Energy Procurement Insights for April 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'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
Exelon Plans Major Plant Retirement in 2022, ISO-NE Has Other Ideas

On March 29, Exelon Generation, a subsidiary of Exelon, notified ISO-NE of its plans to retire the Mystic Generating Station located in Everett, Massachusetts, by June 2022. With nearly 1,500 MW of nameplate gas capacity (Units 8 & 9) and an additional 500 MW of gas/petroleum dual-fired capability (Unit 7), Mystic is the largest facility in the state of Massachusetts. Reiterating concerns that low wholesale energy prices and declining capacity prices are not adequately compensating traditional resources, Exelon Power President Ron DeGregorio stated in a news release, “ISO-NE market fails to properly reflect the reliability and fuel security benefits that these power plants provide to the region.”

Generators using the traditional baseload resources of coal, gas, and nuclear tend to blame the suppression of prices on new renewable resources like wind and solar for distorting price formation in deregulated markets because they receive out-of-market compensation through state initiatives. For its part, ISO-NE has begun the process of reconciling states’ wishes to support renewable generation with its desire to maintain an open market that properly values all resources. ISO-NE has introduced new rules to remove new renewable resources from the first round of the capacity auction and allow them to take on an obligation only when paired with a retiring fossil fuel resource. Exelon has indicated that if there is some interim legislation that supports baseload generation, the company may reconsider its plans to close Mystic.

Exelon’s announcement marked the first planned removal of generating capacity in the region in the past three years, which coincided with a period of significant decline in forward capacity auction (FCA) prices. In the NEMA Boston region, where the Mystic Generating Station is located, prices reached a high of $15/kW-month for the 2017/2018 delivery year but dropped to $4.63/kW-month in the most recent auction, following three consecutive years of capacity price decreases. In FCA 8 (2014 auction for 2017/2018 delivery), transmission constraints exacerbated issues for the NEMA capacity zone because it could not import sufficient electricity from neighboring ISO-NE zones to meet its local reliability requirements. Subsequently, capacity prices were higher in NEMA than for any other capacity zone that year.

It is likely that ISO-NE’s decision to file with FERC to retain Mystic 8 and 9 was at least partially based on concerns over local constraints. If granted, ISO-NE could pay Exelon out-of-market expenses to keep the facility operational and to stave off reliability concerns even if it is uneconomical. Either way, a shrinking power supply will likely lead to increased prices for ratepayers in the short-run. However, a retiring natural gas plant will not place more pressure on gas itself, unlike recent coal and nuclear retirements, which had amplified the issue by introducing another layer of volatility.

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

New York
NYISO Capacity Auction Clears Lower Than 2017 Levels

NYISO’s summer 2018 capacity auction results came in significantly lower for both New York City (Zone J) and Rest of State (Zones A-F), decreasing 11% and 42%, respectively, relative to last summer’s auction. In comparison, the Lower Hudson Valley (Zones G-I) was down only 1%. The auction results were right in line with where the futures markets were trading for the summer strips.

Delays in the 650 MW CPV Valley plant has most likely contributed to the Lower Hudson Valley avoiding a similar decline as seen in the rest of the New York capacity markets. The Roseton power plant, in the Lower Hudson Valley, has approval to export 500 MW to New England for the 2018/19 period. This also contributed to tightness of supply in the Lower Hudson Valley.

The NYISO runs two strip capacity auctions a year: one for the summer and one for the winter. In addition, there are monthly and spot auctions held each month to allow supplier and load to procure capacity not cleared in the strip auctions. This strip auction cleared only 2,614 MW of the 35,562 MW requirement. Most of the capacity is procured during the spot auction as well as bilaterally. Capacity represents the need to have adequate generating resources to ensure that the demand for electricity can be met at all times. In a capacity market, the utility or other electricity suppliers are required to have enough resources to meet their customers’ demand plus a reserve amount.

With more renewables coming, it is hard to be bullish on either energy or capacity until Indian Point retirements hit in 2020 and 2021. By this time, the market will have a better idea as to how large the renewable footprint will be and whether the proposed new natural gas combined cycle plants totaling nearly 1,800 MW become operational.

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

Mid-Atlantic
PJM Releases Final Capacity Prices for the Upcoming 2018/19 Delivery Year

On March 9th, PJM released results from the 3rd Incremental Capacity Auction which finalized capacity prices for the 2018/19 delivery year. The auction had very little impact on the final pricing, with the largest zonal increase in DPL coming in at $0.29/MW-day, a 0.13% increase. The final zonal Capacity prices are paid by all PJM customers based on their individual Capacity tag.

The 2018/19 capacity prices are currently the highest prices over the four delivery years seen in the chart below. Customers cannot do anything to alter the final capacity prices that they must pay, but customers can manage their capacity tags through Enel X’s PJM peak predictor program. This program aims to reduce a customer’s capacity tag by reducing demands during peak summer periods. Learn more about how our customers in PJM save thousands by reducing capacity charges through Enel X’s system peak predictor program with this brochure, and contact an expert at Enel X for additional information.

