As the saying goes, “the only constant is change.” This statement can be used to describe the energy industry over the past few decades. “Booms” and “busts” have occurred numerous times as prices rose and then fell back again. Companies have come and gone. Enron shook the very foundation of energy trading. Investigations of supply and price manipulation have occurred, resulting in fines and imprisonment. The new exploration ("3-D & 4-D" seismic), drilling (directional & horizontal), and completion techniques (so-called “fracking”) have not only led to a substantial increase in the production of crude oil and natural gas, but have also led to great controversy and new regulation over the methods themselves. The abundance of natural gas is leading to the exportation of liquefied natural gas (LNG), making the US a major player in that global market.
The “how” and “why” these occurred will be presented throughout the course, and you will come to understand the ever-changing landscape that is the energy industry in the United States.
Despite the reference to alternative & renewables energy sources in the course description, we will spend very little time discussing them. This course focuses largely on the five fossil fuels that are traded both physically and financially in energy markets. These are natural gas, crude oil, unleaded gasoline, heating oil, and natural gas liquids (NGLs). The reason for this is that these energy commodities are heavily traded in financial futures markets. Understanding how these financial markets work is the primary goal of this course. These fuels, along with coal, comprise the “non-renewable” energy sources. They are so named since their supply is seen as finite over the long-term. Then we will extend our knowledge to the electricity market, its characteristics, and differences. We will also introduce the risk management methods.
Each of these products has a profound effect on the United States and global economies. Billions and billions of dollars of infrastructure and hundreds of thousands of jobs are involved in the exploration, production, transportation, and distribution of these forms of energy. And price volatility for these commodities has increased dramatically over the past several years going back to the historic run to $147 per barrel (Bbl) for oil in 2008. Since that time, crude oil has been recognized as a truly global commodity with a host of new factors influencing price. And, once again, in 2014, prices fell from $100 in June to less than $50 by December, caused largely by Saudi Arabia flooding the market with cheap crude. It was said they feared a loss of market share to the new shale oil in the US. One of the major players in the oil market is Organization of Petroleum Exporting Countries (OPEC), with about 40 percent market share of the world's crude oil production. OPEC decisions and members' agreement have a substantial effect on crude oil price. Following the oil price drop in late 2014 and 2015 to about $30/Bbl, OPEC members (and some other producers) came to an agreement to decrease their production, which caused the prices to increase in late 2016 and 2017. In March 2020, following the global pandemic, crude oil futures price dropped to about - $40/bbl for the first time in history.
However, before we proceed into the details of these fossil fuels, we need to understand how these fit into the overall profile of energy production and consumption in the United States. In order to do this, we must also include the various other forms of energy produced and consumed in the United States, known as “alternative” and “renewable” energy. This is the only lesson regarding alternative and renewables.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday at 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
Lesson 1 doesn't have any reading assignments. However, the following readings are optional and recommended.
“Non-renewable” energy sources (such as Oil and Petroleum Products [6], Natural Gas [7], Natural Gas Liquid [8], Coal [9], and Nuclear [10]), as well as “renewable” energy and “alternative fuels” (such as Hydro [2], Solar [3], Wind [1], Geothermal [4], Biomass [5], and Biofuels [11]), help to satisfy the nation’s energy needs. Fossil fuels and nuclear power are considered non-renewable sources of energy. Coal and natural gas play large roles in the generation of electricity as well as in industrial processes such as the manufacturing of steel. Hydro, solar, wind, biomass, biofuels, and geothermal are all considered “renewable” forms of energy and comprise varying levels of supply in this country. They are classified as renewables since their source is seen as being virtually unlimited. Of these, solar, wind, biomass, biodiesel, and geothermal are all considered “alternative” energy sources since they are not the “traditional” kind (fossil fuels, nuclear, and hydro).
The following chart is from EIA reported data [12] and shows major energy sources and percent shares of U.S. electricity generation at utility-scale facilities in 2021. Please note that in 2021 natural gas has the largest share (38%) in U.S. electricity generation, coal is in the second place (22%), and nuclear has the third place (19%). As shown in Figure 1, renewable energy sources contribute to about 20% of the U.S. electricity production at utility-scale facilities as of 2021, with about 9.2% wind power and 6.3% hydro. Please note that 2019 was the first year that wind power surpass the hydro. Other renewable sources such as solar, biomass and geothermal have a minor share.
Figure 2 below shows the break-out of fuel sources used in the generation of electricity. As you can see, the single largest fuel has been coal in the past decades, although this is changing as historically low natural gas prices during 2010-2020 caused some “fuel switching.” This was followed by natural gas, nuclear, and renewable energy sources. This final category is comprised of energy sources such as wind, solar, hydroelectric, biomass, and geothermal.
Figure 3, below, displays the renewable energy sources that contribute to power generation. As you can see, there has been a rapid increase in wind and solar power generation. However, it will take decades for alternative fuels to make a substantial contribution to the energy portfolio in the United States. Thus, there is a need to continue to use fossil fuels and nuclear power to “bridge” the gap. How the former (fossil fuels and nuclear power) are delivered to market and how they are priced is the main focus of this course.
Now that we have clarified the difference between renewable and non-renewable sources of energy, let’s have a look at the production and consumption of energy in the United States on a macro level.
The United States is the world’s largest consumer of energy in general and of oil and refined products in particular. However, our current and forecasted energy production and consumption balance is improving towards a position of declining imports and more efficient use of all energy sources. The vast new supplies of oil and natural gas coming from domestic shale are radically altering our outlook for eventual self-sustainability. And the continuing development of “renewable” and “alternate” energy sources will decrease our reliance on traditional “fossil” fuels. We will now take a look at the current state of energy production and consumption in the US, followed by a brief examination of the renewable and alternative energy sources.
The following pie chart (Figure 4) shows the United States' energy consumption by source in 2021. As shown in the chart, petroleum that is mainly used for the purpose of transportation has the biggest share of 36%. Natural gas is in second place with 32% share of energy consumption.
Figure 5, below, illustrates the historical energy consumption in the United States by source. Notice the decline in the use of coal, while natural gas and renewables consumption are increasing. The increase in natural gas consumption has much to do with the following: the current historically low prices resulting from the huge amount of new shale gas being produced, and new tighter emissions standards being imposed on coal-fired power plants. If you are interested to see the historical trend by the source, individually, click on the following link, it is a graph showing the history of energy consumption in the United States from 1750 to 2015 [15].
Alternative energy sources will continue to grow as long as economically feasible, and especially if government subsidies are available to support their production (e.g., – ethanol). Note that EIA publishes annual reports for the US Energy Outlook, which include future projections. If you are interested in the projected energy outlook in the United States, click here [17]. You may notice EIA (Energy Information Administration) is projecting a significant increase in production and consumption from renewables by 2050. While, nuclear production is shown as being stable, and with the negligible emissions they produce.
In addition, as far as natural gas goes, an increase is indicated. The residential use of heating oil and propane is steadily declining as conversions to natural gas steadily continue. (50% of US homes use natural gas for space heating and hot water.) Add to that the retirement of coal plants, or the outright switching from coal to natural gas, and growth in the consumption of natural gas will naturally occur.
The future consumption of oil and “other liquids” will be interesting to observe as well. With automobile efficiency improving and electric cars gaining in popularity, this segment should decline. Also, there are decades-old power plants, mostly in the Northeastern US, that use fuel oil. These, too, will become obsolete or convert to natural gas. (The Northeast US is also the world’s largest consumer of heating oil.)
There should also be a more dramatic decline in the use of coal than what is shown above, as emissions restrictions and lower natural gas prices make coal less economic to use.
The fuels we will study in-depth, natural gas and “oil and other liquids,” comprise more than half of the projected total US energy consumption profile, thus making it crucial to understand the logistics and “value chain” of these fuel sources.
The following chart illustrates the various types of energy in the US and the corresponding consumption types.
In Figure 6, above, we see the energy sources matched-up with their respective categories of consumption. Both petroleum and natural gas are used in each sector of consumption, while coal is utilized in only industrial, residential (this would have to be a very small amount), and power generation. Nuclear energy is strictly used for electric power generation, and renewables can be consumed in all categories but contribute very little to each on a percentage basis.
The sources and uses of energy are important for the overall understanding of the impact of supply, demand, and pricing on the macroeconomic environment. Everything depends on energy, and understanding these interrelationships can help us manage our supply needs and price exposure.
So far, we have examined the energy portfolio of the United States, and next, we will take a look at the global energy production and consumption as well as the energy profiles of several major countries.
Figure 7 shows the total energy consumption of the world by sources over two centuries. Until the mid-19th century, traditional biomass, like the burning of wood, crop waste, or charcoal, was the dominant source. With the Industrial Revolution, coal replaced traditional biomass as the dominant one, and then was replaced by oil in the 1960s. Natural gas, nuclear, and hydropower were added to the mix around the same period. Solar and wind came much later in the late 1980s. A fast expansion of natural gas and renewables has been ongoing since the 21st century. Compared to the energy portfolio of the U.S., the worldwide reliance on fossil fuels is much greater, where more than 77% of energy demand is met by oil, natural gas, and coal. It is also worth noting that traditional biomass is still one of the major sources for many developing regions.
Figure 8 shows the 2021 energy consumption by country. Here we briefly introduce energy portfolios and energy import/export of several major counties/regions.
Figure 9&10 shows the top 10 importer and exporter countries of crude oil and natural gas. Top importers are major economies while exporters come from all over the world. As we will see in the following lessons, these countries will have significant impacts on the demand and supply in the world energy commodity market.
So, what are the “renewables and alternate” sources of energy? As previously mentioned, “renewable [18]” energy sources are those which can be replenished over and over again, such as solar [3], hydro [2], wind [1], biomass [5], biofuels [11], and geothermal [4]. “Alternate” energy sources are those which are not the traditional fossil fuels or nuclear power. These include the renewables: hydro, wind, solar, biomass, biofuels, and geothermal.
As stated previously, it will take a long time for renewable and alternate energy sources to make a significant dent in the US reliance on fossil fuels. In the interim, the fuels we will study in depth, primarily natural gas and crude oil, will continue to be produced and consumed in substantial quantities. Natural gas, as the cleanest burning of the fossil fuels, represents the “bridge” fuel until renewable and alternate energy can be produced in sufficient quantities to wean us of our dependence on fossil fuels.
The following 8:57 minute "mini-Lecture" will cover Alternate and Renewable energy sources in more detail. Mini-Lectures such as this will be provided in most Lessons and will supplement the textual lesson or be the lesson itself. The slides can be found in the Modules under Lesson 1: The Energy Industry - Overall Perspective in Canvas.
Energy consumption in the United States takes many forms. The traditional “fossil fuels,” such as coal, oil, natural gas, gasoline, and other refined products and, natural gas liquids, do not have a limitless supply.
Renewables, however, such as hydro, wind, solar, biomass, biodiesel and geothermal, are self-replenishing.
Alternative fuels comprise the non-traditional energy sources and include nuclear and fossil fuels. Alternative fuels represent the smallest amount of energy consumed in the US and are not expected to expand greatly over the next 20-25 years. And, for many alternative fuels, government subsidies are essential for them to be produced economically.
In the interim, fossil fuels such as natural gas and crude oil will continue to grow in usage and importance. Their supply, demand, and pricing will have a great impact on the US economy for decades to come.
Now that we have examined production and consumption in the United States as well as the energy “mix,” we will focus on the fuel sources that comprise over 57% of the energy used in this country. Crude oil, with refined products, and natural gas and related natural gas liquids (NGLs), make-up this large sector. The factors that influence their supply and demand are varied and ever-changing. Besides the obvious impact of weather, the economy, the US dollar, and the global geopolitical conditions can all influence energy commodities and affect their prices.
You have reached the end of Lesson 1. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson. (To access the next lesson, use the link in the "Lessons" menu.)
In mid-2008, crude oil shocked energy markets as it reached an all-time high of $147/barrel (Bbl.) on the New York Mercantile Exchange. (See Figure 0 below.) Within four months, prices had sunk to $50 per barrel. Then, again in 2014, prices hit a high of about $100/Bbl in June only to fall to under $50/Bbl by December. In April 2020, crude oil futures price dropped to about - $40/bbl for the first time in history. How could these happen, and what were the factors causing these levels of price volatility? We will be exploring these questions in Lesson 2.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday at 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
Before we begin our discussion of the logistics and value chain for natural gas and crude oil, we need to have at least a cursory understanding of the “upstream” processes for the exploration, drilling, fracturing, and production of these fossil fuels. The following readings and video support this learning.
Go to the EIA website and read the following sections from “Nonrenewable Sources [20]”:
Please take some time to review the optional materials. They will give you context for the rest of the lesson.
Economists have long recognized that we are truly a global society and all of our economies are intrinsically tied together. Growth or recession in one region of the world could have a ripple effect on other regions. China and India were emerging as large-scale industrial countries with vast exports of manufactured goods. Both were consuming new, higher levels of energy (Figure 4), and most specifically, crude oil. News of increasing crude imports by both countries sparked buying of the financial commodity contracts.
The so-called “speculators” were blamed for a lot of the price increase that year, but there was a whole new set of players who greatly influenced the market. Investment funds and private investors, both domestic and international, saw the crude market as a “safe harbor” from the ups-and-downs of the stock market and the US dollar. When the stock market fell, they bought crude oil contracts. And when it rose, they sold those same contracts. The dollar is a little more complicated. When the value of the US dollar falls relative to foreign currency, overseas investors have more “buying power,” that is, they can buy more crude with their currency than those holding US dollars. So, to some extent, it is true that “traders” had a major influence on oil prices that year. But the definition of “trader” had changed from the stereotypical “day trader,” who wreaks havoc on markets, to sophisticated investors and real demand from emerging nations.
Today, the economic health of various countries still impacts the volatility in oil prices, and the US dollar and crude prices have a very high but inverse correlation. And geopolitical conflicts involving oil-producing countries and regions always cause concern over potential supply disruptions.
US oil production has been risen over the past years (before the unprecedented situation in 2020) and stayed at about 12.8 million barrels per day in December 2019. This represents an increase from 2008 to early 2015, decrease in production from around mid 2015 to September 2016, and then increase in production again from then to late 2019. Production from 2014 to 2018 has been over 8.0 million Bbl/d. In 2016, U.S. crude oil production represents only about 55% of consumption, with the remainder coming in the form of imports. However, as Figure 3 shows, imports continue to decline as domestic crude supplies increase.
