

Customers in the Midwest should note that as renewable energy targets are established, compliance costs will most likely increase in the near-term as well. Investment in BTM renewables or an in-state virtual purchased power agreement could serve as a hedge against rising REC prices or solidify additionality claims for business operations.

If you’re interested in learning more about what a renewable energy strategy could look like for your business, please contact your Enel X Account Manager or

For further updates on the power and natural gas markets, read our full report for this month.

ERCOT Expects Sufficient Generation for Winter Season

ERCOT’s preliminary Seasonal Assessment of Resource Adequacy (SARA) report forecasts sufficient generation to meet the needs of the region for this winter (peak load of 62,257 MW and total generation capacity of 82,740 MW), and notes that 1,179 MW of generation capacity is expected to be added before December.

The SARA report also modeled a variety of weather and forced outage scenarios, and is anticipating between 24.5% and less than 1% in reserve margin. Should the region experience a combination of intense weather and unplanned generation outrages, another Energy Emergency Alert 1 could be enacted as reserve margin approaches negative territory again.

Despite the risk, the region’s overall resource availability is expected to improve over that of this past summer, when negative reserve margins caused energy spot prices to spike up to $9,000/MWh. In less extreme scenarios, resource availability should more than meet the demands of the region, and could provide as much as a 20% year-over-year reduction in wholesale North Hub Day Head prices. Customers looking to navigate the extreme volatility all too common in the Lone Star state should consult with their Enel X energy advisor.

For further updates on the power and natural gas markets, read our full report for this month.

Renewables Displace Gas & Nuclear in California

On September 12, the California Public Utilities Commission (CPUC) released a proposal that requested the procurement and implementation of 2,500 megawatts (MW) of new low-carbon generation resources by 2023. The proposal, which was structured to ensure future grid reliability, cited both the retirement of more than 4,000 MW of gas-fired generation by 2020 and the variability of hydro generation during peak demand as motivations.

In September 2018, Governor Jerry Brown signed Senate Bill 100, which formalized two major goals within the state: to achieve 100% carbon-free electricity generation by 2045, and to increase the renewable portfolio standards to 60% by 2030. These goals have put pressure on the CPUC to accelerate the de-carbonization of the state’s generation profile while maintaining the reliability of the grid for consumers. A review of California’s generation mix and its trajectory is highlighted below.


  • Solar is the fastest-growing resource in California and has contributed 14% of generation year-to-date. From 2013 to 2018, electricity produced by solar plants increased 400%, or 16,000 GWh, per year.
  • According to S&P Global Platts, there are 88 solar generation projects in the state of California that are either planned or in development. Once completed, these arrays are expected to bring on more than 5,000 MW of nameplate capacity to the state. For comparison, as of July 2019, there were 12,300 MW of installed solar capacity in California.


  • Wind is the second fastest-growing power resource in the state, contributing 8% of total generation in 2019. Since 2013, total power produced by wind has increased more than 3,500 GWh, or 30%, per year.
  • According to S&P Global Platts, there are 19 wind generation projects that are planned or in development in California with a total planned capacity of nearly 2,200 MW. Given the recent success of several large offshore wind resources along the east coast, many environmental interest groups are calling for development to begin along the California coastline.

Natural Gas:

  • Natural gas has accounted for 26% of statewide electricity generation through the first nine months of 2019. By comparison, gas-fired sources made up 44% of the generation mix in 2013. This delta represents a decline in natural gas generation by more than a third (37%) over the last five years.
  • The CPUC released a proposal last month to extend the compliance period for generators impacted by an act passed by the state’s Water Resources Board in 2010. The legislation in question, CWA 316, introduced new restrictions on generators using sea water for Once-Through Cooling (OTC) to generate steam in their facilities. Analysts initially projected that the act would result in the retirement of 4,000 MW of gas-fired generation by the end of 2020. September’s proposal would add limited short-term relief for impacted generators.

