There is an old joke from the oil industry that goes something like this:

An oil company executive walks into a bar and sees a wildcatter slouched over the bar, staring into his drink.

“What’s the matter,” says the oil company executive, “another dry hole?”

“Worse,” says the wildcatter, “we found gas.”

For many decades, natural gas was the poor cousin to crude oil. Often found alongside crude oil in reservoirs, natural gas was considered to be a low-value waste product that was often flared or vented into the atmosphere in very large quantities (enough to supply several European countries for an entire year), in order to more easily access the high-value crude. Nowadays, the world has changed. Particularly with the rapid emergence of unconventional natural gas resources (these are often grouped into a catch-all category of “shale gas” but includes natural gas found in sandstone formations, coal beds and other types of geologic formations other than shales), there are lots of perceived opportunities in natural gas. We will discuss shale gas in the next lesson, but first we will walk through an introduction to natural gas as a commodity and the functioning of North American markets for natural gas.

Learning Outcomes

By the end of this lesson, you should be able to:

• identify the role that the “Henry Hub” plays in North American natural gas pricing;
• explain why prices for natural gas change seasonally;
• define “wellhead” and “citygate” prices for natural gas, and explain why these prices are usually different;
• use the NYMEX website to construct a forward curve for natural gas;
• calculate correlations between natural gas prices in different regions of the United States, using data from the Energy Information Administration.

Reading materials

Aside from the online materials on the course website, you will need to access the websites of the EIA and NYMEX (CME Group). The EIA has a nice introductory reading [1] to the world of natural gas as part of their "Energy Explained" series. You will also need to download the following reading from the Lesson 03 module in Canvas:

• S. van Vactor, Flipping the Switch: The Transformation of Energy Markets, Ph.D. Dissertation, Cambridge University, 2004.
  • Note: Chapter 5 of the van Vactor reading has a nicely detailed discussion of the development and structure of markets in both the U.S. and Europe.

What is due for Lesson 3?

This lesson will take us one week to complete. Please refer to the Course Calendar in Canvas for specific due dates. Specific directions for the assignment below can be found on Canvas.

• Answer some questions regarding the role of the Henry Hub as a "benchmark" for North American natural gas prices.
• Collect and analyze natural gas pricing data from the U.S. Energy Information Adminstration.

Questions?

If you have any questions, please post them to our Questions about EME 801? discussion forum (not email), located in the Lesson 00 module in Canvas. I will check that discussion forum daily to respond. While you are there, feel free to post your own responses if you, too, are able to help out a classmate.

Like crude oil, natural gas is an energy source based on hydrocarbon chains, but the composition of natural gas is generally different than the composition of crude oil. Natural gas is primarily composed of methane, though some natural gas deposits also contain substantial fractions of other hydrocarbon gases or liquids such as ethane and propane (these are longer hydrocarbon chains that have substantial value as chemical feedstocks). Most gas deposits also contain impurities such as sulfur or other carbon compounds that must be separated prior to the gas being injected into transmission or distribution pipelines. Gas deposits that consist primarily of methane are known as “dry” gas deposits, while those with larger fractions of other hydrocarbons are known as “wet” or “rich” gas deposits.

Figure 3.1. Natural gas pipeline.

Credit: www.eia.gov [2]

Unlike oil, natural gas is essentially wedded to its transportation system – without pipelines (and liquefied natural gas tankers, which we’ll discuss later), there is no economical way to get large quantities of gas to market. Moreover, natural gas pipelines generally need to be dedicated assets. Using oil or petroleum product pipelines to move natural gas is not really possible, and moving other products in natural gas pipelines is not possible without completely repurposing the pipeline (and the injection/withdrawal infrastructure on either end). This asset specificity and complementarity between natural gas and the pipeline transportation infrastructure has been a significant factor in the development of the natural gas market. Each has little use without the other.

Natural gas is used in industrial, commercial, residential, and electric power applications. Natural gas demand in the United States has remained virtually flat for the better part of a decade, although, as shown in Figure 3.2, there has been a shift in the composition of that demand, away from industrial utilization and towards the electric power sector. Expectations are that the emergence of low-priced gas supplies from unconventional sources will change the drivers of natural gas in two ways – first, demand among both the industrial and electric power sector is anticipated to increase. Second, surplus natural gas supplies may open up an entirely new export sector for North American natural gas.

