Report finds competitive markets in 2014 in ISO New England region

Wholesale power markets in New England operated competitively last year, with prices that reflected the cost of production, according to the 2014 Annual Markets Report issued May 20 by the Internal Market Monitor (IMM) of ISO New England, the operator of the region’s bulk power system and wholesale electricity markets.

The average real-time price of wholesale electric energy in 2014 rose about 13%, to $63.32 per megawatt-hour (MWh), largely driven by higher fuel costs in the first quarter when extreme cold weather increased demand for natural gas, which generates almost half the electricity produced in New England.

Jeffrey McDonald, ISO New England’s vice president of market monitoring, said: “When the cost of the fuel used most often to generate electricity goes up, wholesale power prices rise as well. Overall, 2014 weather was milder compared with 2013, but the extreme cold in January, February and March and the resulting high natural gas and power prices were the main reason for 2014’s higher annual average power price. Lower oil and natural gas prices, combined with mild summer weather that contributed to lower energy usage, and the implementation of several ISO market enhancements that helped improve both reliability and market efficiency, brought generally lower wholesale electricity prices during the rest of the year.

“The wholesale electricity price trends we saw in 2014 tracked the fluctuations in fuel prices, which is what we expect from competitive markets. In fact, our structural measures of competitiveness for the near-term markets indicated a high degree of competitiveness among participants who provided energy and operating reserves in 2014,” McDonald said.

Key findings of the 2014 Annual Markets Report include:


  • Wholesale electricity market value – The total value of the region’s wholesale electricity markets, including electric energy, capacity, and ancillary services markets, rose about 12%, from about $8.8 billion in 2013 to about $9.9 billion in 2014. Electric energy comprised $8.4 billion of the total in 2014.
  • Wholesale energy prices – The average real-time price for wholesale electric energy rose 13%, from $56.06/MWh in 2013 to $63.32/MWh.
  • Fuel costs – The average price of natural gas, which set the wholesale electricity price in 70% of the hours in 2014, rose 15% last year, from $6.97 per million British thermal units (MMBtu) in 2013 to $7.99/MMBtu in 2014.
  • Consumption – At 127,138 gigawatt-hours, total electricity usage in New England was 2.0% lower in 2014 than in 2013.
  • Reliability commitments – Resources can receive payments, in addition to energy market revenues, to cover their costs if they are needed to help ensure the reliability of New England’s power system. These additional payments increased 10% to $173.7 million in 2014; about 62% of the payments stemmed from the need to operate more expensive generation during extreme cold weather in the first quarter of 2014.
  • Reserve prices – Additional resources are maintained in reserve at all times so the system can recover from the unexpected loss of a resource. Reserve payments fell from $54 million in 2013 to $38.6 million in 2014. Reserve payments may be incurred during resource outages, extreme weather, or other events for which the frequency and magnitude vary each year.
  • Capacity – The cost of capacity in 2014, resulting primarily from the third and fourth Forward Capacity Market (FCM) auctions held in 2009 and 2010, respectively, rose by 1% to $1.06 billion. The report notes that the first seven auctions cleared with excess capacity but the eighth auction, conducted in February 2014 for the 2017-2018 capacity commitment period, concluded with a slight shortfall after 3,135 megawatts (MW) of existing resources announced plans to retire in 2017. The retirements triggered administrative pricing rules designed to protect consumers from higher capacity prices while still providing incentives for developers to build and retain resources.
  • Demand resources – Participation in the FCM by demand-side resources, which include both energy-efficiency measures and active demand-response resources, increased 19%, from 1,535 MW in December 2013 to 1,821 MW in December 2014. Payments to demand resources providing capacity totaled $90.3 million in 2014, up 3.2% from the $87.5 million paid in 2013.

ISO New England makes progress with gas supply issues

The report noted that one of the most pressing challenges identified in the ISO’s Strategic Planning Initiative has been the region’s reliance on generators fueled by natural gas.

In the 2013 Annual Markets Report, instances were identified when generators fueled by natural gas were not available to produce electricity because natural gas was not available due to a constraint or limitation on the natural gas pipeline system. In tandem, the ISO undertook a number of projects aimed at improving the reliability of generators fueled by oil and natural gas through improved market incentives and market design, and supplemental payments to improve fuel diversity.

For example, the 2013/2014 Winter Reliability Program provided financial incentives to oil-fired generators to maintain on-site inventories. The program also provided incentives to dua-fuel generators capable of burning oil or natural gas to test and maintain their dual-fuel capability. The 2014/2015 Winter Reliability Program, built on the prior winter program, also provided incentives for resources to enter into contracts for liquefied natural gas (LNG) and included additional market monitoring changes designed to provide greater flexibility to dual-fuel resources. By ensuring that oil- and dual-fuel-fired generators had sufficient on-site fuel inventory, and that participating gas generators contracted for liquefied natural gas, the winter reliability programs helped mitigate concerns about the reliance of generators fueled by natural gas on pipeline deliveries of fuel during periods of high natural gas demand and stress on the pipeline system.

The number of reductions in generation availability associated with the availability of natural gas declined in 2014 compared to 2013. This decrease is coincident with the Federal Energy Regulatory Commission’s August 2013 order clarifying the obligations of resources to procure fuel, the changes in the Day-Ahead Energy Market supply-offer timeline that went into effect in mid-2013, and the implementation of Energy Market Offer Flexibility (EMOF) that went into effect in December 2014.

The combination of market fundamentals such as the increased supply of LNG in New England in late 2014, lower oil prices, a mild summer, along with the implementation of a number of ISO-NE initiatives had the expected outcome of increasing reliability during 2014 and lowering electric energy prices after the first quarter of 2014, the report noted.

As part of the winter reliability program package, FERC approved an IMM proposal that dual-fuel generators be exempt from the requirement to justify and verify the use of the higher-priced fuel when oil and natural gas index prices converge—specifically, when the ratio of the generator’s higher-priced fuel index price to its lower-priced fuel index price is less than or equal to 1.75. FERC required that the appropriateness of the ratio be reviewed and that the analysis and recommendations be provided as part of the Annual Markets Report. Notwithstanding the reduction in natural gas price volatility during the winter of 2014/2015, the 1.75 ratio continues to be a reasonable and appropriate indicator of oil and natural gas price convergence and consequently should remain as the exemption threshold, the report said.

Created in 1997, ISO New England is the independent, not-for-profit corporation responsible for the reliable operation of New England’s electric power generation and transmission system, overseeing and ensuring the fair administration of the region’s wholesale electricity markets, and managing comprehensive regional electric power planning.

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.