Across the Midwest and Eastern US and into Canada, the extreme weather events of 2014’s winter tested the regional energy markets in unprecedented ways. Successive polar vortexes swept cold over North America and pushed energy prices to record highs. January 7thsaw PJM’s West Hub price for day-ahead on-peak power traded above $250 per mWh, roughly 5 to 6 times the average day-ahead on-peak price between October and December 2013. The day-ahead price reflects the prices market participants pay for purchasing power in the market a day in advance of when it will be needed. In real-time the price spikes for spot market power were even more vicious, edging over $1500 per mWh in PJM!
And although a culprit, the cold weather alone was not responsible for the price power market’s high over the winter. A shift occurring in the underlying energy supply of the US, particularly in the North East, has had consequential impact on power market economics. Illustrated in Figure 1, by 2040, the Energy Information Administration (EIA) estimates that of all new capacity additions in the US, approximately 40% of those will be Renewable while over 50% will be Natural Gas-fired.
The changing mix benefits the environment because these are low-emissions power sources, but they put new stresses on the gird and the power markets.
The Independent System Operators (ISOs) are essentially tasked with running the grid. The ISOs’ primary functions are to ensure cost effective and reliable power markets—the lights turn on when the switch is flipped, air conditioners are powered when needed, the fridge keeps humming. This consumption of power is referred to as load. In order to meet the constant demand for electricity, the ISOs administer a number of markets which enable them to plan for and balance load and generation in real-time and multiple years in advance. As the markets help the ISOs quantify demand, they also serve the ISO to incentivize power producers to ensure adequate supply plus reserves are on hand day-to-day, hour-to-hour and down to five minute increments. The ISO markets are complex and range from markets for physical power, to rights to access transmission systems, to incentives offered to power plants for simply existing for the times when extra generation is needed.
The market for physical electricity is centered on the Locational Marginal Price (LMP) of power across the different geographies of the ISOs’ territory. The LMP is determined by the cost for the ISO to dispatch the next megawatt needed to meet demand at that location. Units with lower marginal costs will be dispatched first while the plants more costly to operate will not be called upon until needed. As behavior changes across the grid and over the course of any given day, the generation stack—the range of units across fuel types at the ISOs’ disposition to be called upon—requires fewer or more plants at lower or higher cost, respectively. Through its protocols, the ISO keeps tabs on all power sources connected to the grid.
The variance of plants’ cost structures occurs for a host of reasons which cannot be simply characterized, however one of the major cost differentiators relates to the fuel cost for a given plant producing electricity. Renewable plants have relatively low marginal costs because they run on low- or no-cost fuels. Their fuel inputs are intermittent however and thus can be somewhat unpredictable. These plants are generally called upon when they are producing but require other plants with more certain production capabilities to be available alongside them—typically nuclear- or coal-fried pants, and even natural gas-fired plants to an increasing extent. Traditionally, coal plants were the low-cost power source until more recent times. Upward price pressure on coal due to environmental regulation, along with decreased natural gas prices, has led to a shift away from coal-fired plants towards natural gas-fired ones. This switch is the mega trend occurring in the US energy sector as coal plants are retired to make way for natural gas-fired plants being brought on-line in increasingly greater quantities. This has created a shift in the ISOs’ generation mix as demonstrated in Figure 2.
Although the day-to-day marginal costs of power may be decreased as a result of more competitive fuels displacing the more costly ones, the more costly ones are still required for the times when excess generation is required to meet peak demand and ensuring reliability during extreme occasions such as this winter. What was seen across the North East was a calling of the ISOs on the more costly generators to meet the excess demand that spiked on the coldest days of the winter. And as the infrastructure for transporting and delivering natural gas is fixed at a given point in time, competing demands for gas increased constraints across the system. The supply of gas for some plants was limited or in some cases cut all together. The result was that in order to ensure reliability, the ISOs began to dispatch some of the most costly resources in the system.
So while prolific hydraulic fracturing and the shale boom enable a domestic natural gas supply at favorable prices, it has significantly increased the power markets’ reliance on the natural gas industry. This increased reliance has brought to light operational and regulatory concerns that are and need to be addressed for the purposes of continually increasing reliability and smoother market conditions.
Current discussions are being undertaken by the Federal Energy Regulatory Commission (FREC) and the ISO planning committees in order to more closely link the natural gas and electricity industries. The first being pushed by FERC is the synchronization of the daily gas and electric schedules in order to facilitate more seamless coordination between the two industries. The second is the potential requirements placed by the ISOs on natural gas-fired power plants to secure firm gas supply contracts from pipelines and maintain back up fuels. This new obligation would represent a significant change but could have a high impact on the ability of the ISOs to better ensure market stability. Currently power plants operating on natural gas can be subject to supply cuts based on lack of capacity within the existing pipeline infrastructure. And as mentioned before, when these lower marginal cost plants face increased fuel costs or reduced operations, the entire grid pays the price in terms of what units are dispatched by the gird instead. Yet another conversation recently started by energy giant, NRG is aimed at further breaking down the time blocks of natural gas that trade in the market so that the natural gas products and thus their prices in the market more closely align with those of electricity and the demand for power.
As natural gas takes greater role in the production of power, it’s important to understand how changes in the natural gas market have increased implications for what occurs in the electricity markets. Below our feet the energy landscape is shifting though, most prevalently as noted by natural gas-fired generation’s displacement of coal-fired generation. Because of this greater connectedness it’s more important than ever to consider our energy system holistically and understand that the wholesale power and natural gas markets are ever-evolving ones. Market participants and administrators are in a continuous effort to make these markets function reliably and efficiently to meet the needs of our lives. Uncovering the weaknesses in the current system and addressing those issues with practical measures and reasonable policies are the necessary steps to getting us to a greener, more reliable grid that can balance a more diverse energy mix than ever before.
 Energy Information Administration (EIA) Today in Energy – Jan 21, 2014
 EIA Energy Outlook
 Public data from ISONE, NYISO, PJM; GP Renewables & Trading analysis
 Black & Veatch – “Shifting Natural Gas Supplies Adding to US Pipeline Constraints”
 Platts Megawatt Daily – “NRG Pushes for splitting weekend gas packages”