Energy Market Update

By The Numbers:

• NG '21 prompt-month opened at $5.299/MMBtu on Monday, October 18, down from last Friday's settlement of $5.41/MMbtu. 
• WTI '21 prompt-month futures opened at $82.60/bbl on Monday, October 18, up slightly from last Friday's settlement of $82.28/bbl.
• Coal spot contracts (Central Appalachia) are trading at $75.50/ton, EIA reported on 10/15/21, unchanged from the previous week.

• According to the Energy Information Administration (EIA), net injections to working gas totaled 81 Bcf for the week ending October 8. Working natural gas stocks totaled 3,369 Bcf, -13% lower than year-ago and -5% lower than the five-year average for this week. The composite price for natural gas plant liquids at Mont Belvieu, Texas, rose +$0.02/MMBtu to $12.38/MMBtu for the week ending October 13. For the week ending October 5, Baker Hughes reports 99 gas-directed rigs, unchanged from the prior week. Oil-directed rigs rose by +5 units to 433 for the same period.

Weekly Power Report:

Power - Bullish

• Nearly all deregulated regional power forward averages increased last week as natural gas prices surged.  Forward prices in the Mid-Atlantic region (PJM) increased 8% for calendar 2022 and an average of 5% for the period 2022 through 2026.  The Great Lakes Region saw a similar 4% increase in the forward strips through 2026 gaining 4% on the week.

Great Lakes Electric Summary

• The Great Lakes Region’s forward power prices have continued to advance over the past couple of weeks despite some softness in the near-term natural gas prices.  The downward pressure on near-term gas prices can be attributed to rising production levels and milder temperature forecasts through the start of November, but the level of concern for shortages this winter is still high and keeping power prices elevated for the prompt-year.  The forward power price strips through 2026 increased by +2% on average this past week with the front of the price curve (2022) trading +1% higher and the longer-term prices (2025/2026) prices +2% higher.  Forward prices for the entire strip are currently trading approximately +56% above the all-time low prices for those years with the prompt-year +86% higher than the lows and the longer-term prices trading +44% above the lows.  Index prices continue to climb month-over-month and remain significantly higher year-over-year.   The day-ahead index power prices in COMED for October are averaging $53.60/MWh which is +27% higher than the September average and +167% higher than October of last year, while the month-to-date average settlement price for AdHub is $58.69/MWh, which is +32% higher than the September average and +164% higher than October of last year.  In Michigan prices for October are averaging $59.73/MWh or +28% higher than the September average and +133% higher than October of last year, while the month-to-date average settlement price for Ameren is $58.29/MWh or +30% higher than the September average and +150% higher than October of last year.
• Due to soaring natural gas prices this year, coal-fired generation is expected to jump 22% year-over-year according to the Energy Information Administration (EIA).  It will be the first time since 2014 that electricity sourced from coal would have increased year-over-year, despite the fact that 30% of all coal-fired generation has been retired since 2010.  Coal and natural gas account for the majority of the fuel inputs that generate electricity in the US and often compete for market share in many regions of the country.  Natural gas prices have been historically lower and as a result have typically determined the role that coal plays in meeting electricity demand.  With natural gas prices increasing so much this year and experiencing a lot of volatility, coal has been much more stable even though those prices are expected to jump as well.  Coal-fired power in the Midcontinent Independent System Operator (MISO) has averaged 40.4% of the total fuel mix through September of this year, an increase of 8.5% year-over-year, while natural gas-fired generation has averaged 28.4%, or a decrease of 7.1%, according to MISO data. In the Southwest Power Pool (SPP), they have seen similar percent increases in coal generation which is up 6.4%, while natural gas-fired generation is down 7.5%, according to SPP data.  Source:  Platt’s

Northeast Energy Summary

• At the October 7 Participants Committee meeting, ISO-NE’s COO Vamsi Chadalavada expressed some fuel security concerns for the 2021/2022 winter.  Without a winter reliability program in place, ISO-NE is seeing a drop of 5% in on-site oil versus the same period last year with most of the oil reserves being concentrated in a few resources.  Additionally, Chadalavada expressed concerns that the LNG forwards in Europe are currently trading at a $13 premium over the forwards in New England, weakening the incentives to import LNG into the region. Typically, New England sets the price for LNG in the winter.  Chadalavada will provide updates on the status of the region’s fuel supplies at the November Participants Committee meeting. 
• A public hearing by the Maine Department of Environmental Protection (DEP) is scheduled on October 19 to deliberate whether to revoke the construction license for the New England Clean Energy Connect transmission project, the 145-mile-high voltage undertaking to bring over 1,200 MW of Canadian hydropower to Southern New England through the state of Maine. The DEP scheduled the hearing in August after the Maine Superior Court nullified the state’s Bureau of Public Lands approval from 2014 because they did not obtain legislative approval. While the project owners are appealing that decision, NECEC President Thorn Dickinson pleaded in a written testimony that the suspension of the construction license would essentially decommission the project, originally slated to be operational by December 2023. 

