Energy Procurement Insights for October 2018: 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 North America'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.

To receive this update in your inbox every month—as well as insights on energy management from throughout the industry—subscribe to the EnergySMART blog today. You can learn more about Enel X's energy procurement services here, and talk to one of our experts here.

New England
2018 Summer Peak Load Reaches Five-Year High

Preliminary data shows that ISO-NE’s 2018 summer hourly peak demand of 25,763 MWs (August 29, 2018 Hour Ending 18:00) will be the highest since 2013.

ISO-NE will reveal the official peak hour in February 2019. A facility’s demand during that peak hour 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 ~$120K in annual capacity costs for the June 2019 – May 2020 period.

Weather and economic factors are the primary drivers of fluctuations in energy demand, where weather affects demand in the near-term and economic factors typically exert their influence on longer time horizons. Peak demand, in particular, tends to follow a period of sustained heat and relatively high humidity as heat build pushes up energy consumption from air conditioning systems. The highest peak on record of over 28 GW occurred on August 2, 2006, when the temperature in Boston was 97oF following six consecutive days of average temperatures near 90oF. This past summer’s preliminary peak of ~25.7 GW occurred on the second consecutive day of 97oF weather.

Average demand at the time of the system peak and the Forward Capacity Auction zonal clearing price are the main determinants of capacity costs. A third, lesser-known component, is the reserve margin. Since the Forward Capacity Auction procures a certain number of MWs based on projected system demand, actual demand must be scaled up to account for the difference, with the percentage increase 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 last summer, reserve margins have reached an all-time high near 52.5% in the current 2018/19 delivery year. Preliminarily, because of year-on-year increases in peak demand, the reserve margin is projected to decrease to just above 40% for 2019/2020. For customers with capacity pass-through contracts or even customers seeking fixed-price contracts, which span the 2019/2020 delivery year, the decreased reserve margin will offer some price relief year-over-year, all else equal.

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

New York
Gas Plant Comes Online Despite Opposition

Competitive Power Venture’s Valley Energy Center started commercial operations of its 680 MW combined cycle natural gas plant on October 1. The facility was supposed to become operational in February of this year, but issues around the natural gas lateral needed to supply the plant delayed the project. The plant is an integral piece in replacing the retiring Indian Point nuclear units (2,060 MW), which are set to retire in 2020 and 2021. The facility has endured a protracted path to become operational. Although operational, the facility is still in need of a Federal Title V air permit from the US EPA after arguing that it has one year to obtain the permit after it begins full-time operations. The plant can operate pending a court determination regarding the permit issue.

New York’s State Energy Plan aims to achieve a 40% reduction in greenhouse gas emissions from 1990 levels by 2030. CPV Valley will reduce net carbon emissions, as its electric production displaces older and less efficient generators. In New York, the average age of the current fleet of electric generators is 37 years old. In fact, New York has 3,200 MW of generation plants that are over 46 years old, and that figure could grow to over 6,000 MW by 2025. An independent study conducted by the Brattle Group determined that a new, efficient power generator in the Lower Hudson Valley zone will reduce carbon emissions by 0.5 million tons per year.

It has taken 10 years to get the plant operational, and they are still facing opposition. Local residents have complained about noise from the plant as well as feeling sick when the plant was operational. The Title V air permit requires a more comprehensive application, as well as the opportunity for the public to provide more input. In the past, New York state officials and some local officials have stronlgy opposed the project, and their continued resistance could prevent the plant from getting its Title V air permit.

CPV and Cricket Valley, a 1,100 MW combined cycle natural gas plant with an estimated in-service date in 2020, are two major pieces of the plan to replace Indian Point and avoid the increased utilization of inefficient fossil generators. If CPV is successful in getting its air permit, the addition of this facility should bring more stability to energy and capacity prices in the Lower Hudson Valley and Westchester zones, especially as Indian Point retires.

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

Mid-Atlantic
Nuclear Retirement Update for PJM

Planned nuclear retirements have been increasing in the PJM footprint over the past few years. Many nuclear generators attribute these retirements to forecasts showing that operating costs are outweighing expected revenues through energy and capacity markets. Generation owners have even asked their respective states for nuclear subsidies, in the form of Zero Emission Credits, based on the claim that nuclear generation does not emit hazardous carbon by-products like coal and gas generators. 

As these nuclear generators are forecasting that they could be operating in the red, some plants have announced retirements across the United States. Retirements and retirement dates for nuclear generators in PJM can be seen in the graph below, along with nameplate capacity by generator, with information provided by the EIA.

Because these retirements are showing a sizeable decrease in available generation in the future, expectations are that this capacity will be replaced by gas, solar, and wind resources to create a cheaper and cleaner alternative to power generation.

