Weekly Energy Industry Summary

Commodity Fundamentals

Week of July 25, 2021

By The Numbers:

  • NG August '21 prompt-month opened at $4.025/MMbtu on Monday, July 26, down -$.035/MMbtu from last Friday's settlement. 
  • WTI September '21 prompt-month futures opened at $71.46/bbl on Monday, July 26, down -$.61/bbl from Friday's settlement.
  • Coal spot contracts are trading at $61.95/ton, flat to last week.

Natural Gas Fundamentals -  Neutral/Bullish

  • Prompt-month NYMEX natural gas opened trading on Monday, July 26, at $4.025/MMbtu, down -$.035/MMbtu from the previous settlement. Gas then traded up to $4.187/MMbtu, a two-and-a-half year high before settling back to $4.08/MMbtu in early afternoon trading.
  • Extended hot summer temperatures in key market areas have some of the storage models potentially ticking downward bringing in some additional support to the gas market.
  • Production of natural gas remains flat but steady at 91.5 Bcf/day.

Crude Oil - Neutral

  • Prompt-month crude oil prices opened on July 19, 2021, at $71.46/bbl, down -$.61/bbl from the previous settlement.
  • Prompt-month crude oil traded at $71.56/bbl in early afternoon trading.
  • The crude oil market is somewhat in check over the past weeks as the effects of COVID-19 variants is in a period of discovery.

Economy - Bullish

  • Investors around the globe are pouring money into U.S. financial assets, a sign confidence that the world's largest economy remains poised to pull through the COVID-19 pandemic better than many others, The Wall Street Journal reported. 
  • Utilities and startups are racing to build fast charging networks for electric vehicles throughout the U.S. as auto makers bet their future on EVs, The Wall Street Journal reported.
  • Earnings reports from tech giants Apple, Tesla and Amazon are coming later this week.

Weather - Neutral/Bullish

 
  • Heat in the West continues unabated.
  • Above-normal heat in the Midwest will carry on till the end of the week and moderate—temperatures will also moderate in the East and Northeast—the deep south will be hotter than normal through the end of the month.
  • August is trending slightly above normal.

Weekly Natural Gas Report:

 

The U.S. Energy Information Administration (EIA) reported an injection of +49 Bcf into storage for the week ending July 16. Current inventory is 2,678 Bcf, -17% lower than last year and -6% lower than the 5-year-average. The natural gas plants liquids composite price at Mont Belvieu, Texas, averaged $9.23/MMBtu for the week ending July 21, down -$0.10/MMbtu. The natural gas rig count (June 15) increased +3 to 104 units, and oil-directed rigs were up +2 at 380, according to Baker Hughes. Natural gas exports continue to be at record levels in the month of July.

Prices reflect week ending July 23, 2021
Prices reflect week ending July 23, 2021

Weekly Power Report:

Power - Bullish

  • National forward power prices for Cal'22 strip on a week-over-week basis were higher in every region averaging an increase of 4.9%. ERCOT experienced the largest increase with prices moving up 6.9%.
  • Cal 2023 was also higher week-over-week in all regions averaging an increase of 2.9%. Continued above-normal temperatures and concerns over low natural gas storage have been the main catalysts of the price movement.

Mid-Atlantic Electric Summary

  • The Mid-Atlantic Region’s forward power prices again continue to follow natural gas prices upwards over halfway through the summer. NYMEX prompt-month gas reached a 31-month high on Monday as expectations for warmer temperatures, through mid-August, along with slow production growth and strong exports, will likely continue to provide price support for energy prices. Last week, the forward power pricing strip through 2026 increased by +3% on average with the front of the curve +5% higher and the back of the curve only +1% higher. Over the past year, the average increase for the entire price curve was +17% higher. Forward prices for the entire strip are currently trading within +19% of the all-time low prices for those years, with the front part of the pricing curve (2022) averaging +31% higher than the lows, while the back-end of the curve (2026) is averaging less than half of that at +13% off the lows. Day-ahead index power prices in West Hub are averaging $35.73/MWh thus far in July, which is +17% higher than last month but +36% higher than in July of 2020, while the month-to-date average price for July in the Eastern Hub is $38.55/MWh, which is 16% higher month-over-month and 54% higher than last year for this month.
  • On July 14th, the Board of Public Utilities (BPU) approved Staff’s Report on Resource Adequacy Alternatives and directed staff to take additional action, in accordance with the recommendations in the report. The report includes analysis of a number of resource adequacy paths including Fixed Resource Requirement (FRR) options, an Integrated Clean Capacity Market (ICCM) at both the NJ-only and PJM-wide levels, and continued participation in a PJM capacity market that does not include an expanded MOPR, showing savings from the status quo with most alternative approaches. The report recommends/concludes the following: (1) incorporating New Jersey’s clean energy goals in the regional market is the most efficient way to provide customers with reliable, affordable and carbon-free electricity; (2) existing regional wholesale market structures have fulfilled their design objectives to maintain reliability at competitive prices, saving New Jersey customers hundreds of millions of dollars annually; however, those same markets have lagged behind in addressing state clean energy policies; (3) regulatory developments at the regional and national level including PJM's commitment to radically scale back its mitigation of clean energy resources as part of the expanded MOPR make it premature to consider leaving the regional market structure; and (4) the ICCM design, proposed by BPU staff consultant Brattle, would allow states to directly leverage the competitive efficiencies of the broad regional marketplace for efficient achievement of their clean energy goals.