ERCOT Energy Summary

• In a flip of the usual hot/cold dynamic, California is the only spot on a map of the Lower 48 states showing consistent below-normal temperatures through the end of month. This pattern will likely peak on Wednesday and Thursday and drive support for gas basis at both PG&E and SoCal’s city gates. In an early sign of what may be needed for system balancing this heating season, SoCal Gas called a low OFO Sunday night (actually a Stage 2 OFO). Driven by the cooler temps and an expectation that the shortfall due to imports at the Border and demand would force a -0.2 Bcf draw from storage, this was an unexpected twist for the third week of October. The near-term weather outlook in the West notwithstanding, buyers should not look past the market opportunity present today. Yet another sizable sell-down in NYMEX pricing on Monday brought prompt gas futures to a three-week low. Combined with the improved gas flow outlook that we detailed in our last update for SoCal’s Northern Zone (tied mainly to the end of maintenance on L4000 and its return to service at a higher operating pressure) and a recent proposal for the CPUC to authorize higher storage levels (to either 41 Bcf or 68.6 Bcf) at Aliso Canyon this winter, basis prices have watered down in SoCalGas territory for this winter. The forward curves for power have dropped in step and are giving the dawdling bargain hunter a buying opportunity. Don’t look past this break in the uptrend as it can quickly return if a sharply colder forecast materializes.
• These pages have detailed the various gymnastics that the California ISO and state energy regulators have performed this year to help the state’s grid survive what was widely expected to be a precarious summer. And they did it: California survived with zero blackouts and only eight flex alerts being issued this year, an improvement over the nine alerts issued in 2020. (For context, there were only seven alerts in total issued between 2002-19). To shore up the grid, the CPUC ordered the IOUs to procure more than 14,000 MW of new generation and storage capacity. In 2019, the CPUC called for 3,300 MW of new gens by 2023. This includes the five natural gas plants to be sourced by CDWR totaling 150 MW; four of these are online now. The second procurement order this summer called for 11,500 MW of wind and solar generation, along with battery storage and other carbon-free resources. All of the major industry publications and most mainstream news outlets have covered California’s slow-moving crisis, especially as the state grappled with wildfires impacting power flows along transmission lines and the drought significantly cut into hydro generation. The WSJ printed an eye-catching article over the weekend, California Scrambles To Find Electricity To Offset Plant Closures, highlighting how yet even more extreme gymnastics will be necessary over the next few years to keep the grid centered on the balance beam as it deals with crosswinds caused by, wait for it, climate change, and the closure of nearly 10% of in-state generation, including four natural gas gen stations along the coast and the 2,250 MW Diablo Canyon nuclear station. It’s worth a read.
• One subscriber asked last week about the status of Vistra’s massive 400 MW/1,600 MWh Moss Landing Energy Storage Facility and if it has come fully back online following the thermal event in early September that knocked the 300 MW/1,200 MWh Phase I portion offline. Short answer, no. The company released a brief update at the end of September indicating that "… initial data shows that the operating temperatures of the batteries in the areas that we've been able to inspect were within normal limits at the time the safety systems deployed … So, we know there was some smoke. We're not sure of the source of the smoke. We have a low single-digit percentage of batteries that are affected. But it appears to be something, and we've got to get to the initiating event." Bottom line, the root cause probe continues. The 100 MW Phase II part of the system that came online this summer is in a separate building and continues to operate. Zooming out a little: Vistra’s facility is part of the roughly 2,400 MW of batteries currently synched to the CAISO grid with about 1,100 MW in NP15 and 1,300 MW in SP15. Expectations are that we’ll see another 500-1,000 MW online by summer 2022. This summer we saw a gradual rise in day-ahead price spreads and a collapse in real-time hour-to-hour volatility which has nearly erased the premium that real-time used to provide over day-ahead. Was this the direct result of all of the new batteries online? Will project owners continue to dispatch these the same way? What we’re watching is how timelines for projects scheduled to arrive in 2023 may speed or slow as the shape and magnitude of the day-ahead and real-time energy prices change.
  

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