The rise in domestic oil production is mostly attributed to the new, “unconventional”, sources found in shale formations and high levels of oil price make the production from these sources more profitable. Advances in seismology (“3-D”), directional drilling (“horizontal”) and, fracturing methods (“fracking”), have made this once inaccessible resource commonplace today. Contrary to some beliefs, the number one source of imported crude oil in the US is not the Middle East, but Canada. Oil from tar sands in their Western Provinces is shipped via pipeline into the US.
Figure 2 is extracted from the EIA report on the U.S. crude oil production [44]. Figure 2 shows the upward trend in oil production over the (6) years before 2015, downward trend from mid 2015 to late 2016, and upward production trend again from late 2016 to late 2019 (before the unprecedented global pandemic in 2020). (Based on the latest completed study by the Energy Information Agency of the US Department of Energy.) This link from the EIA includes the historical data from the 20th century [45].
Figure 3 shows the downward trend in oil imports for the same time period (2000 - 2020).
Crude oil is produced in 32 states in the United States and as of 2021 about 71% of domestic crude oil production comes from the following five states [47]:
Crude oil is produced in about 100 countries around the world. In 2021 about half of the world oil production comes from the following five countries [47]:
Here are the top five oil consumer countries in the world in 2021 [48]:
According to EIA [49]:
" In 2022, the United States imported about 8.32 million barrels per day (b/d) of petroleum from 80 countries. Petroleum includes crude oil, hydrocarbon gas liquids (HGLs), refined petroleum products such as gasoline and diesel fuel, and biofuels. Crude oil imports of about 6.28 million b/d accounted for about 75% of U.S. total gross petroleum imports, and non-crude oil petroleum accounted for about 25% of U.S. total gross petroleum imports. ”
Here are the top five countries that the US is importing oil from with their share in 2022 [50]:
Figure 4 displays the China and India oil production and consumption since the 90s. As you can see in this graph, oil consumption by these two countries has increased substantially during the past two decades, while their oil production hasn't changed significantly. This gap has created a large oil demand from these two counties in the global oil market.
Many, many factors can influence the price of crude oil either directly or indirectly. Some of the major factors influencing US crude oil prices are:
The following videos go into greater detail about the factors which can influence crude oil prices. Please note that some of the statistics might be a bit out of date, but please do not worry about that. These are just examples and are meant to teach you about how the various factors influence the market. You will not be responsible for the example details.
(The lecture notes can be found in the Lesson 2 module in Canvas (Lesson 2: Supply/Demand Fundamentals for Natural Gas & Crude Oil.)
(9:04 minutes)
(9:29 minutes)
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Extracted natural gas [7] is mainly composed of methane, with small amounts of hydrocarbon gas liquids (HGL) and nonhydrocarbon gases. After natural gas is produced, it has to be processed and impurities have to be removed to meet the pipeline standards and become marketable. The infrastructure of natural gas delivery (before distribution) can be divided into three main categories [33]:
In 2021, U.S. dry natural gas production was about 34.5 trillion cubic feet and about 13% more than total U.S. gas consumption. This year, five states produced about 69% of total U.S. dry natural gas:
Natural gas is used in more than 50% of US homes for space heating and hot water. In addition, it is the largest source of energy for electrical generation at the moment (2021), see Figure 5. Natural Gas is also widely used in industrial, commercial, and industrial sectors. Figure 6 illustrates the breakdown of natural gas consumption by sector.
Domestic production in the US (see Figure 7) has grown dramatically in recent years due to the same advanced technologies that have allowed crude oil production to increase: “3-D” seismology, horizontal drilling and new “fracking” methods. All contribute to successful recoveries from hard formations such as the new “shales.”
Figure 8 illustrates the growth in the production of the currently active shale basins in the US. As you can see in the graph, natural gas production from Marcellus Shale formations, located mostly in Pennsylvania, West Virginia, Ohio, and New York, has been increasing during the past decade and has the largest portion of gas production among the shale formations.
Due to the increasing demand since the late 1980s, the US also imports natural gas (see Figure 9). Canada represents the largest source (more than 97%) of imported natural gas, with Mexico contributing a minor amount. The export of natural gas had been very limited through pipeline export points into Canada and Mexico. However, the export changed dramatically since 2016 due to the skyrocketing LNG export. In 2017, the U.S. became a net exporter of natural gas and in 2021, the LNG export exceeded pipeline export for the first time since 1990.
Figure 11 displays the U.S. average annual natural gas wellhead, city gate, and residential prices (1995-2019). Please note the increasing trend before 2008 and decreasing prices after. In order to fully understand these trends, have a look at Figure 7 (U.S. annual natural gas marketed production [53]) and U.S. GDP [56]from 1995-2019.
In contrast to crude oil, natural gas was almost strictly a domestic North American commodity* whose price is more influenced by weather and the health of the US economy. It is gradually becoming a global commodity in recent years due to increasing LNG export capacity [57]. Other factors, such as the level of US natural gas inventory, impact prices on a weekly basis. While US economic indicators, such as the stock market, employment figures, housing and, manufacturing indexes, are deemed to be indicative of demand for natural gas, global economies and the US dollar do not have much effect on pricing in this country.
Among the major factors influencing US natural gas prices are:
The following video goes into greater detail about the factors which can influence natural gas prices. (The lecture notes can be found in module 2 in Canvas. (Lesson 2: Supply/Demand Fundamentals for Natural Gas & Crude Oil.)
As we explore pricing for crude oil and natural gas in a later lesson, we will consider the major influential factors for each and define their individual impact. We will also have a weekly activity about the market prices for crude oil and natural gas and the factors we believe affect them.
Note: When commodity price is expected to go up, the market is called bullish [59]. In this case, an investor will invest in the commodity. On the other hand, if prices are expected to go down, then it’s called a bearish [59] market. In this situation, an investor is expecting the commodity to lose its value. Consequently, the investor sells the financial commodity.
Now that we have examined production and consumption in the United States as well as the energy “mix,” we will focus on the fuel sources that comprise over 57% of the energy used in this country. Crude oil, with refined products, and natural gas and related natural gas liquids (NGLs) make-up this large sector.
You have reached the end of Lesson 2. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
In 2008, the price of crude oil on the New York Mercantile Exchange (NYMEX) hit an all-time high of $147 per barrel. And, within (6) months, the price had fallen to about $35. Again, in 2014, oil was over $100/Bbl in June only to fall to below $50/Bbl by December. While many factors led to these "peaks and troughs, the nature of futures trading and the exchange itself made this possible. The New York Mercantile Exchange has been around since the late 1800s. Financial energy commodity contracts, such as futures contracts, are traded on the New York Mercantile Exchange, and it is still the most influential financial energy commodities exchange in the world. Futures contracts are financial tools to hedge against the price fluctuations. In this lesson, we will explore the history of the exchange, how it functions, who participates, what commodities are traded and futures contracts. In this lesson, we will also learn about the NYMEX order flow. Standardized Order Forms are used on the floor of the NYMEX during order execution. All orders placed on the NYMEX to buy or sell contracts are done in a very precise manner where each party involved is fully aware of the details of the transaction.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday at 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
Please take some time to review the optional materials. They will give you context for the rest of the lesson.
Financial energy commodity contracts are traded on the New York Mercantile Exchange (NYMEX). The New York Mercantile Exchange building is located on the Hudson River in New York City and owned and operated by CME Group of Chicago (Chicago Mercantile Exchange & Chicago Board of Trade). NYMEX has offices in other cities as well (Boston, Washington, Atlanta, San Francisco, Dubai, London, and Tokyo.) The New York Mercantile Exchange [63] started in the 1800s. There were scattered markets for the goods in large cities. You can picture a city like New York City and agricultural products being brought in and sold in various parts of it. So, some entrepreneurial businessmen decided that they needed a central exchange. So, in 1872, it was founded as the Butter and Cheese Exchange. In 1880, it was changed to the Butter, Cheese, and Egg Exchange. And then, finally, in 1882, it was changed to its present name, the New York Mercantile Exchange.
Later products would include yellow globe onions, apples, potatoes, plywood, and platinum. Platinum is the only one of these products which is still traded today on the New York Mercantile Exchange. Today, it trades crude oil, heating oil, gasoline, propane, natural gas, platinum, and palladium.
For a quick overview of the Exchange, view this "This is NYMEX" video (2:20 minutes).
The definition given by the New York Mercantile Exchange is “...a legally binding obligation for the holder of the contract to buy or sell a particular commodity at a specific price and location at a specific date in the future.” The key word here is future. These are known as futures. We are buying and selling energy commodities at a future date and time. And again, this is a legally binding obligation. This is what makes exchanges a sound place to conduct business. If you fail to perform under a contractual obligation with the New York Mercantile Exchange, there are both financial and legal ramifications.
The components of a standard NYMEX energy contract are as follows.
Here are the links to the crude oil [64]and natural gas [65] features in NYMEX. These links take you to the crude oil futures quotes [66] and natural gas futures quotes [67]in NYMEX. You can click on the “About This Report” at the bottom right of the table to find the column head explanations. Reported information in the table will be explained later in this lesson.
The trades on the New York Mercantile Exchange between the counterparties are conducted under the International Swaps and Derivatives Association, or ISDA, 2002 Master Agreement. This is a standardized contract under which all financial energy commodity contracts are traded.
One of the primary functions of energy contracts on the New York Mercantile Exchange is that they provide us price discovery. We can establish a price for crude oil, natural gas, heating oil, and unleaded gasoline at any future point in time. Years back, prior to the advent of the New York Mercantile Exchange, no one could really tell what the price was at any point in time. Most trades were conducted over the telephone. But now, with the New York Mercantile Exchange, at any point in time, you can look up the live trading.
The New York Mercantile Exchange is owned by the Chicago Mercantile Exchange, or the CME Group. If you go to cmegroup.com [68], you can find the commodity prices. Under the "Trading" tab, you can find the commodity and then the commodity futures contract.
In addition, this allows us to perform what we call hedging. Hedging is to reduce risk in a transaction. In the case of the futures contracts, it helps us to reduce our price and/or physical risk. We may be concerned about high prices if we're a consumer of energy commodities. We may be concerned about low prices if we are a producer of energy commodities. We may also be concerned about receiving physical supply or having to guarantee physical market. The New York Mercantile Exchange contracts guarantee that.
Remember from microeconomics [69]that a perfectly competitive market has the following characteristics: 1) Nobody has market power 2) Product is homogeneous 3) Information is perfect and 4) There is no barrier to enter and exit. Indeed, such a hypothetical market with all these characteristics doesn’t exist in the real world. However, the futures market is one of the closest markets to the perfect competition. There are many buyers and sellers. There is no or very limited government intervention in this market. There is no significant barrier to enter and exit the market, except the legal and financial responsibility of market participants. Traded products are futures contracts that are standard and homogenous for each commodity. In addition to these, cost of information is relatively low. All these features make the futures market an efficient market. And from microeconomics, we know that in an efficient market 1) price is determined by the market dynamics, 2) price represents the true value of the good, and 3) price fluctuates around the true value of the good. These happen because the futures market is highly related to the cash market. A portion (even though it’s a very small portion) of the futures contracts ends in actual delivery.
Note that an important feature of the futures contracts is, gains and losses to each party is settled every day. This is called marking to market or daily settlement. It’s equivalent to closing the contract each day and opening another one for the next day. When opening the position, either long or short, each party only pays a small amount of money, which called margin requirement. The margin is used for daily gain or loss (daily settlements) due to the price changes. And if the loss is more than amount in the margin account, the party has to immediately deposit more money into the account.
The following lecture will take you through the history of the NYMEX, the type of trading that occurs ("pit" vs. electronic), the major players, the commodities traded, and futures contract specifications.
Figure 1 displays the NYMEX building located on the Hudson River in New York City and the NYMEX trading floor, where all the trades occur. Watch the video lecture at the bottom of this page to learn more about the NYMEX futures contracts.
While watching the Mini-Lecture, keep in mind the following key points and questions:
The following video lecture is 20:30 minutes long.
The lecture notes can be found in the Lesson 3 module in Canvas (Lesson 3: The New York Mercantile Exchange (NYMEX) & Energy Contracts.)
As explained in the video, “ask” is a motion to sell and “bid” is a motion to buy at a specific price. We use the word motion because the traders use hand signals to communicate to one another across the pits. The following video illustrates some of these hand signals. Please watch the 3:37 minute video, Trading Pit Hand Signals [72] below.
All orders placed on the NYMEX to buy or sell contracts are done in a very precise manner with each party involved fully aware of the details of the transaction. As legally-binding agreements, non-performance under a futures contract can have severe financial and legal consequences. Therefore, most phone conversations are taped to ensure the accuracy of the orders placed as well as the results of the execution of those orders. Standardized order forms are used during order execution and daily "check-outs" occur between brokers and their clients for verification of all trades conducted that day. In this section, we will follow a natural gas futures contract trade from the beginning to end for a producer and end-user wishing to lock-in a fixed price for a 12-month period.
While watching the mini-lecture, keep in mind the following key points and questions:
The following video is 10:40 minutes long.
"High Frequency Traders" (HFT) are impacting the market in a huge way by using super-computers to execute high volumes in nano-seconds. To get an explanation of HFT and their impact on the market, view this video (2:29 minutes).
Please watch the following short video (1:55) about the future of the NYMEX trading floor and how electronic trading is affecting the trading pits.
Now that we are familiar with the workings of the Exchange and futures contracts, we will walk through the cash market and its relationship to the financial market in the next lesson.
You have reached the end of Lesson 3. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
Energy is being consumed at every hour of the day everywhere on earth. Thus, energy commodities are being bought and sold constantly to fill this demand. When we are talking about prices for the actual physical production and consumption of natural gas and crude oil, we are talking about the "cash" market. In this lesson, we will explore the ways in which cash prices are established in the physical marketplace, historical pricing, the main publications that report these prices, and the methodologies they use to collect the data.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday, 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
The market where the actual physical commodity is traded is called the spot market. It can also be called the physical market or the cash market. This is similar to the traditional type of market that physical commodities are delivered for immediate sale and use on the spot. There are many local places where the spot market and local spot market price is determined by the local supply and local demand. Consequently, there might be high spot prices at one location and low spot prices at the other location, depending on the local supply and demand.
The actual demand for the physical energy commodity can change over time. In earlier lessons, we learned some of the factors that can affect the demand, for example cold winter days or hot summer days. However, local supply has to be planned by the producers in advance and since producers don’t know the exact demand ahead of time, spot market prices can become very volatile.
Basis represents the difference in price between financial and physical markets. Locational Basis is the difference in value between the financial commodity contract delivery point and other cash points.
