Areas of the US in which large supplies of natural gas are extracted are called producing regions. Areas of the country with significant demand for natural gas (e.g. industrial centers, population centers, etc.) are called consuming regions. Generally, demand is low and supply is high in producing regions while demand is high and supply is low in consuming regions.
To monetize their assets, producers need to move their natural gas from their producing region to one or more consuming regions. To keep costs low, consumers need cost-effective access to gas from one or more producing regions. Pipelines, offering reliable and cost-effective service, have become the primary method of moving natural gas around the United States.
Before the US natural gas markets were deregulated, pipelines served as merchants to their customers – customers purchased their natural gas from a pipeline for a price which included transportation and producers sold their production under long-term agreements (i.e. “life-of-lease”). The pipelines were regulated to prevent monopolistic behavior but these regulations were imperfect and led to shortages and gluts. In the 1980s, industrial customers, rebelling against high prices, began switching to other forms of energy leaving pipelines unable to monetize their asset. In response, pipelines started to allow these industrial customers to transport gas on their pipelines without requiring that the customers also buy the natural gas from the pipelines. Although later ruled discriminatory against the non-industrial customers, it helped lead to FERC Order 436 (commonly known as the “Open Access Order”) which was the first big step toward the natural gas markets as they exist today. Although voluntary, the 1985 order allowed pipelines to change their business model to provide only transportation. In 1992, FERC Order 636 (commonly known as the “Final Restructuring Rule”) moved further by prohibiting pipelines from acting as a merchant and requiring them to sell each of their services independently and without bias. No longer able to participate in gas purchases and sales (“the shipper must have title”), the order completely restructured the pipeline industry leading to the market we have today in which pipelines must offer their services without bias to any qualified customer and must publish their rates via electronic bulletin boards (EBBs) meeting the FERC’s standards and equally accessible to all customers. Note that pipelines with infrastructure completely within a single state’s borders (i.e. intrastate pipelines) are not subject to the FERC requirements.
Building a pipeline is an expensive exercise resulting in a highly-regulated long-term immovable asset. Market conditions may change significantly over the life of the pipeline leaving the pipeline’s investors exposed to changes in demand for their asset. To defray these risks, pipelines will generally contract with customers to take a portion of the capacity on a long-term basis (referred to as “subscribing”). These agreements are “firm” capacity agreements as the shipper’s access to the capacity they’ve purchased is a “firm” obligation on the pipeline. Since pipelines are built to address specific market inefficiencies (i.e. high prices caused by constrained delivery capacity or low prices caused by a lack of market access), there are generally customers willing to invest in a pipeline to improve natural gas prices at one end of the pipeline or the other. By entering into these agreements, pipelines essentially sell a portion of the pipeline’s capacity for the term of the contract leaving the shipper holding the risk of changing market conditions. Some pipelines may even be fully “subscribed” before construction begins.
Pipelines may or may not sell all their capacity under firm capacity agreements. Regardless, pipelines know that some shippers will not use all their firm capacity every day. For example, an industrial may need to shut down for a week or two for a plant expansion or a utility may have lower than forecasted load and be unable to store additional gas. The greater the number of firm capacity holders, the more likely that one or more of the shippers will choose not to use all their firm capacity on any given day. On average, this can leave pipelines with at least a small amount of unused firm capacity each day. This capacity, along with any unsold capacity as well as any additional capacity available due to operational conditions (pressure, temperature, etc.), means pipelines will often have available capacity. To monetize this capacity and maximize the value of their asset, pipeline companies will sell another class of service called “interruptible” capacity. Interruptible capacity is sold by the pipeline on an “as available” basis meaning that the pipeline will attempt to meet the shippers needs but may not do so (or may only partially do so) should the pipeline not have sufficient available capacity.Companies which have capacity rights on natural gas pipelines are called shippers. Capacity agreements allow shippers to move a defined volume of gas between defined locations on a pipeline. When a shipper ships natural gas through a pipeline, the pipeline uses some of the shipper’s natural gas as energy to power pressure-generating pumps to move the natural gas. In addition, a small amount of natural gas escapes during transport (referred to as “lost and unaccounted for”). This natural gas is lost to the shipper and is referred to as “Loss”. Loss is measured as a percentage (e.g. 0.075%), so a loss of 1% would mean that the pipeline would redeliver to a shipper 99% of the natural gas the shipper delivered to the pipeline. The pipeline also charges fees for moving the gas. There can be multiple fees, generally denominated in cents per MMBtu ($/MMBtu), with the total referred to as the “Commodity Charge”. Shippers only incur loss and pay commodity charges for natural gas actually shipped on the pipeline. However, pipelines charge a separate fee for “firm” capacity, referred to as a “demand charge” or a “reservation fee”, which is due regardless of usage and reflects the “take or pay” nature of the firm capacity agreement. Although a shipper holding firm capacity will still pay a commodity charge, it is trivial compared to the commodity charge for interruptible service.
Now we're ready to review the concept of pipeline capacity segmentation.
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