U.S. Electricity Generation in 2021

Total = 4.12 trillion kilowatt hours (kWh)

• Natural Gas: 38%
• Nuclear: 19%
• Coal: 22%
• Renewables: 20%

The renewables are broken down as follows:

• Wind: 9.2%
• Hydropower: 6.3%
• Solar: 2.8%
• Biomass: 1.3%
• Geothermal: 0.4%

Renewable electricity generation 1950 - 2020 (history) 

Geothermal: Geothermal generation was relatively stable, and very low, from 1990 - 2020. 

Biomass: Biomass generation has remained steady at about 50 - 60 billion kWh from 1990 - 2020.

Hydroelectric: Hydroelectric generation varied widely between about 220 billion kWh and 350 billion kWh from 1990 - 2021. 

Utility-scale and end-use solar: Solar generated almost zero kWh before 2010. It rose from almost zero to about 115 billion kWh by 2021.

Wind: Wind power generated almost no power until 2004. From 2004 until 2021 it rose to about 378 billion kWh, more than 25 times of 2004 generation level. 

U.S. Energy Consumption by Energy Source

Total = 97.33 quadrillion British thermal units (Btu)

• Petroleum: 36%
• Natural Gas: 32%
• Coal: 11%
• Nuclear electric power: 8%
• Renewable Energy: 12% (12.16 quadrillion Btu)

Renewable energy is broken down as follows:

• Hydroelectric: 19%
• Biomass: 40%
  • Wood: 17%
  • Biofuels: 19%
  • Biomass Waste: 4%
• Wind: 27%
• Solar: 12%
• Geothermal: 2%

Energy Sources

Petroleum (36%)

69% of the petroleum goes to the Transportation Sector

25% of the petroleum goes to the Industrial Sector

5% of the petroleum goes to the Residential and Commercial Sector

1% of the petroleum goes to the Electric Power Sector

Natural Gas (32%)

3% of the Natural Gas goes to the Transportation Sector

33% of the Natural Gas goes to the Industrial Sector

26% of the Natural Gas goes to the Residential and Commercial Sector

37% of the Natural Gas goes to the Electric Power Sector

Coal (11%)

9% of the coal goes to the industrial sector

<1% of the coal goes to the residential and commercial sector

90% of the coal goes to the Electric Power Sector

Renewable Energy (11%)

12% of the renewable energy goes to the Transportation Sector

19% of the renewable energy goes to the Industrial Sector

10% of the renewable energy goes to the Residential and Commercial Sector

59% of the renewable energy goes to the Electric Power Sector

Nuclear Electric Power (8%)

100% of the nuclear electric power goes to the Electric Power Sector

Energy Consumption by Source

Transportation (27%)

90% of the energy used in this sector comes from petroleum

4% of the energy used in this sector comes from natural gas

5% of the energy used in this sector comes from renewable energy

Industrial (26%)

34% of the energy used in this sector comes from petroleum

40% of the energy used in this sector comes from natural gas

4% of the energy used in this sector comes from coal

9% of the energy used in this sector comes from renewable energy

Residential (16%)

8% of the energy used in this sector comes from petroleum

42% of the energy used in this sector comes from natural gas

7% of the energy used in this sector comes from renewable energy

Commercial (about 28%)

10% of the energy used in this sector comes from petroleum

37% of the energy used in this sector comes from natural gas

<1% of the energy used in this sector comes from coal

3% of the energy used in this sector comes from renewable energy

Electric Power (35%)

1% of the energy used in this sector comes from petroleum

32% of the energy used in this sector comes from natural gas

26% of the energy used in this sector comes from coal

19% of the energy used in this sector comes from renewable energy 2

22% of the energy used in this sector comes from nuclear electric power

Top 10 crude oil importer and exporter countries

Top 10 importers: China, India, U.S., South Korea, Japan, Germany, Spain, Italy, Netherlands, Thailand. Top 10 exporters: Saudi Arabia, Russia, Canada, United Arab Emirates, Kuwait, Norway, Kazakhstan, Nigeria, Brazil, Mexico

Top 10 natural gas importer and exporter countries

Top 10 importers: China, Japan, Germany, Italy, South Korea, Mexico, Turkey, France, Spain, United Kingdom. Top 10 exporters: Russia, Norway, U.S., Australia, Canada, Algeria, Malaysia, Iran, Nigeria, Indonesia

This lesson is going to be on alternative and renewable energy sources. The main types that we're going to talk about are wind, hydro, solar, geothermal, and biomass.

Wind power once was used for mechanical drives only. It's gaining in popularity as a clean alternative source of electricity using turbine generators. The old windmills, as they were called, were used on farms to draw water up from aquifers, to serve as wells on their land. And way, way back, they actually ground flour, and corn, and those types of things. Today, large wind farms are being built across the country where wind becomes a natural resource. Some of the concerns with these-- obviously, noise pollution in the area for the residents of that area. And there have been numerous reported deaths to flocks of birds flying in those areas. And as you can see, the picture on the left there just shows what are some 750 kilowatt turbines in the state of Minnesota on a large wind farm there.

Hydropower. Basically using water force as energy. Traditionally, it had been used to churn mills. That's why we would have those water mills. And again, they did several things with those from a mechanical energy standpoint. But today, we have hydroelectric generators. We have, most predominantly, hydroelectric dams. But we also have what are known as tidal power turbines, and these are actually utilizing the current flows, generally in and out of a river, or in and out of some type of an inlet. They use these in the North Sea off of Scotland. There's an experimental one in the East River in New York City as well. Again, there are subsurface turbines that actually spin as the current goes in one direction or another, and those drive a generator, which produces the electricity.

Solar energy has been around for quite some time. The interest in it, and the expansion of it, really began with the oil embargo of 1973 and 1974. And then the second embargo in 1979 caused even more interest in it. The idea is to collect heat and energy from the sun and use it for things such as pure heating, generation of steam for electric turbines, or to actually create electricity directly, which would be the use of photovoltaic cells. In a lot of cases, it's used to heat water, even for space heating.

And we generally have two types. The passive solar energy is using the direct heat of the sun. There are solar collectors, and they can direct the heat in a particular area. It's primarily used for space and water heating, and it can also be used to create steam. So some of the panels you might see on office buildings or residences may be doing nothing more than circulating water through for hot water heating. You would probably recognize the difference or the photovoltaic ones that are producing power.

And again, this brings us to the active part. It's the photovoltaic conversion of sunlight to electricity using semiconductor materials. It's dependent on the atmosphere condition and the Earth's position relative to the sun. And obviously, off to the right there you see a photovoltaic array. Small scale use here. But you see them more and more throughout-- they're using them now for traffic signs, communications systems, for instance pipeline companies, or any type of long distance lines, or cables, or whatever else. Signals are transmitted, and the power is coming from photovoltaic cells.

Geothermal energy. We generally think of geothermal energy as natural steam coming from geysers and from other places. And in those cases, it could be used for direct space heating. It can also be used directly for industrial processes. Steam will also drive steam turbines at a power plant or on site somewhere where there is the geothermal steam coming up.

But the flip side of that, which a lot of people are not necessarily aware of, is the fact that you also have geothermal energy that's used for space cooling. After all, if you go several feet below the surface, the soil and the temperatures down there are much cooler than above ground. And so you can literally drill down into a cooler area and draw up cool air to use for space cooling. This is becoming more and more prevalent. I have personally seen large homes that use this, as well as midsize office buildings.

Biomass. These are the various types when we talk about biomass and energy coming from biomass. We're talking about things like wood, garbage, crops, various alcohol fruits, in other words, fruits that can produce some type of an alcohol that can be burned as energy, and then landfill gas.

Biomass. The one form here is landfill gas. Basically, you have decaying trash that's in landfills, and it's going to create methane. All the biological material that breaks down and decays will end up giving off methane gas, and over time, the older landfills will actually have pockets of methane within them. And there are people who will go out, and they literally will poke a hole down into the landfill, and they will get the pockets of natural gas, and they'll use it on site, mostly. They can use it to drive some small turbines or small generators to create power on site. In some cases, they may have a process whereby they need to create some steam, and so they use the natural gas for that as well.

Another form of biomass is to actually take solid waste and convert it to energy, or trash to energy. This is where using solid waste that would normally go to a landfill-- you're using it as a fuel to create heat via combustion, and in turn, create steam from the boilers where the combustion is taking place. The steam can actually be sold for industrial purposes, or the generation of electricity can be accomplished by using steam as well. Now, there's a company in Fairfield, New Jersey by the name of Cogentrix Corp, and they actually build and operate several of these trash to energy, or solid waste to energy, facilities around the United States.

Wood and wood waste. These are normally the byproducts from large wood mills and paper mills. And what they'll do is, again, to be efficient, and to be environmentally conscious, they'll go ahead and use the wood, or the wood waste, the wood pulp-- they can actually burn it, and then it becomes a heat source where they can create their own steam that they'll use in the process, say, for instance, for making particle board or even paper. They can also use the heat source to run small generators on site for their own consumption and operations. The Weyerhaeuser Company, a huge manufacturer of various forms of lumber, and wood, and particle board, and those types of things, does this on location with a couple of their very large facilities they have in southeast Oklahoma.

And most of us are more familiar with this type of biomass where we're making fuel from things like crops, grasses, and biodegradable matter. One of the more well-known ones, of course, is making ethanol that we use as an additive to gasoline in our cars. And the primary food source there is corn, but there's also sugars that can be broken down into alcohol, as well as certain types of grasses. And on the biodiesel front, we could use vegetable oil, peanut oil, soybean oil, and then recycled grease from restaurants once it's cleaned. You can burn any of these in an existing diesel powered vehicle.

Farid Tayari: In this video and following videos, I'm going to explain the factors that are influencing the crude oil price. So there are many factors that can have an impact on crude oil price that we can name some of them as weather, US economy, international economy, US dollar exchange rate comparing to other foreign currencies, geopolitical events, supply and demand statistics, and crude oil and petroleum distillates inventory.

First, US weather-- heating oil is a refined distillate of crude oil. And it is being used by 5.7 million-- around 6 million households-- in the United States for space heating and warming of the water. Around 80% of those six million households are living in Northeast part of the country.

So if there is a cold winter, if there is a cold wave hitting this part of the country, we're expecting to have higher demand for heating oil. And it could be a good signal for price of oil being potentially increased.

I put a link here and this is slide to EIA website-- Energy Information Administration-- that includes the heating oil prices. So in addition to looking for data such as temperature or having a potential prediction of wind chill, there's also another indicator called HDD or Heating Degree Days. It's a good sign for energy demand.

So HDD represents the amount of energy being used to heat the space inside the building to reach 65 degrees, Fahrenheit. The lower outside temperature, it means that more energy has to be used for space heating. So historical and forecasted issues can be found at this link. It takes you to the National Oceanic and Atmospheric Administration. It can be a good metric for expected demand of heating oil and eventually, crude oil.

So one thing that we have to note that HDD is always positive-- there's no negative-- in case for the summer, the outside temperature is higher than 65, and then energy has to be used to cool down the space to the 65. We use this metric called CDD, or Cooling Degree Days. It's a measure for the amount of energy that needs to be used to cool down the building.

The other weather event that could potentially affect the crude oil price is a hurricane. According to EIA-- Energy Information Administration-- around 23% of the offshore oil production and 45% of the US oil refining capacity is around the Gulf of Mexico. And this is the section that in case of hurricane, that could potentially be affected and the supply can be interrupted.

So around 24 hours before the hurricane, the site-- which is a production site or drilling site-- has to be evacuated. And after the hurricane, it takes around at least 72 hours to reman the facility and start production.

In case of hurricane, there are two possible things that can happen, the interruption in the production because the site has to be evacuated. Or if the hurricane is severe, it can also damage the facility. For example, two cases-- Hurricane Katrina in 2005, 12 rigs and 30 platforms were damaged. And 18 of those platforms were completely destroyed.

Hurricane Ivan in 2004 damaged seven rigs and destroyed two rigs, and seven platforms destroyed. And it had consequences-- flooding and so on and so forth. And this can cause the supply interruption or the prediction of supply interruption. So when there is an interruption in supply, price can potentially increase.

I put a link here and it takes you to National Hurricane Center. It is a good resource for getting information of hurricane events. The official hurricane season begins on June 1st and it goes to November 3rd with a peak around mid-September. During this time, Weather Channel provides information through tropical update report.

The other factor that fixed the price of oil is the economy. Oil is a global commodity and the United States economy and other major countries in terms of economy. They can potentially influence the price of crude oil.

In this video, I'm going to explain the effect of US economy and crude oil. And in the following videos, I'm going to focus on international aspects of the economy and factors that are affecting crude oil price.

So energy runs the economy. And every aspect of economy can potentially influence the crude oil price. If economy is doing good, if economy is growing, it means there will be higher demand in future. Demand will be increasing. Strength and weakness of domestic economy directly impacts their prices, and also the perception of prices change and the prediction of the demand and eventually, the price predictions and the reaction of the traders to the price.

One of the most obvious and most frequently reported indications of economic health is stock market. Dow- Jones Industrial Index, S&P 500, and NASDAQ are daily reports that indicate the performance of the stock market. If these metrics are showing a good performance for the stock market, it means that economy is growing. And it could go up.

There are also weekly, monthly, quarterly economic reports that can have immediate impact on the price perception. Unemployment rate and reports being published by US Department of Labor-- this report is published every Friday. Institute of Supply Management Index report published monthly. Inflation rate, which is calculated from the CPI, Consumer Price Index, is being reported by US Bureau of Labor Statistics. It's a monthly report. GDP, US Gross Domestic Product, which also being published by Bureau of Economic Analysis and it's being published quarterly.

Also, US Department of Commerce's Economic and Statistics Administration has number of economic indicators that include data from US Census Bureau and US Bureau of Economic Analysis. These economic metrics are including construction spending, housing starts, housing sales, US international trade, monthly wholesale trade, manufacturing and trade, sales for retail and food services, personal income, and personal spending.

Also, quarterly earning reports from US companies-- these are the report metrics in economic parameters that can help us predict the future demand.

The next video-- so I'm going to explain the other factors that can influence crude oil price.

Farid Tayari: Following the previous videos, in this video, I'm going to continue explaining the factors that are affecting crude oil price. In this video, I will start with international economy. As we learned previously, crude oil is an international commodity. It's a global commodity. It's being traded everywhere in the world. Every part of the world economy can have impact on the crude oil price. Some countries that are contributing to biggest portion of crude oil consumption, their economy can potentially have a big impact on crude oil price.

So when trading starts early in the morning on the exchange in New York, Asian market is already closed and European market is at midday. So the behavior of the market, the signs of how market will behave, they are already known.

And probably the most watched nation these days outside of the US is China. China is contributing to around 15% of the world GDP. And China is, after the United States, the second-largest consumer of crude oil.

After China, Japan used to be the third-largest consumer of crude oil. After the Fukushima nuclear disaster, Japan's imports of fossil fuel increased. But at the moment, India is in the third place, taking Japan's place in oil consumption of the world. Also, the European Union and Europe region is consuming around 22% of world crude oil, and this data is from 2013.

So economic growth in these regions that are large consumers of crude oil can influence the crude oil. If the economy is doing good, if growth rate-- economic growth rate-- is high, it gives the signal that the demand in the future-- there will be high demand for crude oil in the future. And if the economy is slowing down, it means that the expected demand will not be as high as before. The increasing demand will be not as high as before, and it is going to potentially affect the price of crude oil.

The other factor that can potentially influence the crude oil price is the United States exchange rate. As you know, crude oil is globally being traded in US dollar. So the fluctuation of exchange rate, US dollar compared to other currencies, can potentially affect the crude oil price.

Why? Because there are many traders outside of the United States, and they are trading the crude oil which is being traded in US dollar. So if the dollar value decreases-- if US dollar loses its value-- it means that those traders living outside of the United States will have higher buying power. So they can buy more crude oil futures contracts. It means that there will be higher demand from outside of the United States. It will increase the demand of crude oil and can potentially increase the price.

So usually, there is a strong correlation, negative correlation, between the United States US dollar value and crude oil price. During the periods of a strong US dollar, foreign traders, investors try to sell their future contracts. And when the US dollar loses its value, they tend to buy more contracts.

The other factor that can impact the price of oil is geopolitical events, especially in the regions that are big producers of oil. Any conflict or potential conflict can impact the prices. Any news that can give the sense of potential interruption in supply can increase the price.

Please note that it doesn't necessarily need something to happen that interrupts the supply. Traders are also humans. They behave emotionally. They can react to the news in an emotional way. So if news says some potential conflicts in the region where large producing countries are located, it can potentially affect the perception of the supply in the future. It could potentially interrupt the supply, or it can influence the perception of the supply in the future and can have a significant impact on the crude oil prices.

For example, in mid-June 2014, WTI-- West Texas Intermediate-- crude oil price was about $107 per barrel. And at the end of that year, it went down to around $54 per barrel. We can explain this price behavior into two major factors that influence the price. First, the increased supplies of oil in the United States, mostly coming from unconventional reservoirs, shale and tight sands, because the price of oil was high. And at this price, at around $100, it's totally economically feasible to produce oil from costly unconventional reserves.

Around this time, Saudi Arabia-- that is, one of the largest producers and exporters of crude oil-- tried to maintain the market share by flooding the market with cheap oil, but this strategy caused excess supply and price to drop substantially. Low price of oil can have a large impact on oil-producing countries that are highly dependent on the revenue from oil. Also, in the United States, the companies who are working on the exploration and production section of oil, they will have to cut back on exploration and drilling activities, too, because they lose their revenue. And potentially, if the price is too low, they can potentially-- the small companies-- they can go bankrupt.

The other major player in the oil global market is OPEC, or the Organization of Petroleum Exporting Countries. OPEC was formed in 1960 by the first five members, including Iran, Iraq, Kuwait, Saudi Arabia, and Venezuela. And right now, at the moment, 2017, it has 14 members. OPEC produced around 43% of the world's total crude oil in 2015, and OPEC members control about 73% of the world's total crude oil reserves. So every decision that OPEC members-- every agreement or even the meetings that don't come to an agreement can potentially affect the price of crude oil.

For example, if OPEC members come to an agreement and they cut back to production, it can cause the supply-- the world's total supply-- to decrease and eventually cause price increase. And if in their meetings, let's say there's time and there's a conflict-- politics is always involved in the decisions. If there is a period that prices are going down and they cannot come into an agreement for cutting back the production, then it can potentially affect market prices and potentially cannot stop the price decrease.

Farid Tayari: Following the previous videos, in this video, I'm going to explain the factors that can influence the crude oil price.

The last factor that I'm going to explain is supply and demand statistics. Any informational report that can give some information about the production or consumption of crude oil and, also, its distillates products can cause an impact, can cause a price change.

There are a variety of reports being published by governmental entities, both US and international, as well as industry associations. And these reports are good sources to predict the behavior of the crude oil price.

EIA, Energy Information Administration, from the US Department of Energy, issues a report on the status of country's inventory of crude oil, and its various distillates. This report is being published every Wednesday at 9:30 AM, and it has several pieces of key supply and demand statistics.

I'm going to explain some of the items that are included in this report. First, a refinery utilization, the percentage of total US refinery capacity that is running indicates both demand for crude oil as well as production of gasoline.

And, two, is an import report, both raw crude oil and refined products, such as gasoline. They are imported and volumes are compared to last year, which could be indicators of improving or worsening the balance.

The other part of the report includes commercial crude oil inventory. The change in inventory from one week to the next week has a profound impact on crude oil prices from a trading standpoint.

Analysts provide forecasts for the change in inventory ahead of the actual report. And financial and energy commodity traders react to the difference between the forecasted and actual report.

The other piece of information that is included in the report is gasoline inventories. Total gasoline products, as well as, breakdown between finished gasoline and blending products, gives a picture of supply and demand for gasoline. A decrease in total products could mean more demand for refinery feedstocks. Surplus could mean just opposite.

If there is an inventory, it means that there will be more supply to the market, and price won't go up, then they potentially could go down.

Information about distillate fuel is also included in EIA Inventory report which, in this category, is mainly about heating oil. And as I explained earlier, the cold winter-- the cold weather, or low temperature, means higher demand for heating oil.

And if there is low inventory, if there is low storage, it can be translated to low shortage of supply and higher prices in the cold days.

So as I explained in previous video, value of the US dollar or US dollar exchange rate versus foreign currencies is one of the factors that affects the crude oil price. As we know, crude oil is a global commodity that is traded globally, but in US dollars. So any fluctuations in the exchange rate between US dollar and foreign currencies can affect the crude oil price.

I'm going to explain that in a very simple example. Let's assume there are two traders who trade crude oil futures contracts. So one is Trader A is in the United States and Trader B is in Europe. Trader A has $1,000, and Trader B has 1,000 euros.

So first, let's assume that the exchange rate between US dollar and euro is 1-to-1 so meaning that $1 is equivalent to 1 euro. And let's assume that crude oil price is $50 per barrel. OK, let's see what happens for Trader A.

Trader A has $1,000 and can buy 20 barrels of crude oil or can buy futures contract equivalent to 20 barrels of crude oil. So $1,000 divided by 50 leaves 20 barrels of crude oil.

Let's see what happens to the trader in Europe. So Trader B has 1,000 euros. The first thing that Trader B has to do is going to the exchange and convert the 1,000 euros to the equivalent dollar amount, which is $1,000. Then with that amount, Trader B can buy crude oil. So Trader B can also buy 20 barrels of crude oil.

So the total demand will be 20 from inside the United States and 20 internationally, assuming there only two traders. So there will be 40 barrels of crude oil demand, total demand.

OK, now let's assume the case that US dollar loses its value. So again, same traders, two traders, Trader A is located in the United States and has $1,000. Trader B is in Europe and has 1,000 euros.