The relationship between futures and spot market prices can be explained by parallelism and convergence. These two form the basics of hedging and speculation. The effectiveness of hedging is highly dependent on this relationship.
Parallelism explains the close relationship (high positive correlation) between futures and spot market prices. It basically says futures and spot market prices follow each other (vary together) closely, (with a gap or difference that is called basis). Parallelism recognizes the fact that both financial and physical markets are influenced by similar things.
Close to the expiration date, the futures contract price tends to get very close (converge) to the cash market price. It is called convergence. This happens because they can be substituted, meaning that a futures contract close to its expiration date is similar to having an immediate delivery of the commodity in the cash market.
If the futures price is higher than spot, the futures contract is sold at a “premium” to cash. The converse is true when the spot price is higher and the futures contract is sold at a “discount” to cash, this happens when demand in the spot market is higher than the supply and the spot prices go up.
As explained in the previous lesson, futures contracts expiring in the later month tend to have higher prices, meaning that the closer expiry month usually has a lower price. This is called contango market.
Contango market represents sufficient supply of the commodity in the spot market to meet the demand. In a contango market, contracts with a later expiration date are sold at a “premium” to closer contracts, and close to expiry futures contracts are also sold at a premium to the cash. The “premium” is because of the carrying charges. For example, let’s assume a consumer needs the commodity in three months. The consumer has two alternatives: 1) buy the futures contracts that expire in three months, or 2) buy the commodity in the cash market now and store it for three months.
There are some costs associated with the second alternative (buying the commodity in the cash market and storing it until it is needed). These costs are called carrying charges (carrying costs) and mainly include storage cost, insurance, and cost of borrowed money to finance the commodity.
Because futures contracts don’t require carrying charges, futures contracts with later expiration dates tend to be traded at higher prices. This is the reason that we usually experience a contango market.
There are also situations where the market experiences the inverted behavior. In such situations, futures market that are expiring in later months are traded at lower prices compared to the ones that are expiring in earlier months. This is called “backwardation” or an “inverted market”. This could happen when there is a supply shortage in the cash market. In that case, spot market prices would be higher than the futures market.
Arbitrage is buying the commodity at low price in one market and selling it at higher price in the other market and taking advantage of the price differences and making profit. Arbitrage causes the difference in prices to eventually decrease by balancing the supply in the two markets.
Locational arbitrage opportunity exists in the spot market as low risk. Spot market is spread out geographically and when the price difference in two locations is higher than the costs (mainly transportation cost) it’s a good opportunity for arbitrage.
As explained earlier, futures prices tend to be higher than spot prices and if the basis (price difference between futures and spot market) is higher than the carrying charges, arbitrage opportunity exists between futures and spot market. This arbitrage opportunity causes the convergence.
Even though the prices of energy "futures" influence the physical markets, prices are negotiated outside the infamous and chaotic trade floors of the exchanges. Buyers and sellers, looking at their supply and demand situations, make pricing decisions daily and actually buy and sell the physical commodities. The results of these trades are reported in industry publications and become market indicators for the physical "cash" market.
While watching the mini-lecture, keep in mind the following key points and questions:
The lecture slides can be found in the Modules under Lesson 4: Energy Commodity Logistics - Crude Oil.
Now watch this 6:24 minute video about the cash pricing for the physical pricing of crude oil and natural gas.
Now watch this 8:52 minute video about the publications used for cash pricing of crude oil and natural gas
The following links will take you to each publication's website and some sample publications.
In this lesson, we addressed the physical cash marketplace that, for the most part, deals with the "here and now." Below are some key points you should have learned in this lesson.
You have reached the end of this lesson. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
In the next lesson, we will delve into the financial "futures" markets, whereby commodity prices can be obtained for future months and years.
The term “logistics” has become more and more popular to define the process whereby goods move from the point of manufacturing and production to the point of sale and consumption. UPS® and FedEx® are no longer just in the package shipping business. They now provide a full range of services, from receiving parcels to transporting them via truck, rail, and plane, to storing them in warehouses, and, ultimately, distributing them to their final destinations. All the while, they are tracking packages throughout the entire process, which can also be done by their customers.
The delivery system for energy commodities is no different, as products—either from the wellhead, plant, or refinery—are transported using various methods, stored, and ultimately distributed to places of final consumption. As we explore the ways and methods in which energy commodities are delivered to market, you will see this same basic theme consistently applied.
Additionally, we will learn the “value chain” for energy commodities. That is, what are the costs and revenues along this delivery path?
This graphic illustrates the various steps in the "wellhead-to-burnertip" logistical path for oil and natural gas: aggregation (gathering), the "cleaning" of the raw stream and production of valuable natural gas liquids (NGLs) and, the steps for getting crude oil and natural gas from the wells all the way to market. As you can see, there is processing of natural gas or refining of crude, the transportation and storage and, finally, the distribution and retail delivery to the various end-users. As you will see, each step along this "path" will have some costs associated with it, and most will represent an opportunity for generating revenue. These will add to the total profit that can be derived from the initial wellhead production.
Over the years, many industries have been regulated by the federal government. But one by one, they became "deregulated" over time. The banking and airline industries were once heavily regulated, as was the telephone business. In exchange for federally-approved rates of service and a set return on investment, companies were given exclusive franchises, or service territories. Today, the deregulation of formerly regulated businesses has spurred on competition and stimulated new products and services. The natural gas and crude oil businesses followed behind, but eventually became deregulated as well. The chain of events leading up to that, and the current regulatory status of these industries, is presented in this lesson.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday, 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
The refining of crude oil is a complex process. In preparation for this topic, please complete the reading assignment below. My lecture will closely follow the steps in refining as outlined here.
Crude Oil Refining Process
Go to "How Oil Refining Works" [80] and read pages 1 through 6 in preparation for the mini-lecture on Crude Oil Refining. As you read the sections, keep these questions in mind:
Also, see "A Brief History of Energy Regulations" [81] and read the "Overview" and "Oil Market Policies."
The following mini-lecture traces the flow of crude oil from the wellhead to the refinery using various forms of transportation. We also discuss the two global standards for crude oil, West Texas Intermediate, and Brent North Sea. The major supply/demand districts in the US are presented, as well as supply and demand statistics.
The history of regulation for crude oil and liquids pipelines goes back to the first regulation of the railroads in the 1800s. A fear of a monopoly by the few railroads in existence prompted the US government to form the Interstate Commerce Commission. The body was later given jurisdiction over interstate crude oil pipelines based upon the same monopoly fears. Today, that responsibility lies with the Federal Energy Regulatory Commission (FERC).
Under federal regulations, pipelines must file “just and reasonable” rates and provide access to any shipper requesting space, if available.
While watching the mini-lecture, keep in mind the following key points and questions:
The following lecture is split into two parts.
The first video is 11 minutes long.
The second video explains the PADDs and crude oil supply and demand from these regions. This video is 6:07 minutes long.
Figure 2 displays the price difference between Brent and WTI crude oil. As you can see in this graph, there has always been a price difference between WTI and Brent. Before 2011, this difference was very small with Brent being slightly cheaper than WTI. In 2011, increased domestic light crude oil production, along with pipeline and transportation limitations, caused the WTI to be traded at a lower price with a larger gap compared to Brent. Recently, infrastructure limitations are decreasing and the difference is once again becoming smaller; and WTI can be supplied to the Gulf of Mexico. The green area in this graph indicates the price difference. More recent charts and data can be found here [88].
Please review Figure 1 and Figure 2 in Lesson 2 [89] to see the upward trend in oil production and the downward trend in oil imports for the same time period.
The following links provide good resources for the U.S. pipeline infrastructure:
Please go to this map on Pipeline 101.org [85] and find Cushing, OK.
More information about tankers can be found on this article, "Oil tanker sizes range from general purpose to ultra-large crude carriers on AFRA scale [86]", on the EIA website.
Figure 3 is drawn from the EIA data for the U.S. Crude Oil Refinery Receipts by mode of transportation in 2020. As you can see, pipelines transport the largest portion of domestic crude oil, and tankers transport the largest portion of foreign crude oil to the refineries.
The following mini-lecture presents each phase of the crude oil refining process and the various products that are extracted from each barrel of oil.
While watching the mini-lecture, think about the following:
As explained in previous lessons, crude oil is one of the energy commodities that are traded on the NYMEX. Its symbol is CL. We refer to this as West Texas Intermediate or WTI crude. It is low sulfur, and so, therefore, is given the nickname sweet crude. The NYMEX contract for crude oil was initiated in 1983. Every contract represents 1,000 barrels, which is the equivalent of 42,000 gallons of oil. Price quotes on the New York Mercantile Exchange are all US dollars and cents per barrel. The minimum price fluctuation, the amount that the price has to move for a trade to take place, is one cent per barrel, or $10 per contract.
The delivery point for crude oil under this contract is what's known as FOB, or free on board, or delivered to the seller's facilities at Cushing, Oklahoma and to any pipeline or storage facility with access to Cushing Storage, TEPPCO, or Equilon pipelines. So, if you buy or sell crude oil contracts on NYMEX for a particular month, you are obligated to either receive the crude oil or deliver the crude oil at Cushing, Oklahoma.
The delivery point for the NYMEX Crude Oil contract is the Cushing Hub in Cushing, OK, USA. It is the world's largest crude oil storage facility and represents 16% of the US capacity. It has been in the news over the last few years as TransCanada seeks approval for its Keystone XL pipeline and, as the excess supply at Cushing looks for new outlets to the Gulf of Mexico refineries.
While watching the following mini-lecture, please keep in mind the following key points:
The lecture slides can be found in the Modules under Lesson 3: The New York Mercantile Exchange (NYMEX) & Energy Contracts in Canvas.
You have reached the end of this lesson, Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
This graphic illustrates the various steps in the process of getting crude oil and natural gas from the wells all the way to market. As you can see, there is wellhead aggregation (production & gathering), the cleaning (processing and refining) of the raw stream, and production of valuable natural gas liquids (processing or refining), the transportation and storage, and finally, the distribution and retail delivery to the various end-users. As you will see, each step along this "path" will have some costs associated with it, and most will represent an opportunity for generating revenue. These will add to the total profit that can be derived from the initial wellhead product.
Watch the following video about natural gas (3:38 minutes).
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday, 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
From Wellhead to Burnertip
While reading each of these short descriptions, try to visualize the movement of the natural gas through each stage and what exactly is occurring. We will go into more detail for each of these steps in the mini-lectures.
Read the following sections on the NaturalGas.org [95] website.
Please go to this page "Understanding Henry Hub [105]" from the CME Group. Read the content on the page and watch the video (2:59).
Go to the EIA website and read the following sections from “Nonrenewable Sources [20]”:
The first step in the movement of natural gas from the “wellhead-to-burner tip” is to determine the "deliverability," or sales volume of the well and then get it connected to a pipeline. This is normally done by midstream companies who gather wells together and deliver the gas to processing plants or directly into transmission pipelines.
The following mini-lecture explains these concepts in detail.
While watching the mini-lecture, keep in mind the following questions:
Natural gas that is going to be injected into the pipeline has to meet the pipeline specifications and has to have more than 98% methane. The second step in the logistics chain for natural gas is the processing of the produced gas. Processing is done for two main purposes: 1) removing other heavy hydrocarbons and removing the contaminations. Other extracted hydrocarbons, natural gas liquids (NGLs) and condensates are marketable and can be sold.
The first mini-lecture explains the refining and processing of natural gas. The second one focuses on the NGLs, their applications, and their market.
While watching the mini-lecture, keep in mind the following key points:
Once the raw natural gas stream has been processed, it is now “commercial grade” or “pipeline quality” natural gas. The outlet, or residue, side of the processing plant delivers the gas to the transmission pipelines. The primary function of transmission pipelines is to move the gas from the producing basins to the market areas.
The following mini-lecture will illustrate the function and operation of the transmission pipeline systems.
While watching the mini-lecture, keep in mind the following key points:
Natural gas storage facilities provide the industry with flexibility. During times of “peak” demand such as harsh winters or extremely hot summers, utilities can rely on supplies stored beneath the ground. Likewise, during times of low demand, excess supplies can be stored for when they are needed. For savvy marketers, storage capacity can be used to take advantage of the price fluctuations in the market. There are three main types of natural gas storage facilities: depleted oil & gas reservoirs, salt caverns, and aquifers.
The following lecture covers the types of natural gas storage, traditional and current uses, and the industry players who use storage capacity and why.
While watching the mini-lecture, keep in mind the following key points:
The final step in the logistics chain for natural gas is delivered to the burner tip. This can be accomplished by Local Distribution Companies (“gas companies”), or pipelines can deliver gas directly to connected end-users. We generally classify the end-users as utility, residential, commercial, and industrial.
The following lecture explains the function of Local Distribution Companies (LDCs) and presents various other natural gas end-user groups.
While watching the mini-lecture, keep in mind the following key points:
While watching the mini-lecture, keep in mind the following key points:
All pipelines are regulated by the Federal Energy Regulatory Commission, which has rules for how they conduct business. The services that pipelines provide and the rates they charge must be posted on their websites. These requirements came about after years of heavy regulation, which eventually led to de-regulation of the industry and a more competitive environment.
You have reached the end of this lesson. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
We've learned that NYMEX energy contracts represent the actual right to buy or sell energy commodities. So, for the commercial market participants, these provide both a market for production and a source of supply. For instance, producers of natural gas, crude oil, or refined products such as heating oil and gasoline, can sell financial contracts, thus guaranteeing that they will have a firm market in the future at a fixed price. Conversely, consumers of these same products can buy contracts to ensure that they will have a firm supply source in the future at a set price. Utilizing financial contracts to reduce price and/or commodity risk is known as "hedging." In this lesson, we will discover the ways in which commercial players in the energy industry use the financial markets for hedging their risks.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday at 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
Seng - Chapter 6
Errera & Brown - Chapter 5
This text is available to registered students [112] via the Penn State Library.
In Lesson 3, we defined an energy futures contract and the function of the NYMEX. We also identified the two main participants in financial energy markets as “commercial” and “non-commercial” players.
Commercial entities have an interest in the commodity itself due to the particular business they are in. For example, an oil refinery not only needs actual crude oil but also has a stake in the future price of oil. This is the basic feedstock for all of the refined products they produce and, therefore, their profitability is impacted by the purchase price of crude.
In addition, refiners sell products such as gasoline and heating oil, both of which are traded in the financial markets. So, the refiner’s profit is also dependent on the feedstock price for crude and the market price for what it produces.
On the other hand, exploration and production companies need to know the future market price of the crude oil they will extract from their wells.
