Extreme ERCOT volatility strikes this week under a prolonged heatwave paired with low wind generation. ISO-NE will pay baseload generation for fuel inventory during winter, natural gas prices slip downwards, report finds deregulation in OH responsible for billions in savings.
The September 2019 NYMEX Henry Hub forward contract decreased -$0.15 (-6.7%) from the previous Wednesday, reaching $2.083/MMBtu. The price of the 12-month strip averaging September 2019 through August 2020 futures contracts decreased -$0.12 (-5.0%) to $2.304/MMBtu.
Northeast natural gas prices fell in demand markets. Boston’s Algonquin Citygate prices decreased -$0.17 (-7.7%) to $2.05/MMBtu last Wednesday. Transco Zone 6 NYC prices fell slightly, decreasing -$0.09 (-4.2%) from $2.16/MMBtu to $2.07/MMBtu.
Pennsylvania’s Dominion South decreased -$0.06 (-3.1%) to $1.88/MMBtu. Tennessee Zone 4 Marcellus spot prices decreased -$0.08 (-4.3%) to $1.78/MMBtu.
California prices have been mixed since last week. SoCal Citygate prices increased $0.07 (2.4%) to $3.02/MMBtu last Wednesday. Prices at Northern California PG&E Citygate decreased, falling -$0.20 (-7.3%) to $2.53/MMBtu.
For the NEMASSBOST zone in ISO-NE, the 12-Month ATC strip decreased -$0.36 (-0.9%) to $39.61. The 24-Month ATC strip decreased -$0.19 (-0.5%) to $40.42 and the Cal '20 ATC strip decreased -$0.26 (-0.4%) to $40.47.
For the NYC (J) zone in NYISO, the 12-Month ATC strip decreased -$0.31 (-0.8%) to $37.44. The 24-Month ATC strip decreased -$0.07 (-0.2%) to $37.90 and the Cal '20 ATC strip decreased -$0.16 (-0.4%) to $38.02.
For the PEPCO zone in PJM, the 12-Month ATC strip decreased -$0.29 (-0.9%) to $33.19. The 24-Month ATC strip decreased -$0.06 (-0.2%) to $32.89 and the Cal '20 ATC strip decreased -$0.03 (-0.1%) to $32.81.
For the HOUSTON zone in ERCOT, the 12-Month ATC strip increased $4.39 (13.3%) to $37.51. The 24-Month ATC strip increased $2.69 (7.9%) to $36.66 and the Cal '20 ATC strip increased $1.4 (4.0%) to $36.58.
The upcoming Price to Compare for Maryland’s Potomac Edison General Service Small Commercial Type I 0-700 kWh and >700 kWh calculated blend rate class (GSCS) is approximately $0.09546/kWh, in effect from September 1, 2019 through September 30, 2019. This rate is a -1.8% decrease from the current rate of $0.09717/kWh for the August 2019 price period.
Headroom is now available for the 1, 3, 6, 9 and 12 month terms, with $0.02630/kWh and $0.02763/kWh of likely headroom for the 9 and 12 month terms, respectively.
Over the last week, the APS ATC 12-month strip increased slightly, rising 2.1% to finish at $30.71/MWh yesterday. This time last year, the strip was trading at $35.82/MWh, which is approximately 16.6% higher than this year.
Since the beginning of the year, the ATC strip has reached a high of $38.76/MWh on January 17, 2019 and a low of $29.68/MWh on July 5, 2019.
For the week ending August 2, the EIA reported net injections from storage of 55 Bcf, which is higher than last year’s net injections of 46 Bcf for this week and higher than the 5-year (2014–18) average net injections of 43 Bcf.
Working natural gas in storage totaled 2,689 Bcf, which is 343 Bcf (14.6%) more than last year’s working gas totals of 2,346 Bcf at the same time and 111 Bcf (-4.0%) lower than the 5-year (2014-2018) average of 2,800 Bcf. Total working gas is within the five-year historical range.
Supply and Demand
Average total supply of natural gas increased 1% week/week. Dry natural gas production was up 1% while net imports with Canada decreased 9%.
Total US consumption of natural gas increased 1%. Consumption for power generation was up 3% week/week, industrial sector consumption decreased 2%, residential-commercial consumption increased 4%, and exports to Mexico increased 1%.
US LNG exports decreased week/week, with eight vessels departing US ports for a combined 29 Bcf.
ISO New England’s Inventoried Energy Program has gone into effect after FERC failed to act to block it. The initiative will compensate baseload generation, including coal and nuclear, for having on-site fuel supplies during winter months for the 2023-2024 and 2024-2025 capacity years. ISO-NE hopes this compensation will improve system reliability during strained winter periods, while opponents fear that the subsidized resources will depress capacity clearing prices and prevent unsubsidized resources from clearing. Additionally, the program does not compensate offshore wind resources, which enhance system reliability during cold weather according to an ISO-NE report released last December. The program costs will be allocated to load-serving entities.
A study by The Ohio State University and Cleveland State University found that electricity ratepayers in Ohio saved a total of $8.7 billion from 2016 through 2018 due to deregulation of retail electricity. These savings are realized through retail shopping, or customers finding a lower rate from a competitive retail electric supplier than the utility price-to-compare, and through lower prices in Standard Service Offering (SSO) Auctions, competitive auctions in which utilities procure electricity for their default service offering. According to the researchers, electricity prices have fallen in deregulated Midwestern states like Ohio and Pennsylvania while they have risen in neighboring regulated states like Indiana and Michigan. Importantly, the study claims that these savings may be jeopardized by subsidies to uncompetitive utility generation resources, which are funded through customer surcharges.
Above normal heat is forecasted to take hold over the bulk of the lower-48 in the 8-14 day window. A higher degree of probability for anomalous heat is in the Mid-Atlantic, New York, and New England, driving bullish risks to eastern power markets. Above normal precipitation risk also takes hold of most of the country, though the northeast is more likely to see normal rain levels.
Texas will share in the heat blast, though the more intense temperature anomalies will take place in the western half of the state. The key here might be the lack of rain, with exceptionally dry conditions allowing for elevated demand risks in ERCOT.