And now let's assume US dollar has lost its value. Now $1 is equivalent to 0.8 euros. Or with 1 euro, you can get $1.25. And let's assume the crude oil price has stayed the same, $50 per barrel. And let's see what happens.

OK, trader A still has $1,000. Crude oil price is still $50 per barrel. So Trader A inside the United States can still get that 20 barrels of crude oil.

And let's see what happens to Trader B. Trader B has 1,000 euros. Trader B has to go and exchange that 1,000 euros to equivalent dollar. And as we can see, because dollar has lost its value, that 1,000 euros will be converted to $1,250 because, with 1 euros, Trader B will get $1.25. So Trader B has $1,250, which can buy five more contracts. So Trader B would end up buying 25 barrels of crude oil or futures contract equivalent to 25 barrels of crude oil.

So 20 barrels demand from Trader A inside the United States and 25 barrels of crude oil demand from Trader B outside the United States-- so total demand will be 20 plus 25, 45 barrels. So we can see the demand increase from 40 barrels to 45 barrels when the dollar has lost its value. So it means that demand has increased. So demand curve shifted to the left-hand side, which changes the market equilibrium price for crude oil. And it potentially increases the crude oil price.

PRESENTER: In this video, I'm going to explain the factors that can influence natural gas price. In contrast to crude oil, natural gas is almost not a global commodity, yet. It can be construed as a domestic commodity in the United States. So things that are happening outside the United States, they don't have a major impact on the natural gas prices.

So we can focus on the factors that are happening in the United States. And two of these major factors are the US economy and weather events. Other factors, such as the level of US natural gas inventory, can also impact the natural gas prices on a weekly basis.

The higher natural gas inventory means high supply or having enough supply for fluctuations in demand. So if there is a high level of inventory, it can translate to not having, not experiencing, not expecting the higher price of natural gas.

US economic indicators such as the stock market, employment, figures housing and manufacturing, they impact the natural gas prices. On the other side, global economy, US dollar exchange rate would not have an impact on the pricing of natural gas.

The first factor is the weather. More than 50% of American homes are heated by natural gas. So any cold or extreme weather could potentially increase the price if there is a shortage of supply. If there is an unexpected demand, it could shift the price to higher prices.

Also, hot weather could cause the price increase, because people will use air conditioning to lower the inside temperature for space cooling. And so increase in demand for electricity could potentially increase the natural gas prices.

The other weather event is hurricanes, same as crude oil, that we explain how a hurricane in the region of Gulf of Mexico can disrupt the supply and damage platforms. Evacuation and recovery after a hurricane can potentially interrupt the supply.

US economy-- similar to crude oil, fluctuations in economy translate into an increase or decrease in energy consumption. North American natural gas is not a truly global commodity, so the global economy does not have an impact on the price of natural gas.

The other factor that could potentially affect the natural gas price is the reports about production levels versus demand indicators. Any statistics, any information about supply or demand of natural gas can potentially affect the price.

EIA, Energy Information Administration from Department of Energy, publishes a weekly report every Thursday at 9:30 AM. This report is about natural gas storage. And it has some pieces of information that I'm going to explain them in the following slides.

So EIA Weekly Natural Gas Storage Report includes pieces of information on natural gas storage. The first piece of information is regional breakdown-- the activity for the EIA-defined regions, which includes the major consuming regions, both east and west, and producing region. The producing region is further broken down into the salt and non-salt storage facilities, with the majority of the salt caverns existing along the Gulf Coast.

Injections, or gas added, and withdrawals, gas removed, by region can be telling about the weather conditions in each area. A good balance is when the consuming regions are withdrawing the same amount of gas as producing region is injecting gas.

The other very important piece of information included in EIA Weekly Natural Gas Storage Report is the total gas in storage. It is the change in historic levels from one week to the next week. It is the first thing that traders and other parties involved in the natural gas market would look to for guidance.

Excess storage, a high level of storage or injection in the report, can be translated to a bearish price signal. That is, the production exceeds demand for the prior week.

The converse is also true for the removal of gas from the storage, or withdrawal in the report, that can indicate demand exceeded the production for the prior week. Prior to the release of the report, analysts have compiled forecasts in the variance of the actual volume to these predictions.

The other piece of information that can be found in EIA Weekly Natural Gas Storage Report is a comparison to a year ago. This data includes the information-- the current inventory level compared to the same period the previous year. In order to truly interpret this comparison correctly, we must consider the weather in this year with the last year, if there was or there is harsh winter we are experiencing or we were experiencing cold days.

The last piece of information in EIA Weekly Natural Gas Report that is important for us is a comparison to the five-year average that can be found in the report.

The other factor that can influence natural gas price is electrical generation fuel switching. A large amount of country's power plants were fueled by coal. And they can switch. They can switch their fuel to natural gas if natural gas prices are competitive or more restrictions are being enforced for the emissions. But this effect is a more long-term effect.

Also, the Nuclear Regulatory Agency publishes a daily status report for all nuclear power plants in the United States. When plants are down, more electricity is generated by natural gas.

[MUSIC PLAYING]

PRESENTER: New York City, financial capital of the world. Home to global giants in banking, investing, and finance.

AUDIENCE: We only have four and 1/2.

AUDIENCE: Sell 20 and 1/2.

PRESENTER: Where there is always a transaction on the table, money on the line, and business never sleeps. It's also home to the New York Mercantile Exchange where billions of dollars in commodities are traded every day, but one way or another, impact business and consumer alike.

[MUSIC PLAYING]

[CALLS AT MERCANTILE EXCHANGE]

PRESENTER: What appears, at first glance, to be pure pandemonium, is in reality, a very structured business, as highly choreographed and orchestrated as any Broadway show. The New York Mercantile Exchange is a marketplace for buying and selling futures and options contracts in commodities. For instance, energy products such as crude oil, natural gas, gasoline, home heating oil, propane, and electricity, as well as metals like gold, silver, copper, aluminum, and platinum.

But what does that matter to me, you might ask. Here's an example. Oil refiners sell fuel-- mainly gasoline, heating oil, diesel, and jet fuel. Airlines buy large quantities of jet fuel. It's similar to heating oil, and the two products are often priced within a few cents of each other. As price protection against unexpected increases in the cost of jet fuel, an airline can buy a heating oil futures contract at today's known price for use in the future.

If prices rise tomorrow, the airline saves money by having locked in a lower fuel cost. That's called hedging. The fuel savings could mean lower airfares for you and me. The same principle applies to heating oil we use to keep our homes warm in winter, and the gasoline we buy for our cars. When companies protect themselves from volatile prices, they can help pass along those savings to their customers.

Price transparency is a key advantage to doing business on the Exchange. Everyone knows the price of all contracts being bought or sold. This benefits the entire marketplace and builds confidence and credibility for business and consumer alike.

90 bid!

Okay, let’s start reviewing what futures are, and before that, I will need to explain forward contracts first. So, forward contracts: let’s say on the left-hand side we have an oil-producing company, and on the right-hand side, we have a refinery which consumes oil and produces some refined products. So, on the left-hand side, we have a producer that sells the oil, and on the right-hand side, we have consumers that buy the oil.

Let’s say right now the refinery needs some crude oil, and the producer has some oil. They just sell and buy, and that’s it. Okay, but this is an ongoing business activity, right? The producer knows that for any time in the future, they know the production rate and how much crude oil they will have in the future. Also, the refinery, this is a continuous production process, they know they’re going to need crude oil for almost any time in the future, right? Both of these are concerned about market fluctuations, and they want to make sure they have a market for the produced crude oil or that they can have the crude oil they need. They are also concerned about the price. The producer is concerned that if the price drops, they’re going to lose money. On the other side, the refinery is concerned that if the price goes up, they’re going to lose money, and they want to hedge their risk against price fluctuations.

So, what they can do is negotiate a contract called a forward contract, and they can discuss three things: time, price, and quantity. Let’s say we are going to sign a contract that sometime in the future, let’s say in November, at the locked price of 50 dollars, the producer is going to deliver a specific quantity of crude oil, let’s say 5,000 barrels, to the refinery. So, they have a contract that locks the price for delivery at some time in the future, and they can have many of these. This is called a forward contract. By doing that, they first make sure the producer has a market for crude oil, and the consumer knows for sure they will have crude oil in November. Also, they know the price is locked. The price is locked at 50 dollars. The price doesn’t change.

Okay, what are the restrictions or limitations of these forward contracts?

First, let’s say these two entities, the producers and consumers, are not exactly the same size. Let’s say the refinery is very large, or the producer is a very large producer, and one of them is a lot smaller or larger than the other one. Then, they have to go and probably find 10 other counterparties to negotiate and sign the contract with each of them, and they have to do it for almost every month, and so on and so forth. It’s doable; it is still an ongoing activity in the financial market, but it’s not the most efficient way of doing it.

The other problem with this is, let’s say this contract is signed to deliver the crude oil in November, and the price is locked at 50 dollars. Let’s say a couple of months before November, the price of crude oil goes up to 60 dollars. If it goes to the market, it’s 60 dollars, but under this contract, it is locked at 50 dollars. Because it is locked, the producer loses money. If there was no contract, the producer could have sold it in the market at 60 dollars. So, the producer will get more and more upset, thinking, “Okay, I am losing money under this contract,” but there is no way they can cancel the contract. On the other side, if the price of crude oil starts going down, the producer is happy, but the consumer cannot cancel the contract and go and buy the cheaper oil in the market. They have to pay the 50 dollars locked price. So, the problem is: they cannot cancel the contract at all.

So, this is the kind of introduction to how there is a better, more efficient type of contract needed based on the forward, and that’s going to be called futures, which I’m going to explain in a bit.

Okay, now let’s make some changes and move toward that more efficient contract, which we’ll call futures later on. The first thing that we want to do is introduce a third party here. Let’s say we call this third party an exchange, a businessman, businesswoman, or a company. Instead of the producer going and trying to find consumers, these producers will just go and sign a contract with this third party. The consumer, the refinery, will also go and sign the contract with this third party. This solves the problem that they don’t need to go and find, let’s say, 10 more consumers and sign individual contracts with them.

Let’s make some more adjustments. Let’s say we make these contracts standard. You remember in the previous slide I said these forward contracts are case-based? They are signed for a specific case between these companies, and their contract terms are negotiated between these two entities.

Now let’s introduce a type of contract where all the terms are standard; there’s nothing negotiable. These are all fixed in place, and nobody can change them. The quantity is fixed, the delivery point is fixed, the price is fixed, which I’m going to talk about in a bit. Everything is fixed under these contracts, except the delivery date. The delivery date goes by the incremental month. It’s either January, February, March, and so on. The only difference between these contracts is the delivery date or expiration date. When we make these contracts exactly similar, there’s no need for any negotiation back and forth. We will have these standard contracts, and what we can do is have all the other entities join this market and trade these contracts.

So, we will end up with an exchange in the middle, which will have these contracts that are all standard, exactly the same. We have these players, the actual producer, the refinery, and the oil producer, who can also join as one of these players in the market. They can either buy these contracts or sell them. If they buy this contract, we say their position is long. If they sell this contract, their position is short.

If they buy the contract (long position), they have to take the delivered crude oil; they will receive the crude oil when the contract expires. On the other side, those players, those entities who sold the contract (short position), have to deliver the crude oil, the amount of crude oil, at the expiration date.

Because all these contracts are exactly the same, these are called futures. They have a fixed quantity of one thousand barrels of crude oil, the delivery point is fixed (Cushing, Oklahoma), and the spec is WTI (West Texas Intermediate), which is low sulfur, sweet crude oil. The expiration date goes by the month: January, February, March, and so on. The price is set by these trades, by these market movements, sell and buy, supply and demand. If somebody does not like the loss they are making based on the price movement, they can get out of the contract anytime they want. They don’t have to wait until the expiration date. If the prices are going up and the position is short, they can immediately close the position by buying back, by closing the position with the exchange.

The entities who are long these contracts, the entities who bought the contracts, will make money, will profit, when the price goes up. On the other side, if an entity has a short position, they will lose money. If the price starts to go down, the long position will lose money, and the short position will make money.

An important point here is that these contracts are binding. The entity, the party that is short, the party that sold this contract, has to deliver crude oil at the expiration date. If that party is not an oil-producing company, or if that party is not interested in delivering or cannot deliver the crude oil, they have to close their position, they have to cancel the contract. How? If they are short, they have to buy back; if they are long, they have to sell.

Some of the common terms used by NYMEX. An ask-- an ask is a motion to sell at a specific price. It's the same as an offer. So ask and offer are interchangeable. It's your asking price. What do you wish to get in the marketplace for your commodity? And notice this is a motion because they're addressing the idea of the physical trading that takes place in the pits, the movement of hand gestures back and forth as traders buy and sell. A bid, then, is the opposite. It's a motion to buy at a specific price. What is your bid for the energy commodity?

A bull-- in this case, we're talking about a person. It's one who anticipates prices will increase or volatility in the market will increase. They're the opposite of a bear. A bear is one who anticipates a decline in price or the volatility in the marketplace. Obviously, the opposite of a bull.

This is a picture of the New York Mercantile Exchange trading floor. It just so happens in the foreground is the natural gas trading pit. Off to the left, barely seen, is the crude oil trading pit. Notice the various colors of jackets around the floor. I will identify who some of those are in a minute. But the yellow jackets, for the most part, those are NYMEX compliance personnel. The multi-colored jackets, the blues, the burgundies, some of the other colors, represent brokers, what are known as clearing brokers on the floor of the New York Mercantile Exchange. They have posted credit, and they have licenses to trade on behalf of their clients.

So we have the floor brokers, which I mentioned. We have locals. These are the individuals and firms and in some cases funds that have a large amount of money and wish to trade. They are speculators. They're not interested in the physical commodities whatsoever. They're interested in price movement, and wherever the price is moving, that's where they want to be.

Ring reporters and ring chairmen-- we'll drop back here a second, and I will show you. The ring reporters are in the yellow jackets near the trading rings themselves. There is a podium, if you can tell, situated above the natural gas pit with some personnel in yellow jackets. Those are the ring chairmen. Their primary responsibility is to oversee the activity of the pits and to resolve any disputes. Since we have people who are yelling orders back and forth to one another and using paper slips, sometimes mistakes can be made, and if there's a disagreement over the actual details of a trade, the ring chairman is supposed to step down and resolve that trade between the two counterparties.

We have floor committee members. Those are basically NYMEX committee members. The New York Mercantile Exchange also has compliance people. And the Commodity Futures Trading Commission is the regulatory body for energy financial derivative trading. They have their own personnel on the floor as well. And then there are hundreds of line staff from the New York Mercantile Exchange.

We'll now talk about each one of the specific contracts for energy commodities. The first is crude oil. The 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, in this case per barrel. A minimum price fluctuation-- that is, the amount that the price has to move for a trade to take place-- is a penny, or $10 a barrel.

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.

Deliveries are to be made uniformly across the month. This is the contractual obligation. The idea here is to make all parties deliver as equally as possible. The actual obligation-- for instance, if I sold 30 contracts for the month of September, that means 30,000 barrels of crude oil-- the Exchange would like me to deliver that at 1,000 barrels a day. However, if I cannot, my real legal obligation is 30,000 barrels for the month.

The trading hours on NYMEX for what we consider to be the open outcry or pit trading, the general session where the traders are in the pits yelling orders back to one another, run from 9:00 AM to 2:30 PM Eastern Standard Time. The Chicago Mercantile Exchange also has an electronic trading platform known as Globex, and this is virtually 24 hours a day, seven days a week. It starts at 6:00 PM on Sunday evenings and ends at 5:45 PM on Friday, Eastern Time.

Crude oil can be traded for up to nine years. And then we also have products that are known as strips. These are available for terms of 2 to 30 consecutive months. In essence, strips amount to an average price. If I wanted to buy six months' worth of crude, rather than go out and have my broker quote me one month's price at a time, they'll just give me an average price across the six months. Therefore, I am purchasing a six-month strip of crude oil.

The last trading day, every contract expires. Again, we are talking about future contracts. So currently, the closest future contract is September. The crude oil contract, then, settles three business days prior to the 25th of the month. So just in case the 25th is a non-trading day, either a weekend day or a holiday, the settlement occurs three business days prior to the business day that is prior to the business day ahead of the 25th. I know that sounds very confusing. I can't quite figure it out myself half the time.

Margin requirements. This is a big issue here. You can see that if you want to buy or sell crude oil contracts, for every single contract that you wish to enter into, you have to have $5,100 in a margin account. That's a safety net against losses that you could incur. This protects your clearing broker and protects the New York Mercantile Exchange from default by you as a counterparty.

This also discourages a lot of traders from just jumping in and trying to trade contracts. For example, if a trader wanted to speculate on 10 crude oil contracts-- that's only 10,000 barrels-- that's not a lot of volume, per se. They would have to put $51,000 in a margin account before they could even get started.

Here is the symbol breakdown. When you look at futures screens, or if you see the prices reported in the Wall Street Journal or any other type of publication, you'll see these funny symbols. The first two letters of the symbol represent the energy commodity themselves. So CL represents crude oil. The second letter is the actual month of delivery. For example, U equals September. The final symbol is the number that corresponds to the year. In our example, 2. So the September 2012 contract for crude oil on the NYMEX is expressed as CLU2.

Other symbols that represent energy commodities-- NG for natural gas, HO for heating oil. RBOB represents unleaded gasoline, and then PN for propane. And then here's the breakdown of the symbols that they use. Feel free to use this as a cheat sheet if you ever run across those quotes and can't remember what they mean.

When you look at futures screens, you're going to see column headers that will use these types of terms. When you see the open, that's the opening price at the opening bell. When you see people on television ringing the bell for the open of whatever market it might be-- the stock market, the NYMEX, the Chicago Mercantile Exchange-- as soon as the bell goes off, the very first trade that is consummated, that price is registered as the open for the day.

The high is the highest price that traded that day, including the after-hours electronic trading. The low is the lowest price that traded for that day, including after-hours electronic trading. That gives us the range on the day-- what was the entire range of pricing that day.

When you see last, that's the last trade that just occurred. In other words, what was the last trade that had occurred? The net would be the change in price from that last trade to the one prior to it. So are we going up or are we going down as we're trading currently? And then change-- the change is the change in price from the trade that just occurred, from that last trade, versus the prior day's settlement. What was the final price for the energy commodity the day before, and where do we sit relative to that today? That's what change represents.

We refer to futures contract trading as a zero-sum game. For every buyer, there is a seller. I can't buy crude oil contracts without someone being willing to sell them to me, nor can I sell them without a market. And believe it or not, less than 2% of all the contracts traded actually go to physical delivery. In other words, less than 2% of the contracts will actually be energy commodities exchanged between counterparties. Now, on the one hand, that may sound like a small number, but with each crude oil contract representing 1,000 barrels, and you can trade between 50,000 and 100,000 contracts a day, it does amount to a substantial amount of physical energy commodities being exchanged.

This is what a typical futures screen would look like. These are the headers that I mentioned to you. On the day that I printed this off, you can see the last trade was $92.68 and, represented a drop of $0.19 from the prior day's settle of $92.87 in the far right corner there. We had the opening price of $93.25, and a high and low on the day as well. And the very far right column is the time at which the trade occurred.

Natural gas futures contracts. The contract unit is 10,000 MMBtus-- that is, 10,000 million British thermal units. Prices are quoted in US dollars and cents, and the minimum fluctuation between trades has to be 1/10 of a penny or what we refer to as a tick. Trading hours are exactly the same, but the trading months for natural gas-- you can actually trade natural gas out 12 years if there was, in fact, a need to buy or sell for that long of a period of time.

Last trading day for natural gas contracts, the futures, is the third business day prior to the first calendar day of the delivery month. We do trade options in energy futures contracts. In the case of natural gas, those expire one day prior to the actual contract itself.

The delivery point for buying and selling under NYMEX natural gas contracts is a place known as the Henry Hub in Erath, Louisiana. Texaco has their Henry plant in Erath, Louisiana. Sabine Pipeline Company runs the hub on behalf of the New York Mercantile Exchange. And again, the delivery period is to be uniform across the month of production for which the contracts were exchanged.

This is a schematic of the pipelines going in and out of the Henry Hub. There are various sources of natural gas coming offshore, onshore. There is gas moving to the Northeast, the Southeast, the Upper Midwest, as well as from Louisiana back into Texas. So it made an ideal market hub for indicating various supply and demand.

Settlement price. Every day, the New York Mercantile Exchange will put together a final price for that day's trading. The settlement price is the weighted average of all the trades that occur during the last two minutes of trading in that regular session. Now, when the closest future month, or what we call the prompt month, when that contract expires, they're going to take the total number of trades in the last 30 minutes to come up with a weighted average, and that will be the price for that month. And that month rolls off, as we say, and it's in the history books.

Margin requirements for natural gas are substantially less than crude oil, but the value is substantially less, so there's only $2,100 margin requirement per contract.

This is what a natural gas futures screen would look like. If you ever see one of these on a trading floor or somewhere else, perhaps on someone's screen who trades in these contracts, this is what it would look like.

We're now going to talk about unleaded gasoline, referred to as RBOB. RBOB stands for Reformulated Blend for Oxygenated Blending. What we get at the gas pump-- you usually have the opportunity to get 100% unleaded in very few places. Mostly, it's a 90/10-- that is, it's 90% gasoline, 10% ethanol or some other type of blending component. In some cases, you hear about E85, which is 85% unleaded, 15% of some other additive, normally something like ethanol.

So what's traded on the New York Mercantile Exchange is actually the 100% unleaded. It becomes a feedstock for unleaded because it's only 90% of what we get at the pump unless we're buying 100% unleaded. So it's reformulated blend for oxygenated blending. They're going to blend oxygenators into the unleaded gasoline.