The same holds true for natural gas. In some cases, natural gas is a component of manufacturing costs in such industries as fertilizers and food processing. In the power industry, the price of natural gas impacts the cost of generating electricity. And for midstream processors, natural gas is the main component for the extraction of valuable natural gas liquids (NGLs).
E&P companies that produce natural gas can also see the future market prices for their production.
Keeping in mind that futures contracts are legally binding obligations to buy or sell a commodity, they guarantee a market for producers and a source of supply for consumers. They also guarantee a set or “fixed” price, thereby reducing price risk as well.
In Lesson 4, we learned about the spot market (it is also called the physical market, or the cash market), as the market where the actual physical commodity is traded. Local spot market price is determined by the local supply and local demand, and it can become very volatile because local supply has to be planned by the producers in advance and producers don’t know the exact demand ahead of time. The difference between financial and physical market prices is called basis.
The effectiveness of hedging is highly dependent on the relationship between futures and spot market prices. This relationship can be explained by parallelism and convergence.
Parallelism represents the close relationship between futures and spot market prices, and the fact that both are influenced by similar factors. Parallelism explains the fact that futures and spot market prices track each other (they are highly correlated). The fact that futures contract price tends to get very close to the cash market price is called convergence.
Commercial parties could enter the financial energy marketplace to reduce their supply and/or price risk. For instance, a producer has a commodity and needs a market. In the futures market, they will sell contracts and thus create a future market for their natural gas, crude, etc. This guarantees that a counterparty will take their production and will do so at a known, fixed price. Consumers of energy do not have the commodity. Therefore, they can buy contracts in the futures markets. For them, this guarantees that a counterparty will provide the commodity and will do so at a known, fixed price.
Exxon-Mobil, the largest producer of natural gas in the US, wishes to sell some of its production for December at the current market levels since those prices help them meet earnings targets. To mitigate the price risk that can occur between now and December, they will sell the financial NYMEX contracts. Thus, they are guaranteed a market at Henry Hub at a fixed price when the December production month comes around. They can do this for any month up to the 118 months that the Natural Gas contract trades.
In the case of a natural gas midstream company engaged in the gathering and processing of natural gas, their profit depends on the changes of the price of natural gas (their feedstock) and the natural gas liquids (NGLs) that they produce. Let's say they are concerned about rising natural gas prices. They can buy December contracts and thus be guaranteed supply at Henry Hub at a fixed price when the December production month comes around.
In each of the above cases, the counterparty to the contracts will be responsible for delivering or taking the crude oil at Cushing, OK or, the natural gas at Henry Hub, LA. Per the NYMEX contracts, this is legally binding. That is what guarantees both the supply & market as well as the price.
Physical players (commercial parties active in the spot market) are subject to price risk in the spot market. They can take a financial position which is opposite to their physical position, in order to mitigate the price risk. This is called simple hedging. This is much the same as one who bets on the “favorite” in a horse race, but “hedges” that bet by also placing bets on another possible winner. They hope to mitigate their losses should the favored horse not win.
Futures prices, for any commodity, are deemed to represent the “market” as it is known at the moment. (We also addressed, in Lesson 3, the idea of the “price discovery” that futures markets provide.) A producer is considered to have sold “at market” at the time they enter into futures contracts. But we know that prices will change between the time this deal was transacted and the time the actual commodity changes hands. This fluctuation will impact the perception of the actual cash price until the delivery month arrives and the “real” price is established through physical, cash, trading (as reflected in the cash price "postings" we spoke about in Lesson 4). (The fluctuation of cash and futures throughout the life of the contract is known as, "parallelism"). Cash and futures prices tend to approximate one another at the "settlement" of the financial contracts, thus, allowing them to move "in sync". This concept is called "convergence".
In Lesson 3, we also said that less than 2% of all futures contracts actually go to delivery, that is, the physical commodity does not usually change hands as a result of the financial transactions. (Think about the non-commercial players. They neither have, nor want, the actual physical commodities. They are just trading price.) So, how does this “hedging” work?
Hedge includes taking two equal but opposite positions in the cash and futures market. In that case, gain and loss in one market is offset by loss and gain in the other market and the hedger’s risk exposure will be reduced or eliminated.
Assume the current spot market price for crude oil is $60/bbl. A crude oil producer is planning to sell 500,000 barrels of crude oil in the cash market in December (they are said to be “long” the commodity). As we learned in Lesson 4, commodity prices in the spot market (cash or physical market) are affected by the local supply and demand. Consequently, spot market prices are more volatile than the futures prices and the producer is subject to price risk until December.
Assume the current NYMEX December futures market price is $61.00. In order to hedge the December price against the price fluctuations, the crude oil producer has to take the short position (the opposite of the physical position) in the financial market and sell 500 December crude oil contracts. When the hedger has the long position in the spot market and the short position in the financial market, it is called seller's hedge or short hedge. In this case, the price is now set at $61.00 for December delivery of West Texas Intermediate Crude Oil at the Cushing, OK, Hub.
However, the crude oil producer is intending to sell the product in the spot market and not interested in delivering the crude oil at the Cushing, OK, Hub. And remember that all December futures contracts must be financially settled at the end of November according to the rules of the exchange. So, by the end of November, the producer must buy back the contracts in order to balance their financial position (close the position). Remember, if producer doesn't close the financial position, they have to deliver the crude oil to Cushing, OK, Hub.
So, what happens to the price that the producer will receive when they actually sell their crude oil in the December cash market? Since the futures pricing represents the “market,” the December futures prices rose and fell as the contracts traded. Both the value of the futures contracts that the producer sold, as well as the cash price (market), fluctuated throughout the life of the December futures contract trading. When the producer had to buy back the futures contracts on final settlement day, if the contract price had risen, they took a loss on their financial transaction. But what happened in the cash market? Since futures rose, so did cash, thus providing a gain in the physical market for the producer. Conversely, if futures prices had fallen by final settlement, the producer would’ve paid less for buying the futures contracts back and made a profit on the financial transaction. However, since the futures market declined, so did the cash market, thus lowering the actual price the producer received when the December crude oil production was sold in the physical market.
In both of these scenarios, the gain or loss in the financial market is offset by a corresponding and opposite gain or loss in the physical cash market. If the spot and financial markets move exactly in tandem, this results in a perfect hedge. We refer to a “perfect” hedge when there is a 1:1 correlation between the financial and physical markets.
Example 1: Assume the price has gone down. On November 1st the spot market prices are $59.3/bbl and in that case (assuming perfect hedge) the December futures contract would be $60.30/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Long Price = $60/bbl |
Short Producer sells 500 December contracts Price = $61/bbl |
|
November 1st | Price = $59.30/bbl Loss = (59.30-60)*500,000 = - $350,000 |
Close the position: Producer buys 500 December contracts Price = $60.30/bbl Profit = (61-60.30)*500,000 = $350,000 |
-$350,000 + $350,000 = 0 |
In this case, the loss in the spot market is offset by the profit in the financial market.
Example 2: Assume the price increased and on November 1st the cash prices are $60.50/bbl. In that case (assuming perfect hedge) the December futures contract would be $61.50/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Long Price = $60/bbl |
Short Producer sells 500 December contracts Price = $61/bbl |
|
November 1st | Price = $60.50/bbl Profit = (60.50-60)*500,000 = $250,000 |
Close the position: Producer buys 500 December contracts Price = $61.50/bbl Loss = (61-61.50)*500,000 = - $250,000 |
$250,000 + (-$250,000) = 0 |
As we can see in the above table, the profit in the spot market is offset by the loss in the financial market.
Assume a refinery is planning to buy the same amount of crude oil in the same spot market and the refinery wants to hedge the December price and its profit against the price fluctuations. The refinery is said to be “short” the commodity and having the short position in the spot market. In order to hedge, the refinery has to buy 500 December futures contracts (1000 bbl each) in the financial market and sell them by the end of November (closing position). This is called buyer's hedge or long hedge, which is opposite to the seller's hedge.
Example 3: Assume on November 1st, the spot market prices are $59.3/bbl and in that case (assuming perfect hedge) the December futures contract would be $60.30/bbl.
Date | Cash market | Financial Market | Net |
---|---|---|---|
Now | Short Price = $60/bbl |
Long Refinery buys 500 December contracts Price = $61/bbl |
|
November 1st | Price = $59.30/bbl Profit = (60-59.30)*500,000 = $350,000 |
Close the position: Refinery sells 500 December contracts Price = $60.30/bbl Loss = (60.30-61)*500,000 = - $350,000 |
$350,000 + (-$350,000) = 0 |
The profit in the spot market is offset by the loss in the financial market.
Example 4: Assume prices increased and on November 1st the cash prices are $60.50/bbl and in that case (assuming perfect hedge) the December futures contract would be $61.50/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Short Price = $60/bbl |
Long Refinery buys 500 December contracts Price = $61/bbl |
|
November 1st | Price = $60.50/bbl Profit = (60-60.50)*500,000 = -$250,000 |
Close the position: Refinery sells 500 December contracts Price = $61.50/bbl Loss = (61.50-61)*500,000 = $250,000 |
-$250,000 + $250,000 = 0 |
As we can see in the above table, the refinery's loss in the spot market is offset by the profit in the financial market.
Note that based on the concept of "convergence", getting close to the expiration date, the final settlement price for the December crude oil contract on the NYMEX would represent the cash market price for that month.
This process can be performed many times over by the producers and consumers as desired. Thus, suppliers and end-users can establish a fixed-price and hedge against the price fluctuations. And theoretically, they can do so for as many future months as the particular contact allows (this is dependent on the number of market participants willing to trade that far out).
As we learned previously, the perfect hedge can remove the price risks for sellers and buyers in the spot market. In the perfect hedge, we assume spot and financial market move exactly in tandem and prices in both markets are perfectly correlated, which means the case basis (the difference between spot and futures prices) stays unchanged. However, this assumption is not very realistic. Spot and futures market prices are highly correlated (parallelism) but the correlation is not usually perfect and basis changes over time. In that case, hedging is still effective, but it doesn’t eliminate the price risk. The hedger’s gain and loss in the spot and futures market are not fully offset, and the hedger will end up with some gain or loss. This is called imperfect hedge. Note that the gain or loss of hedging will be much less than not utilizing hedge.
Following the example from the previous page, assume the price has gone down between the time of selling the futures contract and November 1st and the basis has changed a bit (imperfect hedge). Let's explore two cases:
Example 5: On November 1st, the spot market prices are $59.50/bbl and the December futures contract would be $60.60/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Long Price = $60/bbl |
Short Producer sells 500 December contracts Price = $61/bbl |
|
November 1st | Price = $59.50/bbl Loss = (59.50-60)*500,000 = - $250,000 |
Close the position: Producer buys 500 December contracts Price = $60.60/bbl Profit = (61-60.60)*500,000 = $200,000 |
-$250,000 + $200,000 = -50,000 |
Example 6: November 1st the spot market prices are $59.60/bbl and the December futures contract would be $60.40/bbl:
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Long Price = $60/bbl |
Short Producer sells 500 December contracts Price = $61/bbl |
|
November 1st | Price = $59.60/bbl Loss = (59.60-60)*500,000 = - $200,000 |
Close the position: Producer buys 500 December contracts Price = $60.40/bbl Profit = (61-60.40)*500,000 = $300,000 |
-$200,000 + $300,000 = 100,000 |
As the results show, gain or loss in the spot market are not fully offset by the loss or gain in the financial market. But hedging is still effective in reducing the risk.
Now, let's assume the price goes up from the time of selling the futures contracts in NYMEX to November. We consider two cases:
Example 7: November 1st, the cash prices are $60.35/bbl and the December futures contract would be $61.50/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Long Price = $60/bbl |
Short Producer sells 500 December contracts Price = $61/bbl |
|
November 1st | Price = $60.30/bbl Profit = (60.35-60)*500,000 = $175,000 |
Close the position: Producer buys 500 December contracts Price = $61.50/bbl Loss = (61-61.50)*500,000 = - $250,000 |
$175,000 + (-$250,000) = -75,000 |
Example 8: November 1st the cash prices are $60.50/bbl and the December futures contract would be $61.40/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Long Price = $60/bbl |
Short Producer sells 500 December contracts Price = $61/bbl |
|
November 1st | Price = $60.50/bbl Profit = (60.50-60)*500,000 = $250,000 |
Close the position: Producer buys 500 December contracts Price = $61.40/bbl Loss = (61-61.40)*500,000 = - $200,000 |
$250,000 + (-$200,000) = 50,000 |
Following the example from the previous page, assume prices have gone down from the time the refinery buys the future contracts until November 1st. Let's consider the above cases:
Example 9: On November 1st, the spot market prices are $59.50/bbl and the December futures contract would be $60.60/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Short Price = $60/bbl |
Long Refinery buys 500 December contracts Price = $61/bbl |
|
November 1st | Price = $59.50/bbl Profit = (60-59.50)*500,000 = $250,000 |
Close the position: Refinery sells 500 December contracts Price = $60.60/bbl Loss = (60.60-61)*500,000 = - $200,000 |
$250,000 + (-$200,000) = 50,000 |
Example 10: On November 1st, the spot market prices are $59.60/bbl and the December future contract would be $60.40/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Short Price = $60/bbl |
Long Refinery buys 500 December contracts Price = $61/bbl |
|
November 1st | Price = $59.60/bbl Profit = (60-59.60)*500,000 = $200,000 |
Close the position: Refinery sells 500 December contracts Price = $60.40/bbl Loss = (60.40-61)*500,000 = - $300,000 |
$200,000 + (-$300,000) = -100,000 |
Now let's assume price increases considering two cases:
Example 11: On November 1st, the cash prices are $60.35/bbl and the December futures contract would be $61.50/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Short Price = $60/bbl |
Long Refinery buys 500 December contracts Price = $61/bbl |
|
November 1st | Price = $60.35/bbl Profit = (60-60.35)*500,000 = -$175,000 |
Close the position: Refinery sells 500 December contracts Price = $61.50/bbl Loss = (61.50-61)*500,000 = $250,000 |
-$175,000 + $250,000 = 75,000 |
Example 12: On November 1st, the cash prices are $60.50/bbl and the December futures contract would be $61.40/bbl.
Date | Cash Market | Financial Market | Net |
---|---|---|---|
Now | Short Price = $60/bbl |
Long Refinery buys 500 December contracts Price = $61/bbl |
|
November 1st | Price = $60.50/bbl Profit = (60-60.50)*500,000 = -$250,000 |
Close the position: Refinery sells 500 December contracts Price = $61.40/bbl Loss = (61.40-61)*500,000 = $200,000 |
-$250,000 + $200,000 = -50,000 |
As we can see from the above examples, imperfect hedge doesn’t fully eliminate the price risks. In this case, hedging is still effective and gain or loss is much less than the case of not using the hedge.
