Posted January 12, 2018
U.S. infrastructure promises to be a top priority for the Trump administration in 2018. In his State of American Energy keynote address, API President and CEO Jack Gerard highlighted how resistance to infrastructure development has left New Englanders with some of the highest electricity costs in the nation, particularly so through extreme winters.
In December and early January, New England’s wholesale electricity prices averaged nearly three times those of equally-frigid Chicago. Over the past four years, New England’s wholesale electricity prices averaged 24 percent higher than those in Chicago and were nearly three times more volatile.
While price volatility provides signals that are important to the efficiency of wholesale energy markets, the disproportionate rise of the region’s winter prices stems from New York’s beggar-thy-neighbor policies, which blocked planned, much needed and federally approved new pipeline capacity. Politics and policies that accentuate high and volatile natural gas and electricity prices, not only in New York but also in New England, harm consumers and undermine regional investment, jobs and competitiveness. It is high time that New York and New England take a collective and collaborative approach to solve the problems with permitting and incentives that utilities have to contract longer-term for natural gas.
In the first week of January, contrasting headlines proclaimed natural gas got bomb-cycloned in the new year with daily New York (Transco Zone 6) prices spiking as high as $140 per million BTU (MMBtu). Yet the U.S. Energy Information Administration (EIA) reduced its 2018 price forecast to $2.88/MMBtu at Henry Hub, Louisiana. The low Henry Hub price represents a major natural gas production region and liquid trading hub. By contrast, the high New York City price reflects a major natural gas production region that could have ample low-cost natural gas, except that it is stymied by a lack of effective political and regulatory mechanisms to enable responsible resource and infrastructure development.
The rise in natural gas prices has reverberated through electricity markets. For example, the chart below compares wholesale electricity prices for December through early January between Boston and equally-frigid Chicago. Chicago is amply supplied by natural gas pipelines that flow from the U.S. Gulf Coast, Appalachia, and Rockies regions plus Canada. Based on data from Bloomberg, wholesale electricity prices between Dec. 1 and Jan. 8 averaged $31.31/MWh and had a standard deviation of more than $35/MWh. By comparison, Boston’s prices averaged $85.36/MWh with a standard deviation of $67.64/MWh over the same period. New England utilities thus paid more than twice as much for electricity and experienced about twice the price volatility.
Chart 1. Regional wholesale electricity prices – 12/1/2017 to 1/8/2018
Over the past four years, from January 2014 through the first week of January 2018, New England’s wholesale electricity prices averaged 24 percent higher than those in Chicago, and daily prices were nearly three times more volatile. This period includes two years with extreme winter weather events (2014 and 2018) and two years without such extremes (2016 and 2017). New England’s wholesale electricity prices were markedly higher and more volatile than those of Chicago in years with extreme winters.
The region’s relatively high and volatile energy prices are rooted in the inadequacy of natural gas infrastructure to meet peak seasonal demand and, to a lesser extent, the long-standing shift in market incentives toward utilities’ reliance mainly on spot markets and very short-term contracts for gas. Specifically, natural gas-fired generators set the region’s electricity price about 75 percent of the time. Gas-fired power generation in the Northeast census region rose by 53 percent between 2007 and 2017, according to the EIA short-term energy outlook. Natural gas-fired generation contributed 38.6 percent of the region’s electricity in 2017, compared with 24.3 percent in 2007, and gained market share due to its abundance, low cost and efficient and clean-burning environmental properties.
However, natural gas pipeline constraints have hampered utilization at peak times. For example, ISO New England recently highlighted that four gigawatts of natural gas-fired generation capacity – 24% of the region’s gas-fired net winter capacity – was at risk of not being able to get fuel when needed. Much of the constraint is due to New York state’s blocking the Constitution and Northern Access Pipeline projects, among others.
To compensate for New York’s un-neighborly policies, ISO New England performed triage for the past five years with its Winter Reliability Program, which has been paying as much as $32 million per year for reserves of oil and liquified natural gas (LNG) as back-up fuels. Beginning this year, ISO New England will change to a Pay for Performance plan that alters how a generation resource’s capacity payments are calculated. These costly plans might not be needed if economic rationality and the overall region’s welfare were top of the New York state of mind.
Raising Cain in New York about high natural gas and electricity prices generally has not resonated with the electorate since most consumers are insulated from wholesale price spikes. Industrial firms and utilities are the ones that pay these peak prices, and they have the ability to employ sophisticated natural gas portfolio and risk management strategies. Natural gas price volatility is a business risk that these consumers accept, but the overall retail cost of electricity is higher in New York by as much as 50 percent above the national average; the same holds true for Boston.
From an economic planning perspective, wholesale price variability goes hand-in-hand with efficient price signals and discovery in deregulated electricity markets. Importantly, the system’s early January response was reliable but could have been made easier for consumers to afford, as the prices which resulted were extreme. New York and New England must take a collective and collaborative approach to solve the problems with permitting and incentives that utilities have to contract longer-term for natural gas. Given policy alternatives that provide positive incentives and enable investment and infrastructure development, lower prices, and lessen price volatility, it should be a dominant strategy for the region to pursue outcomes that are less risky, better facilitate market operations and ultimately provide a win for the region’s consumers and economy.
ABOUT THE AUTHOR
Dr. R. Dean Foreman is API’s chief economist, specializing in energy and global business. With a Ph.D. in economics from the University of Florida, he came to API from Saudi Aramco Strategy & Market Analysis in Dhahran, where he managed short-term market monitoring and the long-term oil demand outlook. Foreman has more than 20 years of industry experience in corporate strategic planning, forecasting, finance / risk management and regulatory policy at ExxonMobil, Talisman Energy and Sasol North America.