The limited availability of non-firm gas supply during periods of peak winter demand is driving significant increases in spot natural gas prices in New England. Spot market natural gas prices have historically been priced at a premium, but this premium has increased in recent years. This premium, or difference, between the price in New England and the Henry Hub, a location in Louisiana considered representative of the general U.S. market, is referred to as the “basis differential.”
The number of days in which the New England natural gas price differential to the Henry Hub was greater than $2/MMBtu increased from 51 days in the winter of 2010/11 to 65 days in winter 2012/13 and to 77 days in winter 2013/14.73 The rising frequency of days with basis differentials exceeding $10/MMBtu is even more impressive. Whereas basis differentials rarely exceeded $10/MMBtu before 2012, the basis differential exceeded $10/MMBtu on 25 days in 2012/13 and 28 days in 2013/14.74 This considerably raised average delivered gas prices in New England, affecting generators and wholesale electricity prices.
Figure 8 shows how monthly average basis differentials have increased over time, particularly in
the winter: from only about $1-3/MMBtu in winters prior to 2012/13, to about $8/MMBtu in 2012/13, and to almost $14/MMBtu in 2013/14; this also lifted annual average basis differentials from about $1/MMBtu before 2013 to about $3/MMBtu in 2013. Futures prices for the next year (March 2015 through February 2016) are similarly around $3/MMBtu on average.75
73 Based on daily spot natural gas data compiled by SNL Financial LC. 74
Sussex Economic Advisors, LLC. Maine Public Utilities Commission, Review of Natural Gas Capacity Options. Framingham, MA: Sussex Economic Advisors, LLC., 2014, available at http://www.sussex-
advisors.com/wp-content/uploads/2014/03/Maine-PUC-Final-Report-February-26-2014.pdf.
75
This IRP projects basis differentials using basis swaps futures as of October, 2013.
Figure 8
Algonquin Citygate Monthly Basis Differentials76
The real-time “locational marginal price” (LMP) indicates the cost of buying electricity in a certain area of New England at any given time. In New England, all generators are paid the price of the marginal generator needed to supply load. Natural gas is the primary fuel on the margin in New England when gas is available. As a result, day-ahead and real-time LMPs typically follow the price of gas. When gas pipelines are not constrained, the price of oil is significantly higher than the price of gas. Due to pipeline constraints in the winter of 2013/14, however, the price of gas was often double the price of oil or even higher, as shown in Figure 9.77 This resulted in oil units running more this past winter than in the past, setting the locational marginal price for all generators in more hours. In the winter of 2013/14 there was approximately 11,000 MW of gas fired generation in New England with capacity supply obligations. But on the coldest days, only about 3,000 MW of gas fired generators operated during the peak hours.
76 Actuals are based on daily spot Algonquin Gates and Henry Hub natural gas data compiled by SNL Financial
LC. The 2014 NYMEX basis differentials are based on an average of 30 trading days (9/16/2013-10/15/2013) for the 2014 delivery year. The 2015-2016 NYMEX basis differentials are based on an average of February, 2015 trading days for delivery periods March through December of 2015 and January through February of 2016.
77 Ibid.
Figure 9
Real-Time LMP, Gas Prices, and Oil Prices in 3-month Intervals (March 2003 – March 2014)
Wholesale electric prices were high and stayed high throughout the 2013/14 winter. During the winter of 2013/14, 64% of the average daily real-time prices were above $100, in contrast to 28% in the winter of 2012/13, which was also higher than preceding years. For the first time in ten years, average daily real time electric prices exceeded $250 (25 ¢/kWh). This occurred nine times this past winter. Figure 10 shows how in the winter months of January and February the average real-time LMP in the region has risen 100% since January 2011.78
78 Brandien, Peter. Cold Weather Operations: Federal Energy Regulatory Commission. ISO New England’s
Winter Operations Technical Conference. April 1, 2014.
Figure 10
Daily Average Locational Marginal Prices (January – February) from 2003 to 2014
The winter of 2013/14 was one of the coldest winters in recent history. The ISO-NE Winter Reliability Program was critical in maintaining reliability during that winter, but electric prices still rose and resulted in a dramatic increase in rates to electric customers. The Winter Reliability Program was intended to improve reliability but not suppress electric prices, though it did have some impact. Prices still rose to record levels and operational challenges led to significant uplift payments. As generation units were needed and ran out of merit, they received these uplift payments to compensate them for their higher costs. Uplift payments increased from $20.4 million in December 2013 to $73.3 million in January 2014.
The total wholesale generation cost of serving electric load in New England for the winter of 2013/14 was over $5 billion, compared to $5.2 billion for all of 2012. The winter of 2012/13 also saw days with high gas prices due to constrained pipes, which caused a higher-than-normal cost in that year of $2.9 billion. Because there is a time lag between wholesale cost and the prices retail customers pay in rates, many consumers in New England did not see the bill impact of these wholesale costs until late 2014. The rate increases are staggering: Eversource’s residential Rate 1 increased from 9.99 ¢/kWh in the fall of 2014 to 12.63 ¢/kWh in January 2015 through
June 2015. UI’s residential rateincreased from 8.67 ¢/kWh to 13.31 ¢/kWh for the first six months of 2015. This represents a 26% increase for Eversource and approximately 54% increase for UI. Some of the other New England states have seen even more dramatic increases to the generation charge, largely attributable to the infrastructure constraints in the natural gas system.