Nuclear Power:

  • Nuclear power has contributed 8% of total generation year-to-date in 2019. Since 2013, Diablo Canyon has been the only operational nuclear generator in the state of California. Diablo provides a significant portion of baseload for consumers (between 16,900 and 18,900 GWh) and is now being considered for retirement.
  • In January 2018, CPUC voted unanimously to approve Pacific Gas and Electric’s (PG&E) proposal to retire Diablo Canyon. In its proposal, PG&E stated that replacing the 2,256 MW nuclear facility with renewable resources would be cheaper than relicensing the plant for continued use. Diablo Canyon is currently slated to complete retirement by 2025 and will require substantial backfill generation development.


  • Hydro continues to be a significant source of generation for California, contributing 15%, or 25,000 GWh, to the state’s generation mix in 2019. Total power produced by hydro resources has increased 26% since 2013; however, that growth is almost entirely attributed to the rebound in reservoir levels following the drought from 2012 to 2016.
  • Currently, there is less than 20 MW of planned hydro generating projects in the state. However, 2,100 MW of hydro pumped storage projects are in various development stages, according to S&P Global Platts. Water scarcity remains a pervasive problem for the state. While pumped storage resources would provide significant support to grid reliability, they will likely face increased regulatory scrutiny moving forward.

The graph below, based on EIA data, shows the annual planned additions and retirements of power plants within the state of California (assuming the procurement of 2,500 MW of renewables by 2023 per CPUC’s proposal). Under this scenario, the cumulative increase in new natural gas, solar, and renewable capacity is expected to outpace the retirement of old natural gas plants and result in a net gain of 1,300 MW by 2025. In the event that CPUC’s proposal is not approved, the state would face a net 1,100 MW capacity shortfall by 2025 due to the retirement of the Diablo Canyon Nuclear Facility. This affirms the need for additional generation to address grid reliability concerns. The CPUC will convene next on October 24, at which point they are expected to vote on the procurement.

For further updates on the power and natural gas markets, read our full report for this month.

CFE Rates Down Significantly Year-Over-Year

The CFE published its rates for their Basic Service customers for October. Rates moved slightly lower by about 2.19% for capacity and 1.92% for energy. The September to October dip was subtle compared to the increase that was seen a year ago, when prices began their dramatic escalation that continued through October 2018. While the lower seasonal demand kept rates constant during the winter and the first months of spring, commercial and industrial customers began paying lower rates this month compared to the CFE rate a year ago. For this month, the decrease in costs year over year in October is almost 24% for the capacity component of the bill and about 21% for energy.

The chart on the right shows the capacity prices in the Monterrey region for the GDMTH tariff, where prices for October 2019 are just under $347 MXN/kW-month. This represents a 2.19% decrease compared to the September rates, and a 24% decrease relative to last October’s rates, which registered at just $455 MXN/kW-month. The capacity component accounts for roughly 15% to 25% of overall energy costs.                                                                                                            

Energy rates saw similarly modest declines in October. The chart below shows energy prices for the Aguascalientes region of the GDMTH tariff load-weighted for each tranche assuming an average of 30% base consumption, 60% intermediate consumption, and 10% peak consumption. October energy prices decreased by about 1.92% in most regions compared to the previous month, roughly 21% compared to October 2018. Load-weighted prices in Aguascalientes have decreased from $1.825 MXN/kWh in October 2018 to $1.46840 MXN/kWh in October 2019, a 21% decrease over that period. The energy component of customers’ bills usually makes up 50% to 70% of total costs.

In December 2017, the Energy Regulatory Commission in Mexico (CRE) forced the default utility company CFE to unbundle their power rates and break out supply components like energy and capacity from regulated components like distribution, transmission, and ISO charges. This unbundling was intended to increase transparency and allow consumers to compare offers from alternative third-party suppliers serving the supply portion of their bills.

All over the country, customers have been faced with escalating prices, a trend that began in 2018 and has continued into 2019. Leaving the CFE Basic A service tariff in favor for third-party supply can be an attractive alternative. More than two dozen qualified suppliers now operate in the market and offer a range of products to achieve greater budget certainty and lower costs.

For further updates on the power and natural gas markets, read our full report for this month.

Authored By The Enel X Energy Intelligence Team

The Energy Intelligence team provides talent and knowledge to our customers by making the complexity of energy management simple.

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