Figure 3.2: Sectoral demands for natural gas in the United States.

Credit: Energy Information Administration data

Each demand sector has its own intra-annual pattern of natural gas demand. Residential demand, for example, tends to be highest in the winter (because of demand for space heating), while demand in the electric power sector tends to be highest in the summer, due to higher demand for electricity (for air conditioning). Overall, natural gas demand in the United States peaks in the wintertime, with a lesser peak during the summer. A typical set of annual demand profiles is shown in Figure 3.3. There are some shifts occurring here as well, particularly as demand from the electric power sector continues to climb.

Figure 3.3: Intra-annual demand patterns for natural gas in the United States. Graph based on data from the U.S. Energy Information Administration, averaged over the period 1997-2011.

Credit: EIA

Beginning in the mid to late 1990s, the U.S. electric power sector started undergoing a transformation away from building new coal-fired power plants and towards building new natural gas plants. This shift took place for a variety of reasons, including increasingly stringent environmental requirements for power plants and a shift in the market for electricity induced by deregulation and restructuring. This shift towards more gas-fired power generation was associated with a pronounced increase in both the average spot price of natural gas and the volatility of natural gas prices, as shown in Figure 3.4. This association seems to have broken down since 2009 – there has been additional investment in, and utilization of, gas-fired power generation but a pronounced decline in natural gas prices. This trend reflects the influence of additional gas supplies from unconventional deposits (primarily shales and tight sandstone formations) coming online. Referencing our discussion of capacity constraints in the lesson on petroleum refining, the price and utilization trends in Figure 3.4 reflect textbook energy economics – the build-out in natural gas generation represented increased demand without a corresponding increase in natural gas supply, pushing the global demand curve towards the capacity constraint and rapidly increasing prices (some price spikes such as those observed in 2000, 2005, and 2008 are associated with extreme weather events like hurricanes or interruptions to gas pipeline networks, such as an explosion in the Western U.S. in 2000).

Figure 3.4: The trend of natural gas prices and natural gas used for power generation over time. The build-out in gas-fired power generation capacity began in the mid-1990s and electricity restructuring efforts began in the 1996-1998 time frame. Shale gas production started to climb rapidly beginning in 2009.

The North American natural gas market is structured based on what has been called the “hub” model of gas pricing. In markets with hub pricing, the interaction of supply and demand sets prices at a small number of specific locations. These locations are the "hubs." (In the van Vactor reading and in one of the assignment questions for this week, there is some discussion about the properties of a good "hub" trading point.) The "local" price at any other location or points of consumption in the commodity network is thus the hub price plus the cost of transportation from the hub. Price differences between any two points in the gas pipeline network represent just the cost of transportation between those two points.

We can also describe this using some terminology from the natural gas industry (this terminology is also commonplace in the oil industry). If the hub represents some point where it is easy to obtain natural gas without much transportation, this would be referred to as the wellhead price. The point where the natural gas enters the distribution system for local delivery (see Figure 5.1 from the van Vactor reading) is known as the citygate. The citygate price should generally be higher than the wellhead price because of the transportation cost associated with moving the gas from the wellhead to the citygate. The wellhead price simply represents the market equilibrium for the natural gas commodity, not including any transportation costs.

One implication of the hub pricing model is that the entire gas market should roughly obey the law of one price, which says that if the gas market is working efficiently, then price differences should reflect transportation costs. A change in the wellhead price of natural gas would be reflected everywhere else in the network.

Figure 3.5: Example natural gas network

Credit: Seth Blumsack

Here is a simple illustration of the law of one price, using the small network shown in Figure 3.5. In this example, p represents the price at a given location and c represents the transportation cost to get from the supply point (wellhead) to a specific location. Gas fields A and B are connected via pipeline to market centers (you can think of these as citygates) 1 and 2. A and B can deliver to both markets, but the transportation cost c is higher to get to market 2 than market 1. Thus, c1 < c2 and in equilibrium, p1 < p2. Thus, gas at Market 1 will be cheaper than gas at Market 2.