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

Midwest
FirstEnergy Solutions Files for Chapter 11 Bankruptcy

FirstEnergy Solutions (FES), the merchant generation subsidiary of FirstEnergy Corp, filed for Chapter 11 bankruptcy protection on March 31, as the parent company continues moving toward exiting the competitive power generation business and shifting focusing to the regulated utility segments of its business.

The move has been anticipated for years, frequently spurring state and federal legislatures to consider assistance for the company’s coal and nuclear units, which have struggled to make a profit. FES announced the sale or closure of most of its competitive generation fleet in the next two to three years, including three large nuclear facilities in Ohio and Pennsylvania. Retirements of these generators could cause capacity prices to rise in PJM zones such as ATSI in northern Ohio. The impact of the bankruptcy to customers under retail supply contracts with FES is currently unknown. However, the retail book of FES is likely to be sold off and served by another entity, resulting in little impact to end users.

In 2017, FirstEnergy aggressively pursued state subsidies to support its struggling nuclear fleet in the form of “Zero Emissions” credit programs. While some states have passed similar legislation, such as New York’s ZEC program, Ohio’s legislation repeatedly denied these arguments, refusing to pass the costs of supporting these loss-making generators onto the state’s ratepayers. On the Federal level, the US Department of Energy’s (DOE) Notice of Proposed Rulemaking (NOPR) in late 2017 had the same intention of supporting at-risk coal and nuclear generation on the premise that they are necessary for grid “resiliency.” FERC rejected the proposal in early 2018, after the cold snap in January showed the competitive merchant generation fleet is functioning well and there is little or no threat to grid reliability during extreme weather. Without out-of-market support in the form of subsidies, the uneconomic generators owned by FES have succumbed to the decrease in costs for natural gas-fired generation and the increasing share of renewables in the competitive merchant generation market.

Looking forward, a number of potential scenarios could play out with the competitive coal and nuclear facilities owned by FES. For now, the units will remain in normal operation; however, FES plans to sell or retire most of these units within 18 months, including all three nuclear facilities. These nuclear facilities amount to 4,048 MW of capacity in northern Ohio and Pennsylvania, with the two plants located in PJM’s ATSI zone representing approximately half of this capacity. If these units do go offline within the two-to-three-year timeline and do not bid into the 2021/2022 Capacity Auction, an increase in capacity prices could be on the horizon for the ATSI zone. As capacity prices have steadily declined in ATSI over the past three base residual auctions, clearing prices should be closely monitored for the upcoming and future auctions in this zone.

News of FirstEnergy Solution’s bankruptcy did not come as a surprise to many market participants, as the company’s merchant generation fleet has struggled to turn a profit for many years. With the last state and federal subsidy options exhausted, the bankruptcy falls in line with the new narrative in competitive generation markets. Uneconomic coal and nuclear facilities are unable to compete with the low cost of natural gas and the increase in renewable generation.

For retail customers, retirements of very large nuclear facilities could result in increases in capacity clearing prices in zones such as ATSI in northern Ohio. The impact to customers under existing retail supply contracts with FES is still unknown at this point. However, it is not currently a major concern, as these customers will likely be picked up by another supplier or, in a last resort, default to the local utility.

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

Texas
ERCOT Wholesale Spot Power Prices Remain Steady; Declined 4% Year-over-Year in March

Last month, day-ahead spot market power prices fell about 4% compared to March 2017 as average fuel prices fell and mild weather helped register lower daily peak demands. Delivered natural gas prices dropped about 7% year-over-year. As a result of milder temperatures, the measured peak load of 46,962 MW was less than 1% lower than in March 2017. The monthly average day-ahead power price for March 2018 was $22.40/MWh across all hubs, whereas the average monthly spot price in March 2017 was $23.23/MWh.

Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. This past March, temperatures around the central footprint of ERCOT were about two degrees lower than their seasonal daytime averages for the duration of the month. On balance, the wholesale power prices were softened by lower delivered prices for natural gas when compared to last year. The monthly average natural gas price in March was $2.674MMBtu at the Houston Ship Channel delivery point in Texas, about a 7% decline under the $2.879/MMBtu average seen in March 2017. Since natural gas is the predominant fuel used to generate power in Texas, the price of electricity is closely linked to the cost of natural gas in the state. In fact, natural gas-fired power plants usually set the price of wholesale electricity in the region.

Power prices will generally react to electricity demand, which is driven by weather and economic factors. As mentioned above, the ERCOT system demand peaked at 46,962 MW in March 2018, which is less than 1% lower than the March 2017 peak load of 47,106 MW. Aside from the observed temperatures and lower natural gas prices, power prices remained in check as a result of a balanced mix of generation resources.

