Energy Procurement Insights for February 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
New England Nukes to Receive Assistance from Connecticut State Government

In late-December, Connecticut announced the results of its clean energy competition, which attracted over 100 different options. Not surprisingly, the biggest winner was Connecticut’s Millstone nuclear plant, which entered the solicitation as an “at-risk” resource, meaning that other factors besides price could be considered in its selection.

Millstone, which is New England’s largest remaining nuclear plant, at over 2 gigawatts of capacity, was under threat of closure according to its owners, Dominion Resources, because of low average power prices, caused primarily by cheap natural gas. Although the contract awarded is for 10 years, the “at-risk” portion does not begin until 2022 and Connecticut’s distribution utilities, Eversouce and United Illuminating, have until March 31, 2019 to come to financial terms on the balance of the contract. The initial financial assessment performed in early 2018 did not affirm Dominion’s opinion of Millstone’s financial distress, and there were significant questions surrounding the nature of Millstone’s participation in the competition. In somewhat of an unexpected twist, New Hampshire’s Seabrook plant, New England’s only other nuclear facility, was also awarded a contract, though without an at-risk designation. Together, the existing nuclear resources cover 80% of the contracts awarded.

The remaining 20% fell to the Revolution Wind Expansion project, an additional 100 MW of offshore wind, as well as various solar projects in Connecticut and around New England. Roughly half of the renewable energy resources include a storage component. In total, the roughly 11.7 million MWhs contracted represent roughly 45% of Connecticut’s load and allow for an additional 17% available for future renewable RFPs.

While many view the competition as a success, several environmental groups are unhappy with the decision to allow participation from existing nuclear resources. The subsidization of nuclear resources has also met objections at both the ISO and FERC levels, because of its anti-competitive nature. These challenges are not New England-specific, and have been surfaced in New York and Illinois, where other “zero-emission” payments are intended to keep flagging nuclear plants online. Uncertainty still surrounds how these objections may impact states’ abilities to continue to conduct these RFPs.

In the near-term, the PPAs were awarded at roughly a 3.7 cents/kWh levelized cost, meaning the impact to CT ratepayers will likely be minimal. Similar to other state-mandated renewable procurements, utilities will enter into long term PPAs with the project developers/owners and recover any costs above and beyond what they receive in wholesale markets from ratepayers on their utility distribution bills. Uncertainty in the final negotiations for Millstone’s contract, as well as uncertainty in long-term power prices, complicate projections for long-run costs to CT ratepayers.

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

Mid-Atlantic
PJM Withstands Polar Vortex of 2019 Without Major Disruption

The PJM footprint experienced extremely cold weather as a polar vortex creeped into the RTO in late January. In Pittsburgh, a central location in PJM, temperatures dipped to negative-four degrees Fahrenheit on January 30 and negative-five degrees Fahrenheit on January 31.

With temperatures dropping below zero, power demand for PJM climbed fairly high on the last two days of January. Preliminary Metered Load data from PJM calculated the two load peaks from this polar vortex at 135,760 MW by 8:00pm on January 30 and 137,361 MW by 6:00pm on January 31.

For comparison purposes, the chart below shows PJM’s 5 Coincident Peaks (Summer June – September) over the past five years. The five coincident peak methodology, used to determine a customer’s capacity tag, remains a summer-only measurement timeframe, but if the RTO experiences more frequent or more severe demands during the cold weather, PJM could alter the way tags are calculated.

PJM was fully prepared for the January 2019 polar vortex, and LMPs did not jump to the extreme levels seen during similar conditions in the past. Western Hub Day Ahead LMPs averaged $50.38/MWh, peaked at $81.54/MWh on January 30, and on January 31 peaked at $154.82/MWh with an average of $88.21/MWh. Natural gas pipelines and electric generators planned far in advance for the cold weather, a positive result from the changes that PJM implemented after the polar vortex of 2014 (mainly Capacity Performance).

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

Midwest
PJM’s Capacity Performance Measures Pay Off Amid January Polar Vortex

The Polar Vortex that hit the US in 2014 served as a valuable lesson in the parts of the Midwest and Northeast as temperatures plunged below -60 degrees F in late January 2019. The utilities in the Midwest were able to manage their way through the deep freeze with few interruptions and by working with customers to reduce demand. The cold snaps in 2014 and 2018 illuminated some of the problems associated with grid reliability, which assisted the Midwest’s utilities in preparing for the sub-zero temperatures. PJM efforts to curb market price volatility and generation shortages were addressed with the implementation of Capacity Performance measures in 2015. Generators that participate in the Capacity Performance program receive incremental capacity payments as incentive to maintain equipment properly and firm up supplies to increase its probability of performing when needed.