The oxygenators are seasonal in nature, depending on the regions. Again, oxygenators help to burn the gasoline more efficiently and therefore reduce the emissions. Oxygenators are things such as ethane, ethanol, butane, isobutane, and natural gasolines.

Every RBOB contract is 42,000 gallons. US dollars and cents, and the minimum fluctuation is 1/1000 of a penny per gallon. The delivery point is free onboard or delivered into the petroleum products terminals in New York Harbor. Margin requirements-- $8,100 per contract.

Last but not least, heating oil, or HO. It's sometimes referred to as number two fuel oil. Every contract is 42,000 gallons. We are still dealing with US dollars and cents per barrel. Minimum price fluctuation is 1/1000 of a penny per gallon. The delivery point is the same as for RBOB, and that is free onboard or delivered to the petroleum products terminals in New York Harbor. Everything else pretty much remains the same under the standardized NYMEX contracts.

As mentioned in the introduction to this lecture, we're going to walk through the specific steps of executing a buy and sell order on the floor of the New York Mercantile Exchange. We're going to be doing this during the regular session where there are active traders in the pits doing what they call the open outcry trading. In order to understand what's going on, there are two key terms here that we're going to need to understand.

One is a bid. And it's a motion to buy a futures contract at a specified price. The opposite of that is an offer. Again, a motion to sell a futures contract at a specific price. And that's also known as the asking price. And we use the word motion because the traders are using various hand signals to communicate to one another across the pits, if they're buyers or sellers, what volume, and what price.

So the example we're going to use in this case is a 12-month price, a 12-month "strip" average of $3.50. As mentioned in Lesson Seven, you can go out and you can buy or sell contracts at an average price as opposed to having to buy or sell at each individual month's price. In this case, we're looking at 12 months out. So currently, this 12-month strip is running $3.50. And there's a producer out there who would like to lock this price in, or better, if he or she can get that. So the producer's going to call a trader at the energy company and tell them that they're interested.

So the trader will turn around then and they'll ask the personnel on the fixed price desk to call New York and find out where the market currently is, where are the bids, where are the offers, for this 12- month strip for natural gas. Energy trading companies that have financial derivative trading, they will have a fixed price desk. These are the personnel mostly responsible for dealing with the New York Mercantile Exchange.

So the fixed price desk calls their broker on the floor of the New York Mercantile Exchange to find out the current market quotes and both the bid and offers. Now the person that they're talking to is the clearing broker and, specifically, the phone clerk. If you recall the picture of the floor of the Mercantile Exchange from Lesson Seven, you can picture those phone banks. So this is where that phone call is going to.

The fixed price desk person turns around then and gives the trader the current market quote. The producer then gets that bid and offer from the trader. And given that the market is still in the $3.50 range, the producer decides that he or she would like to lock in the price of $3.50 or better for the next 12 months if in fact it can be executed. The trader now takes the order from the producer and passes it along to the fixed price desk.

Now, at this point in time, the producer is obligated to perform under this contract. In other words, the producer realizes that the energy trading company's going to have to enter into the legally binding contracts on the New York Mercantile Exchange to obtain this fixed price for them. So the producer is going to have to perform by giving the physical gas when the time comes to the energy trading company.

So, the trader gives that order, the sell order, to the fixed price desk. The fixed price desk then calls New York again and, tells the phone clerk with the clearing broker on the floor of the NYMEX that they would like to sell the one month strip $3.50. The phone clerk immediately stamps the ticket that they have, indicating when the order was received from the fixed price desk at the energy trading company.

The phone clerk will then walk over to the pits and hand a copy of that ticket to their broker who is trading in the pits themselves. That pit broker then offers out the 12-month strip into the market at $3.50. Another broker, who has received a buy order from another customer, decides to go ahead and lift the offer on the 12-month strip at $3.50. So keep in mind that, as we mentioned in the prior lesson, it's a zero-sum game. For every buyer, there is a seller.

So, in this case, the producer is having the trading company sell contracts for them. There has to be a buyer across the pit willing to buy those contracts in order for the deal to be consummated. So in this case, there happened to be an interested party on the other hand. And for our purposes, we'll go ahead and assume that it's an end user who's interested in buying the natural gas at $3.50 for the next 12 months.

So, once the counterparty across the pit has gone ahead and lifted the order, the broker now hands the order back to their phone clerk. And the pit brokers also then have an official form that they have to fill out for the New York Mercantile Exchange, which includes the details of the transaction. So the phone clerk now time stamps the ticket, as in they've had it timestamped when the order was received, and it again is stamped with the time when the order is actually filled.

So, phone clerk calls the trader's fixed price desk. The trader's fixed price desk receives the fill from the floor of the NYMEX and repeats the fill verbally to ensure that there's no error. So the clearing broker phone clerk and the trading company's fixed price desk repeat the details of the transaction so that there's no mistake as to exactly what has occurred. And as mentioned in the prior lesson, the phones are also recorded.

So, if there's any dispute at the end of the day when it comes to checking out the trades between the energy trading company and their broker, they can pull the tapes, as we say, if there's a discrepancy and have it resolved that way. OK. The fixed price desk, now having confirmed the order, passes along the fill to the trader. The trader now passes along the completed order to the producer.

So, the producer has gotten done what the producer wanted. So the producer is now what we call hedged if natural gas prices decline below $3.50 over the next 12 months. So they can't get a price any lower than $3.50. However, because of that, they give up any upside. In other words, the producer you cannot get a price higher if the market does move up. But in this situation, the producer liked $3.50. And they wanted to make sure that prices didn't fall on them.

Here are some more terms that are frequently used in terms of New York Mercantile Exchange trading. We already covered the ask and the bid. A bull, a lot of you have already heard this term. But it's actually someone. It's a person who anticipates an increase in price or an increase in volatility. (Volatility is a measure in the magnitude of price change, as well as the frequency of the change in price). And they are the opposite of a bear. A bear, again, is a person who anticipates a decline in price or volatility. And they are the opposite of a bull.

Backwardation. It's a market situation in which the futures prices are lower in each succeeding delivery. It's also known as an inverted market. It's the opposite of contango. So let's take, for instance, the September crude oil contract. If right now it was the highest price, and October was lower than September, and November was lower than October, and so forth, we would have a backward- dated market. Because the normal situation is, the prompt month or near month, and for several months going out, prices do rise.

A broker. A broker is a party or company which is paid a fee for transactions in the financial and physical markets. Brokers do not take title to the contracts. They do not take title to the commodity being traded. They simply join counterparties together and they extract a fee for doing so. They are truly middlemen. The cash market is the market for a cash commodity where the actual physical product is traded.

So, we've mentioned a couple of times, we differentiate between financial and physical or cash marketplaces. When I talked about the pricing publications, they cover the cash market. The CFTC, that's the Commodity Futures Trading Commission. This is the federal agency responsible for the oversight of all commodities trading, not just energy commodities. The contango market. This is the opposite of the backward dated market. It's a market situation which the prices are higher in succeeding delivery months than in the prompt month.

To cover. We use that term to talk about a trader or company who happens to be short futures or options positions. In other words, they've sold contracts in anticipation of prices falling. And so that open position is known as a short position until such time as they buy those contracts back and cover that open position. A derivative is a financial instrument derived from a cash market commodity, a futures contract, or other financial instruments.

The New York Mercantile Exchange contract for natural gas is derived from natural gas itself, the commodity. And the same applies to the other energy commodities on the NYMEX. The last trading day. It's the last day of trading for the prompt month contract. Currently, for natural gas, it's three working days prior to the next calendar month. We covered the deadlines for each of these in Lesson seven.

Long. This is a market position based on owning contracts which must be sold, or the delivery of the underlying commodity must be accepted. It's the opposite of short. So a trader or a company who takes a long position, they're buying contracts in anticipation of prices rising. And then they will sell those contracts hopefully at a profit. The offer, we mentioned already. We talked about what an offer is.

Open outcry is the name given to the pit trading. OK. For NYMEX purposes, it's a method of public auction for making verbal bids and offers for contracts in the trading pits or trading rings of commodity exchanges. It is totally different than electronic trading platforms. The short. This is a market position based on selling contracts which must be brought back or the delivery of the underlying commodity must be made. It is the opposite of long.

So again, this is where traders are selling contracts in anticipation of prices falling. They'll buy them back and make a profit. We mentioned earlier the idea that when they are short, they'll have to cover those positions by buying the contracts back. Strike price. We will get more into this when we talk about options. But it's the price at which the underlying futures contract is bought or sold in the event that an option is exercised. It's also called an exercise price.

In a previous lesson, we talked about the financial markets for crude oil and natural gas. And keep in mind, those are future markets. They're telling us what the prices are every day for months going forward. But what about what's happening each day? And what about the trading for the actual physical commodity where the financial markets aren't even involved?

We're going to talk about how those things are priced. And we're going to talk about some key publications that come out that actually show the results of all the trading in the physical marketplace. And then, the market uses those as price discovery. We talked about the fact before that the New York Mercantile Exchange provides price discovery for future months for crude oil and natural gas.

In terms of the natural gas industry itself, actually, both industries were heavily regulated over the years. And we've seen deregulation occur across the board in several industries-- the airline industry used to be regulated. The banking industry was regulated. The telecommunications industry was regulated.

And so, both crude oil and natural gas had been regulated. From the natural gas standpoint, the utilities and the pipelines were regulated. And then, from the crude oil standpoint, the pipeline industry itself was regulated. The idea in both those cases was to basically make sure there wasn't a monopoly, that no one had excessive market power that would hurt the market participants, especially the consumers.

So, generally speaking, way back, there were long-term contracts entered into, mostly by producers and pipelines for natural gas or utilities. These prices were fixed prices. That means they agreed upon a fixed price for the duration of that contract. Now, back in 1978, the Carter administration enacted what's known as the Natural Gas Policy Act. There was concern-- in fact, the Department of Energy back then predicted that the United States would run out of natural gas by the year 2000. Obviously, that was not the case.

But what they did was, they set prices for natural gas. They had a starting price. And then, every month, the price would go up by a few cents per MCF. Now, obviously, this was not market responsive. In other words, if you were producing, you were guaranteed a price, and you were guaranteed that price will go up every month. So, this is what led to the bubble that we had in the early '80s, and then the subsequent crash in natural gas pricing as producers decided just to go out and drill and produce as much as they could at these fixed prices. And the pipelines and utilities had to take the gas because they had these long-term commitments.

Finally, in January of 1985, those price controls of the NGPA had expired. This began what we call the beginning of the spot market. In other words, you would have these long-term arrangements where pipelines and utilities were buying gas from producers. And now, they didn't need as much gas as they were obligated to purchase. The federal government allowed them to get out of those contracts, but they had to open up their pipelines to allow others to use the services on the pipeline.

So, the surplus supplies led to the advent of the marketing companies that we still have today. The marketplace then turned to shorter-term contracts and shorter pricing periods. You could now negotiate prices for natural gas on a monthly, and even a daily basis, and these were more market responsive. In other words, when producers had extra gas to sell, they would contact a potential buyer. And that buyer would look at the demand picture. And then, conversely, if buyers were out there and they needed additional gas, they would contact producers and suppliers.

And so you had more of a sense, truly, of supply and demand as opposed to just some long-term commitment to buy or sell. But again, pre-NYMEX-- in other words, pre-April of 1990 for natural gas, there was no price discovery. People would negotiate transactions over the phone and hope that the price turned out to be a good one. And then, they would rely on these publications that we're going to talk about to see where prices actually came out.

Now, in the case of crude oil, I think as we all know, this is a very, very old business. Refiners and producers used to enter into long-term contracts. These were fixed prices. And then, back-- way back, the railroads and pipelines themselves were regulated by the federal government. Again, this idea of the fear of monopoly. Initially, it was the Interstate Commerce Commission, which was later rolled into the Federal Energy Regulatory Commission, which has jurisdiction over railroads and pipelines. Again, those that cross over state lines, or what is known as interstate.

Crude oil pricing, again, the same situation with natural gas. Prior to the advent of the NYMEX contract for crude oil in 1983, there was no price discovery. And so, negotiations would go back and forth, and prices would probably change with almost every phone call.

Now, today, we've got global market pricing. These are known as markers-- key markers around the globe, where people look at the prices that are being traded at those major hubs. Of course, we have WTI here in the United States at the Cushing Hub. And then Brent, that's the North Sea crude oil pricing. And then in the Middle East, you have the Dubai/Oman price index as well.

Now, crude oil is different from natural gas in that the contracts are negotiated at a certain price or certain marker, but then, there can be price adjustments based on the specific gravity of the crude oil, the sulfur content-- is it sour or is it sweet like WTI-- and then what's known as the Reid vapor pressure, and that's essentially the propensity for it to turn to vapor. You actually lose some energy content when it does that. So, the contracts will have that.

Whereas, in a natural gas marketplace, all the gas has to meet the pipeline specifications. So, you can't have certain contaminants or high content of oxygen, nitrogen, and those types of things. So, there's pretty much a standard to the contracts for physical and natural gas in the cash marketplace. They don't have to make deductions for those quality specifications.

Now, the methods for establishing price, as we talked about and as Errera mentions, both NYMEX and cash can influence one another. For instance, if cash prices tick up due to high demand in a cold winter or hot summer, then those trading the NYMEX contracts are going to get that information. And they're going to essentially assimilate it and then buy contracts accordingly.

And then, the converse is also true. If the cash marketplace, let's say, for instance, in a particularly a shoulder month or if the cash marketplace is trying to determine what prices might be for the following winter, they're going to look to the New York Mercantile Exchange for price discovery and price indications. So, again, the idea that both financial and physical prices tend to track one another in parallelism and the fact that they tend to match one another upon the settlement of the futures contract, or convergence, means that they both can influence either in the prices themselves.

What we have are, though, we've got major publications that we'll talk about. And what they do is they have polling or survey methodology. In a lot of cases, they'll actually call markets and suppliers to find out what types of trades that they have conducted in the physical marketplace.

These days, it's probably more than likely that the information is being emailed to the publication or faxed to the publication. And when the publishers get that information, they have to establish what we call a weighted average cost of gas, or WACOG, or a weighted average sales price, or WASP. That means that they're taking, say, for instance, natural gas.

If there was 5,000 MMBtus, they trade it at $2.50. And then another supplier reports that there's 10,000 MMBtus. They traded it to $2.55. You can't just take the simple average. OK. They actually weight those.

And then, what happens is they post the prices. That's the term that we use. That means they put a publication out, and they actually have the prices there. And then, we refer to them as indexes or postings. Generally, in things like the crude oil and natural gas liquids, they do use the term postings. On the natural gas side, they tend to use the word index.

And generally, what you'll see on under the postings is the actual location, which is important. It's the physical location where either natural gas or crude oil is changing hands. They'll show the volume, the total volume traded at that location for that period of time that they're reporting it. It could be monthly. It could be a daily time period.

And, of course, the price range. In other words, what was the range of pricing at that location that was reported by the people who turned the pricing information in to the publications? And then, finally, the piece of information that we're interested is the actual index. What was that weighted average price at that location?

In the natural gas industry, we've got some publications. Again, we refer to these as indexes. And they'll conduct surveys for monthly, weekly, and even daily pricing.

We've talked about this idea that especially the power industry ramps up and ramps down every day, even peak, off peak. There's times when the power plants may generate up for a few hours and then back down again. So, we have a daily market. And, again, they're talking to end users, producers, and even marketing companies who are buying and selling natural gas to get the information from them.

One of the key ones is Platts. It's a Mcgraw-Hill company. And they produce what they call their monthly price guide.

Now, this is more familiarly known as Inside FERC because, initially, this was a newsletter that reported on the things that were going on at the Federal Energy Regulatory Commission. It is not affiliated with FERC. But those who have been in the industry a long time, especially traders, will refer to the Inside FERC index. But it is more formally known as Platts Monthly Price Guide.

Now, this is the most widely used monthly price guide. It's a bi-monthly newsletter and price report. What they're reporting on is transactions that have taken place for an entire month. So, for instance, at the end of May, as an example, the various entities in the natural gas business are buying and selling gas for June. And when the Inside FERC publication comes out after they've assimilated all the information-- it usually comes out about the second or third working day of the following month-- people will see what the indexes are.

Now, another one that Platts puts out is what's known as Gas Daily. This is a daily price guide. OK. They actually show prices as well for monthly transactions, but they're not as widely used as Inside FERC for those. More importantly, they're used for daily and weekly prices.

OK. This is the most widely used report for daily natural gas pricing, especially what we call swing. In other words, as supply and demand change from day to day, transactions and pricing will move up or down. And then, Platts gets survey information and posts it out there every business day.

In terms of the crude and natural gas liquids industry, the common-- excuse me-- the most important publications there and therefore the most important postings are going to come from generally two sources. One is what's known as OPIS. It's the Oil Price Information Service.

This is for natural gas liquids. They put out the monthly and daily negotiated pricing. They have a market overview; no, it's a commentary. And then they report prices at the major natural gas liquids hubs around North America.

Now, ARGUS. ARGUS is primarily known for crude oil pricing and refined products pricing, things like gasoline, jet fuel, et cetera. They put out monthly pricing, daily pricing. Now, they have a market overview. And then, they give major hub reports. In their case, though, in addition to giving major hub reports around in North America, they give prices for various global oil markers, not just WTI, Brent’s, and Dubai Oman, but various other marker prices around the world.

And then, I want to talk for a minute about electronic platforms. The Intercontinental Exchange. They're based out of Atlanta, Georgia. They also own ICE Futures Europe, which used to be the international petroleum exchange in London.

At the end of every day, they have settlement prices that are automatically calculated. In other words, they're calculating all the trades that occurred electronically on their system. In other words, it's not manually done. The weighted average cost and the weighted average sales prices are calculated.

Now, they handle thousands of physical and financial products. And it's anonymous counterparty trading. In other words, when you buy or sell on ICE, you're just looking at prices. And if you execute a trade, then you'll get a pop-up window that tells you who the counterparty is that you just transacted that with.

ICE themselves, they're strictly a broker. That is, all they're doing is getting a minor commission for providing the platform out there for counterparties to trade. And then they, again, they put out their daily postings where everything gets settled. And you can go out there and look and see.

For instance, you can find a natural gas hub and see what the average price was for all the trades that occurred on the Intercontinental Exchange. Now, one of the big advantages is this is not human beings reporting prices. This is a machine in essence spitting out actual transactions that occurred. So, there's no price fixing possible, and there's no erroneous prices being reported to the publications.

The natural gas industry especially went through a period in the early 2000s where there was in fact price fixing, false reports-- excuse me-- false prices were reported to publications, which influenced pricing. As a result, the Commodity Futures Trading Commission along with the SEC did investigations. There were natural gas traders who were fined and even got some jail time for doing that.

So really, the ICE prices to me would be the most transparent and the most honest, so to speak. And it should be utilized. And really, some of these other publications should go away because they're-- to me, they're relying on human pricing.

Flow chart in the shape of an arrow.
Production & Gathering (Wellhead Cost, Gathering Fees, Fuel)

Leads to

Processing/Refining (processing fees, refining fees, inputs/outputs)

Leads to

Transmission (levels of service, tariffs, rates & fuel)

Leads to

Storage (levels of service, tariffs, rates of fuel)

Leads to

Distribution (utilities, end-users, residential, retail)

In this lesson, we're going to talk about crude oil, the actual logistical path getting it from the pump at the wellhead to the pump, basically, at the retail gasoline station. And then, we'll talk about the value chain. Crude oil itself has no real value. It's what the refiners can turn it into is where the value actually lies.

Here, again, is this schematic of the value chain for both natural gas and for crude oil. But if you look at the crude oil parts, basically we go from the wellhead where there is the cost to lift the crude oil. Then, we've got the refining, and then, there's fees associated with that. Then, we're going to have to get it, the crude, to the refineries via various methods that we'll talk about.

Then, we also have to take away the refined products to market itself. You can store crude oil. You can also store the refined products. And, ultimately, you get to a distribution point where you're at the retail level. Or, in the case of crude oil, you're also manufacturing some petrochemical feedstocks.

So, we're talking, again, about crude oil logistics from pump to pump. Here's an old wooden derrick, crude oil, probably back from the time of the first discoveries in Titusville, Pennsylvania. West Texas Intermediate Crude Oil is going to be the standard we talked about. We did talk about that in a previous lesson when we talked about the contracts with the New York Mercantile Exchange.

But it's the North American standard. It is known as low-sulfur sweet crude, traded in international currency as the US dollar. It is priced free on board in Cushing, Oklahoma. And again, as we talked about in a previous lesson, it is traded on the New York Mercantile Exchange as a financial derivative, which does allow for hedging.

And then, Brent crude is the North Sea global standard. It is traded on ICE Futures Europe in London, which is formerly the International Petroleum Exchange in London. There are financial derivative instruments over there that are similar to the NYMEX crude contract. A lot of traders take the price opportunity or arbitrage between the London contracts and the NYMEX contracts in New York City.

Currently, still due to some supply bottlenecks, US Gulf Coast refiners are paying higher prices since imports are priced off of the Brent crude price. Now, we can't get enough of the surplus domestic supply that we have to the Gulf Coast refiners at the present time.

Here is, basically, what the EIA shows to be the growth in crude oil production over the last year or so, going back actually two years to 2013, a four-week average on each plot point, and then showing the 2014 to 2015 period, again, four-week averages on each plot point. So, you can see, there's been a significant increase in US domestic crude production. And then, imports-- as you would guess-- imports have declined steadily over the same two-year period and will continue to do so.

The pipeline infrastructure, of course, is critical to balancing the supply and demand for energy across the United States. And the same holds true for crude oil and petroleum product pipelines. Here is a very simplified schematic of the grid across the US.