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

California
California ISO’s Latest Transmission Plan Reduces Project Costs by $2.6 Billion

The latest 2017-2018 Transmission Plan put forth by the California grid operator, CAISO, is the guiding document that lays out the necessary transmission system improvements required to maintain system reliability as energy demand grows. This latest plan approves 17 transmission projects that will cost a total of $270 million. The scope of the plan outlines anticipated necessary transmission system improvements over the next decade.

The more eye-popping statistic belongs to the avoided cost of $2.6 billion. The latest transmission plan calls for canceling 18 projects and alterations to another 21 in the PG&E and SDG&E service territories. The motivation for the change is primarily the emergence of a lower demand growth trend driven by greater energy efficiency and distributed energy resources. With less power needing to be transported long distances from centralized generators to local communities, less high-voltage transmission will be needed. These transmission cost reductions are an important aspect of the state's renewable power push as California targets a 50% renewable power policy.

Customers will reap the benefits of the new, lower-cost plan as they will avoid the $2.6 billion in transmission improvements that would have otherwise been passed on to them. Customers may not see any decrease in their bills as a result of the new plan; however, they will not see the price increases that would have otherwise been required to fund the transmission projects that are now being replaced and downgraded.

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

Mexico
CFE Confident that Energy Reform Will Deliver Benefits in 2019

Among the benefits touted as motivation for Mexico's energy market reform were lower overall energy prices for end-users. Since the market officially deregulated in January 2016, customers have seen a mixed bag of price increases and drops, opaque utility pricing, and monthly uncertainty. However, there are reasons for optimism, and CFE anticipates that 2019 will broadly achieve the goal of lower energy prices for customers.

While natural gas pipeline growth has widely struggled to stay on schedule, many projects have been holding on to in-service dates for the end of 2018. In addition to the pipeline growth, a number of new, more efficient natural gas-fired power plants are expected to enter into service in 2018 and 2019. Access to lower-priced gas and more efficient units will help to lower overall power prices in the country.

In December, the utility company CFE began publishing unbundled tariff rates that broke out generation costs from regulated cost components. This was an important step toward a more competitive market that will allow suppliers to compete on an even playing field with the utility. There has also been strong growth in the supplier landscape over the last year, with many more independent companies participating in the market and offering customers alternatives to the utility.

While we agree with the CFE sentiment that the market reform will continue to see benefits over the next few years, customers are already realizing savings relative to the default utility rates by contracting with third-party suppliers. Certainly as the market continues to develop and more suppliers enter the field, prices will become increasingly competitive and favorable. For those reasons, we recommend customers look to short-term contracts to capture some of the savings currently available in the market, but will also allow them to explore new contracts more quickly as the market develops over the next few years.

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

Henry Hub
April, Summer Temperature Forecasts Call for Elevated Gas Demand

On April 5, the US Energy Information Administration (EIA) released final storage data for March, showing that the withdrawal had an implied flow of 20 Bcf and left 1,354 Bcf in storage heading into April. Traditionally, withdrawal season spans from November through March each year. However, the National Oceanic and Atmospheric Administration (NOAA) temperature forecast through mid-April is calling for a strong likelihood of below-normal temperatures, which is adding to the bullish sentiment in gas pricing. The temperature map below indicates a strong likelihood for elevated gas demand to serve the Northeast regional heating load, which may exert upward pressure on NYMEX gas pricing.

The below-normal temperatures will likely force two additional withdrawals from storage in early April. Historically, the five-year average calls for injections of 9 Bcf and 38 Bcf respectively for the first two weeks of April. In 2017, EIA reported injections totaling over 60 Bcf for the first half of April. The delta between 2018 storage levels and the five-year average will increase over the next two weeks because of the delay to the start of injection season.

Currently, there is a stronger potential for upward price movement since the start of the shale boom nearly a decade ago. Over the past 10 years demand took a back seat to supply. The current projections are significant because they hint at more of a balanced market going from late 2019 and beyond. With the most recent storage announcement from the EIA, the current deficit to the five-year average is 347 Bcf, or 20.4%. Traditionally, a large deficit to the five-year average exerts upward pressure on gas pricing. Furthermore, NOAA forecasts are calling for summer 2018 temperatures to come in above normal for the majority of gas consumers. The temperature variation map below illustrates a strong probability for hot summer temperatures to warrant higher levels of gas power generation to meet cooling load demand.

The chart below illustrates the historical significance of the end of March 2018 gas storage levels coming at 1,354 Bcf and the potential impact to NYMEX 12-month strip pricing and beyond. This level is the second lowest end-of-March gas storage level since 2010, when NYMEX 12-month strip was $4.64. Only March 2014, when NYMEX 12-month strip pricing was $4.46, left gas storage in a tighter scenario than 2018. The tighter supply/demand balance puts additional weight on the previously unforeseen April 2018 gas storage withdrawals. In the image below, the inverse relationship between NYMEX price and storage is evident during early 2018, when NYMEX rallied above $3.00/MMBtu as the deficit to the five-year average grew.

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.

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