As we learned in the previous pages, gain and lose in hedging depends on the basis. Predicting the behavior of the basis could create an opportunity for making a profit. This is called arbitrage hedging. For example, from the concept of convergence, we can predict the basis to narrow over time. In a contango market, basis narrows with respect to the storage cost per time. However, in an inverted market, the basis narrows at the expiration date, but this rate is unpredictable.
In a contango market (carrying charges market) when basis narrows, short hedgers make a profit and long hedgers lose. And when basis widens, long hedgers make a profit and short hedgers lose.
In an inverted market (backwardation) when basis narrows, short hedgers lose and long hedgers make a profit. And when basis widens, long hedgers lose and short hedgers make a profit.
Note that in reality, many companies use different hedging techniques to not only reduce the risk but improve the profit.
Futures contracts exist for a limited number of commodities. However, existing futures contracts could also be used to hedge the price risk of relevant commodities that have no futures contract market. This is called cross-hedging.
Over the past few weeks, you have been researching various Fundamental Factors that can be used to aid in making trading decisions. In the next two lessons, we will explore quantitative methods and price analysis.
You have reached the end of this lesson. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
In the previous lesson, we learned about risk management and hedging. In this lesson, we will learn more about the quantitative methods in risk management.
We will review some basic statistics topics, such as variance standard deviation as measures for dispersion, and learn how to apply them to the price data for our risk evaluations.
We will also learn about correlation, which basically explains how two variables are related, how two variables change together, and, if they are highly correlated, how they tend to move together.
Statistics can help traders evaluate and estimate price changes. Statistics could be used to summarize the data and also provide the accuracy of that summary. It can also be used to explore the relationship between parameters.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday, 11:59 p.m. Eastern Time.
Variation of a parameter, such as price data, is an important factor in risk management. A commodity with high price variation is considered a high-risk investment. Consequently, variation and measures of dispersion are among the useful information for traders and investors.
As we learned in the previous section, variance and standard deviation (square root of the variance) indicate variation in the data. Standard deviation measures the amount of variability or dispersion around the average. Standard deviation is more useful than variance, because it has the same unit as the parameter that it is representing, which makes it easier to compare and interpret the changes in price.
Standard deviation can be used as a measure of volatility. Volatility is a term for measuring the dispersion (in the prices, returns, …), which is widely used in the financial arena. Intuitively, when prices are volatile, it means prices have been changing a lot. Volatility is calculated based on the standard deviation. Volatility substantially affects the value of many financial instruments such as options (we will get to this in future lessons).
Note that standard deviation is dependent on the price level; commodities with higher price levels could have a higher standard deviation. So, calculated standard deviations have to be compared appropriately.
Example: The following table includes 10 prices for the NYMEX crude oil February futures contracts in January 2018 extracted from EIA. We are going to calculate the 10-period mean, variance, and standard deviation of these prices:
Date | Price | 10-period Average |
Difference (distance) |
Squared Difference |
10-period Sample daily Variance |
10-period Sample daily Standard Deviation |
---|---|---|---|---|---|---|
Jan 02, 2018 | 60.37 | -2.19 | 4.77 | |||
Jan 03, 2018 | 61.61 | -0.95 | 0.89 | |||
Jan 04, 2018 | 61.98 | -0.58 | 0.33 | |||
Jan 05, 2018 | 61.49 | -1.07 | 1.13 | |||
Jan 08, 2018 | 61.73 | -0.83 | 0.68 | |||
Jan 09, 2018 | 62.92 | 0.36 | 0.13 | |||
Jan 10, 2018 | 63.6 | 1.04 | 1.09 | |||
Jan 11, 2018 | 63.81 | 1.26 | 1.58 | |||
Jan 12, 2018 | 64.22 | 1.66 | 2.77 | |||
Jan 16, 2018 | 63.82 | 62.56 | 1.26 | 1.60 | 1.67 | 1.29 |
Note that the equation to calculate the sample variance is where is the average (10-period moving average) and represents the observations (each price data).
So, in order to calculate the sample variance, we need to calculate the summation of the fifth column and divide the summation by 9 (n-1).
Note that standard deviation is just the square root of the variance (the last column).
Note: Excel functions STDEV() or STDEV.S() can conveniently calculate the standard deviation of a price vector.
We can calculate the standard deviation for a moving window of prices. In that case, we include a new price data each time and remove the oldest price data for calculating the new standard deviation. This is called moving [118] (rolling or running) standard deviation.
Example: The following table shows the price data for the NYMEX crude oil February futures contracts in January 2018 extracted from EIA. We are going to calculate the 10-period moving mean, variance, and standard deviation:
Calculating the moving standard deviation, like what we did in the previous example, is not very straightforward. So, we will just use the Excel function STDEV() or STDEV.S() to calculate the 10-period moving standard deviation.
Date | Price | 10-period Sample daily Standard Deviation |
---|---|---|
2-Jan-18 | 60.37 | |
3-Jan-18 | 61.61 | |
4-Jan-18 | 61.98 | |
5-Jan-18 | 61.49 | |
8-Jan-18 | 61.73 | |
9-Jan-18 | 62.92 | |
10-Jan-18 | 63.6 | |
11-Jan-18 | 63.81 | |
12-Jan-18 | 64.22 | |
16-Jan-18 | 63.82 | 1.29 |
17-Jan-18 | 63.92 | 1.10 |
18-Jan-18 | 63.96 | 1.04 |
19-Jan-18 | 63.38 | 0.95 |
22-Jan-18 | 63.66 | 0.72 |
23-Jan-18 | 64.45 | 0.43 |
24-Jan-18 | 65.69 | 0.65 |
25-Jan-18 | 65.62 | 0.79 |
26-Jan-18 | 66.27 | 1.00 |
29-Jan-18 | 65.71 | 1.06 |
30-Jan-18 | 64.64 | 1.02 |
31-Jan-18 | 64.82 | 0.98 |
There are many parameters to calculate the volatility. One indicator is calculating the moving (rolling) standard deviation for the changes of price rather than the actual price.
A change in price is also called a return in finance. It can be simply calculated as:
Example:
We calculate the price changes (return) in the third column and then calculated the 10-period daily standard deviation for the returns. This is a measure for volatility.
Feb. Futures crude oil NYMEX | Arithmetic Change | 10-period daily standard deviation | |
---|---|---|---|
2-Jan-18 | 60.37 | ||
3-Jan-18 | 61.61 | 2.05% | |
4-Jan-18 | 61.98 | 0.60% | |
5-Jan-18 | 61.49 | -0.79% | |
8-Jan-18 | 61.73 | 0.39% | |
9-Jan-18 | 62.92 | 1.93% | |
10-Jan-18 | 63.6 | 1.08% | |
11-Jan-18 | 63.81 | 0.33% | |
12-Jan-18 | 64.22 | 0.64% | |
16-Jan-18 | 63.82 | -0.62% | 0.93% |
17-Jan-18 | 63.92 | 0.16% | 0.78% |
18-Jan-18 | 63.96 | 0.06% | 0.88% |
19-Jan-18 | 63.38 | -0.91% | 0.80% |
22-Jan-18 | 63.66 | 0.44% | 0.85% |
23-Jan-18 | 64.45 | 1.24% | 0.85% |
24-Jan-18 | 65.69 | 1.92% | 0.83% |
25-Jan-18 | 65.62 | -0.11% | 0.86% |
26-Jan-18 | 66.27 | 0.99% | 0.93% |
29-Jan-18 | 65.71 | -0.85% | 1.08% |
30-Jan-18 | 64.64 | -1.63% | 1.08% |
31-Jan-18 | 64.82 | 0.28% | 1.14% |
Note:
Return can be calculated using the mathematical method or using the natural log method. Log change (return) can be calculated using the following equation:
In the following table both methods are used to calculate the price change (return). As you can see, surprisingly, both methods give very similar values. The natural log method might be preferred for computational purposes.
Feb. Futures crude oil NYMEX | Arithmetic Change | Natural Log Change | |
---|---|---|---|
2-Jan-18 | 60.37 | ||
3-Jan-18 | 61.61 | 2.05% | 2.03% |
4-Jan-18 | 61.98 | 0.60% | 0.60% |
5-Jan-18 | 61.49 | -0.79% | -0.79% |
8-Jan-18 | 61.73 | 0.39% | 0.39% |
9-Jan-18 | 62.92 | 1.93% | 1.91% |
10-Jan-18 | 63.6 | 1.08% | 1.07% |
11-Jan-18 | 63.81 | 0.33% | 0.33% |
12-Jan-18 | 64.22 | 0.64% | 0.64% |
16-Jan-18 | 63.82 | -0.62% | -0.62% |
17-Jan-18 | 63.92 | 0.16% | 0.16% |
18-Jan-18 | 63.96 | 0.06% | 0.06% |
19-Jan-18 | 63.38 | -0.91% | -0.91% |
22-Jan-18 | 63.66 | 0.44% | 0.44% |
23-Jan-18 | 64.45 | 1.24% | 1.23% |
24-Jan-18 | 65.69 | 1.92% | 1.91% |
25-Jan-18 | 65.62 | -0.11% | -0.11% |
26-Jan-18 | 66.27 | 0.99% | 0.99% |
29-Jan-18 | 65.71 | -0.85% | -0.85% |
30-Jan-18 | 64.64 | -1.63% | -1.64% |
31-Jan-18 | 64.82 | 0.28% | 0.28% |
In calculating the volatility, we may prefer to give higher weights to the more recent data. There are many methods of assigning these weights. Exponentially weighted volatility is a common method that uses a decay factor, λ, to apply higher weights to the recent returns and lower weight to the older returns:
Where w is the weight, t is the time and λ is the decay factor. t=0 for today, t=1 for yesterday, and so on. λ is a constant that is defined by the analysts and usually takes a value between 0.99 and 0.94.
For example: Assuming
Today's weight:
Yesterday's weight:
The day before yesterday's weight:
As you can see, older data will have a lower weight (importance).
The average and standard deviation for exponentially weighted values can be calculated as:
There are many other volatility measures that each give some signals and information about the price movement. Some of these measures might be a bit complicated to calculate. Some of these volatility indicators are provided in the NYMEX chart data, such as the Relative Volatility Index [119] (RVI). Relative Volatility Index gives us an indicator of the direction and magnitude of the volatility.
For example, to see the Relative Volatility Index for the WTI crude oil NYMEX futures contracts:
The lower section of the following graph shows the Relative Volatility Index for May 2018 WTI crude oil NYMEX futures contracts. We will learn more about the RVI in lesson 9.
Correlation is a measure of the strength of the linear relationship between two quantitative variables. The equation for the correlation coefficient is:
Correlation coefficient takes a value between -1 and 1. As you can see in the following video, a correlation coefficient of 1 indicates a strong positive linear relationship between two variables and a correlation coefficient of -1 shows a strong negative linear relationship. And if two variables are not related or not linearly related, the correlation coefficient can take a value close to zero.
As we learned in a previous lesson, a high correlation between spot and futures market prices makes the hedging efficient. Note that in the case of backwardation, the correlation between spot and futures would be lower.
The following chart shows the last 10 prices of February 2018 crude oil spot and futures from EIA.
Date | NYMEX Futures [120]$/bbl | Spot [121]$/bbl |
---|---|---|
Feb 14, 2018 | 60.7 | 60.6 |
Feb 15, 2018 | 61.48 | 61.34 |
Feb 16, 2018 | 61.89 | 61.68 |
Feb 20, 2018 | 61.91 | 61.9 |
Feb 21, 2018 | 61.73 | 61.68 |
Feb 22, 2018 | 62.72 | 62.77 |
Feb 23, 2018 | 63.52 | 63.55 |
Feb 26, 2018 | 63.81 | 63.91 |
Feb 27, 2018 | 62.94 | 63.01 |
Feb 28, 2018 | 61.43 | 61.64 |
The following chart displayed the data and, as you can see, they are closely related.
As the following graph shows, we can use the Excel function CORREL() to calculate the correlation between spot and futures for these price data as 0.994, which shows a strong relationship between them.
Note that cross hedging is using futures contracts (for commodity A) in order to hedge the price risk for the commodities (commodity B) that don’t have futures contract market. And cross hedging is possible when the futures price of commodity A are highly correlated with spot prices of commodity B.
Note that we can calculate the correlation of the returns in a similar way to what we did to calculate the volatility (calculating the standard deviation for the returns).
Over the past few weeks, you have been researching various Fundamental Factors that can be used to aid in making trading decisions. In the next two lessons, we will explore quantitative methods and price analysis. The other type of information, used by "day traders," is Technical Analysis. In the next lesson, we will get an elementary overview of Technical Analysis.
You have reached the end of this lesson. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
Thus far, we have addressed the fundamental factors that influence energy prices. We also established that there are two main groups that trade in the financial energy commodities markets, commercial and non-commercial. The latter group represents the “pure” traders or “speculators." These participants are only interested in price movement. The type of commodity does not matter to them. In order to make trading decisions, they use technical analysis as opposed to fundamental analysis.
Technical analysis involves the use of charts to track price movement, establish the current market trend, and determine the probability of prices moving in one direction or another. Simply put, technical or “day” traders are interested in market activity as illustrated by the resulting prices.
Since the prices that occur in the market are the result of human decision-making, technical analysis really examines the behavior of market participants. As such, patterns emerge that have a high probability of recurring. It is precisely these events that technical traders are looking for. But, make no mistake; fundamental events cause traders to react emotionally, the results of which are also reflected in the price action.
In technical analysis, traders must first establish what the current price trend is, up or down. Then, they must determine the probability of the trend lasting or changing direction. It is this information that guides their buy/sell decisions.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday at 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
Seng - Chapter 10
Errera & Brown - Chapter 8
This text is available to registered students [112] via the Penn State Library.
There are several types of charting methods, but three of them are the most popular.
In a bar chart, a vertical line is shown for each time increment selected. In the chart below, a “daily” chart is used to show the May NYMEX contract for natural gas. Each bar shows the price results for that day’s trading. The mark to the left of the bar represents the first trade of the day, or the “Open.” This is the price of the first trade that occurs right after the bell rings to start trading. The vertical line itself represents the full range of prices for the day, that is, the High and Low prices. And the mark to the right of the bar represents the final closing, or “Settlement” price for the day. This is often referred to as the "OHLC" chart (Open/High/Low/Close). Note that if the Open price is lower than the Close, the bar is green. If the Open price of the day is higher than the Close price, the bar is red. It shows the direction of the market movement; do prices tend to go up or down?