Further, in equilibrium p2 = p1 + (c2 – c1), which in words says that the price at Market 2 would be equal to the price at Market 1 plus the transportation cost to Market 2 from Market 1 (the transportation cost to Market 1 from the wellhead is already reflected in the price at Market 1). Using number, suppose that the price of natural gas at the wellhead (either field A or B) was $5 per million BTU ($/MMBTU). The transportation cost to market 1 is $1/MMBTU and the transportation cost to market 2 is $3/MMBTU. If this gas market obeyed the law of one price, then the citygate price at market 1 would be $5/MMBTU + $1/MMBTU = $6/MMBTU. The citygate price at market 2 would thus be $6/MMBTU + ($3/MMBTU - $1/MMBTU) = $8/MMBTU.

One implication of the law of one price is that changes in supply or demand at one location can affect pricing at all locations in the network. Here is another example, again using the same network (see Figure 3.6). Suppose that demand in market 2 were to increase. Suppliers in both fields would increase their offer prices so that p2 > p1 + (c2 – c1). Assuming that there are no constraints on the size of the pipeline, that increased demand at market 2 would bid up the price for all market points in the network since all suppliers would try to move their gas to market 2. (Of course, there is some limit to this redirection of supply since demand in market 2 is finite.) Supply to market 1 would decrease, raising prices in market 1 to restore equilibrium (where the price difference between markets is equal to the difference in transport costs).

Figure 3.6: Example natural gas network with an increase in supply at market 2. The increased demand at market point 2 also causes price to increase at market node 1.

Credit: Seth Blumsack

It is possible for markets connected by pipelines to depart from the law of one price. The simplest example of how this might happen is if there is a constraint or an interruption on a pipeline. For example, suppose that the pipeline between markets 1 and 2 were to be removed from service, isolating market 2. What would happen to prices at market 1? Market 2? In the assignment for this lesson, you will get some practice looking at the law of one price in the North American natural gas market using data from the U.S. Energy Information Administration.

Every natural gas field within some geographic area has the potential to be a hub pricing point. Locations that are close to producing areas and are also connected to a large number of gas transmission pipelines also have the potential to be good hub pricing points. In general, hub pricing points need to be highly connected to the rest of the network – it should be easy to move gas from the hub point to any other location in the network.

The major hub pricing point in North America is the “Henry Hub,” which is a physical location in Louisiana, indicated in Figure 3.7. Henry Hub is well-connected to the rest of the North American market (as indicated by the flows of gas through North America as shown graphically in Figure 8).

The Henry Hub is also the point at which the NYMEX futures contracts for natural gas are priced. The following video (2:14) shows how to access natural gas pricing data from EIA and NYMEX.

Figure 3.7: The North American gas pipeline network showing the location of the Henry Hub.

Credit: Energy Information Administration, Office of Oil and Natural Gas, Natural Gas Division, Gas Transportation Information System

Figure 3.8: Major flows of natural gas in the North American market. Note the large volumes of flow from the area of the Henry Hub to other areas of the United States.

Credit: Energy Information Administration, Office of Oil and Natural Gas, Natural Gas Division, Gas Transportation Information System

Summary

Natural gas as an energy commodity is different than crude oil in several important ways, but markets for natural gas and oil share some important similarities as well. Like crude oil, natural gas is an energy commodity whose prices were gradually deregulated through the 1980s, culminating in full wellhead price deregulation in the early 1990s. Pricing of natural gas is determined by supply, demand, and transportation (pipeline) factors, and the natural gas market has its own distinct North American price benchmark - the Henry Hub - just as crude oil has West Texas Intermediate as its North American benchmark (we will get more into globalization of gas markets in the next lesson). Unlike crude oil, natural gas is used directly in virtually all sectors of the U.S. economy (residences, businesses, industry, power generation), with the exception of transportation. Also, unlike crude oil, natural gas is more homogeneous but more difficult to transport, meaning that trade in natural gas is more closely tied to the availability of pipeline capacity than is trade in other energy commodities.

Reminder - Complete all of the Lesson 3 tasks!

You have reached the end of Lesson 3! Double check the What is Due for Lesson 3? list on the first page of this lesson to make sure you have completed all of the activities listed there before you begin Lesson 4. Note: The Lesson 4 material will open Monday after we finish Lesson 3.