Economic, technological, and political factors have encouraged the extensive installation of gas-fired power plants in the United States, which has caused electric systems to depend heavily on reliable gas supplies. This has greatly strengthened the interdependence between the electric power and natural gas industries. Recently, the intra-day fluctuations in pipeline loads that arise from changes in gas-fired electric power plant operation have become particularly problematic. In order to provide pipeline operators better insight into these loads, this paper describes the procedures used by power system operators to decide when and where electric generators are committed to operate, and at what level. We place particular emphasis on the evolving role played by gas-fired generators. In addition, we discuss recent Federal Energy Regulatory Commission (FERC) policy changes that aim to improve operational coordination between the two industry sectors.
New extraction technologies, cheaper gas, and other factors have led to widespread installation of gas-fired electric power plants and caused the electric power grid to depend on reliable gas supplies. Recently, natural gas has eclipsed coal as the largest fuel source for electric power production in the US. Gas-fired generators are advantageous for meeting peak electric loads and providing rapid-response contingency power. However, these attributes can cause high and unpredictable intra-day variability in takes from gas transmission pipelines. These new conditions create challenges for current methods for flow scheduling and real-time physical control. The resulting impacts on pipeline efficiency, capacity, and security often translate to gas price fluctuations, supply disruptions, and increased operating expenses. Better coordination between the electric power generation and natural gas transmission industries would mitigate some of these problems. However, coordination between power and gas industry markets and intra-day planning of physical operations is nontrivial.
In the gas marketplace, day-ahead and intra-day bilateral gas contracts are purchased, sold, and cleared. These agreements are based on steady rated gas takes, and gas transmission companies then use this information to create operational plans. The resulting flow schedules are based on capacities rated by FERC regulations, which are estimated using steady-state flow models. Real-time pipeline control is then performed in reaction to customer behaviors that may not be communicated in advance. This approach to pipeline scheduling and control is satisfactory when nearly all customers were local distribution companies (LDCs), which are firm contract holders whose takes were more predictable and far less variable. In current markets where over half the gas customers are electric power plants who purchase non-firm contracts, this approach may not be sufficient to guarantee supplies to non-firm contract buyers with highly variable demand. Today, operators need to make decisions in a limited time-frame based on only a handful of scenarios that were evaluated using transient simulations.