Crude oil and petroleum pipeline product lines are supplied to major demand centers in the United States by over 200,000 miles of pipelines, representing about a $31 billion investment. Pipelines transport over 38 million barrels of crude oil, feedstocks, and petroleum products each day. 17% of the nation's freight is transported via pipelines for only 2% of the nation's cost.

The infrastructure now for crude oil in terms of various pipelines, you've got pipelines to transport the crude oil from major producing basins and various ports, import ports, to various refining centers and/or supply hubs. Other pipelines transport refined petroleum products, including gasoline, diesel, jet fuel, and LPGs, which are liquefied petroleum gases, from refineries and ports to end-user markets. Other liquids, energy-related petrochemical feedstocks are transported between supply chain points, perhaps from the tailgate of a refinery to the inlet side of a petrochemical processing plant.

Various modes for crude oil delivery, the primary one is the pipeline. You've got, in essence, it's a wellhead to transmission pipeline to the refineries themselves. You have pump systems along the way. And they can batch process the crude, put it in different volumes at different times, and separate them with a batch separator.

The interstate grid in the United States transports about 2/3 of all the oil. The pipelines are subject to the Federal Energy Regulatory Commission and the former Interstate Commerce Commission. They are labeled as common carriers. They do not have utility status, which natural gas pipelines do get.

The US network of petroleum and petroleum product pipelines is the largest in the world. It's also the cheapest method on a cost-per-barrel basis to move crude around. We also truck crude oil, mostly from wellhead tanks to refineries or from the wellhead tank batteries to rail terminals where it's loaded onto rail cars. It is the most costly method, you can imagine. It's the smallest amount that can be transported. It's the least volume capacity, approximately 200 barrels per tank, per truck tank, or 8,400 gallons.

Other modes of transportation, rail cars, they're very large capacity, 2,000-barrel tank cars, relatively cheap cost. The problem is there is limited access. Railroads obviously aren't everywhere.

Tankers, we're mostly familiar with those. Generally, for import purposes, they are very large capacity. Of course, they vary from standard tankers to what they call VLCCs, which are the very large crude tankers, so-called supertankers. Now, these are water-bound. We also can barge crude oil intra-country. These are large capacity tanks also. But they are strictly water-bound as well.

Here's just a schematic, kind of a simplistic map, of petroleum refined product transportation infrastructure across the US. What you see here on the map is pipeline, rail, barge, and tanker locations around the US.

Just a quick couple of thoughts on the actual regulation of crude oil. We've talked about regulated and non-regulated industries before. And pipelines have been regulated going way far back. You can see here, in 1887, the Interstate Commerce Act placed pipelines under the regulation of the ICC, the Interstate Commerce Commission, because railroads had been regulated. And now, there was a concern about potential monopolistic power for those who owned the pipelines.

This then, in 1906, pipelines where placed under what was known as the Hepburn Act. And then the Interstate Commerce Act of 1887 set some ground rules which still apply to the pipelines today. Rates that they can charge have to be just and reasonable. They have to disclose their terms of service, in other words, the rules and regulations under which they will transport the crude oil.

They have to have form and content of tariffs. That means they have to have some documentation in terms of how they are going to conduct operation, the rules for you to be a shipper to move crude oil, on there. And then, tariffs are the rates that they're going to charge. Accounting methodologies, all reporting requirements, and then disclosure of shipper information, all of these things are requirements for pipelines to operate and, again, come out of this Interstate Commerce Act from 1887.

And today, the Federal Energy Regulatory Commission, or FERC as its most widely known, has jurisdiction over the crude oil pipelines. Congress abolished the Interstate Commerce Commission in 1995. Again, they have common carrier status. That means they need to be able to carry or ship crude oil for just about everyone. They don't have utility status. Natural gas pipelines received utility status under the Natural Gas Act, or the NGA, of 1938. So, they don't have franchises, in other words.

Crude oil pipelines don't have protected territories. They also have no right of eminent domain. The right of eminent domain, especially for those of you who are familiar with land law, allows the entity to come in and condemn the property if the property owner protests the building of the pipeline. But again, these pipelines still have to provide just and reasonable rates and have the reporting requirements that I mentioned above.

Here's just a sample crude pipeline tariff. This is from Shell Pipeline Company. They have a pipeline and a crude line in the Houston, Texas area. And if you look at the top, the issuer is Shell Pipeline. The regulator in the state of Texas is the Texas Railroad Commission.

And we have, in essence, the originating point or the input points to the pipeline for the crude oil. And then the destination is East Houston, which is more than likely the very large Houston ship channel, which is the world's largest petrochemical refining corridor. That is the US Gulf Coast. They're shipping petroleum. You can see that the date of this particular contract agreement was June 1st of 2012.

The unit measuring, they're going to be paying so many cents per barrel. And if you get all the way down to the bottom here, you can see that the actual tariff rate for volumes of 0 to 65 million barrels, they're going to be paying $0.16 per barrel. If they ship a greater amount than 65, almost 66, million barrels, they will only be paying $0.08. So this would be a typical crude oil pipeline tariff. If you were interested in being a shipper, you would be issued one of these by the operator of the pipeline.

Here's just a shot, actually just a partial shot, of what is the Houston Ship Channel Complex east of Houston. It's a huge crude refining and petrochemical refining complex.

Back during World War II, there was concern about the amount of crude and refined products that we would have for the war effort. And so, the Department of Defense came up with what they call the Petroleum Administrative Defense Districts. And this is the way that they could keep tabs on the supply, the demand, and at times of rationing, set the rationing limits for the various districts across the United States. Well, these have remained in place today, and we talk about the various PADDs, the supply, the demand, the pricing and those types of things.

Now, PADD 1, it's the highest petroleum consumption rate in the United States. And you can see, I mean, it's running from Maine down to Florida. So several very, very large metropolitan areas. They are highly dependent on imports for both crude oil and refined products. 100% of the crude oil, traditionally, has been imported. But now, they do have access to some of the oil coming from the shales, such as the Marcellus and the Utica.

There's also crude oil coming from the Bakken by rail. But in this case, they mean imports as in importing crude oil from other PADD regions. 25% of the refined products in the Northeast, they do, in fact, import. They are the largest recipient of supplies from the other PADD districts.

The south Atlantic region is experiencing higher population growth rates and the slower growth in New England. So, again, demand is expected to expand in the southeast part of the United States. It's also the largest concentration of oil-heated homes. There's still a considerable amount of heating oil used in the Northeast. It's used to create hot water, as well as for space heating purposes.

And when we had our discussion about the supply-demand fundamentals that impact crude oil, we talked extensively about the idea that the Northeastern part of the United States is the world's largest consumer of heating oil and fuel oil.

PADD 2, as you can see, it runs all way down to Oklahoma, and Tennessee and all the way then up to the Canadian border in what we generally call the Midwest region. They're dependent on crude oil imports, mostly from Canada. Except now, we do have the Bakken oil, which can help supply the region as well, coming from North Dakota.

Second highest crude oil demand region in the United States. Again, several major metropolitan areas, including Cleveland, Detroit, Chicago, Kansas City, St. Louis, those areas. They are chronically short, the market, due to a combination of demand growth and refinery closures.

So, they don't have a lot of crude being produced in that area, with the exception of the Bakken and, potentially, Utica shale. There is crude oil in Oklahoma. The question is are they getting it to the refineries? And as this indicates, there have been, anyhow, reductions in the refining capacity over the years.

PADD 3, this is the origin of 90% of the crude oil and 80% of the refined products shipped among the various other PADD regions. It's the largest crude oil and refined product supply region in the US. And only two OPEC nations, that is Saudi Arabia and Iran, have a higher crude oil production rate than PADD 3.

So, you can look and every one of these is an oil-producing state. And then, no foreign nation has a higher refined product output than PADD 3. Again, the Gulf Coast petroleum refining and petrochemical manufacturing corridor is the largest in the world.

PADD 4, which is sensibly the Rocky Mountain region. PADD 2 and 3 have historically supplied the market to augment local production. It's a small, but growing, market. There's minimum demand for specialty products. The infrastructure's not developed due to long distances, limited markets, and high costs.

The Rocky Mountains are running right through this region. And so, it makes it tough to, basically, transport, have an interchange, so to speak, of crude and refined products. There is a large refinery in the Denver area.

And then, PADD 5 is the entire west coast plus Alaska. And West Coast is traditionally isolated from other US supply regions, again, due to the Rocky Mountains. Growing population continues to increase demand for products. Alaska North Slope crude oil is an important source of supply for West coast refineries. North Slope Crude oil has been around for decades. And it is piped. And in some cases, they do use large tanker ships to bring it down to the lower 48.

The California Air Resources board rules, they kind of isolate the market, which limits supply options. In other words, I think a lot of you've seen the fuel standards for California, from an emission standpoint, are much more restrictive than the rest of the country. And so refiners in that region or refiners wanting to sell to that region have to meet those standards.

Just an overview of supply and demand. Over 50% of all the US crude oil demand exists in the Gulf Coast. The demand, yes, because when we talk about crude oil demand itself, we're talking about refinery demand. Production from the Gulf Coast region supplies the majority of the Midwest and East Coast refined product deficit.

New England regions becoming increasingly dependent on foreign imports as the South Atlantic region continues to grow. The Midwest deficit is expected to grow as regional refineries struggle to keep up with demand. And the West Coast and Rocky regions are fairly well-balanced between regional refined products, supply, and demand.

In the previous lesson, we talked about the actual logistics of getting crude oil to the refineries. And again, keep in mind, crude oil itself is not where the value lies, it's once the refiners turned it into various refined products and also petrochemical feedstocks.

Here's a picture of a petroleum refining complex down in Port Arthur, Texas, which is again, part of that huge refining petrochemical corridor along the US Gulf Coast. A map of where the current refineries are located, and this one is shaded in to show the petroleum administration defense districts, or the various PADDs, that we discussed in the prior lesson. Just a simple illustration of how the process might work. You can see these are seafloor gathering systems for crude oil, bringing through onshore, then you got offshore drilling and production platforms there. You can also see some tankers that are offloading and more than likely imported crude oil directly to the refineries.

The refining process itself, these are the types of products that you can extract from a simple barrel of crude oil. You can see gasoline being the largest, and then diesel being the second largest percentage. So, we have, again, basically, the largest component being motor fuels. Now the distillation process, it's the same as distilling anything. You're going to heat up the crude oil, and then naturally there's going to be some vapors, and some other moisture, or some other condensation, and they're all going to represent products that are derived from raw crude oil. So, you're going to separate heavier and lighter components by heating raw crude oil, feeding it into a distillation tower where the cooling occurs.

The lighter fractions rise to the top while heavier fractions remain on the bottom layers according to weight and boiling points. Again, we're talking about fractions, in other words, the hydrocarbon fractions that can be removed from the complex hydrocarbon molecule that is crude oil. The primary fractions come out of this first process of distillation but things like liquefied petroleum gases, or LPGs, naphtha, kerosene, diesel, heavy oils, and residual oil. And now, we have some other processes that all these will go through, processes like reforming, alkylation, cracking, and coking to make additional products that we might need.

And here's just illustration of the distillation column, and you can see off to the right the products that come out simply by heating up the crude oil in this first phase. One of the next phases, then, is conversion, and this is where they're going to crack the remaining heavy hydrocarbons into lighter once. You've got thermal cracking where heat or steam is actually used to break down larger hydrocarbons into smaller ones, or chemical cracking where a specific catalyst is used to speed up the cracking process. The result of the cracking process is to create additional gasoline, to create jet fuel and diesel fuel. Now, again, the overall process of a refinery is to take complex hydrocarbon molecules break them down, and then reform them into the products that the refinery chooses to market at any one time.

Again, the next phase in what we call the conversion process is the reformer. This is where you have heat, pressure, and catalysts that take these smaller molecules and combine them back into larger ones. For instance, naphtha, which is a product of the distillation phase, can be turned into gasoline. Another conversion process is that of alkylation. You take some of the lower weight molecules, and they're combined using a catalyst to form high-octane hydrocarbons for gasoline blending. This are the so-called anti-knocking compounds that are added to gasoline.

And then last, but not least, we have coking, which is another conversion process. Coking is where the residual oil, the heaviest stuff that comes from the distillation process, is going to be heated, and it's broken down into heavy oil, gasoline, and naphtha as well. The remaining product then is known as coke. It is used as a fuel source, it's used as iron ore smelting, and this is what is inside of dry cell batteries.

And then you have all-in-one the refining process. You can see here, you start off with the raw crude oil, you have the distillation column, the LPGs come off the top, you can see here, the naphtha can be sent to the reformer to create gasoline, then we have the cracking, the alkylation unit and last, but not least, the coking. So, all of these together combined form the refining process, which then gives us these various products that are going to be sold in places like retail, gasoline outlets, but then, also, there's going to be some of these that are used as feedstocks for the actual production of petrochemicals.

In the last lesson, we talked about Cushing as the New York Mercantile Exchange crude oil hub for the buying and selling of physical crude products under the New York Mercantile Exchange contracts. We're going to talk a little bit about this. But I want to spend some time on it only because it's made the news a few times in the past year. There are certainly some issues related to pricing of crude oil, which again impacts the price of unleaded gasoline throughout the United States, involving Cushing and a surplus of crude oil that happens to be there.

Here are some aerial pictures of Cushing itself. It is a pipeline and above ground crude oil storage hub in Oklahoma. It is a pipeline hub. Hub-- we use the term whenever we're really talking about the intersection of multiple pipes where any type of crude, natural gas liquids, natural gas can be exchanged or moved from one pipe to another.

They also have, as the previous picture showed, it's a crude oil storage tank farm as well. It's the world's largest crude oil storage facility. The companies of TEPPCO, Equilon, and TransCanada have crude oil pipelines that run to and away from Cushing.

It has 46 million barrel storage capacity that represents 16% of the total US crude oil storage capacity. It's designed to receive Gulf Coast and Midwest crude, to store it, and then transport it to refineries in Oklahoma and throughout the upper Midwest. Some of the key companies that are participants and owners of facilities of Cushing are Enbridge, BP, SemGroup, ConocoPhillips, Sunoco, Plains All American, and TEPPCO.

Here, in the last couple years, there have been historically high inventory levels. In fact, they're running out of storage capacity for crude. There's no incremental storage capacity at present. In part, this is due to the dramatic increase in domestic production of crude oil from the shale plays.

The most recent ones are the Bakken Shale in North Dakota and the Mississippian Lime play in central or northern Oklahoma. The Canadian imports continue to increase. The Keystone XL pipeline received some press earlier this year. But a lot of people do not know that TransCanada already has a pipeline in place known as the Keystone pipeline. So, there are shipments of Canadian crude oil entering the United States, coming to Cushing as we speak.

One of the biggest issues, though, is that we can't get the surplus crude oil to the Gulf Coast. So, as a result, Gulf Coast refiners-- that's the largest petrochemical refining area in the United States-- are having to pay more for crude oil than the WTI price. They're having to import more.

And so, it's a price that is above WTI. It's not quite the North Sea Brent Crude pricing that occurs in Europe. But it's more than they should have to pay because we can't get this excess supply down to them.

A couple of solutions to this problem, this bottleneck or this glut of supply, is to reverse the Seaway pipeline. The Seaway pipeline has been in existence for several decades. It originally was a crude oil pipeline that brought crude that was offloaded from tankers near Houston in the Ship Channel and Beaumont-Port Arthur areas of eastern Texas, right there on the Gulf. And the pipeline shipped it up to Cushing from there. In the late '80s, early '90s, it was actually a natural gas pipeline, taking natural gas from the mid-continent down to the Houston Ship Channel petrochemical and refining corridor, and was later converted back to crude oil. And it currently would bring crude oil to Cushing.

However, the demand is actually in the Gulf of Mexico. So, Enbridge and Enterprise bought this pipeline from ConocoPhillips. It's 500 miles, runs from Freeport, Texas, up to Cushing, Oklahoma. And they have already reversed the flow, currently by, in essence, redirecting the pumps along the pipeline. They're able to push 150,000 barrels a day of crude oil from Cushing down towards the Gulf Coast refiners. They're working on a project to expand the pipeline. And hopefully, by next year, they'll be able to ship 400,000 barrels a day southbound to the Gulf Coast refineries.

The Keystone XL project is the one that has received some press in this past year. It's TransCanada Pipeline Company's proposed two-phase crude oil pipeline. The objective is to move tar sands, crude oil, from Canada's Alberta province all the way down to Texas.

Phase one would run from Alberta, Canada, to Cushing, Oklahoma, approximately 1,180 miles. Phase two would run from Cushing, Oklahoma, to Nederland, Texas, on the Gulf Coast. And that segment is about 435 miles.

This is a picture of the Seaway pipeline, as you can see running from Cushing all the way down to Freeport, Texas. And in fact, the flow on this has been reversed. And here's the Keystone XL project, the yellowish dotted lines, and, the existing Keystone pipeline, is in orange. And so, you can see that TransCanada plans phase one to hook up with a portion of the existing Keystone pipeline. But phase two would run from Cushing on down to both the Houston Ship Channel and Port Arthur, Texas.

Some of the project issue's, as I've already mentioned, Seaway pipeline. It's already reversed their pump stations. And it's flowing southward again already as we speak.

Keystone XL, phase one, requires a presidential permit for the international border crossing. Back in February, this was delayed by the US State Department because the pipeline route was going to go through a sensitive environmental area known as Sandhills in Nebraska. The TransCanada Keystone project's parent is investigating alternate routes, and in fact, I believe has refiled for the permit to get the international border crossing.

Phase two, the section from Cushing, Oklahoma, down to Texas, is going to proceed. TransCanada has already received most of the regulatory approvals that they need. As a crude oil pipeline, they can only receive common carrier status. They are not a utility. And so they will have to negotiate with landowners the entire way.

There is a new project that ONEOK, out of Tulsa, Oklahoma, has announced. They're going to build a crude oil pipeline, which will run from the Bakken Shale area in North Dakota all the way to Cushing. It's estimated to be somewhere between $1.5 to $1.8 billion and 1,300 miles of pipeline. And they hope to have it in service in approximately three years' time.

Flow chart in the shape of an arrow.
Production & Gathering (Wellhead Cost, Gathering Fees, Fuel)

Leads to

Processing/Refining (processing fees, refining fees, inputs/outputs)

Leads to

Transmission (levels of service, tariffs, rates & fuel)

Leads to

Storage (levels of service, tariffs, rates of fuel)

Leads to

Distribution (utilities, end-users, residential, retail)

PRESENTER: Natural gas-- natural gas is primarily methane or CH₄ with smaller quantities of other hydrocarbons. It was formed millions of years ago when dead organisms sunk to the bottom of the ocean and were buried under deposits of sedimentary rock. Subject to intense heat and pressure, these organisms underwent a transformation in which they were converted to gas over millions of years.

Natural gas is found in underground rocks called reservoirs. The rocks have tiny spaces called pores that allow them to hold water, natural gas, and sometimes oil. The natural gas is trapped underground by impermeable rock called a cap rock and stays there until it is extracted.

Natural gas can be categorized as dry or wet. Dry gas is essentially gas that contains mostly methane. Wet gas, on the other hand, contains compounds such as ethane and butane in addition to methane. These natural gas liquids or NGLs for short can be separated and sold individually for various uses such as in refrigerants and to produce products like plastics.

Conventional natural gas can be extracted through drilling wells. Unconventional forms of natural gas like shale gas, tight gas, sour gas, and coal bed methane have specific extraction techniques. Natural gas can also be found in reservoirs with oil and is sometimes extracted alongside oil. This type of natural gas is called associated gas. In the past, associated gas was commonly flared or burned as a waste product, but in most places today it is captured and used.

Once extracted, natural gas is sent through small pipelines called gathering lines to processing plants, which separate the various hydrocarbons and fluids from the pure natural gas to produce what is known as pipeline quality dry natural gas before it can be transported. Processing involves four main steps to remove the various impurities-- oil and condensate removal, water removal, separation of natural gas liquids, sulfur, and carbon dioxide removal. Gas is then transported through pipelines called feeders to distribution centers or is stored in underground reservoirs for later use.

In some cases, gas is liquefied for shipping in large tankers across oceans. This type of gas is called liquefied natural gas or LNG. Natural gas is mostly used for domestic or industrial heating and to generate electricity. It could also be compressed and used to fuel vehicles and is a feedstock for fertilizers, hydrogen fuel cells, and other chemical processes.

Natural gas development, especially in the United States, has increased as a result of technological advances in horizontal drilling and hydraulic fracturing.

When natural gas is burned, there are fewer greenhouse gas emissions and air pollutants when compared to other fossil fuels. In fact, when used to produce electricity, natural gas emits approximately half the carbon emissions of coal. Despite fewer emissions, natural gas is still a source of CO2.

In addition, methane is a potent greenhouse gas itself, having nearly 24 times the impact of CO2. During the extraction and transportation process, natural gas can escape into the atmosphere and contribute to climate change. Natural gas leaks are also dangerous to nearby communities because it is a colorless, odorless, highly toxic, and highly explosive gas. That's natural gas.

In this lesson, we're going to talk about the entire logistics and value chain, now, for natural gas since we've already covered the one for crude oil itself. And the phrase we tend to use for this is wellhead to burner tip.

On the left is just a picture of a low-pressure well, kind of a small well. That's known as a Christmas tree-- the configuration of the various valves. And to the right is what's known as an oil/gas separator. First thing that happens when the raw natural gas comes out of the ground is to separate the heavier components, the oily substances, which, in essence, are what we call condensate.

Here's a schematic just kind of showing the overall industry and the different paths that the natural gas goes through. You can see you've got the gas well. You're going to have separation between oil, water, and natural gas. It's going to go through gas processing plants. There are some opportunities for storage here. And then, ultimately, it's going to get to the end users.