Proponents for nuclear power and corresponding subsidies argue that nuclear generation is a necessary piece of the overall PJM fuel mix as these plants provide reliable baseload generation to the grid, meaning that the electrical output covers much of the minimum level of generation needed at any given time. As stated earlier, some states are willing to set up nuclear subsidy programs, like Illinois and New Jersey, to compensate generators with an extra cash flow to operate in the future. However, opponents may claim that these subsidies create an uneven playing field in PJM’s capacity market, as other types of generation do not receive these extra cash flows. PJM is currently working for a solution on how to value subsidized nuclear generation resources in the capacity market.

Enel X North America customers should be aware of the evolving PJM Capacity market. Even though it is too early to predict the effect on future capacity and energy prices, LMPs could become more volatile as steady nuclear generation is replaced by natural gas and renewable generation.

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

Midwest
ComEd Experiences Average Summer Peak Load

Capacity represents a large portion of a customer’s total cost of electricity supply in ComEd and is determined by the zonal capacity prices set at auction and a customer’s peak demand in the summer months. A customer’s peak load contributions, or PLCs, are determined under a different set of rules than most zones in PJM, a market design which makes managing expensive capacity costs more difficult. This month’s market commentary will recap this summer's zonal peak performance and explain the importance of the capacity market design in ComEd.

In ComEd, a customer’s peak load contribution (PLC) is dependent on the outcome of both the PJM system peaks as well as the ComEd zonal peaks. In strict terms, a customer’s PLC is the average demand during either the five highest PJM system peak hours from June through September or the five highest ComEd zonal peak hours from June through September, whichever is greater. Historically, the PJM system and ComEd zonal peaks rarely overlap, making capacity tag management difficult for most customers. In the past five years, typically only one hour has been the same across both measures, meaning on average nine total hours of the summer must be managed to reduce a customer’s PLC effectively. Therefore, there is little benefit to passing through capacity costs unless there is an overall reduction in demand expected in the future.

During the summer of 2018, the average of the five highest zonal peaks reached 20,503 MW, compared to a 10-year average of 20,925 MW. The maximum peak load was reached on June 18 at 21,349 MW. The five highest ComEd zonal peaks are listed below. Hours one and three align with the PJM system peaks.

The electricity procurement strategy in ComEd is further complicated by the utility default rate structure for medium to large commercial and industrial customers. As covered in previous market commentaries, the default rate structure in ComEd is determined by prevailing hourly LMP rates. Essentially, the default rate is similar to an indexed rate with capacity and transmission passed through, a high market risk position. Projecting future LMP rates is challenging and highly dependent on hourly market conditions, meaning a forward-looking utility default can vary substantially from observed rates. Customers who are unwilling to accept full market risk are in the best position to enter a fixed all-in position for budget certainty.

The combination of the capacity market design and the default utility rate make energy procurement challenging in ComEd. Effective capacity PLC management means customers must be able to predict more hours in the summer accurately and curtail demand proactively. While the default rate can appear to be attractive for some customers, it is important to consider the risk involved with a fully indexed rate. Predicting this rate is difficult, and Illinois has introduced legislation requiring utilities to place a price-to-compare on customers’ electricity bills. As explained above, this posted rate will vary considerably as monthly market conditions and customers’ usage change on an hourly interval. Budget certainty and the ability to add blocks to an indexed contract continue to be benefits to third-party supply.

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

Texas
ERCOT 2018 4CP End of Season Summary

The 4CP season for ERCOT ended September 28 after a record-setting year. Early season forecasts from the market operator anticipated elevated levels of demand this year due to consistent load growth throughout the region. The final Seasonal Assessment of Resource Adequacy predicted a seasonal peak of 72,756 MW to occur in August, in addition to setting new monthly peaks in June, July, and September.

The 2018 season started off bullish when June ended with a new monthly peak of 69,102 MW, eclipsing the previous record of 67,617 MW from last year. July also followed suit, setting a new system peak of 73,259 on the July 19. Despite the lack of any major weather issues, August and September both failed to live up to pre-season expectations, setting peaks of 69,846 MW and 64,662 MW respectively. We called 19 Red days during the season and hit every peak demand hour. A summary of the top 10 peak demands per month is included below, with highlights of the days we called.

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

California
Approved Senate Bill 237 Results in Expanded Direct Access Program in CA

On September 20, California Governor Jerry Brown approved and signed into law Senate Bill 237, which expands the pool of customers that can shop from competitive energy suppliers rather than rely on investor-owned utilities for electricity. Even though this is not a full deregulation of the electricity market, it will result in an immediate increase in the Direct Access program. 