Great Lakes Electric Summary

  • The Great Lakes Region’s forward power prices again continue to follow natural gas prices upwards over halfway through the summer. NYMEX prompt-month gas reached a 31-month high on Monday as expectations for warmer temperatures through mid-August, along with slow production growth and strong exports, will likely continue to provide price support for energy prices. Last week, the forward power pricing strip through 2026 increased by +4% on average with the front of the curve +5% higher and the back of the curve only +1% higher.  Over the past year, the average increase for the entire price curve was +20% higher. Forward prices for the entire strip are currently trading within +25% of the all-time low prices for those years, with the front part of the pricing curve (2022) averaging +35% higher than the lows, while the back-end of the curve (2026) is averaging markedly less at +22% off the lows. Day-ahead index power prices in ComEd are averaging $35.57/MWh thus far for July, which is +16% higher than June's average settlement price and +55% higher than last year, while the AdHub monthly average price so far is $36.79/MWh or +14% higher month-over-month and +44% higher than a year ago. In Michigan, July is averaging $38.55/MWh month-to-date, which is +10% higher than June's settlement average and +25% higher than last year, while Ameren's monthly average price for July is $36.49/MWh or +10% higher month-over-month and +38% higher year-over-year
  • This week, Representative Sean Casten (D-IL) reintroduced legislation to require that FERC find any rate for the wholesale sale of electricity that does not incorporate the cost of greenhouse gas emissions to be unjust, unreasonable, unduly discriminatory, or preferential.  The bill did not previously receive a hearing, but Casten and other Democrats have re-filed the bill to increase awareness of FERC and the need to install a Democratic majority on the FERC as soon as possible, as well as the agency’s potential ability to unilaterally implement a carbon price.     

Northeast Energy Summary

  • Day-ahead locational marginal prices for New England have lacked significant elevation this summer with July’s month-to-date averaging ~$37/MWh thus far; this is only about a $1/MWh higher than June’s average despite June being a “peakier” month. The unofficial summer-to-date peak demand value, day and hour for the region currently comes from Tuesday, July 29 hour ending 6 p.m. at 25,101 MW. We also saw the only triple digit day-ahead hourly prices register from June, all between June 28 and the 30th, for only 22 hours and maxing out at $181/MWh. The standing peak will likely remain in place for at least the next 2 weeks as temperature expectations for New England are expected to be variable at best with a cooler lean with the probabilities for significant and prolonged heat (heat wave) very low. August will bring a new month and those looking to manage their peaks and index exposure should remain vigilant as 2 out of the last 10 years still saw the peak demand day and hour come from the 8th month of the year. .
  • This week, the NYISO presented its Buyer Side Mitigation (BSM) Reform Proposal and Capacity Accreditation Considerations to stakeholders at the Joint ICAP/Market Issues/Price Responsive Load Working Group meeting. NYISO proposes to exempt from BSM (NYISO’s version of the MOPR) resource types that align with the state’s climate mandates, such as solar and wind (i.e., terrestrial and offshore), energy storage resources and demand response. The NYISO hopes to complete the stakeholder process with respect to new BSM rules by the end of the September with a FERC filing shortly thereafter.