Here's sort of another setup of kind of how we separate upstream, midstream, and downstream within the natural gas industry. The upstream is, obviously, the production portion of it. Gathering, processing, and transmission and even storage are considered midstream along with the trading-type functions. And then, ultimately, downstream is going to be the actual end users for that.

Some of the players, some of the labels that we talk about on the various participants-- you've got operators and producers at the wellheads. You have the processing plant, which is your midstream companies-- they're gatherers and processors-- storage operators, which, a lot of times, can be independent storage. Or they can be pipeline and storage operators.

And then we have what's known as the city gate, which, really, is the distribution point, where the gas company, or LDC, picks up the gas from the transmission system and distributes to all of its customers.

So we're going to start at the wellhead. This is the production. This is what we're interested in once the well is completed, starts producing. We're interested in how much volume can be sold on a daily basis. This is known as the deliverability.

Now, this depends on the type of reservoir that you have. Some reservoirs, once they start producing, cannot be shut in. That is, they can't be turned off because you can actually lose the production.

Also the operator of the well. There's an entity or participant who actually operates the well. That means they are responsible for the day-to-day operations of the well. They also have an interest in the well. When we talk about working interest donors, those are the ones who actually have invested in the well and have an ongoing investment commitment to any operational costs. Now, the operator is also a working interest donor.

And then the joint operating agreement, or JOA, is the contract between the operator of the well and the various working interest owners. And it spells out exactly how things are going to happen, shared costs, how revenue is going to be dispersed, and those types of things.

Again, because we're interested in the production of the deliverability-- these are the sales volumes, again, so we want to know what are the ways in which we could actually increase the amount of gas flowing from a natural gas well. Well, I think by now, we're all familiar with horizontal drilling. Horizontal drilling allows you to pull more out of the reservoir than straight vertical drilling.

Another method would be to, basically, drill another well, or what we call in-field drilling-- go ahead and drill an offset well.

Wells that start to decline-- there can be a recompletion. Now, that can be two different things. Recompletion can be where you go down in, and you attempt to do something additional to the existing reservoir. Or you find another reservoir-- another layer, another producing zone-- and you go back down, and you complete that.

Of course, fracking is a form of initial releasing of the production. It can also be done multiple times if you think that there's more to be released.

Acid is one of the ways in which wells are completed. It's an older method instead of fracturing. But if you have a well that's in decline, then you may agree as a producer and an operator together to go ahead and try and use some acid to free it up. This works mainly in places like sand formations.

Compression. Now, compression is going to be another thing where you can use natural gas compressors to draw additional gas up out of the reservoir once the reservoir pressure itself has dropped to the point where the gas can't just free flow into the connected pipeline.

And the other course is to look for what we would call a low pressure connect. This is generally a service that's provided by midstream gatherers and processors, where they have compression at their plant, which can draw the gas from your well if the pressure of your well can't by itself exceed the pressure of the pipeline that it's connected to.

The quality of the gas-- this is very important because it's going to end up in a pipeline, and then, eventually, some type of end user whether it's a power plant, or it's someone's home hot water heater. And so a couple of things here initially.

The Btu value-- this is what we're after. This is what we sell. It's the heating content, a British thermal unit. That's the amount of energy required to raise 1 pound of water one degree Fahrenheit. Again, this is what we are marketing.

Water vapor. We don't want water in the gas stream nor to the pipelines.

Any types of corrosives-- there is sulfur, which naturally occurs in the raw natural gas down in a well. It can actually lead to the formation of hydrogen sulfide, which is a corrosive. That is, it can eat away at the steel pipe.

Nitrogen itself just takes up space. It has, obviously, no heating content. The same thing with CO2. Carbon dioxide just takes up space in the pipe. And so you don't want these inerts in there because you want to fill that pipeline up with as much heating content as you can.

And then the question of whether or not the gas is processable. In other words, can it be processed. Is the Btu content high enough to extract natural gas liquids, which are valuable on their own.

The other side of that question, really, is does it need processing. The pipelines are only going to accept a certain maximum amount of Btu content. If you think about it, something volatile, like propane, which I think we're all fairly familiar with-- you can't have that in someone's home hot water heater. You also can't inject propane into a boiler at a power plant. You will literally have an explosion.

And then any other kind of treatments.

Just some of the folks that I've already mentioned-- these are your wellhead participants. A producer has a working interest in the well. They're known as working interest donors. That means-- let's say, for instance, a particular well-- you had 10 owners. Everyone essentially contributed 10% of capital up front to drill the well. And now, because they're working interest owners, they are on the hook for any additional operating costs or investment of things like the recompletion of a well or drilling an offset well.

So, as a result of that, they're entitled to 10% of the production coming out of the reserves of the natural gas well. And so we refer to that as their entitlement.

As I mentioned before, the operator is also a working interest donor. They've got a percent of reserves, or their entitlement. They are responsible for the day-to-day operations.

They're also responsible for what we call well balancing or allocations. In other words, if you've got 10 owners-- if that well plays out eventually-- in other words, it's depleted-- then every one of those owners should have at some point in time received their 10% of those reserves that are in the ground.

If not, then the operator has to cash balance that out so that everyone is on a equal basis at the end. Otherwise, this is-- we have a considerable number of lawsuits over these types of things.

And as I mentioned previously, the operator initiates this joint operating agreement among all the working interest owners.

Here's just a quick diagram of how these things might be set up in the field. You've got gathering lines. They're going to come to a central point, a common point, and then go into a pipeline. Generally speaking, this pipeline is going to go to a processing plant so that the gas can be cleaned up as well as natural gas liquids extracted.

In terms of how you would connect these, a question might be whether or not you do need compression. And that's going to be a function of the pressure downstream into the pipe in which you wish to flow your gas.

And then we have to also recognize that there's going to be costs. The more compression that you use that you have to boost up the pressure of your well relative to the downstream pipeline-- it's done in stages, and there's going to be a cost. A lot of them run on natural gas. Some run electricity. So there is a cost inherent there, not to mention just the regular O&M-type costs.

Connect costs. You're going to have to eventually connect your well, and there's usually a fee of some kind. These are referred to as taps.

And then most pipeline companies these days require what's known as electronic flow measurement. They want to be able to see from a remote location how much gas is actually flowing in. And then, again, in terms of the point at which you connect to a downstream pipeline, there may be additional treatment that may be needed at that spot. And either you pay for that up front, or the pipeline or a midstream company may do that.

Here's just a quick picture here of some compressors. This is what's known as a horizontal compressor. The actual pistons that draw the gas in and push you back out are, in fact, laid out horizontally.

Compressors themselves-- they are two parts. You've got these large-diameter pistons, and those are the ones that draw the gas in and push it out-- in other words, increase the pressure by using these pistons. And these are driven by a crankshaft.

The other part is, really, an internal combustion engine. A lot of these resemble large diesel engines you might find in a semi tractor-trailer. And as I mentioned before, if you're using natural gas there in the field, then there is a cost of that, the cost of that gas. Because you're not able to market it, you are actually consuming it at your pad site. Or if you're running electric compression, there's going to be a charge by the electric utility.

The best way to think about these is if you've ever seen one of those little electric Black & Decker machines you might have in your garage that inflates car tires, bicycle tires, et cetera. There is literally a little piston in there that's moving in and out at about 1,000 times a second, and it is taking the air at roughly atmospheric pressure-- 14.75 pounds per square inch-- and boosting it up to-- let's say, for instance, in terms of car tires-- it may be anywhere from 32 to 40 pounds per square inch.

And then just here are some more compressors. The upper left and the lower left-- these would be at a well site, at a small well, whereas the upper right would be at a central location, sort of that common point that I showed you in a diagram a few slides back. It would be drawing in gas from multiple wells out in the field.

Now, the lower right-- that's actually a turbine compressor. A turbine compressor is literally a jet engine-type of setup with fan blades and everything else running at a very high speed using natural gas. Now, a turbine compressor generally is going to be used at a processing plant to circulate the gas through it. This would be a very, very large-scale version of little turbines that might be added to car engines or turbo diesel-type of engines.

After we've gathered the natural gas from various wellheads and perhaps, brought them to a common point in a gathering system, the next thing that we want to do is kind of twofold. Number one, we want to purify the gas because the gas that goes into the pipeline system has to be about 98% methane with a lot of contaminants removed from that.

But additionally, the processing plants allow us an opportunity to extract natural gas liquids which add to the overall value chain and the actual revenue that can be derived from natural gas.

Here's just a picture of a processing plant up in Colorado. You can see, this is one of the more complex ones.

Now, the basic operations of natural gas processing plants, the first step is to remove the heavy hydrocarbons. Anything that has a specific gravity greater than methane, is considered a heavy hydrocarbon. If you think about it, the raw stream coming out of a natural gas well is going to have a lot of liquid in it. And the liquid happens to be, for the most part, these natural gas liquids. And so we can't have things like propane or butane ending up in someone's hot water heater.

Likewise, in natural gas-fired power plants, they cannot end up with any of these volatile fuels inside a boiler. They literally can have an explosion that occurs there.

And the other side of this, of course, is that we want these heavy hydrocarbons. They are marketable in the form of ethane, propane, butane, isobutane, and natural gasoline.

Simple processes with a processing plant, things like condensation. This is just, you vary the pressure and temperature of the gas stream itself, and then, you can knock out the natural gas liquids. So, for instance, when you heat something up and cool it off, liquids will drop out. If you put something under high pressure and then you reduce the pressure dramatically, liquids will also drop out of the gas stream.

Some of the towers that we'll talk about, they have oils in there which can actually absorb some of the light hydrocarbons. And those then, get funneled off. And then, fractionation is where we actually take the various liquids that may be combined and break them down into individual fractions. Thereby, forming what we call purity products, things like purity ethane or purity propane, which means the majority of that liquid is actually that hydrocarbon.

We want to purify the gas stream as well. Every natural gas pipeline company has certain standards that you can find on their website within their tariff under their statement of operating conditions. You will see that they have certain limitations on things like water, H2S, or hydrogen sulfide, which is corrosive.

Carbon dioxide and nitrogen, they simply take up space in the pipeline so they have no heating value and they just do literally waste space in the pipeline. You'd rather be pushing 98% methane than to have a higher percentage of carbon dioxide or nitrogen for that matter.

So some of the processes would be nitrogen rejection, literally, nitrogen is taken out of the gas stream.

Glycol absorption, now this is ethylene glycol. It's essentially antifreeze and it's heated up, and it can be heated up beyond the boiling point of water. So in essence, the gas stream run through a glycol absorption unit would burn the water off so you reduce the water content in the natural gas stream.

And then, also, if there's a higher level of sulfur than should be in the natural gas stream, they have what's known as an amine treater that will remove that as well.

So now we've purified the gas stream at the processing plant, essentially, we should be left with 98% methane to put into the transmission pipeline that what we call the residue point or outlet of the processing plant.

Some of the general types of processing plants. We have simple separator tower type plants, literally, the natural gas flows through the bottom. And because methane is lighter than the other heavy hydrocarbons, it will rise to the top of the column and then be basically recirculated through the plant.

Then you've got what we call bubble trays on each level and as, again, the gas flow goes through there, the heavier hydrocarbons will settle back down on these trays depending on their specific gravities. And then, again, they are piped off into tanks for storage.

As I mentioned earlier, you're going to vary pressure and temperature with reciprocating compressors. Refrigeration units and so-called re-boilers, the re-boilers are going to heat up the gas stream. Obviously, the refrigeration units are going to cool it down. And the entire time, you're pushing the gas through the processing plant using compressors. So again, raise the temperature of the gas, cool it off rapidly, we'll get condensation, and natural gas liquids will knock out of the stream.

Then we have the next step up and these are the more sophisticated processing plants-- cryogenic or what we call cryo plants. In this case, you're going to cycle the gas through refrigerants using turbine expanders. Turbine expanders in lieu of the type of compressors I was talking about that are jet engines. They're turbine engines.

Again, this idea is to cool it down. Expand the stream using a turbine compressor. And then, when you cool it down, again, you knock out natural gas liquids through the process of condensation.

The idea here, though, is to circulate this gas through the plant several times until essentially, it's been wrung out and you can extract as much NGLs as possible. It's what's called the recovery percentage of the natural gas liquids out of the gas stream.

Here's an overall schematic, and you can see here, you've got some basic-- you start at the wellhead. The oil gas separator that I had in the photo under the natural gas value chain. Condensate separator, that's the heavier liquids that are in-- they are traded in the marketplace similar to oil because they have a lot of crude oil properties.

The dehydration will knock the water out. The next tower takes out the contaminants, the hydrogen sulfide, the CO2. Nitrogen extraction will knock out the nitrogen. A de-methanizer tower literally takes the methane out. You can see when it comes off the top of the de-methanizer tower, it's dry gas. And it goes to the pipeline at the residue part of the processing plant.

And then, the final stage is what's called the fractionator. All these liquids are then broken down into their individual components-- ethane, propane, butane, isobutane, the pentanes which are C5s, and then, your natural gasolines.

And just a quick diagram here based on EIA information that shows the rise in natural gas liquids production over the last several years.

Here are some pictures of-- in the upper left-- the small processing plant and the lower right, a much larger one.

One more thing that we kind of want to talk about here regarding the processing plants is, that processing plants themselves, use some of the natural gas to run their compressors. But also, when you squeeze the natural gas liquids out, you're squeezing out hydrocarbons. You're squeezing out BTU value, heating value.

And so, the amount of gas that you put in, in terms of natural gas, is not going to be the same as what you take out in, again, in the form of natural gas, not necessarily natural gas liquids. So you can kind of see here, we call this plant volume reduction, the volume of BTUs, or the volume of natural gas that comes out on the residue side of a plant, is not the same amount that goes in on the inlet side of the gas.

Now, these are some of the ways that producers and midstream or processing companies put together their contracts. One of the most popular ones is a POP or Percent of Proceeds contract, this is a type of revenue sharing. And so what happens is, the midstream processing company goes ahead and markets the natural gas, and they find markets for the natural gas liquids. And then, they share in that revenue with the producer.

So the producer gets a percent of the net back pricing of the residual gas and the liquids sales, less whatever the midstream company's charging for their processing fees and fuel. So, for instance, we have contracts that might be a 90/10 or an 85/15. Under 90/10, the producer receives 90% of the net revenue and the midstream company receives 10%.

Now there are other producers who prefer to go ahead and market their own natural gas, and what they want then, is what's known as a keep whole agreement. That means that they want the same amount of BTUs that they gave the midstream company on the residue side. And they're going to market it so there's no revenue sharing. And they're going to pay the midstream company some fees for the actual processing.

And now, we'll talk about some of the specific products that come out, the actual natural gas liquids themselves.

These are hydrocarbon liquids derived from natural gas through the processes that we spoke about. You've got ethane which is C2H6. Propane, C3H8. Butane, C4H10. iso-Butane is an isomer of butane, IC4. The pentanes are what we call C5 pluses, that's C5H12. Natural gasolines, some of them are C5s and some are C6 through C9. And then, condensate is C6 plus. Again, condensate is a very, very light type of oil, and it is marketed in the oil markets.

Again, as we talked about, we've got to remove them from the gas stream itself because of their volatile components, but a lot of these, then, are converted into chemical feedstocks. Some are used as gasoline blending components.

The raw stream coming from most processing plants has to be processed into Y-grade. Y-grade is a composite of all the NGLs that makes it easier to ship it, either by pipeline or for trucks. Then when they arrive at a fractionation facility, that's where they're separated into so-called purity products. And a purity product would contain at least 90% composition of a single natural gas-liquid.

So, for instance, when I talked about purity propane, that would be, the liquid would be at least 90% propane.

The types of NGLs that we have, probably one of the most common ones that we do know is propane. It's approximately 40% of the overall NGL market. It is mostly used for home heating and cooking, but it is also largely used as a chemical feedstock. You can take propane and you make propylene which is a base chemical for plastics.

The primary markets for propane are the Gulf Coast petrochemical facilities. Again, the Gulf Coast is the world's largest refining and petrochemical corridor in the world.

Mont Belvieu, Texas is a large complex east of Houston. It is a huge fractionation facility. There are deliveries to and from the plant. It's a trading point. There's storage there, both above ground and underground. And there's a global market. There are actually NGLs that are exported from this area.

There is a secondary market in the mid-continent. It's in Conway, Kansas. Again, this is a much, much smaller plant than Mont Belvieu, but they have fractionation towers. There is NGL take away and delivery. There is storage there. It is a trading point. And there happens to be a petrochemical refining plant adjacent to the Conway NGL fractionation plant.

And, of course, they do have pipelines that can move southbound to Mont Belvieu so additional NGLs can make their way down to Mont Belvieu.

Ethane is about 25% of the natural gas liquids market. It is primarily used as a chemical feedstock for ethylene and propylene. Again, those are base chemicals used in the manufacture of plastics.

Now, it's rarely used as a fuel source. It can be left in the gas stream as methane. We refer to this as ethane rejection. If ethane prices are low but natural gas prices are fairly strong, then the ethane is left in the natural gas stream which raises the overall BTU content for the stream. And, of course, this is highly price dependent.

Sometimes in the middle of winter, the actual price of the natural gas on a BTU basis far exceeds that of selling the ethane in liquid form. And so you'll find processing plants go into what they call ethane rejection, that means is, they don't want the ethane. They leave it in the natural gas stream.

Same market hubs as the other NGLs, Mont Belvieu and Conway, Texas. If you hear the term E/P mix in the natural gas liquids industry, that means that it's 80% ethane and 20% propane, and that is strictly used for ethylene production.

Butane or n-butane, because now we're talking about the normal butane, 85% of the butane is used for gasoline blending. Now we talk about RVP. In the wintertime, butane is used to stabilize the RVP. RVP is the re-vapor pressure. Now it's a measurement of the ability for gasoline to vaporize at atmospheric pressure.

Any time that you are filling your car up if you see fumes coming back up out of the tank while you're filling it, that's a measure of RVP. You've got vapor there.

Several states in the United States have those vapor recovery nozzles, those plastic things that are over the gas lid. The idea is that you want to recover as much vapor as possible because number one, they do condense and they are gasoline. Number two, they are a form of pollution when they just go to the air.

We talked about the refining process. Butane is used as a cracking component when we talked about the cracking portion of a refinery process. A lot of us know about lighter fluid, meaning butane is used in lighters. It's also a propellant in aerosol sprays. It can be used for household cooking and bottled gas. And it's also a refrigerant. It is a refrigerant that can be used at the processing plants to chill the natural gas. It is also a refrigerant used in air conditioning systems in motor vehicles.

And this is iso-butane which is an isomer of butane, also known as methylpropane. It has similar uses to the butane. Gasoline blending. It's a chemical feedstock. Again, it's also used as a refrigerant in automobiles for the air conditioning systems and it's known as R600a.

And it's also known as isooctane, this is an anti-knock gasoline additive. If you've ever had the situation with knocking your car, seems like it's starting to stall and it bangs really hard and then it shuts down, this helps to stabilize the gasoline so that those things do not happen because they can be very damaging to the engine.

NGLs, the next group of natural gasolines-- C5 pluses are considered natural gasolines. You're literally able to burn those as natural gasolines. So these are also used for gasoline blending. Now they're used to stabilize the RVP mostly in the summertime. They can be used for ethylene production. They are used as industrial solvents. They're also an ethanol denaturant.

If you think about ethanol, the vast majority of ethanol is produced from corn, and it's a form of alcohol. So it literally is corn liquor. You could drink it as an alcohol. So to discourage people from doing that and to prevent the sale of it as that, basically, they have to add a little bit of natural gasoline to it so, in essence, it becomes lethal, and it certainly tastes bad.

It's used as a crude diluent, which means it can be used to dilute crude. For instance, in the Western provinces, especially in Alberta, Canada, you have the tar sands oil which is also known as bitumen, and it's extremely thick. And so they can take the natural gasolines and they can blend those, or add them to the thick crude, which makes it a bit thinner which allows it to more easily ship in the pipelines.

And again, the biggest market hub for natural gasolines is Mont Belvieu, Texas.

Pricing wise, you can see, this is just a comparison of the natural gas liquids which tend to run in sync with things like natural gasolines and crude oil.

And here, you can see just basically, again, another trend where you've got spot prices for natural gas liquids. Compared to Brent crude, Mont Belvieu propane, you can see that that's in here. And then, of course, natural gas.

Now this last slide I want to show you has to do with the fact that you can see the spike of mostly propane, this is propane spot pricing. And you can see in the winter of 2013-2014, there was a huge spike, specifically Conway, Kansas.

Now, this didn't necessarily have to do with the amount of propane, it had to do with the deliverability. We couldn't get the propane to the markets that needed it the most and that was in the Upper Midwest. You can see this past winter of 2014-2015, there was not the same type of spikes in Kansas or at Mont Belvieu.

And then lastly, I've got a slide here that kind of gives you an appreciation of the value of natural gas when you add in the revenue from the liquids. A lot of people want to know, why do producers continue to sell natural gas above or below $3? How is it possibly economical?

Well, if they're also extracting natural gasolines, then you've got a considerable amount of revenue there that's possible so you can see as you move across this spreadsheet and you get over to the liquid price per MMBTU, it is considerable.

And then we talk about the spreads that the midstream or processing companies get, and you can see in this particular sample, the total stream was worth about $3.20. The gas that it cost them to basically run the plant, was $2.65 so their crack spread becomes $0.55 per MMBTU, which is a pretty healthy spread.

Moving along now, in our discussion of natural gas, the logistics and value chain. Now that we have gathered and processed the natural gas, it's ready to be shipped to market using natural gas transmission pipelines.

Now, these are going to be large diameter pipes. This is steel pipe. These days, you'll find a minimum of probably 16 inches all the way up to 42 inch pipelines. And the primary function of transmission pipelines is to connect the supply areas to the market areas.

