New and Expanded Gas Pipeline Capacity Does Not Mean Lower Power Capacity Costs3 min read
In New England, it has become increasingly more apparent that natural gas supply and prices are heavy determinants to power supply and prices. The shale boom in the past 10 years has led to an abundance of natural gas and oil supply in the country and, in turn, caused natural gas prices to reach 17-year lows in New England. The low gas environment and absence of significant coal-fired generation, coupled with two large nuclear baseload plant closures, leaves the region vulnerable to natural gas dependence, especially in the winter during the peak of heating demand season. Almost half of New England’s total generation in 2015 came from natural gas-fueled resources.
Due to the current power market structure, gas-fired generation almost exclusively contracts their gas supply on a daily basis while local gas distribution companies (LDCs) can transact long-term, which guarantees the delivery of the commodity as they pass those costs to the ratepayers. During the winter when gas heating demand is highest, and because the geographic location of the region lies at the “end of the line”, gas-fired power generators are at risk for (1) not receiving gas they want to purchase in the daily market or (2) paying an exorbitant price as supply/demand dynamics play out in the market. These price spikes in gas lead to price spikes in the daily energy market and in turn push up term prices for retail customers from energy suppliers.
During the winter of 2013/2014, commonly referred to as “The Polar Vortex”, New England saw these fears play out as consistent cold temperatures and persistent heating demand in the region pushed gas prices to historical highs. In the wake of such conditions, market and legislative forces have determined that more natural gas pipeline infrastructure is needed to supply the region during times of constraint (the winter). The planned expanded infrastructure is often referred to as increased pipeline “capacity”. The intention of the proposal is to increase pipeline capacity which would increase the flow and supply of natural gas during constrained times when demand is at its highest. More supply equates to an easier fulfillment of demand when it’s highest which would limit price spikes in the gas and energy markets. The merits of additional pipeline capacity are an extremely hot-button topic amongst the gas industry, state and federal legislatures and environmentalists alike: is it really necessary for the benefit of the region’s customers? If it is, benefits might come in the form of fewer price spikes in the energy market and reduced supplier term prices for energy. However, this will not alleviate capacity costs from the supply portion of a business’s energy bill.
This is where industry semantics play a key role in differentiating between “pipeline capacity” and the New England Forward Capacity Market (aka “capacity costs/market”). The capacity market, run by ISO New England, (1) procures the necessary power supply to meet New England’s forecasted demand roughly three years in advance, (2) provides compensation for the cost of generation for existing resources, and (3) attracts new resources to constrained regions through an additional source of income. Costs incurred by the retail customer in the energy market represent the physical electrons delivered through transmission and distribution lines, and the costs for the capacity market compensate generation resources for being available to generate those electrons for grid reliability. The energy and capacity markets are two separate cost structures to the customer, and therefore additional pipeline capacity will not directly affect future capacity costs from the energy supplier.
The Forward Capacity Auction takes place three years in advance and determines the capacity rates in which generators (resources) are paid. Funds paid to the supply resources (generators) must be recouped by ISO New England from the load serving entities, which trickle down to the end user (commercial, industrial, residential accounts). These rising capacity rates have been officially published by the ISO New England, and all power suppliers/load serving entities will be charged these rates for the next three years on their capacity invoices. Capacity costs will be included in a customer’s rate or passed-through as a separate line item, depending on what product a customer chooses.
For new or renewal contracts, the difference in rates between fixed and passed-through capacity is negligible as the rates are essentially set, but customers can manage their capacity tag to offset these cost hikes. The account capacity tag is a key component in determining the capacity costs along with the capacity rate. The capacity tag in New England is set during the previous power year on a single hour when the overall demand for the region hits the annual high. Once that hour is determine each account’s capacity tag is set based on that hour’s consumption.
Constellation provides a number of capacity tag management programs, including the popular Peak Response Program, to mitigate these high capacity rates and lower the overall costs of energy. Reach out to your Constellation representative today to learn more.