Day-ahead, on-peak power prices at the Massachusetts Hub went slightly above $200 per megawatthour (MWh) during a brief cold spell in mid-December 2013 and up to $237.75/MWh during the early January freeze (see first graph above). These prices were mainly driven by corresponding movements in natural gas prices as the demand for natural gas for both power and heating led to full use of natural gas pipelines in the region and a scarcity of supply. Prices at the Algonquin Citygate trading point in Massachusetts, which normally remain around $3-$6/MMBtu during unconstrained periods, reached slightly over $30/MMBtu in mid-December 2013 and were up to $38.09/MMBtu in early January.

According to the North American Electric Reliability Corporation's (NERC's) annual winter reliability assessment, New England faces essentially the same constrained natural gas supply situation as it did last winter. The Independent System Operator of New England (ISO-NE), the grid operator for New England's electric system, has implemented a number of short-term measures to mitigate the effects of fuel supply risks this winter, including a new Winter Reliability Program, which solicited bids from oil-fired, dual-fuel (for more information on dual-fueled generators see EIA's Form EIA-860), and demand response resources to provide extra capacity to the system. The program requires oil-fired generators to maintain oil inventory on-site and dual-fuel generators to demonstrate timely gas-to-oil switching capability.

Natural gas supply into New York City remained constrained during colder-than-normal temperatures as evidenced by the price spikes in mid-December and early January. Spot natural gas prices reached as high as $47.80/MMBtu, higher than in New England—likely because New England was able to meet part of its natural gas demand with imported supplies of liquefied natural gas (LNG) and Canadian offshore natural gas production. Power prices hit $233.59/MWh on January 8.

Several major natural gas pipeline projects came in service ahead of the 2013-14 winter, including the New Jersey to New York expansion of the Texas Eastern Transmission and the Algonquin Gas Transmission pipelines, which will deliver additional natural gas supplies, particularly from the Marcellus region, into the New York City area, the main demand center of the New York electric system. Despite these developments, natural gas supply into the New York region remains constrained during high demand periods.

An additional strain on the New York system came from the unplanned outage of Entergy's Indian Point Unit 3 nuclear reactor located near New York City, which went offline on the evening of Monday, January 6. The loss of the 1,044-megawatt (MW) capacity baseload unit required additional higher-cost generators to be brought on line, which put further pressure on power prices.

In preparation for potential natural gas supply shortages this winter, the New York Independent System Operator (NYISO), New York's grid operator, is requiring dual-fuel generators (for more information on dual-fueled generators see EIA's Form EIA-860) to share fuel-related information with NYISO, including on-site fuel inventory levels and time requirements for fuel switching and fuel resupply. NYISO has also implemented a new extreme cold weather event procedure to request information on gas and alternate fuel supplies throughout the operating day when needed.

The PJM Interconnection's (PJM's) electric system, which covers the broader Mid-Atlantic region and parts of the Midwest, broke its previous record winter peak demand (136,675 MW in 2007) two times on January 7, hitting a new peak of 141,312 MW. This level was about 7% higher than PJM's forecasted peak.

The extremely cold temperatures, combined with unexpected outages of power plants and a natural gas compressor station in western Pennsylvania, pushed day-ahead, average on-peak power prices up to $268.84/MWh and natural gas spot prices to $33.53/MMBtu. Real-time, hourly prices during January 7-8 reached as high as the $800/MWh range with 15-minute periods of more than $2,000/MWh.

Unlike in New York and New England, these price movements went far above prices seen in PJM last winter. PJM relies to a lesser extent on natural gas for power than the Northeast, and the atypical weather and unexpected power plant outages likely played a bigger role in the price spikes than persistent natural gas supply constraints. According to PJM's preliminary report, there were nearly 40,000 MW of forced outages on the evening of January 7 and morning of January 8, far more than encountered during the top six winter peak demand days of the past five years, which saw, at most, about 16,000 MW of forced outages. PJM estimates around 6,000 to 9,000 MW of the January 7-8 outages were due to natural gas curtailments.

In response to the extreme weather conditions, the Federal Energy Regulatory Commission (FERC) granted PJM a temporary emergency waiver to allow it to exchange nonpublic information with interstate natural gas pipelines about gas availability for power generators and generation schedules. FERC had ruled in November 2013 to allow interstate natural gas pipeline and electric system operators to share nonpublic operational information to facilitate natural gas and power reliability. However, PJM had not completed implementation of the ruling by the time the January weather hit.