As we mentioned, with the wellhead and using compressors to boost the pressure of the wells to meet the downstream pipeline pressure, we have to push this gas now, in a transmission pipeline from those points of receipt of the wellheads all the way to the marketplaces. And in some cases, we're talking about pipelines that originate in South Texas and run all the way up to New York City. So again, you can imagine you've got compressors all along the way continuing to boost the pressure up.

We say, that the gas flows to the point of least resistance. That just means that on the consuming end, as the gas is being burnt at the various end users then other gas has to replace it. And so the pressure is lower on that end, the higher pressure pushes that.

Here's just some pictures of the process of actually building transmission pipelines. You can see in the upper left, that's the right away that's being dug out and then all the steel pipe, steel tubing, is laid in place, in the middle picture. You can see where they're actually having to come up over a bend of a mountain there. And then these sections get welded together. And in the lower right, you can see this is specific type of equipment that lifts the pipe up once it's been welded and lays it into the trenches.

When all's said and done, this is what you see. So if you ever see pipeline right away, all you'll see are these above ground valves, everything else is buried. Now, here's a pipeline company in the state of Oklahoma. And I like to use this diagram, only because if you look you can see the red pipes or the transmission systems, and all the yellow are the spidering types of gathering lines. So you have all these various gathering lines of various wells coming to the yellow squares, which are the processing plants. And in turn, once processed and cleaned up, the gas goes to these transmission pipelines.

Terminology wise, we talk about receipts. Any source of natural gas that is received into the transmission pipeline is known as a receipt. Now, these can be wells that are flowing directly in. These can be what we call CDP's or Central Delivery Points.

Again, getting back to the diagram of the multiple wells coming to a common point and then they can come into the transmission pipelines. Processing plants, what we call the residue lines. The gas that leaves the processing plant once it's been stripped of natural gas liquids and it's been clean and now meets the quality standards of the downstream transmission pipeline. It comes in that way.

Pipeline interconnects. The pipelines criss-cross each other in a lot of places throughout the country. And that provides for one pipe to send gas to another pipe. And so any time we have that gas moving from one pipe to another, then the downstream pipe receiving the gas from the upstream pipe, that upstream pipe is then a receipt point.

And then of course, storage facilities. When we put gas in the ground for emergency or peaking purposes, when we draw it out, the gas is then received from the storage facility to the downstream transmission pipeline. And on the flip side, the deliveries, one of the most common deliveries is to a local distribution company or just your common gas company at what's known as the City-gate. And that's where the gas company receives the gas and then distributes it to its various end users.

We also have Direct-connect End-users. Power plants, fertilizer plants, and other industrial and commercial customers like that, may be tied directly to the pipeline as opposed to having a gas company serve them. And again, the flip side of what I was talking about with interconnecting pipelines, one pipeline can in fact, deliver gas to another pipeline. And then storage facilities. In order to fill a storage facility up, we have to take gas off of one pipeline and put it into the ground.

Transmission systems. Because these are-- gas is flowing 24/7, 365 days a year. The pipelines have to monitor that activity. And so this full integrated electronic system we refer to as SCADA. That is Supervisory Control and Data Acquisition. Its the electronic transmittal of pipeline data to a central monitoring and control center. They're looking at the pressures and flows. Pipeline pressures and the amount of actual volume of gas flowing throughout their system. As I mentioned, it's monitored 24 hours a day.

But the control part comes in where they actually have control of the pipeline facilities. They can start and stop compressors. They can open up and close valves. And they also can control what are known as regulators. The regulators can control the volume of the gas or the pressure of the gas on the system.

This is what a typical gas control center might look like. Again, these are manned 24/7 and they're keeping an eye on the pressures and flows throughout their system. Now, here's a simplified map of what the North American natural gas pipeline grid would look like. The sort of shaded areas represent large producing basins. And again, the idea being that transmission pipelines have initially been set up to move gas from these various supply basins to the consuming regions.

Now, here's the traditional flow. Again, coming from major basins to other areas. And you can see, traditionally pipelines were bringing gas to the Northeast, but that has changed in recent years. And the reason it's changed is because of the shale plays. Again, looking in the Northeast at the Marcellus and the Utica, there is a considerable amount of gas coming out of the Marcellus these days.

Well, if there's gas being produced right there in the Northeast, then supplies coming from other regions are being backed up. Here were some of the original projects due to move gas from, as believe it or not, as far back as the Rocky Mountains, all the way to the Northeast. And then the initial production coming from the Marcellus, get it over to the Northeast markets as well.

And now, there are, as you can see, quite a few projects. Some are trying to move the Marcellus gas still towards the east, especially New England, but others are actually going to be moving gas out of the Marcellus and Utica shales to the southeast part of the United States and back to the Western part of the United States. Here are some of the projects that are specific to the Marcellus. Again, moving gas to the east or moving gas to the southeast down the Atlantic seaboard to two, of what will be eventually LNG export facilities.

And still, New England is pretty much starved for gas. So some of the gas is trying to get over there. There are expansion projects that you see over here, in the lower right because prices in Boston and New England for natural gas in the wintertime are absolutely astronomical. And it's because they have-- they do not have a lot of access to the regional supplies. So there will be pipeline expansion projects to help alleviate this problem in the coming years.

And as I mentioned, some of Marcellus shale gas is going to move back west. They actually have a surplus. They're producing more than the Northeast is currently using. And here's just an example. This is Energy Transfer Partners out of Dallas. They've got a plant project to bring Marcellus and Utica shale gas back across to what is known as the Panhandle Eastern Pipeline Company or PEPO, to help serve their markets up in the upper mid-- excuse me, upper Michigan and over even into parts of Ontario.

Some more west bound projects. American Natural Resources or ANR is owned by TransCanada pipelines. And you can see here, they've got projects to move gas west out of the Marcellus and Utica shales as well. Here again, are some specific Northeast to Southeast pipeline projects. There are supposed to be economic growth in the southeastern part of the United States. And so there's expected increase in demand there. So some of this Marcellus gas is going to try and get in that direction.

As I mentioned before, there are two LNG import facilities along the Atlantic seaboard. One is Cove Point, Maryland and the other is Elba Island, Georgia. Now, it's highly likely that these will become natural gas export points so there are some pipeline projects in the works to get gas from the Marcellus down to those facilities.

These are just some of the key cash points. We talked about the cash marketplace before. You have seen on the natural gas intelligence website where ICE daily cash prices are posted. These are some of the key cash market points up in the Marcellus and Utica region.

Now, these are just some pictures of what can happen if the pipeline is not monitored properly. This was actually a pipeline that burst. It was the El Paso pipeline which runs from west Texas all the way to California. This unfortunately, occurred in a national park in Arizona. And it literally, as you can see, blew a crater out. At the time they took these pictures, I'm assuming these were the first people on the scene. The safety people with the pipeline company. You can see there's still methane in there that's burning.

This is the cutaway of the side part of the pipe. Now, it blew out exactly where it was welded together. There were a combination of things that had happened here. Obviously, this part of the line had not been inspected on a regular enough basis to in fact, determine there was some type of a defect in the pipe. The other thing that more than likely happened was that the pipe was overpressure. Then in fact, it was running at a much higher pressure than was safe for this particular segment.

And then there had to be some type of ignition source there because once the pressure of the pipeline erupted the pipeline, something had to ignite the natural gas, unfortunately. You can see this entire area has been scorched by the fire that came from this particular rupture.

Here's a piece of the pipe. This is part of the pipe that's missing. First of all, two things, if you look back here, you don't see any snow whatsoever. This whole scorched area within the right away and then yet, off to the side somewhere you see snow on the ground and literally pieces of the pipe that were blown over into the woods.

This is a section of pipe again, that blew out of there. Now, when the pipe is actually made it's made from sheets of steel and it's rolled. And then there is a weld that runs along laterally and that's where we get the rolled piping or the rolled steel. So you can see this explosion was enough to rip an entire section out of the ground and rip it along its initial weld.

Now we have gathered the gas. We have processed it. We have put it in the transmission pipelines. Before we take it on to the local distribution companies and ultimate end users, there is an incremental step-- which may or may not occur-- and that is the underground storage of natural gas. 

Here, again, is the energy commodity logistics and value chain. You can see that the fourth step in our process here is that of storage. Here's a cutaway of what a potential storage facility could look like. Again, it's really just, in most cases, a depleted oil and gas reservoir. So you treat it the same as you would a typical oil or gas well. 

Here we have some vertical wells and one horizontal well. This is a good example of what a horizontal well looks like. You can see that by cutting across the reservoir horizontally you can extract more production than the straight, vertical holes that come down in traditional wells. 

This is an above ground shot of a storage facility. You don't see the caverns. You just see what's above ground. In this particular case, there is a pipe being laid that's going to connect a power plant directly to this storage facility. 

Traditional uses for storage-- mostly by local distribution companies or gas companies in the winter time, when there was high demand and there was not enough wellhead gas to meet the demand. And so gas had been stored, mostly in the summertime, and was utilized for what we refer to as peaking supply, that is when demand peaks due to unforeseen changes in the weather. 

The summertime-- low demand for natural gas, because again it was mostly a winter fuel. Also, prices tended to be lower in the summer than the winter time, because of lower demand. Also, pressure relief-- as we saw in those photos as to what can happen when the pipeline pressure gets too high, when the pipeline pressure is, in fact, high, pipeline companies can put some of that gas in the ground and reduce the pressure. Also price opportunity-- when prices dip, one can buy some natural gas at those lower prices, stick it in the ground, and save it for when demand may go up and prices can be higher. 

Probably, though, the number one utilization of underground storage by gas companies is for emergency deliverability. We mentioned that term deliverability in talking about the well head, the amount of gas that can be pulled out on a given day. We have seen harsh winters just two years ago, the winter of 2010, 2011, was fairly harsh. And so local distribution companies, your gas company, can rely on gas in storage to supplement the wellhead gas that they're receiving otherwise. 

In the Gulf Coast region, if there is, in fact, an active hurricane that enters the Gulf, a lot of the offshore rigs are going to be evacuated and shut down. There's a substantial amount of natural gas that is then curtailed. Well, supply in underground storage facilities can supplement the loss of that natural gas deliverability. 

Traditional operators and users of natural gas storage facilities-- mainly the pipeline companies in both the supply and market areas, and then local distribution companies in the market areas themselves. 

Types of natural gas storage-- there are mainly three types. Depleted oil and gas reservoirs being the most common. Why? Because you're taking what used to be an oil or gas well, and you're now going to put natural gas down in it. So we already know the characteristics of the wells. We know how much natural gas they can hold. 

There are also terms, permeability and porosity. These are geologic terms. The permeability is how much natural gas can actually be held in the formation. And then the porosity, the types of little pores in the formation itself as well. Those two combined can give us a determination of the deliverability of that particular reservoir. That would allow us to determine whether it would make a good storage facility or not. 

We can inject gas from the transmission pipeline. If the pressure's high enough, the gas will freely flow into the formation. As we add natural gas to the formation, and the pressure increases, we may actually need to use compression to draw the gas from the transmission pipeline, and shove it down into the reservoir. 

Conversely, when it's time to utilize the gas, we can withdraw it. If the pressure is high enough, that is if it's higher than the downstream transmission pipeline, it'll free flow. At such point in time, as the reservoir pressure meets or is less than the downstream transmission pipeline, we'll use compressors to boost the pressure up from the reservoir. 

Oil and gas reservoirs converted to storage take approximately 50% of the capacity to be filled first before they can utilize it. We refer to this as the cushion, or base, gas. So, for example, a one billion cubic foot natural gas reservoir that we would like to convert to storage is going to take 500 million cubic feet of natural gas to be put in place first. The tier above that is what we refer to as the working gas. It is the usable space. It is the recoverable gas. This factor itself is one of the reasons why developing storage facilities can be so expensive -- because that initial 50% of natural gas will have to be purchased and cannot be sold until the end of the life of the storage facility when it's extracted. 

Another type, and these are very much used along the Gulf Coast, are salt domes, or salt caverns. There is literally a large, impermeable hole. When the natural gas, or natural gas liquids, are put into salt caverns, they do not escape. If you find a salt formation, it's very easy to form one of these. 

High pressure water carves out the reservoir. Then you inject gas into the cavern. And free flow it in or compress it, just as you will with the oil and gas reservoirs. The converse process of withdrawing, again, can also be free flow or compression. These actually have very high deliverability. They can be cycled numerous times. That means gas can be injected one day, withdrawn the next day, and so on. And so they make a very, very worthwhile type of storage facility. 

Aquifers, these are water formations that are utilized for storage. You generally see these only in the upper-Midwest market areas, where they are used for emergency supply. You're pushing gas into the aquifer, the water comes out. When you need the natural gas, you push water back in and take the gas out. 

Now, these are the least desirable types of storage facilities. There's a high development cost because there is no pre-existing facility in place. The aquifer reservoir characteristics are literally unknown. The boundaries of an oil & gas reservoir, or the boundaries of a salt cavern, can be determined, but not an aquifer. 

The base gas requirements-- we talked about an oil & gas reservoir requiring about 50% of base gas. In the case of an aquifer, you need 90% base gas to hold back the water. So you only have about 10% of capacity that you can utilize. And then you're going to have to use gas compression to force the gas into the aquifer, or water injection, when you wish to remove the gas. 

We have a couple of classifications of storage. We have what we call seasonal, and these are mostly the depleted oil and gas reservoirs. We inject gas in what is normally the lower demand, lower price period of April through October. And then we withdraw the gas in what we refer to as the winter months of November through March. 

Now, these time-frames are very key to the industry. Pricing for natural gas, when we talk about seasonal pricing, we use the terminology summer and winter. They are not the typical summer and winter periods that we're accustomed to. There are no four seasons within the natural gas marketplace. We talk about summer being April through October because it corresponds to the injection period for natural gas storage. And we talk about the winter as being November through March, because it is the typical withdrawal period for natural gas storage. 

High deliverability classification of storage are your salt caverns and your enhanced depleted oil and gas reservoirs. Has there been additional compression added to the oil and gas reservoir storage facility? Do we have horizontal wells? Both of those will increase the deliverability of the oil and gas reservoir. Salt caverns by themselves have high deliverability characteristics. 

Current users-- we see pipelines still using these to provide what we refer to as market-responsive services. Seasonal storage, as well as cyclable storage-- cyclable storage meaning that you can inject or withdraw at any point in time during the term of the contract that you have with the pipeline and their storage affiliate. Park and loans-- this is a short-term service that pipelines can provide. If you have excess gas, they allow you to store it in their facility for a short period of time. If you find yourself short of supply relative to demand, you can also borrow some gas from the pipeline for a certain fee. But you will actually give them the molecules back upon the repayment time. 

Local distribution companies, again your gas companies-- traditional storage usage. They're going to use the storage for short-term peaking of services. These days, however, what they pay for storage is going to be regulated by the respective public utility commission in the state where the LDC operates. 

The largest group of current users are your marketing and trading companies. We will talk briefly later on about the deregulation of the industry. But there are third-party marketing and trading companies that are now providing services that were once provided by the pipelines and LDC's. We call this the re-bundling of those services. So they can provide peaking gas. They now provide same-day gas. That is, if the utility or end-user needs gas today, for some reason, because they have storage capacity they can sell them gas today. 

In other situations, they can provide gas on demand. A marketing and trading company with cyclable storage can literally allow an electric utility, for example, to draw gas from them as they need it. Each one of these services commands a premium. And this is really where marketing and trading companies make their money on these added value services. They cannot provide these added value services, however, without storage. 

Storage facilities also allow them to respond to changes at the markets. Price volatility, that is the movement of price up and down, as well as the speed at which price changes occur. Those represent opportunities for savvy marketers to buy and sell. And they can do this because they have storage facilities that will allow them to store the gas when prices are lower, and to sell gas when prices are higher, both in the physical cash market, as well as in the financial market on the New York Mercantile Exchange, which we will talk about in both lessons seven and eight.

Now we finally reach the actual end of our logistical path for natural gas from well head to burner tip. We're going to talk about the various types of end users. This is not an all-inclusive list. But we'll cover quite a few of them.

We've got basically local distribution companies which I've referred to thus far as gas companies, that's what they are, and then the various direct end users of natural gas. Local Distribution Companies, otherwise in the business known as LDCs, these are your gas companies. Whoever your local gas company is an LDC. They're going to distribute the gas to the various end users that are connected to their systems.

Their primary operation is to distribute low-pressure gas. When we talked about transmission pipelines, they move the gas at very, very high pressures. And you can't have that type of pressure coming into your house, especially into something like a hot water heater. So, they lower the pressure. You can see here, mainline transmission pipelines can be running 500 pounds per square inch to as much as 1,500 pounds per square inch. Well, the gas flow into your house at the meter needs to be cut down to four to six ounces per square inch. So, we have residential customers, commercial customers, industrial, and electric customers.

Another type of operation, they can actually perform a transportation service. In other words, several states across the country have what's known as a deregulated natural gas industry. And that includes deregulation of the local distribution companies. So, if you're a large enough end user, you actually can buy gas from an entity other than the natural gas company, your local gas company. But they still make sure that it gets delivered to you, and so they charge you a transportation fee.

So, we refer to this as transportation behind the city gate. That means within the distribution territory. So end users can have their own transportation on the LDC system. It's an open access system. So in other words, any entity that qualifies under their regulations to do so can, in fact, buy from someone else and have it transported.

Here's kind of a breakdown of that delivered price. When you get that gas bill and you look at it, these are the components. You've got the commodity is only 34% of that. So the price of the commodity itself. The LDC or the pipeline company is about 19% there of the cost has to do with the transmission pipeline transportation and storage. But then the distribution costs are 47%. So this is your gas company providing that service.

Here's just a typical residential meter. And here, we just have a large metropolitan area. This happens to be Denver. So we're going to address the actual end users. You can just see here some of the end users. Electric power is the largest end user for natural gas, 31%, followed by industrials and then residential. Commercials having a very small percentage as well. And one thing here, notice the vehicle fuel at this point in time, as of 2013, was less than 1% of the consumption of natural gas in the US.

We'll talk about electric generators. There are two different groups. You've got the electric utility generators. These are regulated producers of electricity. They're either federally regulated or regulated by the respective states. And then you have the non-utility electric generators, the so-called independent power producers. These are also known as merchant power companies.

And then, another group is known as the co-generators. These are companies whose plants actually produce electricity and steam-- steam as an actual commercial commodity. It can be shipped by pipeline to nearby facilities such as food processing or actual crude oil refineries.

Within electric generation, we have different types of generators themselves. A simple cycle generator has gas turbines. These are essentially jet engines. They're internal combustion. They use natural gas as a fuel. And then there's also steam turbines where the natural gas goes into a boiler first and creates steam. And the steam is used to push the turbines. It's not the fuel source. It's literally spinning the turbines.

You also have combined cycle plants. This is where you have a combination of gas and steam turbines. The gas turbine, again, is strictly using natural gas as a fuel. But it has exhaust heat. That exhaust heat then is pumped into a boiler where we create steam which then drives a steam turbine. So a combined cycle natural gas plants are among your most efficient. And then again we have the co-generation facilities where they've got a gas turbine which is going to create electricity. But then they also have a steam boiler where are they going to create the steam, as I mentioned, to sell as an actual commercial commodity.

And then, you can see, this is somewhat of a simplified diagram of the process itself. Now, you see on the left you have an energy supply or fuel. Now, the fuel, in this case, doesn't matter. It can be coal. It can be wood. It can be natural gas. It can be nuclear fission. It's anything that can create heat because the idea here is to take water and basically bring it to a boiling point where you have steam.

Now the steam actually drives the turbine. That's the little blue and white area in the middle part of the diagram in the center there. That turbine spins. And on the axle of that turbine are magnets, very large magnets. And they spin within a copper wire field. The magnets are of opposite polarity. And when they spin they actually create current, which as you can see, goes on out into the transmission lines. And most plants re-circulate then the steam. They cool it down. That's what those large cooling towers are that you see. And then, they recycle as much of that water as they can.

Here's what a typical gas turbine looks like. Again, you can see it's got fins on it like a jet engine. Other end users such as industrial end users, you've got petrochemical refining as I mentioned. They're going to have feedstocks created from natural gas, paper production, metals especially things like steel mills use a considerable amount of gas in their furnaces. Stone, essentially cement plants, they have components like clay and glass and silica and sand. And they actually, in addition to having furnaces, once the cement is created it's in a wet mixture, and they use natural gas to actually dry it. All types of food processing, I'm sure that everyone can come up with to use that, and then in fertilizer. Anhydrous ammonia or fertilizer, 80% of that feedstock happens to be natural gas.

Then we also have commercial uses. Believe it or not, there are large air conditioning units at, let's say for instance, in large warehouses or factories that can run off of natural gas, you know, food service, motels, hotels, healthcare, various hospitals, office buildings, and then at the retail level. And then, last but not least, we have natural gas vehicles. The market for natural gas vehicles has grown the last few years. But it's probably going to decline because just recently Honda Motors said they're going to phase out the manufacture of their CNG Civic which has been around for probably 20 years, and then also their Honda Accord CNG vehicle as well.

Now the better ones are dual fuel. You can use gasoline or CNG. But CNG still has an important usage within what we would call fleet vehicles. For instance, metropolitan buses, trucks using on short haul routes like the USPS or FedEx or UPS, and then pool cars. Various companies who have let's say a certain district and they don't need the longer range of cars, they can use CNG. But again the limitations are the limited range and refueling. Now the refueling infrastructure across the United States is getting better. But for most people, it is still a sticking point in terms of buying these types of vehicles.