ERCOT Energy Summary

  • Real-time prices averaged $35.43/MWh for the Houston Zone last week (7/19-7/24), on another week of overall moderate temperatures with the exception of hour ending (HE) 16:00 and 17:00 when prices averaged ~$282/MWh and ~$460/MWh respectively. Things will change this week, at least in North Texas with Dallas finally reaching 100 degrees F on Sunday (July 25th) and will remain at or just under 100 degrees F for the next 10 days. For Monday July 26th, ERCOT is calling for a peak load of 74,326 MW, which is within 500 MW of its all time peak from 2019 of 74,820 MW. South Texas will be a little cooler with Houston only reaching 99 degree F on Monday July 26, but then showers coming through on Tuesday June 27, and temperatures will only reach a high of ~95 degrees F for the balance of the week. Wind generation has declined over the past week with average wind loads declining from ~12 GW late last week to 5-6 GW for this current week of July 26 and output dropping to 2 GW or less in midday periods (1 p.m. to 2 p.m. CST).    
  • The heat ridge in the West continues to dominate the weather models with heat still focused across the interior Northwest while the East will likely continue to see a variable weather pattern with any sustained heat absent at this time through the first week of August. 
  • Last Thursday (July 22), the PUCT chairman Peter Lake and ERCOT’s interim president and CEO Brad Jones held a joint press conference to reassure Texas residents that ERCOT and the PUCT were taking steps necessary to ensure system reliability as we approach August and peak summer conditions in ERCOT. Third party weather data shows that population-weighted average high temperatures average 90.5 degrees F in August vs 88.1 F for June and July so ERCOT is approaching peak heat in late July through mid-August. Brad Jones noted that ERCOT had for conducted its first set of 30 site visits (all of which had experienced issues in February) to ensure plants had implemented their weatherization measures. The PUCT earlier this month ordered ERCOT to "operate the grid more conservatively" and ERCOT's measures include measure to have 6,500 MW of generation reserves during peak hours, via additional ancillary services. CEO Jones stated "We are operating the grid in a more reliable manner than we have ever done before, we are buying more ancillary services [reserves] than we have in the past. We are also releasing those ancillary services quicker to the market.” PUCT Chairman Lake commented that ERCOT had in the past used the higher real-time prices driven by operating reserve demand curve (ORDC) charges to operate in a "crisis-based business model" as reserves dropped to critical levels near 2 GW that would trigger the $9,000/MWh price cap. Chairman Lake commented that "We have completely turned that model on its head, deploying more reserves sooner – 180 degrees different from how we’ve done business before.” 

CAISO, Desert Southwest and Pacific Northwest Energy Summary

  • Both the power and gas grids are running with sprained ankles this week. As noted in our last update, the 3,100 MW intertie that runs from northern Oregon to Los Angeles is derated to zero for maintenance this week. Some light congestion has shown up in index prices as the derate impacts the SP15 zone and forces the pull of supply from NP15 and the pricier DSW hubs; this premium could increase if forecasted heat appears. Also, in Monday’s morning updates, the SoCalGas caverns were showing 79 Bcf in the tank, putting storage at about 95% capacity, severely limiting their ability to accept further gas injections as operators need to maintain some empty tank space for normal operations. If the heat or fire-related causes don’t force additional thermal generation to run, the molecules will start to back up onto the Transwestern, Kern and El Paso pipelines, weighing heavily on August basis prices.
  • While fire crews are making slow progress on containment of the Bootleg fire in southern Oregon, the fast-moving Dixie Fire a few hundred miles north of Sacramento continues to rip through mostly unpopulated forests at a vicious pace and was nearing 200,000 acres when we went to press. Ten days after it broke out in remote Butte County, Dixie is now California’s largest wildfire of the season. The balance of the week forecast is ominous with heat predicted to return later in the week, hampering fire efforts, increasing loads, and potentially bringing thunderstorms to the state. Some of the storms may be of the desert monsoonal variety that are packed with lightning but little rain -- not a good combination when all ground vegetation in the region basically qualifies as kindling these days. Both the gas and power grids remain susceptible to sudden curtailments if the wildfires or firefighting operations begin to encroach upon key import lines.
  • Shortly after the start of the Dixie Fire, PG&E filed to the CPUC that its equipment may have been the cause, citing that a worker investigating a power outage in the area found two blown fuses and fire on the ground near the base of a tree thought to be ground zero. Soon to follow will be the massive investigation, competing expert opinions, court challenges and regulatory hearings. Two days after PG&E’s disclosure, they made front page news again, announcing that they plan to bury 10,000 miles of power lines to reduce the possibility of the lines sparking future wildfires. According to PG&E, they operate roughly 25,000 miles of overhead power lines in the State's highest fire-threat areas, 40% of which the utility said it will move underground. Details on the proposal were scarce, and the utility provided no timeline for the project or how much it would cost. However, in a separate briefing, PG&E CEO Patti Poppe said, “We do see a potential range of $15 to $20 billion as a starting point." In 2019, the latest data that we were able to track down, PG&E spent about $1 billion in total operating its T&D system, including new investment, O&M, and wildfire mitigation measures. PG&E customers might want to start inching their budgets higher for the foreseeable future.

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Questions? Please reach out to our Commodities Management Group at CMG@constellation.com.