ISO New England monitor reports competitive markets in Q4 2014

The Internal Market Monitor for ISO New England said in a report filed Feb. 18 at the Federal Energy Regulatory Commission that it has analyzed the performance in the fourth quarter of 2014 of the region’s wholesale electric energy, ancillary services, and capacity markets using supply offers, demand bids, fuel prices, market results, and other economic data.

Overall, market prices reflected the cost of providing energy, and energy market outcomes were competitive, the report said. In a summary of fourth quarter developments, the report said:

  • The total wholesale market costs in the Reporting Period were $1.57 billion, a 32% decrease compared to the same period in 2013 (Q4 2013).
  • Lower natural gas prices were the primary driver for the decrease in total energy costs in the Reporting Period. Natural gas prices during the Reporting Period averaged $5.02/MMBtu. This is a 35% decrease from Q4 2013.
  • Day-Ahead Energy Market prices during the Reporting Period averaged $40.90/MWh at the Hub, and Real-Time prices averaged $39.27/MWh. Day-Ahead prices were 29% lower than Q4 2013, and Real-Time prices were 35% lower than Q4 2013.
  • Total real-time reserve payments were $8.0 million in the Reporting Period, a 60% decrease from Q4 2013, and Regulation payments totaled $5.8 million, a 10% decrease from Q4 2013.
  • The ISO implemented Energy Market Offer Flexibility (EMOF) changes on December 3, 2014. EMOF allows market participants to vary energy market offers by hour and to change offers in real time during the Operating Day. This functionality improves a market participant’s ability to reflect in its energy market offer the cost of obtaining fuel in real time. Offers that are more reflective of actual fuel prices improve energy market price signals and permit a better match between those prices and the cost of procuring fuel in real time.

In the fourth quarter, the average real-time Hub price was $39.27/MWh, down 35% from $60.24/MWh in Q4 2013. Price differences among the load zones stemmed primarily from marginal losses, with little zonal congestion. Congestion was restricted primarily to smaller, more transient load pockets that formed when transmission or generation elements were out of service. The Maine zone had lower average pricing ($37.22/MWh) than other load zones, as it is an export-constrained area with lower cost generating resources than other load zones.

Units burning natural gas were marginal for 75% of the pricing intervals in the fourth quarter, followed by pump storage units (including pumping demand), which were marginal in 12% of pricing intervals. Coal units were marginal in 7% of the pricing intervals. Units burning oil, diesel, jet fuel, or wood along with traditional hydro units were marginal in the remaining pricing intervals.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.