Here's just pictures of four of the existing LNG import facilities that we have in the United States. And you can actually see there's one off of Massachusetts, one off of Georgia, one off of Maryland, and one of three that we have in the Gulf Coast region. Now, what is liquefied natural gas? It's natural gas that's cooled to a -320 degrees Fahrenheit. Now what this does is it reduces the volume by over 600 times, which makes it easier to transport and store.

So in other words, let's just say if we had a cubic foot of natural gas, there's a certain amount Btu within that. But the same cubic foot of liquefied natural gas would have 600 times the heating value. So you can see where storing the liquid or transporting the liquid, you are actually storing and transporting at a much, much higher heating value than with pure methane. So you can see here a ton of liquefied natural gas is equivalent to 47 MMbtu, or 47 million Btu. And one ocean-going LNG tanker can hold the equivalent of 3.0 Bcf of natural gas.

Pricing around the world varies from region to region. In Japan, they price LNG landed off of the price of crude oil that's imported, the so-called "Japanese Cocktail." What it amounts to is just the average price for the crude oil that's been purchased as cleared through their customs. And so really it's Japanese cleared customs crude pricing, but it's just referred to as the "Japanese Cocktail." In Korea and Taiwan, again, it's the price of LNG landed is tied to the Btu-equivalent "basket" of crude oil postings. In the UK, continental Europe, and Southeast Asia, it's a combination of oil and coal prices. again, converted to a Btu basis. And then the pricing for LNG on a Btu basis is equivalent.

Now in the United States and Canada, we have been traditional importers, and we have very limited export facilities. But we have a competitive natural gas marketplace. As you all know from your studying in earlier lessons, we have the New York Mercantile Exchange. So we have an open, active competitive marketplace for natural gas. Now Russia, China, and the Middle East, they regulate the price-- the various countries, the governments do. And they actually subsidize the price for their citizens. You can see here that because of the growth in the shale gas, we have steadily declined our imports over the years.

Now the US as an exporter, some of the reasons it makes sense for us, we do have a surplus gas supply. The shale plays and the tight formations have resulted in abundant, relatively cheap supply of natural gas. $3 or less is an extremely cheap price for natural gas. And the EIA estimates that we are producing about 3.0 Bcf a day more supply than we have market for.

And as I mentioned in the previous slide, we have a competitive natural gas-based pricing market. This is actually causing some renegotiations of some of the existing global contracts. In other words, Japan sees the coming of LNG exports by the United States. And so they're already talking to some of their suppliers and saying, you know, look, we want to get off of this crude oil pricing type of mechanism in our contracts and convert over to some type of natural gas index.

We have existing LNG import facilities-- those pictures I showed you in the beginning. And we actually, believe it or not, we are exporting virtually at the moment. Since we no longer need natural gas imports in the form of LNG, what's happening is those entities in the United States who have contracted for tanker loads are literally selling them mid-sea, so to speak, sending them to different ports rather than coming to the United States. And then we actually have had, for about 20 years, a small LNG export facility off the coast of Alaska at a point called Kenai, and that's been operated by Conoco Phillips.

You can see here now the red squares represent existing LNG points-- again, off of Massachusetts, Cove Point, Maryland, Elba Island, Georgia, and then we have about four in the Gulf Coast area. Now these are going to be the logical facilities to export. They have about 60% to 70% of the infrastructure in place already. They can handle tankers for offloading. They have onshore storage. They have connections with pipeline companies.

So what they're doing, is they are building the liquefaction trains. We talked about the fact that the natural gas has to be super cooled. Well, that takes a liquefaction facility or train to be built. So, in other words, they've got a lot of the infrastructure already in place. So some of these other companies that believe they're going to dive into this particular arena are not going to have the facilities. It's going to cost them a considerable amount more investment.

You can see here, of course, the natural gas exports and re-exports by country. Again, we have declined in terms of our imports. And then all of a sudden, you can see we've actually started to do some exporting. And then the ways that it gets to market. Again, this is that logistics and value chain we talk about for natural gas. In the case of exporting LNG, you can see here that the wellhead gas is going to move by pipeline to the liquefaction facility. And then it gets shipped to a particular port of entry where it's regasified and then distributed to the various areas of need. So it's sort of the opposite process that we've been used to for decades now, where we actually receive the LNG, and we regasify it and we utilize it through the pipeline systems of the various end users.

Pricing wise, again, here in the United States, we've got a financial natural gas forward market, which you're familiar with is the NYMEX. It provides price discovery. so everyone knows what the price is. Now just currently based on the one-year average price for natural gas at Henry Hub, it's approximately $3.05 at the time that I put this particular lecture together.

Now these are the estimated supply chain costs in US dollars per MMBtu. Approximately $2.15 represents the process for the liquefaction. Shipping overseas is about $1.25. Regasification at the new port of entry is approximately $0.70 per MMBtu. So you have total costs of about $4.10. So in this particular situation, you're really around $7.15. And I apologize, this still says $7.05 on it.

Now when we compare that to world pricing, you can see that there are not that many places in which current LNG exporters can make money at $7.15. Now, throughout Asia, that's still a pretty good deal. And they're still going to make money in parts of South America. But over in Europe, you could not at the present time export LNG and make money over there.

Now this situation has dramatically changed. One of the events that created the impetus for the US to consider exporting LNG had to be back in March 2011 with the Fukushima nuclear power plant disaster in Japan. As I mentioned earlier, Japan is solely dependent on imports for natural gas and imports in the form of LNG. Well, at the time, they shut down all of their nuclear power plants. So the demand for natural gas in Japan spiked, and we were seeing prices upwards of $14 per MMBtu. So you can imagine at the time, those planning the LNG export facilities out of the United States were expecting extremely lucrative business and very, very large profit margins. Such is not the case today. And in fact, Japan is looking at re-licensing their nuclear power plants again.

In this lesson, we're going to talk about another piece of the value chain for natural gas from wellhead to burner tip. And that's the actual transportation rates that transmission pipelines charge for service, and, again, we're talking about moving gas from point A to point B. And we need to talk a little bit about the regulations that form the background for this particular service and for the regulation of the pipelines.

In 1938, there was what was known as the Natural Gas Act. This is still an important piece of legislation today because when you see the lesson on the exportation of LNG from United States, you'll see in there that projects of that nature still have to be approved under the Natural Gas Act of 1938. They have to receive what's known as a 7(c) certificate for the actual construction, and that is issued by the Federal Energy Regulatory Commission.

Now, under the NGA of 1938, both local distribution companies and pipeline companies were given a utility status, because back then we had what was known as a bundled service. The pipeline companies themselves were actually buying the natural gas, transporting it, and selling it to the end users connected to their pipes. Now the NGA utility status gave the pipelines a few things.

Number one, they had a protected territory so no one could duplicate the exact route or service territory that the LDC or pipeline was going to serve. However, in return for that, they had to act "in the public interest." They had to file what were deemed to be "just and reasonable" rates of service.

Now, one of the benefits then of being the utility is that they actually obtain the right of "eminent domain." So, they can actually condemn a land owner's property if they believe that that particular route is necessary for their right of way. And as I mentioned just a few seconds ago, they provided "bundled" services. In other words, they bought, transported, stored, and sold the natural gas, and they had no competition on their particular pipeline.

Under the Natural Gas Policy Act of 1978, the Federal Energy Regulatory Commission was established. It replaced the former Federal Power Commission. Now, in '78, the Carter Administration actually believed, or there had been a study done by the Department of Energy where, in essence, the United States would run out of natural gas by the year 2000. So, to encourage the exploration and production of new sources of natural gas, they set minimum price controls on natural gas. They literally started with a certain price, and it would escalate monthly automatically without any consideration for basic supply and demand fundamentals.

So, this is what led to this big gas "bubble" that we had in the early '80s. As we've seen over the last few decades, prices tend to go up and tend to go down, and we've had these situations where we've had bubbles, and then the bubble bursts. So, in the early '80s, the natural gas industry took a big hit because prices fell dramatically.

Now, in January 1985, those price controls finally expired. Natural gas was now going to be bought and sold in a more competitive environment, and things like supply and demand were going to be taken into consideration. The pipelines, though, had to give up this merchant function. That means they could not be the only exclusive sellers of natural gas anymore, and these excess supplies that we had in the '80s, they led to the need for entities to market those supplies that the pipeline still had under contract.

And so, in some cases, the pipelines themselves formed what were called affiliated marketing companies, but this also-- this January 1985 expiration-- these prices led to what we call today, the "spot" market for natural gas. That is, not so many longer term contracts as had been the case before, and so a lot of marketing companies jumped into the game. These were non-pipeline affiliated ones. And so, they went ahead and decided to go out and purchase this excess gas that was on the market from the producers and turn around and find end users for them, thus duplicating what the pipelines had done for decades.

Again, as I mentioned, this was the evolution of the "spot" market itself. FERC issued Order #436. Now this is known as the "Open Access" rule. What that did was that basically dictated to the pipelines that they were going to have to offer their transportation services to anyone who was interested in it on a nondiscriminatory basis. They also had to file various levels of services that they were going to provide, as well as the rates they were going to charge.

They had to establish what were known as nomination and allocation procedures. Now, nominations are merely a schedule that you as a shipper provide to the pipeline company that lists the supply sources that you have coming into their pipelines. These can be wellheads. They can be processing plants. And then, you also tell them where you want the gas delivered, thereby establishing what we would call a path, a transportation path.

In FERC Order #497, because I had mentioned earlier, some of the pipeline companies went ahead and immediately formed their own marketing groups after 1985 to take advantage of the surplus supplies. But the federal government was, once again, concerned about a potential monopoly, and pipelines were giving capacity to their marketing companies, so this basically prohibited that. The interstate pipeline companies had to separate from their affiliated marketing companies and could no longer offer them any type of private or preferential deals.

Now, the types of services that natural gas transmission pipelines provide today, the first one, in terms of just actual transportation service, is what's known as FIRM, or what we call FT FIRM transportation. Now, what happens here is the shipper pays what we call a Demand Fee or a Reservation Fee. Now, they pay this once a month to reserve a certain amount of quantity in the pipeline. We call that the Maximum Daily Quantity. Now, that's reserved, and the shipper pays for that regardless of whether or not they actually use it.

And then, as they use it, the pipeline measures the actual natural gas that's coming into their pipe and being delivered on behalf of the shipper, and they charge what's known as a Commodity Fee or a Usage Fee. So, at the end of the month, the pipeline has measured the amount of gas the shipper flowed through the system, and they will charge them an additional fee. Pipelines have what are known as minimum and maximum transportation rates that they file with the Federal Energy Regulatory Commission, but they also have the right to sell unused capacity. Any time a FIRM shipper or a shipper who has FIRM transportation does not use 100% of their contracted space, they can actually sublease that, so to speak, to interested parties.

Now, within the FIRM transportation contract that you have with the pipeline, you'll have what's known as a Path. In other words, you will have the right to move gas from the points of receipt that you have, whether they're wellheads, processing plant outlets. You may have gas and storage that you want to bring into the pipeline. So they will give you a Path that will allow you to bring those receipts in and set them to certain delivery points that you have, and, again, this is known as your Primary Path. This is your right. This is what you've got reserved.

And then, sometimes, what they'll do is they'll allow you a Secondary Path. If there are not others using the space, then you may be able to go ahead and use that as rights under your FIRM contract.

Now, another service that they offer is, if the pipeline hasn't sold all of their capacity on a FIRM basis, they'll have what's known as INTERRUPTIBLE space. Now I put this in all caps on purpose, because you have to realize that what's going to happen is if they have extra space and you take it on an INTERRUPTIBLE basis, yes, you're going to get a discounted rate because they want to go ahead and use that space, but it's INTERRUPTIBLE. In other words, it is subject to recall by the pipeline at any time. And so, if you have a situation where you're making a FIRM gas sale to an end user, or you've promised the producer that you're going to take their gas, you do not want to enter into INTERRUPTIBLE transportation. And, again, since it's INTERRUPTIBLE, you're not paying any type of Reservation or Demand Fee. You are strictly paying the Commodity Fee.

One of the pipelines that I like to use in this course, because I believe it's pretty simplistic the way they're set up, is Natural Gas Pipeline Company of America. Now they are a subsidiary of Kinder Morgan out of Houston, but you can see here they have zones. These are-- we would call-- sometimes we call these Postage Rate Zones, but the zonal rate matrix makes it very simple to determine what the rate is going to be.

For instance, we're going to deal with the Midcontinent Receipt and Delivery Zone. And so, you can see, that's sort of in parts of Kansas and Oklahoma, primarily. And so we're going to be dealing with the idea that we're bringing gas or our receipts are in this zone, and then we're going to deliver them to Chicago.

Now, if you look up over near Lake Michigan, where Chicago is, you see it's the Iowa-Illinois Receipt Zone. That's also known as their Market Zone. So, we're going to talk about moving gas from Oklahoma in this Midcontinent Receipt and Delivery Zone, up to the Market Zone, which is known as the Iowa-Illinois Receipt Zone.

Now, when you go to NGPL's website and you look up their tariff, under the tariff, it says, Currently Effective Rate Schedule. And so, these are the rates that they currently charge to move gas from some points that you see on the previous map to another point on the map. Now, we're going to be dealing with the Midcontinent area, so if you look at the Receipt Zone, which is the left column, and you go down 1, 2, 3, 4 categories, OK, you will see there that the Reservation Fee to move gas from the Midcontinent Zone to the Market Zone, which is the top of that column where the rates are, the Reservation Fee is $9.18. That's per month. You pay that up front for the space that you want reserved, and then, when you actually flow the gas, when they meter it at the end of the month, you're paying about a penny and a half for the Commodity Fee.

One of the things that occurs in terms of the cost of moving gas is that of fuel. So far, our costs are the Reservation Fee, a Commodity Fee. And now what happens is, when the gas moves from point A to point B, we've talked before in terms of a logistics chain about this idea that they're using compressors along the way.

Now, compressors, for the most part, are going to be natural gas. They may have some electric compressors, but they have the right to charge you for that. They can charge you for the cost of the electricity to run the compressors, or they can-- what they do is they'll deduct the fuel that they use along that path.

Additionally, when there's some type of a maintenance or some type of operation where they actually have to vent the natural gas pipeline, they get to account for that, and the shippers have to make that up to them. And so, the way it's done is they withhold a certain percentage per path. So, for instance, in the case of our example, whatever the fuel deduction is to move gas from Oklahoma, the Midcontinent Region, to Chicago, the Iowa-Illinois Market Region, they have that in their tariff, and they will retain that much natural gas from you. So, we use terms like "Lost and Unaccounted for" because this is gas that, again, has been vented or, perhaps in some cases, has even leaked from the pipeline, and they really cannot quantify it exactly, but they also have what I mentioned is in terms of compressor fuel.

Now, further down in the NGPL tariff, you will see these fuel percentages. These are the charges of fuel that they have the right to retain. Now, again, getting back to our example, if you look under the Receipt Zone and you find the Midcontinent, and then you move over to the right, that's under the market, what they're saying is it costs them essentially 3.2% fuel to move the gas from Oklahoma to Chicago. In other words, their estimate is that they lose that much.

So, for our purposes, what happens is, let's say, for instance, you want to move 100,000 MMBtu's a day to Chicago. If you put 100,000 MMBtu's a day in Oklahoma, essentially you're only going to get about 997,000 delivered to Chicago because they're going to retain this 3.2%. The reason we need to know that is that is a cost. So, for instance, if we are buying 100,000 in Oklahoma, we're only going to be able to sell the 997,000 in Chicago. So we have to, in terms of our economics, we have to price that in.

Now here is just another pipeline that you can see with zonal rates. This is a pipeline company called Enable, and as you can see, they're all over Oklahoma and over Arkansas and parts of Louisiana. The reason I want to use them is because here is essentially their storage rates, so we can talk about storage. It's set up fairly similarly.

You can see here FSS, or Firm Storage Service, the Deliverability Fee. That's actually similar to the Firm Reservation Fee on a pipeline. You have to pay this to guarantee that, in fact, the gas can get to and from the facility when you need it. The Capacity Fee itself, this is the charge on the total capacity that you are asking to be reserved in their storage facility.

So, let's just say you want a bcf of space in their storage facility. They're going to charge you this 2.3 cents per month for that, and then the actual monthly storage fee is going to be about a penny and a half. And then, you see, they also have an INTERRUPTIBLE Storage Service as well.

So, this basically covers the transportation rates and storage rates, which, again, are part of the value chain, and we have to take those into consideration when we are actually transacting natural gas deals, either with the producer or with an end user. So, we know either what charges to add up from the wellhead forward to charge the end user, or if we have a price from the end user, all the costs to deduct going back to where then we have what we would call a netback price at the wellhead.

If you own or work for an oil-producing company, you know that you’re going to produce crude oil over time. You know that you’re going to have production in April, May, November, and December. But you’re concerned about the price. If the price goes up, then you will make more money. If the price goes down, you will lose.

On the other side, let’s say you own an oil refinery. You know you are going to need crude oil for November and December, so you have to buy that. You have to pay for that. If the price goes up, you start losing money. If the price goes down, you make money, fortunately, but that’s not always the case. That’s where hedging is going to help to reduce the risk and mitigate, and sometimes remove, the risk.

What you can do is go to the financial market, to the NYMEX, and get the futures contract for delivery in November or December, whenever you want it. If you’re a crude oil-producing company, you know you have to take your position. If you’re a crude oil refinery, you will be needing crude oil. You have to go and take a long position. But remember, these contracts are binding.

If you own an oil-producing company, you have to go to Cushing and deliver it there at the time. If you have a long position by the expiration date, you have to take the delivery from Cushing. That’s the location under the contract binding.

Let’s say you have an oil refinery or a crude oil company that is not close to Cushing, or you are not interested in working with Cushing, taking delivery, or delivering it to Cushing. The good news is you can still use this futures contract with a tweak called simple hedging. We’ll go through that right now and walk through some examples.

This is the same for natural gas companies. If you own a natural gas-producing company or a power plant that needs natural gas, you have to buy and are very concerned about the price fluctuation. You want to mitigate that risk and reduce your risk exposure. We’ll see how we can use these futures contracts, a combination of futures contracts, which is called a simple hedge.

Remember, you are operating in some local spot market. As we learned in lesson four, the local prices are going to be more volatile compared to the futures prices. Why? Because they are being affected by the local supply and local demand. Any small fluctuation in supply and demand will change the local price immediately. Local prices, or spot prices, are going to be more volatile. By volatile, I mean more variation in the price compared to the financial market.

A perfect hedge or simple hedging strategy is going to be taking two equal but opposite positions in the cash market and the futures market. A producer will be long in the cash market. A producer is always long commodity because a producer always has the commodity, always has crude oil to sell. So, a producer is going to be long in the cash market and has to take a short position in the futures market. This is called a short hedge.

On the other side, a consumer, let’s say an oil refinery, is always in need of crude oil. An oil refinery is short commodity; it’s always short in the cash market, in the spot market, in the physical market. So, a refinery should take a long position in the futures market. This is called hedging. We’ll walk through some examples and see how this hedging strategy can eliminate or significantly reduce the risk exposure of these two players.

The only difference between a perfect hedge and an imperfect hedge is that a perfect hedge entirely eliminates the risk. An imperfect hedge, which is more realistic, does not fully eliminate but substantially reduces the risk exposure. An efficient hedge is highly dependent on the relationship between the futures and spot markets. Because these two are highly correlated, we can see gain and loss in one market will offset all or some of the loss or gain in the other market.

Simple Hedging

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.

In the case of a natural gas midstream company engaged in the gathering and processing of natural gas. Their profit depends on the changes in the price of natural gas that is 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.

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 prices.) 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.

More on Hedging

As we learned in the previous pages, gain, and loss in hedging depends on the basis.

Predicting the behavior of the basis could create an opportunity for making 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, basis narrows at the expiration date, but this rate is unpredictable.

So we learned that a perfect hedge is when the hedge completely eliminates the gain and loss in the market due to the price fluctuations. We started this with this example and said, "Okay, assume you work for an oil-producing company and you know that you're going to have your production plan and you know you're going to have $500,000 of crude oil for the market in December. Right now, let's say it's March. You know that you're going to produce around $500,000 of crude oil in the market in December. So your position in the cash market is going to be long. Always, it is going to be long. You're going to be long commodity in the cash market. So the hedging strategy is you have to go to the financial market and sell how many? 500 contracts right now in March, right? Let's go through some numbers here. Let's assume the current price in the spot market is $60 per barrel. December futures contract delivering in December is $61, right? So you will go and sell 500 futures contracts expiring in December right now, right?

And let's say time passes and we are getting close to December. It's November, early November. Price changes, and in this scenario, prices go down. Prices go down in the financial market and also go down in the spot market. Why? Because we said the relationship between the spot market and futures can be explained in two terms. One term is when the financial market and the spot market are highly correlated. They track each other. They are being affected by the same factors. One goes up, the other goes up. One goes down, the other goes down too. And the other term is convergence. Convergence is for the expiration date. When we get close to the expiration date, these two prices, financial market and futures, get close to each other. They converge under this scenario. So we'll see that it's early November. It is still some time to the expiration date, but prices have gone down.

Okay, I'm trying to put the pen. So the spot market has gone down 70 cents. You remember in March it was $60. Right now it's $59.30, 70 cents. And also in the financial market, prices have gone down too. It was $61 early on in March when we sold December futures at $61, and right now prices have gone down and it is $60.30, right? So this is how we set up the table. As you can see, early on in March, the price in the cash market was $60. So we went to the financial market and we shorted 500 futures contracts expiring in December at $61, right? Time passes. It's early November. Prices go down 70 cents in the cash market, 70 cents in the futures market, and because we are not interested in delivering the commodity to Cushing, Oklahoma, we have to close our position in the financial market. Now we are going to calculate the money that we lose in each market.