The Direct Access program, as currently constructed, allows certain approved customers to purchase electricity from an Electricity Service Provider (ESP) instead of being subject to utility rates. Only about 13% of the total commercial and industrial load in each utility has the ability to shop, approximately 17,000 customer accounts in the state. The bill will add an additional 4,000 gigawatt-hours to the existing 24,000 gigawatt-hours of load that can be served by a third-party supplier, increasing Direct Access participation to 15.5%. 

Not only does the bill increase the current Direct Access program, it also mandates that the California Public Utilities Commission (CPUC) submit a report to the Senate by July 2020 on whether the state should reopen Direct Access fully. The CPUC will have to consider how reopening Direct Access will affect the state’s green initiative goals of reducing greenhouse gas emissions, ensuring grid reliability, and the impact on customers that remain with the utility. 

As always, there are concerns on both sides regarding Senate Bill 237. Fully opening the Direct Access program will increase the number of ESPs, which are not as closely regulated as the investor-owned utilities. This has the potential to hinder the state’s ability to meet its long-term energy goals of becoming 100% carbon free by 2045.

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

Mexico
CFE Raises Rates Again in September

Commercial and industrial customers on default energy supply service with the CFE saw their rates increase again in September. With September’s rates, customers in certain regions have now seen their capacity prices increase 200% since last December. Energy prices across the country have also risen more than 50% in most regions over the same period. Together, the energy and capacity components comprise roughly 80% of customers’ bills. The CFE argues that the price increases reflect the company’s costs as underlying commodity prices have grown.

The chart on the right shows capacity prices in the Tlaxcala region where prices have risen from $142.71 MXN/kW-month in December to $440.58 MXN/kW-month in September for medium-tension customers. Customers have seen an increase in each subsequent month for the last 10 months, totaling a 208% jump over the period. The capacity component accounts for 15-20% of overall energy costs.

At the same time, energy rates are also increasing. The chart below shows energy prices for the Aguascalientes region, load-weighted for each tranche assuming an average of 30% base consumption, 60% intermediate consumption, and 10% peak consumption. Most regions saw a fall in energy prices after December, but a steady climb since January. Load-weighted prices in Aguascalientes have increased from $1.15 MXN/kWh in December to $1.83 MXN/kWh in September, nearly a 60% increase over that period. The energy component of customers’ bills usually makes up 50-60% of total costs.

In December 2017, the regulatory body CRE forced the default utility company CFE to unbundle their power rates, breaking out supply components such as energy and capacity from regulated components including distribution, transmission, and ISO charges. This unbundling would increase transparency and make it easier to compare pricing offers from third-party suppliers, which can now provide alternatives to the supply portion of the bill.

Customers throughout the country have had to grapple with the steady increases in prices, and 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.

Henry Hub
NYMEX Prompt Price Above Key Technical $3.00 Level

The Henry Hub natural gas rolling prompt contract is trading at $3.165/MMBtu as of October 5. The prompt contract is the futures contract for delivery in the next calendar month, and is the most liquid of all gas futures contracts. The contract reached a high of $3.268/MMBtu in the first days of trading in October 2018. The recent price increase marks the first break above the strong technical resistance level around $3.05/MMBtu (denoted in orange below) for the first time since late January 2018. Shortly after trading above $3.60/MMBtu, the highest level of 2018, the low price hit around $2.55/MMBtu in late February/early March 2018.

The whipsaw from 12-month high to 12-month low in a matter of weeks has many end-users exercising patience in the current market. The abundance of supply had end-users hoping for a repeat of last winter, when pricing raced well above $3.00/MMBtu to below that level over the traditional winter season from November 2017-March 2018. Winter 2018/19 will begin with a storage deficit to the five-year average of 3,473 Bcf, or 17.5%. Until late September, the rolling prompt contract seemed to ignore the large storage deficit, with pricing capped around $3.05/MMBtu throughout 2018 until late September. The chart below shows the past 12 months of the rolling prompt NYMEX Henry Hub futures contract.

Beyond the rolling prompt, pricing rallied in late September for Henry Hub NYMEX contracts from November 2018 through March 2020 (denoted with the orange circle on page 3). A hold above $3.05/MMBtu is potentially short-lived, but may have staying power due to the existing deficit to the five-year average in natural gas storage. The run-up in near-term Henry Hub pricing further exaggerates the backwardation of the forward curve (denoted by the orange trend line in the chart below). There has been minimal price reaction for the futures contracts from summer 2020 and beyond. The backwardation has been in place for several years at this point and will continue to translate to lower Henry Hub strip pricing for longer-term strips. The chart below shows NYMEX Henry Hub futures contracts from November 2018 to December 2022.

For further updates on the natural gas market, 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.

More about the author