In the U.S., total generating capacity increased 10.8 GW in 2014, compared to a net loss of 3 GW of mostly coal and nuclear units in the year before.
“Substantial coal retirements began in 2012 and continued into 2014, however the 2014 decrease in net coal capacity was lower than that of the previous two years,” said a March 19 market report from Federal Energy Regulatory Commission staff. “Greater coal retirements are expected in 2015, largely due to the April effective date of the Mercury and Air Toxics Standards requirements, with natural gas providing the bulk of capacity replacements given its economic advantage.”
The largest year-on-year change between 2013 and 2014 came from natural gas capacity additions, which rose by 7.7 GW in 2014, compared to a gain of 1.9 GW in 2013. Net wind installed capacity increased by 5 GW in 2014, driven in part by the renewal of the Federal Production Tax Credit. Net utility scale solar capacity additions, which had grown dramatically from 2011-2013, plateaued in 2014 at nearly 4 GW.
Electricity average spot prices rose across the country in 2014, primarily driven by high prices in the first quarter due to the “polar vortex” effect. Natural gas remained a major driver of electricity prices, with regional prices reflecting, in part, variations in natural gas prices, the report noted. The largest increases were in the PJM Interconnection region, where average on-peak day-ahead prices at the Western Hub rose 38% due to price spikes in the first quarter. Prices in the Pacific Northwest, where increased hydro generation kept prices down, were the lowest in the country. The California ISO had some of the lowest price increases in the country with average on-peak day-ahead prices rising by 17%. Prices remained modest in the Southeast throughout the year, averaging $42/MWh at the “Into Southern” pricing point.
Nationally, electricity demand remained flat compared to 2013. Residential and commercial demand rose slightly driven in part by the extreme weather in the first quarter, while industrial demand declined. Energy efficiency measures and growth in behind-the-meter generation, such as rooftop solar, helped moderate the growth in electricity demand at utilities.
Compared to last winter, natural gas prices this winter have been lower and less volatile, notwithstanding the fact that natural gas demand in January and February 2015 was 2% higher than for the same period in 2014. Driving this increase was a 13% jump in gas used for power generation. Yet, despite higher demand, natural gas prices had fewer and smaller spikes than in 2014.
The Henry Hub spot price averaged $2.91/MMBtu for January and February 2015, down 44% from the same period in 2014. Prices at major hubs throughout the country were lower than last year. January and February prices in 2015 were below 2014 by an average of 41% in both Boston and New York City, 46% in Southern California, and 65% in Chicago. Several factors accounted for the lower prices and lower peaks, including increased production, new pipeline capacity moving supplies from producing to market areas, fewer and less widespread pipeline disruptions, and better gas-electric coordination.
In addition, imports into Northeast liquefied natural gas (LNG) terminals, including Cove Point in Maryland, and Everett and Northeast Gateway near Boston, averaged 94 Bcfd this winter, 45% above the 2013-2014 winter. Furthermore, this past winter the incidences of extreme cold weather came later in the season, when storage inventories were still robust and market participants were less concerned about having sufficient supplies to see them through spring, said the report.
FERC’s Office of Enforcement’s Division of Energy Market Oversight presented this 2014 State of the Markets Report at the commission’s March 19 meeting.