Despite days in January 2019 seeing colder temperatures than those of the 2014 polar vortex, Midwest LMP pricing settled significantly lower. For instance, in the ComEd market area, prices in January reached just over $51/MWh on the coldest day of the month, January 30. Compare this to January 7, 2014’s price of ~$565/MWh and it is clear that PJM’s implementation of the Capacity Performance market restructure in 2015 is working to stabilize pricing. PJM West Hub settlement prices support the conclusion as well, with PJM West Hub prices maxing out at ~$160/MWh this past month compared to ~$1,800/MWh in January 2014. The program has help helped curb market price volatility and generation shortages that led to price blowouts during the 2014 polar vortex. The price stability evidenced in January 2019 could be a compelling reason for customers with more of a risk appetite to allow usage to settle at an index rather than lock in potentially higher prices when weather forecasts cause a run up in the prompt market.

PJM recently stated that the forced generation outages in 2019 peaked at 21.35 GW, or 10.6% of the total capacity. By comparison, total forced outages during a cold snap in 2018 reached 12.1%, and 22% during the 2014 polar vortex. The reduction in number of outages over the years indicates that the RTO’s efforts to ensure grid reliability are trending in right direction. This year’s outages were dominated by coal and natural gas, with their total share of 85%, including 2.9 GW of gas generation that was idled because of a shortage of fuel. In its subsequent analysis, PJM reported that the forced outages through renewables marked 1.8 GW on January 30 and 3.31 GW on January 31, which also included a 1.1 GW nuclear reactor in New Jersey.

Last week’s challenging weather may have once again ignited the debates about whether FERC should review the federal plans to offer financial support to coal and nuclear plants. In 2017, the US DOE, referencing the 2014 polar vortex, pushed FERC to approve their tactics to support the struggling generators. FERC rejected the proposal last year, but it is anticipated that the agency and resource owners will continue to make similar arguments at FERC irrespective of the outcome of the 2019 polar vortex. 

While PJM came out of this year’s polar vortex event, this does not mean that performance in future events will mirror price reactions from January 30 and 31. Customers with some budget flexibility should consider leaving greater exposure to real-time prices, as prices through peak periods continue to remain stable. Reassessment of winter strategies should take place in the shoulder months to determine appropriate risk appetite. Reach out to your Enel X account manager to review potential strategies.

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

Texas
Spring SARA Report Expects Sufficient Generation

The preliminary spring 2019 Season Assessment of Resource Adequacy (SARA) report from ERCOT expects sufficient generation for the upcoming season, even if there is a combination of extreme peak load and outages. ERCOT expects a total 2,262 MW of new nameplate capacity before the end of the season. Most of the new assets come from 638 MW of wind capacity and 175 MW of solar. Historical outages, per ERCOT, come in around 10,564 MW as units go down for maintenance and other regularly scheduled operations. Even with a worst-case scenario, ERCOT expects enough generation to meet demand. The final assessment for spring 2019, and the preliminary assessment for summer 2019, is expected to be released in the coming weeks.

New Capacity Additions Forecast Includes Batteries

The most recent capacity change chart from ERCOT reinforced the significant growth of both wind and solar facilities over the coming years. Wind assets are expected to add 5,531 MW of capacity in 2019, while solar is expected to add another 1,232 MW, roughly doubling the current level of solar capacity. While gas and other combined-cycle units are currently listed to increase modestly, a new addition to the list is the most surprising. A new battery project named “June Storage” is expected to add 495 MW of battery capacity to the grid in 2021. This coincides with a solar project of roughly the same size in Borden County. ERCOT currently has 89 MW of installed battery capacity, so this addition would significantly increase the amount of battery capacity in the RTO.

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

Mexico
CFE Rates Flat in February, 60% to 80% Higher than Last Year

The CFE published its tariff for their Basic Service customers for February. Predictably, the rates remained very similar to the January rates, moving less than a percent lower for both energy and capacity rates across the country. While lower seasonal demand has kept rates steady through the winter months, commercial and industrial customers are still paying substantially higher prices compared to the CFE tariff from one year ago. In many cases, year-over-year cost increases in February approach 80% for the capacity component of the bill and nearly 60% for energy.

The chart on the right shows capacity prices in the Monterrey region where prices for February 2019 are just under $342 MXN/kW-month. While this represents a 0.7% decrease compared to the January rates, it is also a 75% increase relative to last February’s rates, which registered at just $196 MXN/kW-month. The capacity component accounts for roughly 15% to 20% of overall energy costs.

Energy rates saw a similar sideways movement in February. 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. While February energy prices technically decreased by about 0.6% in most regions compared to the previous month, energy prices across the country are higher by 50% to more than 60% compared to February 2018. Load-weighted prices in Aguascalientes have increased from $0.918 MXN/kWh in February 2018 to $1.45 MXN/kWh in February 2019, a 58% increase over that period. The energy component of customers’ bills usually makes up 50% to 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 confront the price growth experienced throughout 2018 and which has not pulled back so far in 2019. Leaving the CFE Basic service tariff in favor of 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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