You can change the style of the chart and type of information that you want to be displayed by clicking on the Bar Style toolbar and selecting from the list of chart options which include things like bars, candles, line, area, and point & figure. The image below is an example of a “Line” or “Close Only” chart showing the same May natural gas contract. You will notice that it only shows the daily market closing (settlement) price. It provides much less information than the Bar chart and is mainly used for longer-term trend analysis.
Candlestick charts were developed by the Japanese centuries ago. They provide information similar to the Bar chart, but also indicate “up and down” days. That is, they clearly show the direction the market took on a daily basis. The top end of the “candle” still represents the "High" for the day, and the lower end represents the “Low,” but the “body” indicates the Open and Closing prices in relation to one another. For example, if the Open is higher than the Close, the Open price is at the top of the “body” of the candle and represents a day where prices fell (red candle). Conversely, if the Close is found on the top of the “body,” it represents an “up” day, and on the chart below, appears with a green “body.” As you can now see, the up-and-down days are easily visible on the Candlestick chart. By counting these, we can determine the current trend. For traders, the question is, when will it reverse course?
Trend lines can be used to identify both long- and, short-term price trends. They are also used to indicate support and resistance prices and channels (covered later). A trend line only has significance if it touches at least two price points. The chart below shows an obvious long-term downtrend going back one year.
This next chart illustrates two short-term trendlines, one up and one down.
When one trendline connects two or more price points and another trendline connects two or more price points in parallel fashion, they form a “channel,” as shown below. Channels have significance in that traders look for prices to move above or below the confines of the channel. This is referred to as a “breakout,” and depending on the number of days that form the channel, this can occur with good momentum, resulting in a large price move in that direction.
One of the simplest clues to the strength of price movement is that of the volume of contracts traded. If a price shows a large range or change in direction on a particular day, looking at the volume of contracts traded indicates how well-supported that move was by the market participants. A $0.10 movement up or down in natural gas is not very significant if a low volume of contracts is traded. On the other hand, when large volumes trade, that definitely reinforces the price action for the day. It’s as if those trading have agreed on the price outcome. The chart below is a Daily Bar Chart with volume for natural gas. Notice that on April 1st, prices traded in a $0.1 range and a very large amount of contracts exchanged hands, solidifying the move. Also, on March 27th, the second-highest volume for the contract traded. Both of these volumes add legitimacy to the price action for those days.
You can add the volume traded to the chart by clicking on “Indicators, …” on the toolbar and choosing the "Volume" from the resulting list.
For those of you who have had statistics, you should be familiar with the term “reversion to the mean.” For those of you who have not, the concept hinges on the idea that all prices will eventually return to their average, despite dramatic movements up or down. I have found this to be especially true for energy commodities, at least in the short-term. Therefore, tracking commodity moving average prices can be a good signal for a change in the direction of a trend. The chart below shows that the Moving Average (MA) for May 2018, Natural Gas. If prices go up, there is a good probability that they will eventually fall towards the MA. It may be a gradual decline which also means the average will change, but as long as the MA is lower, prices will gravitate towards it. The exact opposite occurs when prices fall below the MA.
Note that the timeframe for the MA is set to the particular trader’s needs. I have set the MA at 5 days, as that represents a full week of trading (regular session, pit trading only occurs on weekdays). See how the prices, while moving above and below the MA, ultimately return to it. This is a key sign for making buy/sell decisions.
You can add the Moving Averages traded to the chart by clicking on “Indicators, …” on the toolbar and choosing the "Moving Average" from the resulting list.
Relative Strength Index (RSI) is a momentum oscillator that measures the speed and change of price movements. RSI oscillates between zero and 100. Traditionally, RSI is considered overbought when above 70 and oversold when below 30. RSI can also be used to identify the general trend. (Technical Indicators and Overlays - ChartSchool [122]) Understanding the exact RSI calculation is not necessary to understand how to use this indicator. The next chart is a Daily Bar Chart with Volume, MA, and now, the RSI study. Note that the current RSI is over "70" which is considered “overbought". This could, therefore, be a signal to "sell."
You can add the Relative Strength Index traded to the chart by clicking on “Indicators, …” icon on the toolbar and choosing the "Relative Strength Index" from the list.
As with trend analysis and market indicators, there are several types of price signals. We will deal with a few of the ones that are more common and easy to use.
As prices move up and down, traders make decisions as to when to continue to buy in an uptrend and when to sell in a downtrend; that is, they try to determine when the current trend will exhaust itself and change direction. One way to do this is to look at the “support” and “resistance” price levels. Support represents a price level at which buyers will step back into the market after a period of selling. This interest establishes a “floor” price. Traders find value at this level and start to buy-up the contracts again. In some cases, traders who have been selling contracts during the downtrend may be buying them back to take some profits. Resistance is the price level at which the market is no longer interested in buying contracts. The price is deemed to be too high and sellers re-enter the market, thus establishing a "ceiling" price.
So, how do we establish these pricing points? As the chart below (shifted to the right) shows, when we draw upper and lower trend lines, the lines continue through price points on the right, vertical axis. Where the upper trend line crosses the right axis is the resistance point, while the price where the lower trend line crosses the right axis is the support point. Theoretically, then, these represent both the maximum the market is willing to pay as well as the minimum at which it is willing to sell.
This chart indicates that resistance and support. Traders will now look to see if prices can trade above, or below, these levels. If they do, there will be a flurry of activity in the direction of the move.
Since we are on the subject of support and resistance, we can discuss price signals related to those concepts. As we have said, traders are interested solely in price movement. And support and resistance levels represent buying and selling interest. So, what happens when the buyers or sellers step in to halt the moves higher or lower? They are testing the points of support and resistance. If the sellers can’t break through support, it is a result of buyers stepping in. As mentioned above, that sets a “floor” or “bottom” price on that day. Likewise, if buyers test the resistance price and sellers step in to prevent a breach of that level, a “ceiling” or “top” is established.
While a one-day occurrence of these events is not a very strong indicator of a change in direction, the more a “bottom” or “top” is tested and holds, the more significant that price level becomes. Think about it this way. Let’s say natural gas Traders are trying to sell May contracts and push the price down to the $2.37 Support level on the chart above. Buyers step in at that price and the sell-off fails. The next day, Sellers again attempt to push prices down to $2.37, and again, the move fails.
Let's assume the market now begins to see $2.37 as a stronger Support price. We refer to this as a “double-bottom.” While this is still a good indicator of price levels, a third day, or “triple-bottom” is a strong indicator that prices could rally higher. Traders have no choice but to recognize the buying interest at $2.37 and thus will buy contracts until the Resistance, or “top” is tested. The same holds true for resistance levels, but in reverse. The more “tops” are established, the stronger the level at which sellers will step in and sell contracts.
Head and shoulder reversal patterns are identifiable, price patterns that signal a change in direction and can be used for long-term or short-term trend analysis. This consists of three trading days where the middle day’s High, or Low, is higher or lower than that of the other two days. The first day then represents the “left shoulder,” the second day is the “head,” and the third day is the “right shoulder.” Using the chart below without all the trend lines, we can see that on June 14th, the High for the day was higher than the 3rd. We are now looking for the completion of the pattern, the right shoulder. And on June 22nd, the High for the day was lower than the head. Now you can see the pattern whereby the 3rd is the “right shoulder,” the 14th is the “head,” and the 22nd is the “right shoulder.” The right shoulder “leans” in the direction of the price change. In this case, prices reversed from an uptrend to a downtrend. There are also “reverse” head-and-shoulders patterns. These occur in an upside-down fashion and signal a move from a downtrend to an uptrend.
When upper and lower trend lines are drawn and are parallel to one another and perpendicular to the Y-axis, they form a rectangular shape. The upper trendline does represent resistance, with the lower trend line indicating support. In this pattern, prices will move up-and-down within the rectangle. This “consolidation” is indicative of market indecision. Traders are not really sure what direction prices should take. It is a battle between buyers and sellers. The key here is the number of days this pattern continues to exist. The longer traders battle, the more momentum builds-up for when prices break-out of this range. Think of it as a spring that winds tighter and tighter for each day prices stay within the consolidation range. That means a very large price movement will occur in the direction of the breakout. A good illustration of this is the May 2021 crude oil contract, shown below. Starting in January, the contract bounded by a Low of about $52 for twenty-four straight days. The High was about $54 with the exception of attempted "break-outs". On February 2nd, prices broke-out to the upside with good momentum.
These are but a few of the methods in Technical Analysis used to try to determine when a greater probability exists of prices moving in one direction vs. another. Once determined, traders enter or exit the market at those price levels.
In addition to my explanations, the definitions of terminology used in Technical Analysis can be found at:
Technical Indicators and Overlays - ChartSchool [122]
In the next lesson, we will explore other, more advanced, financial derivatives that can also be used for hedging. Among these are "swaps", "spreads", and "options". They are mostly traded in the "over-the-counter" markets, that is, non-exchange traded. "OTC" encompasses electronic trading platforms as well as "voice" brokers where transactions occur over the phone.
You have reached the end of this lesson. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
In Lesson 7, we focused on “futures” markets and how simple hedges can be accomplished using exchange-traded contracts. Those provide the "building blocks" for the more advanced hedging tools. Here, we will address the “over-the-counter,” non-exchange traded markets, or “forward” contracts. Keep in mind that NYMEX Exchange contracts are referred to as “futures.” We will also cover financial “spreads” whereby traders take advantage of price differences based on location, time, or inter-commodity relationships. Finally, we will deal with financial options, which are a simpler and less costly form of hedging vs. the financial derivative contracts themselves.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday at 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
Seng - Chapter 7, 8, and 9
Errera & Brown - Chapters 4 & 6
This text is available to registered students [112]via the Penn State Library. [73]
Swaps represent exchanges of payments between two parties. They are financially settled, and no physical commodity is delivered or received by either party. They represent a substitute for the futures contracts but rely on NYMEX pricing to establish the financial arrangement for the swap contract. Similar to a NYMEX contract, the elements of a swap contract include the commodity, location, date, and price.
We use the phrase “fixed-for-floating” swap to signify the prices agreed to by both parties in the contract. The “fixed” price is always the current market price. It is the price known at the time the deal is struck. The exchange of payments will occur when the NYMEX settlement price is known. We refer to this settlement price as the “floating” one, since it is not known until the contract’s last trading day and “floats” with each day’s trading until then. The difference between the two represents the amount of payment due to one party or the other.
For example, as of this writing, the December 2019 NYMEX crude oil contract is trading $62.69. If I bought a swap, I would be setting my contract price at $62.69. On November 20th, 2019, this contract will settle, and the difference between my $62.69 and the NYMEX Final Settlement price that day, will be the amount exchanged between me and my counterparty. If the contract settles at $63.19, since I bought the swap, I would be selling it back at that price for a profit of $0.50 per contract and, my counterparty would pay me $0.50 per contract (1,000 Bbl), or $500. On the other hand, if the contract settled at $62.19, I would be selling the contracts back at a loss of ($0.50) and I would pay my counterparty $0.50 per contract, or $500. The calculations are the same as those shown in Lesson 7's hedging spreadsheet.
As we learned in previous lessons, Futures contracts are standard contracts. However, swaps can be customized. This is another advantage of swaps that make them popular. The advantage of using swaps for hedging is that you can achieve the same price protection without actually having to buy or sell NYMEX contracts. And you can work with brokers either by phone ("Voice" Brokers) or through an electronic trading platform such as "The Intercontinental Exchange (ICE)".
In a previous lesson and in the textbook, we discussed the fact that physical entities wishing to hedge must take a position in the financial market which is the opposite of their physical position. For instance, a crude oil producer is "long" the commodity. Therefore, in order to execute a proper hedge, they must go "short" in the financial derivative they choose. In Lesson 7, I presented how the physical and financial prices interact in a hedge. The same applies to swaps as to the NYMEX contracts themselves.
The following mini-lecture is a summary of the points presented above (3:37 minutes).
“Spread” trading can be used for hedging purposes or purely for trading (“arbitrage”). Spread trading involves taking a long position in one futures contract and simultaneously taking a short position in another, related futures contract. Thus, spread consists of two equal and opposite futures positions. In spread trading, futures or forwards can be used to achieve the desired results. A buy/sell is offset by a corresponding sell/buy. Spread trading involves using price differences in futures or forwards based upon inter-market (time differences, locational differences) and inter-market commodity relationships.
Examples of the types of spreads are:
In addition to traders who are merely interested in price movement to make money, commercial entities can use spreads to hedge their price risk. For example, as mentioned above, a crude oil refiner can buy crude contracts (hedge price of feedstock) and sell heating oil and unleaded gasoline contracts (refined output) to establish a profit margin or “crack” spread. This hedge is illustrated in the spreadsheet, "EBF-301 Lesson 10 refinery hedge.xls" found in Canvas Lesson 10: Advanced Financial Derivatives - Swaps, Spreads, and Options Module.
The following mini-lecture summarizes the points presented above (6:10 minutes).
If one wishes to enter into a contract for underground storage capacity, this transaction can be hedged as well using the time spread.
Example of Time Spread:
Let’s look at an example. The April 2020 NYMEX natural gas contract is trading $2.65 at the time of this writing. We can buy these contracts and that will represent the supply that we would inject into storage in April 2020. Now, we need a market for when we wish to withdraw these same volumes. January 2021 is trading at $3.98, so we would sell the January 2019 futures contracts in the same amount as we bought in April 2020. This creates a “spread” of $0.33. After the respective monthly storage fees are taken-out, we are left with the “net” spread on our storage transaction. This is also known as a “time spread” since it involves a purchase and sale of the same commodity in differing months.
These simple, “fixed-price” hedges are the basic building blocks for more complex financial derivative hedges.
Car insurance is a good example of an option, specifically, a "call" option. A premium is paid and the insured has the right to “call” their insurance agent in the event of an accident. The “price” they will have to pay for the damages is limited to the amount of the deductible (“strike price”). The term is usually one year, and if no claim is made, the “option” expires worthless (i.e. – no payout is made by the insurance company since no claim was made). The insured’s maximum exposure is the deductible, thereby establishing a “ceiling price.” And, the premium is calculated using complicated mathematical models (actuarial tables, statistics & probabilities).
