The U.S. Energy Information Administration reported last week that natural gas in storage increased by 118 Bcf. There was an injection for the same week last year of 75 Bcf while the five-year average injection is 81 Bcf. Total U.S. natural gas in storage stood at 3,288 Bcf last week, 13.9% less than last year and 5.1% lower than the five-year average for this time of year.
Last Thursday, officials from Connecticut’s Department of Energy and Environmental Protection (DEEP) held a virtual press conference to discuss the state’s Integrated Resources Plan (or “IRP”), initially released as Connecticut's first comprehensive analysis of how it could successfully move towards a 100% carbon free grid by 2040. The IRP, greenlighted by CT Governor Ned Lamont in 2019, casted a positive light on the state’s ability to achieve its goal and also addressed the critical role that the Millstone Power Plant plays in moving forward.
DEEP’s report identified multiple pathways for CT to achieve 100% clean energy by 2040, and all scenarios require a significant ramp up in deployment of distributed resources. However in one modeled scenario, in which the Millstone Power Plant is extended 11 years past its current 2029 retirement date, the IRP found the milestones would be met at a reduced rate payer burden, and deployment of distributed resources could occur at a less aggressive rate.
Millstone’s two nuclear units, which currently generate 47% of the state’s electricity and are low-carbon sources, first went online in 1975 and 1986. In 2019, the state negotiated a 10-year deal with the power plant to ensure its continued operation as the state entered the early phase of its energy transition. Millstone, which is owned by the Virginia-based utility Dominion, receives a fixed rate of approximately $0.05 per kWh in that deal. The report suggests the importance of the nuclear plant will extend past the current 10-year agreement in place.
Currently, the IRP found that Connecticut ratepayers currently support more than 600,000 MWh/year of grid-scale renewables and more than 9 million MWh/year of nuclear resources, putting it on track for 92% clean electricity by 2025. But the potential exit of Millstone from the generation mix would leave a massive hole in the state’s clean energy supply, which would need to be made up by, what the report identifies as, hydropower from Canada brought in my new high voltage transmission lines.
The IRP does indeed stress the need for market reforms so that Connecticut can achieve its clean energy goals in a pathway that is fair to its ratepayers. The recent 10-year contract put forward for Millstone was negotiated by the state on behalf of ratepayers, and therefore made outside of current frameworks. The IRP stated that Connecticut must “advocate for and pursue wholesale energy market reforms so that clean energy resources are deployed efficiently, cost-effectively, and costs are spread equitably.”
DEEP Commissioner Katie Dykes said that ISO-NE has made progress on the New England states’ concerns around transmission planning and worked to eliminate the minimum offer price rule (MOPR) with input from NEPOOL stakeholders. While government shot-calling is assumed in the IRP, Dykes believes these “incremental changes” – such as annual open Board of Directors meetings focused on wholesale electricity markets and system planning - by ISO-NE signal that the RTO wants to engage more with the state administration. She says that governance concerns also relate to ensuring broader accessibility to and transparency in ISO-NE’s processes for “all stakeholders and affected ratepayers in the region.”
Last Thursday, the Public Utility Commission (PUC) of Texas voted to approve plans by ERCOT to securitize up to $2.9 billion of extraordinary power costs associated with the Winter Storm Uri this February. Of the total amount, $2.1 billion is distributed to "uplift balances" with the rest $800 million being distributed to "default balances." The bonds are to carry maturities of up to 30 years.
The approved funds were approved to ease liquidity problems and keep companies afloat, for wholesale market participants who incurred extreme costs during the winter weather event earlier in the year. Market participants that receive a pro-rata allocation of the uplift securitization fund must issue refunds for uplift charges passed on to and paid by customers for that period. They must also incur and on-going uplift charge that will be used to pay for the securitization. Suppliers that opt-out of the securitization effort will be required to pay all invoices in full for the period of emergency but will not incur the ongoing fee.
The February winter storm was a disaster for the state and its constituents and resulted in extreme energy expenses because of spikes in wholesale power prices and natural gas prices. Since Winter Storm Uri resulted in outages at many of the generating resources within the ERCOT region, and the demand for power exceeded supply for several days during the storm, electricity regulators set power prices at the maximum rate — $9,000 per megawatt-hour — for several days in hopes that market dynamics would encourage more electricity to be supplied, yet ERCOT was unable to fully pay certain wholesale market participants who were due payments from ERCOT for the power they produced during the storm. On the same day, the Texas PUC also formally issued for comment a proposal for publication that would lower the high system-wide offer cap in ERCOT to $4,500 per MWh, from the current $9,000 per MWh, by January 1, 2022. Commissioners reiterated that the intent is to adopt the changes prior to the winter season while broader market design changes continue to be developed.
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