Energy options are very similar in nature. As with most financial derivatives, they can be used for hedging price risk or for outright trading. One key difference is that options represent the buyer’s right, but not the obligation, to buy or sell futures/forwards contracts. The options contracts themselves are not futures or forwards contracts but rather a right to buy or sell those contracts. They are traded on the exchange as well as over the counter. And, the buyer is under no obligation to purchase or sell the underlying commodity contracts if the pricing makes no sense.
Here are some common terms in option contracts:
Call [123]: An option contract that gives the holder the right to buy the underlying security (futures) at a specified price for a certain fixed period of time.
Put [124]: An option contract that gives the holder the right to sell the underlying security (futures) at a specified price for a certain fixed period of time.
Holder [125]: The purchaser of an option.
Premium [124]: The price of an option contract, determined in the competitive marketplace, which the buyer of the option pays to the option writer for the rights conveyed by the option contract.
Strike Price [126]: The stated price which the underlying security (futures) may be purchased (in the case of a call) or sold (in the case of a put) by the option holder upon exercise of the option contract.
Expiration date [127]: The day on which an option contract becomes void.
Intrinsic value [128]: The value of an option if it were to expire immediately with the underlying commodity at its current price; the amount by which an option is in-the-money. For call options, this is the difference between the underlying commodity price and the striking price, if that difference is a positive number, or zero otherwise. For put options, it is the difference between the striking price and the underlying commodity price, if that difference is positive, and zero otherwise.
In-the-money [128]: A term describing any option that has intrinsic value. A call option is in-the-money if the underlying security (commodity) is higher than the striking price of the call. A put option is in-the-money if the security (commodity) is below the striking price.
Out-of-the-money [129]: A call option is out-of-the-money if the strike price is greater than the market price of the underlying security (commodity). A put option is out-of-the-money if the strike price is less than the market price of the underlying security (commodity).
Time Value [130]: The portion of the option premium that is attributable to the amount of time remaining until the expiration of the option contract. Time value is whatever value the option has in addition to its intrinsic value.
While watching the following mini-lecture (16:13 minutes), keep in mind the following key points regarding energy risk hedging using options contracts:
Now watch the following two videos for more details. (9:20 and 6:50 minutes)
The components of an options contract are:
Option types are:
The buyer of an option’s exposure is merely the cost of the option, i.e., the premium. They will never pay more than that. On the other hand, the seller, or “writer,” of an option bears all the risk and is exposed to any price movement above the strike price of the call option, and below the price of the put option.
One of the main advantages is that, since only a premium is paid up front, the buyer of the options can control a large amount of contracts for a small price. For example, with a call option, they are not buying the underlying contracts outright, but are buying the right to purchase them at a set price (“strike price”) if necessary. The buyer could have the right to buy 100 contracts and only have to pay the premium for the option and not pay the total cost of 100 contracts.
So, who would use options contracts for hedging? Let’s take a crude oil refiner as an example. The company is concerned about rising crude oil prices. But rather than go out and buy hundreds of futures contracts and lock-in the price now, they decide to purchase a call option at a strike price that limits their exposure to rising prices. In doing so, they establish a maximum, or “ceiling,” price. So, for December 2018, they buy a crude oil call option at a strike price of $70.00 since the current price is $65.00. If December prices remain below $65.00, the refiner does nothing and is out only the premium. However, should December prices exceed $70.00, the refiner calls the option seller and requests the number of crude oil contracts agreed upon at the $70.00 strike price (or, they could ask for payment of the price difference in the market). In this scenario, the refiner will never pay more than $70.00 for their crude supply. And, they capture all the downside of prices should the market fall.
On the flip side, let’s consider the crude oil producer who is worried about falling prices, so they enter into a put option to establish a “floor” price. For December, they choose a $60.00 strike price, thus establishing the lowest price at which they will have to sell their crude oil. Should prices fall below that level, they will contact the options seller and request their right to sell the underlying financial contracts at $60.00. Should prices remain above $60.00, the producer would do nothing and be out only the price of the option (premium). In this way, the producer can reap all the benefits of higher prices, regardless of how high they go.
If not exercised, options expire worthless, and, options are time-sensitive. The closer to the expiration date, the less value the option has (less risk exposure with less time remaining).
There are numerous mathematical models that are used to determine options premium values. The most well-known is the Black-Sholes model. It is an extensive algorithm that only needs a few inputs to calculate an option’s value.
A spreadsheet with the Black-Sholes model and sample inputs can be found in the Canvas Modules under Lesson 10: Advanced Financial Derivatives - Swaps, Spreads, and Options.
In the next section, we will discuss the need for risk controls in energy commodity trading. Given your understanding of the complexities of financial derivatives, you should now realize how important a system of "checks-and-balances" is for any energy trading company. However, if the controls put in place are not followed, catastrophic losses can occur......Enron.
You have reached the end of this lesson. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
On December 2, 2001, Enron Corp., at the time the world's largest energy trading company, declared bankruptcy, causing a loss of $11 billion dollars for its shareholders and billions more for its trading counterparties. At the time, it was the largest bankruptcy filing in US history. As events unfolded and the investigations took place, it was revealed that there were several "off-sheet," "paper" companies churning-out false earnings. These were "mark-to-market," unrealized earnings, that had no cash gains associated with them. Ultimately, it was a lack of controls, or a failure to adhere to them, that allowed this to occur. Top executives at Enron were convicted and sent to prison, and their outside auditors, Arthur Andersen, would go out of business.
In this lesson, we will learn about other famous cases where financial disasters took place due to a lack of controls and oversight. We will explore concepts such as "mark-to-market," and "value at risk," both financial risk measures that are mandatory for today's publicly-traded energy companies who deal in financial derivatives.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday at 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
Seng - Chapter 11
Read the three case studies on the following pages before viewing the lecture.
In February 1995, Nick Leeson, a “rogue” trader for Barings Bank, UK, single-handedly caused the financial collapse of a bank that had been in existence for hundreds of years. In fact, Barings had financed the Louisiana Purchase between the US and France in 1803. Leeson was dealing in risky financial derivatives in the Singapore office of Barings. He was the lone trader there and was betting heavily on options for both the Singapore (SIPEX) and Nikkei exchange indexes. These are similar to the Dow Jones Industrial Average (DJIA) and the S&P500 indexes here in the US.
In the early 90s, Barings decided to get into the expanding futures/options business in Asia. They established a Tokyo office to begin trading on the Tokyo Exchange. Later, they would look to open a Singapore office for trading on the SIMEX. Leeson requested to set up the accounting and settlement functions there and direct trading floor operations (different from trading). The London office granted his request and he went to Singapore in April 1992. Initially, he could only execute trades on behalf of clients and the Tokyo office for "arbitrage" (Lesson 10) purposes. After a good deal of success in this area, he was allowed to pursue an official trading license on the SIMEX. He was then given some "discretion" in his executions, meaning; he could place orders on his own (speculative, or "proprietary" trading).
Even after given the right to trade, Leeson still supervised accounting and settlements. There was no direct oversight of his "book" and he even set up a "dummy" account in which to funnel losing trades. So, as far as the London office of Barings was concerned, he was always making money because they never saw the losses and rarely questioned his request for funds to cover his "margin calls" (Lesson 3). He took on huge positions as the market seemed to "go his way." He also "wrote" options, taking on huge risk (Lesson 10).
He was, in fact, perpetuating a "hoax" in his record-keeping to hide losses. He would set the prices put into the accounting system and "cross-trade" between the legitimate, internal, accounts and his fictitious "88888" account. He would also record trades that were never executed on the Exchange.
In January 1995, a huge earthquake hit Japan, sending its financial markets reeling. The Nikkei crashed, which adversely affected Leeson's position (remember, he had been selling options). It was only then that he tried to hedge his positions, but it was too late. By late February, he faxed a letter of resignation, and when his position was discovered, he had lost $1.4 billion USD. Barings, the bank which financed the Louisiana Purchase between the US and France, became insolvent and was sold to a competing bank for $1.00!
(If you are interested in more details regarding this infamous case, you can read "Rogue Trader" by Nick Leeson himself. There is also a movie of the same name starring Ewan McGregor which should be available on Netflix or DVD.)
The following two case studies are brief descriptions of similar, catastrophic losses by traders with little, or no, oversight.
Optional video: Nick Leeson, The Rogue Trader
You can watch the complete interview here [131].
Robert Citron was the Treasurer for Orange County, California, in the early 90s. He was solely responsible for investing several of the county’s funds, which totaled about $7.5 billion USD. Despite having no background in trading financial instruments, he decided to invest in risky interest rate swaps that were tied to the US Treasury Department’s rates.
Citron was a County Tax Collector with no college degree who was later elected to the position of Orange County Treasurer. In this capacity, he was able to push for California legislative approval for county treasurers to increase their use of financial instruments for investment and fund management.
He was attempting to arbitrage the difference between short-term and long-term interest rates. His position was sound, and he could make money so long as short-term rates remained low. During his tenure, the average return on county investments was a healthy 9.4%, but interest rates had been low for that long. The position he took would lose money if interest rates rose. And, he inflated the county’s volumetric position by entering into other derivatives that would also be negatively impacted by higher interest rates.
Beginning in February 1994 the Federal Reserve Board made the first of six consecutive interest rate hikes. Between February and May of that year, the County had to produce $515 million in cash (margin) to cover its position. Further margin calls would occur throughout the year, leaving the County's cash reserves at only $350 million by November 1994.
When word got out about the County's troubles raising cash, investors sought to retrieve their money, and by December 6, 1994, the County declared bankruptcy and lost $1.64 billion.
MG was a huge, German industrial conglomerate that decided to open an energy trading office in the US in the early 90s.
The original plan was threefold:
When the strategy was first implemented in 1992, current physical prices were lower than the futures prices. So, the sales contracts were set at those higher future prices. And it meant that purchasing the "near" month futures contracts would be profitable. So, MG developed a strategy whereby they would cover the long-term, fixed-price sales by buying contracts in these few, near months. As each month "rolled off," they would merely buy contracts in the next month. It was their intent to continue this process until the physical product sales contracts expired in 10 years. This strategy worked as long as the futures market was "backwardated," whereby each successive month is lower than the prior one (Lesson 3).
One of the major flaws in this approach, however, was the volume of contracts being traded since they were "loading up" on closer month contracts. Add to that, the fact that they would not get paid for the product sales for years out, and you begin to have a cash flow problem where margin calls are concerned. Their position in the fall of 1993 was estimated to be between 160 and 180 million barrels, stretched out over the following 10 years.
In 1993, prices fell as the market received a "bearish" signal from OPEC on production quotas. This lowered futures prices and reversed the market from "backwardated" to "contango," whereby each successive month's price is higher than the prior one (Lesson 3). Faced with this position, MG management was changed, and the new team was directed to close all positions. This resulted in losses on the futures purchases totaling almost $1.5 billion USD. They had to seek bailout funds from one of their banks, and in return, had to sell off several divisions. Today, the German industrial giant no longer exists, having been bought out by a competitor.
Please watch the following video (6:20).
There were some common themes that ran through each of these cases:
These events, along with others, prompted the financial industry to institute ways to monitor, track and stay on top of, financial derivative trading. These same methods would later have to be adopted by publicly traded energy companies in the US.
Please watch the following 6:33 minute video about Risk Control.
Please watch the following 14 minute video about Risk Control.
You have reached the end of this lesson. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities.
This lesson will focus on the electricity market and introduce the major players and common financial instruments in the market. Since electricity cannot be stored in large volumes at a reasonable cost, part of the job of the power grid operator is to make sure that supply and demand balance at every moment. This means that the power grid is making adjustments every single second (or less than a second) as demand changes. Many of these adjustments are automated responses. This gives unique characteristics to the electricity market that is not common in other energy markets. Unlike transportation cost in the oil and gas market, electricity transmission cost is highly volatile. Because of these characteristics, NYMEX futures contracts don’t add much value to the market, and they are not commonly traded, or the traded volume is very low. Consequently, other financial instruments are being used for the purposes of arbitrage and hedging.
We will learn what is called the "energy market" portion of the PJM market model. The energy market is essentially a set of two connected short-term forward markets. The first, called the "day ahead" market, commits generators to be able to produce electricity 24 hours in advance, based on forecasted demand. The second, called the "real-time" market or "hour ahead" market, commits generators to be able to produce electricity one hour in advance, based on an updated demand forecast. You can think about the day-ahead market as setting a schedule of which power plants should be available to produce energy, while the real-time market shifts those schedules around a little bit based on an improved forecast of electricity demand.
At the successful completion of this lesson, students should be able to:
This lesson will take us one week to complete. The following items will be due Sunday at 11:59 p.m. Eastern Time.
If you have any questions, please post them to our General Course Questions discussion forum (not email), located under Modules in Canvas. The TA and 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.
The majority of this lesson was modified, with permission, from Penn State's EBF 483, Introduction to Electricity Markets written by Dr. Seth Blumsack.
Please read the following pages from the U.S. Energy Information Administration.
Electric power in the United States is a $350 billion per year business and touches literally every corner of the economy. The "power grid" in North America is massive in scale and scope.
The figure below shows the three segments of the electricity supply chain - generation, transmission, and distribution. For nearly a century in the United States, there was one type of vertically integrated company performing all three of these functions. This company, called the "electric utility," generated its own electricity, moved that electricity over its own transmission lines within its geographic service area, and then delivered the power to its customers using its distribution lines. The electric utility usually had its prices, investments, and business practices tightly regulated by individual states. The federal government in the United States did not have a dominant role in the electric utility business until the process of deregulation and reorganization began in the 1990s.
Prior to the process of electricity restructuring, the primary players in the electric power business in the United States were vertically integrated utilities and their state regulators.
Electricity reforms in the United States began in the 1990s. Not all states elected to reform their electric utilities, but most of the states in the northeastern U.S., along with California and Texas, did choose to reform and restructure the electric utility business. Most states in the southern and western US did not choose to undertake electric utility reforms and still have vertically integrated utilities with tight state regulation.
Broadly, the process of electricity reform (sometimes called "deregulation" and sometimes called "restructuring") consisted of the following:
The vertically integrated electric utility was broken up into three separate companies - one each for generation, transmission, and distribution. Oftentimes, the same parent company owned all three businesses as independent subsidiaries.
Price regulation on power generation was removed or substantially loosened. Rather than charging regulated prices, power generation companies could charge whatever price the market would bear. These new electricity markets would be regulated by the Federal Energy Regulatory Commission rather than by the individual states.
Electric transmission would mostly retain its regulated pricing, but much responsibility for setting transmission prices was shifted away from the states, into the hands of the Federal Energy Regulatory Commission.
Some financing processes for power plants were loosened, allowing for faster accounting depreciation of new equipment.
The process of electricity reform has dramatically widened the number of types of companies and regulatory agencies involved in electricity supply.
Regional Transmission Organizations (RTOs) are non-profit, public-benefit corporations that were created as a part of electricity restructuring in the United States, beginning in the 1990s. Some RTOs, such as PJM in the Mid-Atlantic states, were created from existing “power pools” dating back many decades (PJM was first organized in the 1920s). RTOs are regulated by FERC, not by the states. There are seven RTOs in the U.S., covering about half of the states' and roughly two-thirds of total U.S.'s annual electricity demand. Each RTO establishes its own rules and market structures, but there are many commonalities. Broadly, the RTO performs the following functions:
RTOs have responsibility for ensuring reliability and adequacy of the power grid. They must perform regional planning, meaning that they determine where additional power lines and generators are required in order to maintain system reliability.
Virtually all RTO markets are operated as “uniform price auctions.” Under the uniform price auction, generators submit supply offers to the RTO, and the RTO chooses the lowest-cost supply offers until supply is equal to the RTO’s demand. This process is called “clearing the market.” The last generator dispatched is called the “marginal unit” and sets the market price. Any generator whose supply offer is below the market-clearing price is said to have “cleared the market,” and is paid the market-clearing price for the amount of supply that cleared the market. Generators with marginal operating costs below the market-clearing price will earn profits. In general, if the market is competitive (all suppliers offer at marginal operating cost) the marginal unit does not earn any profit.
As a reminder of how this system works, the uniform price auction is illustrated in Figure 12.1. There are five suppliers, each of which offers its capacity to the market at a different price. These supply offers are shown in Table 12.1. Here we will assume that supply offers are equal to the marginal costs of each generator, but in the deregulated generation market suppliers are not really obligated to submit offers that are equal to costs. The RTO aggregates these supply offers to form a single market-wide “dispatch stack” or supply curve. Demand is represented by a vertical line (the RTO assumes that demand is fixed, or “perfectly inelastic” with respect to price). In this case, demand is 55 MWh. Generators A, B, C, and D clear the market. Generator E does not clear the market since its supply offer is too high. The market-clearing price, known as the “system marginal price (SMP)” would be $40 per MWh. Generators A, B, C, and D would each be paid $40 per MWh. Generators A, B and C would earn a profit. Generator D is the marginal unit, so it earns zero profit.
Supplier | Capacity (MW) |
Marginal cost ($/MWh) |
---|---|---|
A | 10 | $10 |
B | 15 | $15 |
C | 20 | $30 |
D | 25 | $40 |
E | 10 | $70 |
Each generator that clears the market (in this case, it would be A, B, C, and D; E does not clear the market) earns the SMP for each unit of electricity they sell. Total hourly profits are thus calculated as:
Profit = Output × (SMP – Marginal Cost).
Since the SMP in our example is equal to $40, hourly profits are calculated as:
Note in particular that Firm D, which is the “marginal unit” setting the SMP of $40/MWh, clears the market but does not earn any profits.
In the previous page, we learned how the uniform price auction works: Generators submit supply offers; the RTO aggregates those supply offers to form a system supply curve or "dispatch curve;" and the market clears at the point where the dispatch curve intersects the (fixed) level of demand. Those generators with supply offers below the market clearing point are dispatched, while those with supply offers above the market clearing point are not dispatched.
In the absence of any transmission congestion, every generator clearing the market would get paid the SMP. This is why low cost generators, which we call "inframarginal suppliers," can be very profitable, and the marginal generator earns no profit under the uniform price auction.
When there is transmission congestion, however, things get more complicated because the transmission congestion segments the market. Some areas of the market are on one side of the constraint and some areas are on the other side of the constraint, and no further deliveries can take place between the two areas. If demand increases on one side of the constraint, a generator on that side of the constraint has to be dispatched to meet that demand. If demand increases on the other side of the constraint, a different generator on that side of the constraint has to be dispatched. These generators may have different costs and supply offers, and thus the marginal cost of meeting demand in one location is different from the marginal cost of meeting demand in another location. These location-specific costs are called Locational Marginal Prices.
The formal definition is that the Locational Marginal Price (LMP) at some node k in the network is the marginal cost to the RTO of delivering an additional unit of energy to node k. Relatedly, we sometimes define the "transmission price" or "congestion cost" between two nodes j and k in the network as the difference in LMPs between the two nodes.
The LMP forms the basis for payments to generators and payments by buyers in the PJM electricity market and other such markets in the US. Generators are paid the LMP at their node for electric energy produced, and buyers pay the LMP at their node for electric energy consumed. The RTO acts as the middleman for all purchases and sales, so it collects money from buyers and pays money to sellers.
If there is no transmission congestion in the network, then LMPs at all nodes are equal and will be equal to the System Marginal Price (SMP). This says that if no transmission lines are constrained, then the same marginal generator could be used to serve an additional unit of electric energy demand anywhere in the network.
LMPs can be highly variable across different parts of an RTO territory and can be very volatile depending on system conditions. The figure below shows a heat map of LMPs in the PJM system on a warm, but not terribly hot, summer day. The areas in blue (in the western part of the PJM territory) have very low LMPs, indicating that there is a lot of low-cost generation capacity in those regions to meet demand. The areas in yellow and red exhibit higher LMPs, while the area around Washington, DC has the highest LMPs (in white). Why does this happen? The answer is that there are transmission constraints in the PJM network that limit the amount of low-cost generation in places like Ohio that can be used to meet high electricity demand in places like Washington, DC. There is plenty of generation but not enough transmission to move the power around. So to meet electricity demand in Washington, DC, PJM must use higher-cost generators that are located closer to Washington, DC.
Note that electricity demand is highly variable over time. Consequently, in addition to the high variability over the space, LMPs can also be highly variable over time.
Earlier in this lesson, we discussed transmission congestion and Locational Marginal Prices. As you can see in Figure 2. LMPs are highly volatile. They are calculated at thousands of different locations and change almost constantly. You may also notice that the difference between LMPs at various locations is also volatile. Sometimes the price at one node is higher than at another node, and sometimes it is lower.
We generally define two dimensions of risk in electricity markets: temporal risk and locational or "basis" risk.
Temporal risk pertains to volatility in the LMP at a specific location over time; Risk associated with variation in a node or zone of prices over time. Temporal risk arises due to changes in electricity demand and fuel prices at a specific location.
Locational or "basis" risk pertains to volatility in the LMP across space (between two or more locations); Risk associated with variation of the transmission price between two nodes or zones. This is the same thing as variation in the difference between two LMPs or zonal prices. Locational risk is sometimes referred to as “basis risk” in the electricity industry.
These two types of risk may need to be managed through various hedging instruments, but they also may represent arbitrage opportunities.
Two of the most common ways of exercising arbitrage in electricity markets are through "virtual bidding" (arbitraging the difference between the clearing price in the day-ahead and real-time electricity market) and through the "spark spread" (the difference between fuel and electricity prices).
Virtual bidding offers a mechanism for electricity market participants to take advantage of differences between day-ahead and real-time prices at a specific location. It involves buying or selling some quantity of electricity in the day-ahead market, and then taking an offsetting position in the real-time market. Large financial institutions like investment banks and hedge funds engage in a lot of virtual bidding, but other types of market participants like generating companies and electric utilities also engage in virtual bidding. The mechanics of virtual bidding are very simple. A market participant first takes a short or long position in the day-ahead market. A short position is known as a "dec" and a long position is known as an "inc." If that market participant's inc or dec clears the day-ahead market (in other words, if that participant would get dispatched if it represented an actual physical need to buy or sell electricity), then the market participant must take an offsetting position in the real-time market. So, a day-ahead dec would be paired with a real-time inc, and a day-ahead inc would be paired with a real-time dec. The quantities offset one another and in the end, the market participant does not have to buy or sell any actual electricity. But the market participant is paid the LMP for the inc and pays the LMP for the dec.
For example, a market participant submits a 1 MW inc in the day-ahead market, believing that the day-ahead price will be greater than the real-time price. We'll say that the inc clears the market and the day-ahead LMP is $25/MWh. This same market participant would submit a dec to the real-time market, and we'll say that the dec clears the real-time market and the real-time price is $20/MWh. What has basically happened is that this market participant has sold 1 MWh of energy at $25/MWh and bought that same MWh for $20, netting $5 in profit.
The second mechanism for exercising arbitrage is through the "spark spread," which is the difference between the electricity price and the cost of generating electricity, which is mainly the fuel cost. The arbitrage opportunity that the spark spread represents is typically the opportunity to buy fuel and sell electricity. Spark spreads in financial markets are typically defined as the difference between the LMP and the cost of producing electricity by a natural gas generator with certain characteristics (like a heat rate of 10,000 and variable O&M costs of $2.50 per MWh).
As an example, let's say that the electricity price is $100/MWh and the cost of fuel is $5 per million BTU. The marginal cost of a gas-fired generator at this fuel price with a heat rate of 10 million BTU/MWh and variable O&M costs of $2.50/MWh would be 10*5 + 2.50 = $52.50/MWh. The spark spread would thus be $100/MWh - $52.50/MWh = $47.50/MWh.
The figure below shows some historical LMPs in PJM as compared to our hypothetical gas generation marginal cost of $52.50/MWh. During some hours, the spark spread is negative, indicating that it would not be profitable to buy fuel and sell electricity. During other hours, the spark spread is positive, indicating that it would be profitable to buy fuel and sell electricity.
Now we will see how locational and temporal risk can be hedged in electricity markets.
Financial Transmission Rights (FTRs) are financial instruments that entitle the holder to the difference between LMPs at two defined locations (any two points a and b on the grid). The parameters for an FTR are:
Note that the points do not need to be connected neighbors.
The holder of an M megawatt FTR from a to b at time t receives
FTRs are typically auctioned off quarterly by the RTO, and may have different durations (one-month FTRs versus quarterly FTRs, for example) and market participants bid for quantities, source nodes, and sink nodes. Most FTRs are structured as obligations, which means FTR gives the holder the difference, LMP(sink) – LMP(source). If LMPb > LMPa then the holder of the FTR is paid money by the RTO. If LMPb < LMPa then the holder of the FTR must pay the RTO.
Some FTRs may be structured as options that renew every hour, in which case during a given hour the FTR holder would choose to exercise the option only if LMPb > LMPa, i.e. If the payoff would be positive. The payoff from an M-megawatt FTR option from node a to node b would thus be:
FTRs also obey superposition, just like power flows. An M-megawatt FTR defined from a to b and an M-megawatt FTR from b to a will cancel each other out financially (as long as both FTRs are structured as obligations). An M-megawatt FTR from a to b and an M-2 megawatt FTR from b to a would have identical value as a 2 megawatt FTR from a to b.
As financial instruments, FTRs are very similar to swaps. A swap is an agreement to exchange the closing price of two different financial assets. In this case, the "swap" is between two nodes in the power network, not between two different financial assets.
In conventional financial market analysis, a contract for differences (CFD) is an agreement to exchange the opening and closing prices of some financial asset. In electricity markets, a CFD is a bilateral agreement in which one party gets a fixed price for electric energy (the strike price) plus an adjustment to cover the difference between the strike price and the spot price. This adjustment may be a positive or negative number.
CFDs are different than FTRs in two ways. First, a CFD is usually defined at a specific location, not between a pair of locations. Thus, CFDs are a tool principally for hedging temporal price risk - the variation in the LMP over time at a specific location. Second, CFDs are not traded through RTO markets. They are bilateral contracts between individual market participants.
CFDs may be defined as "one-way" or "two-way" contracts. A one-way CFD can have a couple of different payment mechanisms. First, a one-way CFD can be structured so that if the spot price exceeds the strike price, the seller pays the buyer the difference. Otherwise, there are no side payments. Second, a one-way CFD can be structured so that if the strike price exceeds the spot price, the buyer pays the seller the difference. Otherwise, there are no side payments.
A two-way CFD is just the sum of two one-way CFDs and is basically a forward contract for electric energy. In a two-way CFD, the seller pays the buyer if the spot price exceeds the strike price; and the buyer pays the seller if the strike price exceeds the spot price.
Here is an example. Let's say that a generation company signs a 100 MWh one-way CFD with an electricity consumer. The strike price is $50/MWh, and the CFD is defined at the location of the consumer.
Let's first say that the LMP at the location of the consumer is $75/MWh. In this case, the generator would earn $50*100 = $5,000 in revenue from the CFD, but would then need to pay the consumer 100*($75-$50) = $2,500 under the terms of the CFD. So the generator's net CFD revenue would be $2,500.
Now, let's say that the LMP at the location of the consumer is $40/MWh. In this case, there are no side payments and the generator's CFD revenues are $5,000.
Thus far, we have seen that temporal risk can be hedged with Contracts for Differences. A one way CFD can basically put a ceiling on the price of electricity. A two-way CFD is essentially identical to a forward contract for electricity at a fixed price. Locational risk can be hedged with Financial Transmission Rights.
In this section, we will see how a combination of CFDs and FTRs can be used to create a "perfect hedge" that shifts all temporal and locational risk. The end result of this perfect hedge is like a fixed-price contract at the strike price of the CFD, as long as the quantities of the CFD and FTR are equal to the amount of power being transferred from the source node to the sink node.
The table below outlines the perfect hedging model. We'll assume that there is a supplier located at node a, and a consumer located at node b. The supplier produces Q MWh in the real-time market and the consumer uses Q MWh. We will let F denote the size of a two-way CFD defined at the customer's node, and M denote the size of the FTR held by the supplier. The FTR is defined such that node a is the source and node b is the sink.
Mechanism | Payment to Supplier at node a | Payment by consumer at node b |
---|---|---|
Spot Market | ||
F Megawatt Two-Way CFD at strike price p |
||
Total | ||
M Megawatt FTR from node a to node b |
-- | |
Total if F = M | ||
Total if F = M = Q |
Let's walk through the rows of the table:
Note that unlike other energy commodities, electricity transportation cost is highly variable. Thus, due to the temporal and locational risks (high volatility over space and time), NYMEX futures contracts [137] don’t add much value to the market, and they are not popular, or the traded volume is very low. Consequently, it’s more efficient to use the mentioned financial instruments and utilize them for the spot market.
You have reached the end of Lesson 12. Double-check the list of requirements on the first page of this lesson to make sure you have completed all of the activities listed there before beginning the next lesson.
Links
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[8] https://www.eia.gov/energyexplained/index.cfm?page=hgls_home
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