So we learned that because prices have gone down in the cash market, we're going to lose some money in the cash market, right? We are producers. We aimed for $60. Now prices have gone down to $59.30. How much money do we lose in the cash market? $500,000 of crude oil times this difference, $59.30 minus $60, times $500,000, which is going to be minus $350,000. How much do we gain or lose in the financial market? You remember the position is short. We sold the contracts at $61. Price went down from the fundamental factors. We know that if we take a short position, we will make money if the market is bearish, right? So we sell high, we buy low. How much money do we make? The difference, right? It is going to be 70 cents, the difference between these two, times 500,000 barrels, 500 contracts, 1,000 barrels each contract. So it is going to be 500,000 barrels. So we're going to make a profit of $350,000. And as we can see, these two are exactly equal, so the net is going to be zero. This is called a perfect hedge, right? When what we lose or gain in one market equals what we gain or lose in the other market.

Okay, let's work on another example here. We assume from now to November prices went down. Prices go down. Let's assume the other way. Let's assume from now to November prices go up. Let's see what happens. In this example, we saw how hedging was successful in helping us make up the money that we lost in the cash market, right? Okay, another example. Let's say prices go up. Prices go up to $60.50 in the cash market and $61.50 in the futures, right? Again, we set up the table. In March, right now, the price in the cash market was $60. We had 500,000 barrels of crude oil, and the position was short $61. Sorry, this should be $61. I should correct this. I think I missed that. Slide number 41. Okay, so the price was $61. The position was short. Now time passes. It's November. Prices go up 50 cents here, 50 cents here. Let's see how much money we make or lose in the cash market. So prices go up, right? And we are producers. We are crude oil producers. When prices go up, we make money, 50 cents. How many barrels? 500,000 barrels. So we are going to make $250,000 in the cash market. How about in the financial market? Prices go up, right? 50 cents go up. The position was short. From the fundamental factor, we know that if we have a short position, if the market is bullish, if prices go up, we lose money, right? How much? The difference times the barrels that we are going to have in the market. How much do we lose? $250,000. Again, in this case, these two gain and loss, they match, and we end up losing nothing, gaining nothing. Very important point here. If there was no hedging strategy, we could have made $250,000 because prices went up. Now, because we are obligated under this hedging strategy, because we shorted 500 contracts, we are obligated to close the position, and we lose money. So because we hedged, we lose money. If there was no hedging, there was no loss here. But remember, hedging is not only about getting rid of potential loss. Hedging is when you are going to say, "Okay, I don't want any deviation in my revenue. I'm going to stay with what I plan, and I am willing to get rid of potential profit as well as potential loss." So this is what we see here. If there was no hedge, you could have made $250,000. But when you are in March, you don't know what is going to happen in November. So you say, "Okay, I don't want to risk that. I could make money, or I could lose money. I'm going to get rid of both." In this case, we can see under this scenario, we could have made money, but because we are under this hedge, then we lost some money under the hedge, but they cancel out the job.

Perfect Hedge - Seller's Hedge or Short Hedge

• Let's assume a crude oil producer is planning to sell its product of 500,000 barrels of crude oil in the cash market in December.
• They are said to be "long" the commodity.
• Producer sells 500 December futures contracts.
• 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.
• Producer sells 500 December futures contracts.
• The price is now set at $61.00 for December delivery of West Texas Intermediate Crude Oil at the Cushing, OK, Hub.

The profit in the spot market is offset by the loss in the financial market.

We have the same concept for the buyers, right? Buyers, let's say a refinery. A refinery is going to need crude oil as the raw material, right? So, because a buyer is always short in the cash market, they have to take the opposite position in the financial market, which is the long position. That's why this is called a long hedge, right?

Okay, let's work on an example. Same example, let's say you work for a refinery. Right now it's March. The price in the spot market is $60. The financial market delivering in December is $61. Time passes. Early November, prices go down. Prices go down 70 cents in each market, spot market, and financial market.

We set up our table. This is the table, and let's calculate how much we make or lose in the cash market and the financial market. So, as a refinery, you are a buyer, right? So, if prices go down, you aim for $60. Right now, 70 cents less, so you end up paying less money, so you actually make money. How much? The difference between these two times the quantity of oil, the volume of oil that you will need. How much? That is going to be the difference times $500,000. So, you are going to end up making $350,000 because you took a long position in March, right? And you have to close your position in early November. Prices go down. The position was long. From a fundamental factor, we know that if you take the long position, if the market is bearish, if prices go down, you lose money because you buy high and sell low, right? How much? Minus $350,000. And again, under this scenario, you see that if there was no hedging, we could have made $350,000. But because we hedged, we are obligated under this futures contract. We have to close the position. When we close, we lose money in closing. But when it's March, you don't know what is going to happen in December. So, you say, okay, you know what, I'm going to get rid of potential loss and potential profit. In this case, you get rid of potential revenue. If you know for sure the market is going to be bearish, then you should not get involved in any hedging, right?

Okay, the other example, assuming that the market is going to be bullish. So, prices go up 50 cents in each market. We'll set up the table. March, spot market $60, futures market December $61. Then time passes, prices go up, the market is bullish, 50 cents in each market. We end up losing money in the cash market because we planned for $60. Then prices go up, we need to buy at a higher price, so we lose $250,000 in the cash market. Financial market, what happens? We took a long position. The market is bullish, so a long position in a bullish market makes money. How much? The difference times the contracts that we have. We have 500 contracts, $1,000 each. It is going to be 500 times the difference, so we'll make $250,000. And as you can see, the net here is zero. What we make in one market cancels out whatever we lose in the other market. Here, hedging is perfect. So, we were covered. We made some money that covered some of the extra expenses that we had in the cash market.

Okay, so this was a perfect hedge when gain and loss in one market eliminates gain and loss in the other market. This is a bit... In reality, they don't exactly... The spot market and financial markets are highly correlated, but the changes are not exactly the same. You see here, 50 cents here, 50 cents. These are not exactly 50 cents. So, in that case, what creates the situation is going to be called imperfect hedge. Everything else is very similar to here. The hedging strategy is very similar, but the net is not going to be zero because the change is not exactly the same. Still, they are highly correlated. Still, if one goes up, the other goes up. If one goes down, the other goes down, but not exactly the same, you know?

The imperfect hedge, which is a more realistic case. So, same examples but different prices, different scenarios. The structure of an imperfect hedge is very similar to the perfect hedge. The only difference is the change in the prices in the financial and futures markets are not going to be exactly the same. So, we are going to have eight examples: four for short hedger, four for long hedger.

Now, let's walk through the first four examples. Again, let's assume you are working for an oil-producing company. It's early March. You know that you're going to have 500,000 barrels of crude oil ready for the market in December. Right now, the cash market price is $60. The futures delivering in December is $61. And you are a producer, so you're going to be long in the cash market. So, you have to take the opposite position in the futures. Your position is going to be short in the futures. You go and sell 500 contracts expiring in December in the futures market.

Let's start with the first example. Let's assume time passes, and prices go down. Right, first two scenarios, prices go down. Here we can see the spot market goes down 50 cents. The spot market goes down 40 cents. So, it was $61 minus 40 cents, it is $60.60. The second example, which we will get to after a couple of slides, prices still go down, but the change in the futures market is larger than the spot market. You can see the spot market price drops 40 cents, futures price drops 60 cents.

Right now, let's work on the first example. So, price drops in both markets, but in the spot market, it drops a bit more than in the financial market. Okay, so here's the table. Today, it's March. Spot price is $60. December futures are going to be $61. So, we take a short position, 500 contracts delivering in December, right? This is the hedging strategy. Time passes. The market is bearish. Price drops. Price drops 50 cents in the cash market and 40 cents in the financial market.

How much do we lose in the cash and the financial market? How much are the gain and loss in the cash and financial market? So, here we can see we aimed for $60. Now, the price drops. We are sellers, so we make less money. Price is down. How much money do we lose? The difference between these two, right? 50 cents times 500,000 barrels of crude oil, right? So, this is going to be 50 cents times 500,000 barrels of crude oil, and it is going to be $250,000.

What happens in the financial market? That was the loss, right, negative. Do we make or lose money in the financial market? Short position, bearish market, making money. How much? The difference. We sell at $61, we buy at $60.60. How much do we make? We make 40 cents, the difference between these two, times 500 contracts. So, this is a gain, 40 cents times 500 contracts. And what is the net? 500,000 barrels of crude oil, right? So, I have the calculations here. We lost $250,000 in the cash market. We gained $200,000 in the financial market. So, the net is minus $50,000, right? So, in this hedging strategy, we ended up losing $50,000, right? So, hedging is still efficient. It didn't eliminate the entire loss, but as you can see, this minus $50,000 is a lot less than minus $250,000. Under this hedge, we still lost some money, but this is far less compared to minus $250,000, right? So, hedging is still effective. The net is not zero. We lost some money, but this is far less than if we were not hedged.

Second example. Prices drop. Still, the market is going to be bearish, but it drops less in the cash market. Cash market is $60. Right now, it drops 40 cents going to November. Futures, right now, is $61. Then it drops to $60.40. So, in futures, it drops 60 cents. Setting up the table, right now, $60 going down to $59.60 in the cash market. Do we make money or lose money? We lose money. We are sellers. Price goes down, we get less money. How much? The difference between these two, which is going to be 40 cents times these 500,000 barrels of crude oil, which is going to be $200,000.

Financial market. Do we lose or gain money? Short position, bearish market, so we gain money. How much? The difference between when we open the position compared to when we close the position. This difference is 60 cents. How much money do we make? 60 cents is the difference times 500,000 barrels. I have the calculations here. We lost $200,000 in the cash market. We gained $300,000 in the futures. Under this hedge, what is the net? $100,000. So, in this case, we ended up making money. Under this hedging, we are protected against this loss and also made some extra cash.

Now let's move on to the case. Still, we are talking about the seller's hedge, but in this case, the market is going to be bullish, right? Example three and example four. In both cases, prices go up. In one, cash prices go up smaller than the futures, and in the other one, cash prices go up larger than the futures, right?

Example three. It is going to be a seller's hedge or short hedge. It is early March. The spot price is $60. Futures delivering in December is $61. The market is bullish. Prices go up. It goes up 35 cents in the cash market, but it goes up 50 cents in the futures market. We set up the table. This is the hedging strategy. Again, we are going to be long in the cash market, so we take a short position in futures. The market is bullish. Prices go up. Sorry, this is a typo. This should be 35 cents. So, this is what we made in the cash market. This is what we lost in the futures market, and this is the net. As you can see, under this scenario, under this hedging strategy, we ended up losing a little bit of money, $75,000. And again, remember, because we are obligated to close these positions, we lost this $250,000 in the financial market. If we had known that the market was going to be bullish, there was no need for hedging because we didn't know what was going to happen in November. We got into the hedge, and right now, we got stuck, and we have to pay $250,000. If there was no hedging, we could have made $175,000 more, and right now, because under this hedge, we ended up losing $75,000.

Okay, the fourth example. The market is still going to be bullish, but what happens here is the increase in the cash price is going to be higher compared to the futures. So, prices go up 50 cents in the cash market but only 40 cents in the futures. We set up the table. Right now, the cash market is $60, and futures delivering in December is $61. Time passes. It's early November. The market is bullish. Prices have gone up 50 cents in the cash market and 40 cents in the financial market.

So, do we make money or lose money in the cash market? Prices go up. We are sellers, so we are going to make more money, right? So, how much? The difference between these two, which is 50 cents, times the amount of oil that we have, which is 500,000 barrels. We make more money in the cash market. Financial market. Do we lose money or make money? Short position, bullish market, we lose money. How much? The difference between these two, which is 40 cents, right? 40 cents times the 500 contracts times 1,000 barrels each. So, here we make $250,000 in the cash market and lose $200,000 in the financial market. What is the net? The net is positive, slightly positive, right? Again, here, because we are under this hedging, we are obligated to close the position. We lose the money in the financial market. If there was no hedging, if the company was fully exposed to any risk, then we could have made $250,000, but we lost $200,000 of that in the financial market.

Buyer's hedge or long hedge. A buyer is short in the physical market, in a spot market, so the buyer should take the opposite position, which is long in the financial market. Working with the same example, let's assume that you work for a refinery that will need, that will know in December, the refinery will need 500,000 barrels of crude oil. They have to buy 500,000 barrels of crude oil from the cash market in December. So the hedging strategy is they have to take a long position right now in March, or whenever it is right now, and wait until before December.

So, for example, this is, let's say, example five. Under this scenario, we'll have four scenarios. The first scenario, example five, is when prices go down. The first scenario, it goes more down in the spot market compared to the futures. The second scenario is the opposite.

Okay, so we set up the table. Right now, in March, the cash market price is $60. We know that the buyer is always short in the spot market, so buyers should take a long position in the financial market. So the buyer will buy 500 December futures contracts from the financial market. The price is $61 right now. Time passes. It's early November, and so what happens when prices go down? Do buyers make or lose money in the cash market? Because the price goes down, they pay less money in the cash market, so they end up making some money in the cash market. How much? 50 cents per barrel. So it is going to be 50 cents per barrel. They make money in the cash market, make more money because they have to pay less, and they will need 500,000 barrels.

Financial market. Do they lose money or make money? We know that a long position loses money in a bearish market. The market is bearish from now to November, so they lose money in the financial market. How much? The difference between these two, which is 40 cents, times the amount of 500 contracts, a thousand barrels each. So they end up losing $200,000. So they make $250,000 more in the cash market. They lose $200,000, and as you can see, they still end up making a little bit more. The net is not zero, it is a bit more, but under this hedging strategy, they lost money in the financial market, right? Again, the important thing here to remember is because they were under this hedge, they lost money in the financial market. In this scenario, if there was no hedging, they could have made $250,000. But when you are hedging for some time in the future, you don't know what is going to happen in November, right? That's why you hedge.

Okay, the next example. Again, the market is going to be bearish, but changes in the spot market are going to be less than changes in the futures market. Let's see what happens. We set up the table again. Right now, the cash market crude oil price is $60. The financial market delivering in December is $61. The market is bearish moving on to November. Prices drop 40 cents in the cash market, but it drops 60 cents in the futures market. Early November, the contract expires in December, so we have to close our position.

Do we make money or lose money in the cash market? Prices go down. We are buyers. We have to pay less, so we end up making some money because we paid less. How much? 40 cents. 40 cents, and there will be 500,000 barrels of crude oil that we'll need, so we'll make $200,000 in the cash market. We pay less, $200,000.

Financial market. Do we lose or make money? Long position, bearish market, loses money. How much? The difference between when we open this contract, when we open this position, to when we are going to close. 60 cents is the difference. We have 500 contracts. Each contract is a thousand barrels. So we end up losing $300,000 here, and as we can see, the net is going to be negative $100,000. And again, as we can see, under this hedging strategy, we ended up losing some money. If there was no hedging, we could have made $200,000.

The next set of scenarios, which again involves this buyer, is a long hedge but the market is going to be bullish. Prices go up, right? Prices go up.

So, first example, we assume that it's early March. We will need crude oil for December. We work for a refinery. The cash market price right now is $60. The December futures are going to be $61. The market is going to be bullish, so prices go up in the cash market and in the futures, both 35 cents in the spot market but 50 cents in the futures. Let's calculate our loss and gain in each market and the net.

So, the hedging strategy is we have to take a long position in the financial market. This is the table. Prices go up. Do we make money or lose money in the cash market? So, our goal was $60. We are buyers. Prices go up, so we have to pay more. We have to pay 35 cents more, so we end up losing money in the cash market. How much? 35 cents times 500,000. We end up losing $175,000 in the cash market.

Futures. We took a long position. The market is bullish, right? Long position in a bullish market makes money. How much? The difference between prices when we open the position to when we are going to close it. 50 cents is the difference times 500 contracts times 1,000 barrels each. We end up making $250,000. The net is going to be $75,000.

So, under this hedging strategy, under this scenario, we not only didn't lose $175,000 in the cash market, we made some money. We made $75,000 as net under this hedging strategy.

Okay, the last example. The market is going to be bullish, but changes in the spot market are higher than the changes in the futures. So, the spot market increases by 50 cents, but futures increase by only 40 cents.

What happens? How much do we gain or lose in the cash and futures market? In the cash market, prices go up 50 cents. Do we make money or lose money? We are buyers. Prices go up, so we have to pay more. How much? 50 cents per barrel, and there are 500,000 barrels. We end up losing $250,000 in the cash market.

Do we make money or lose money in the financial market? Again, long position, bullish market, making money. How much? The difference between when we open the position to when we close it. 40 cents is the difference. 40 cents, 500 contracts, and 1,000 each, right? So, we are going to make $200,000 here. What is the net? Minus $250,000 plus $200,000. We are negative $50,000.

So, as you can see here, we still lost some money, but this money is far less compared to the $250,000 that we could have lost if we were not hedged, right? So, this is hedging using the financial futures contract hedging strategy.

The video shows a graph with the explanatory variable on the x-axis and the response variable on the y-axis. There are many points on the graph. The correlation value is shifted from -1 to 1. What the correlation is -1 the points are in a linear, negatively sloped line. As the correlation value changes until the correlation value reached +1 where the points are now in a linear, positively sloped line.

So, I'm gonna click on the chart icon. This is the third column from the left, right beside the last, and we will focus on it. I click here to launch in a pop-up menu or a new window. This is May 2020 crude oil futures.

Okay, let me clean up the chart a little bit. I removed the information that we don't need for now. We'll add them later. So, this is the chart. As you can see, the vertical axis is the price. This is dollars per barrel of crude oil. You can change the limit of each of the axes. You can click on the axis, hold the click, and move it up and down, and it changes the range of the axis. It's the same for the horizontal axis, which is time. Click, hold, and move it to the left and to the right. You can also use these features: you can zoom in, you can zoom out, you can move to the left, you can move to the right, or you can refresh the page. You can restart the page. So, this updates. This is the real-time data. We can see this price changes quickly, and once in a couple of seconds, we'll get some new information.

Okay, I'm gonna zoom into more recent data, and we'll go through some of the... So, you are familiar with this type of chart. This is called a bar chart, and we have it. We can clearly see it here. This is... There are multiple pieces of information that are represented. These are presented by each of these bars. So, we should be able to read five pieces of information. Each bar should give us five pieces of information. So, what are those pieces of information? Open, close, high, low, and the trend, which is the color, right, on that day.

For example, let's start from one of these. Let me zoom a little bit to be able to see this. Let's, for example, talk about this. This is March 25th, 2020, and we can see this is a bar. There is this left little tick or little line here, there is one on the right. The bar has some lower part here and the bottom and top of the bar. So, what is the left? The left line, this is sticking to this bar, is the open, right? The right is the close, right? And the top part of each bar is the highest price being traded on that date, and of course, the lowest part is the low. So, if you move the pointer to any of these bars, you can see these numbers up here. They will get updated. For example, here, this is March 25th, and as you can see up there, open was $24.37, high is $25.24, low, close, and percentage change.

Okay, there is another piece of information that is being shown here, and that's the color of these bars. You can see that they come in two colors, green and red. What is the difference? As you can see, if the open on that day is lower than the close, or if the close is higher than the open, this bar is green. If the close is lower than the open, the bar is red. What does it tell us? It tells us the trend of the price on that day. For example, these are the last five business days. We can see it opened high, it closed low. Opened high, closed low. Opened high, closed low. And including today, open and close are fairly around the same value, but this is red. It is telling us that the close is lower than the open. So, if this close goes a little bit higher, if it passes the open, this bar will turn green.

So, the five pieces of information that we get from each of these bars are open, high, low, close, and the trend of the day.

Let's move to the next chart. How do we change the chart? So, up there, there is a chart icon. The next one is the second most common chart, the candlestick chart. On the top part of the chart, you can find them here. These are under chart options, and I select the candle. Okay, the candle is another type of chart. This is very common in finance. Again, this gives us each candle for each day. It gives us five pieces of information, but this one is a little bit tricky compared to the bar chart. Each bar is going to tell us five pieces of information: open, high, low, close, and the trend of the day.

But here, we don't have that left line and right line. We have the upper part of the candle, the lower part, and the actual candle top and bottom. So, these are four. So, how do we know which one is open and which one is close? That's indicated by the color. If the color of the candle is red, then the lower part of the candle is close, and the upper part is open. If the color of the candle is green, then the lower part is open, and the higher part is close. You can double-check that by moving the pointer to that candle. You should be able to read it up here. Let me move it to a pointed point on the candle, and you can read it from there.

So, on this day, March 23rd, the open is $22.52, the low is $20.80, the high, which is the very top part at the end of this line, is $24.70, and the close was $23.36. You move this pointer around. The lower part of the chart, the x-axis, shows you the day. You track this line, and you will see this is March 27. The right-hand side shows you the price. You move it to this top part, and you can see this is $23.30. This is around the high, which, sorry, this is the close that we can read from up there.

One of the biggest problems with this chart is it needs a color printer to be able to read the low and high because if you print this in black and white, these two will look the same. So, how do we know which one is open and which one is close if you need to know the open and close? There is another type of candle chart called the hollow candle. This is for the time that if you are going to print it in a black and white printer, if you have the hollow candle, it means that it's the same as the green color. So, if you have a hollow candle, it means that the trend that day was upward. So, the lower part of the candle is open, and the top part of the candle is close. If the candle is filled, in a black and white printer, it will look filled black. If that's black, then the trend is going to be downward. So, the top part of the candle is going to be open, and the bottom part is going to be close. This is the only difference, but this is a very common chart, and you just need to know when we read the open from the top and when we read the close from the bottom.

There is another chart that simplifies this. If you are not very interested in what happened that day and you want to have only one single price for that day, you will just add a line. You can add it by, and you're more than welcome to open the chart and do this with me. You go to the top part of the chart, from this little arrow, you pick the line. If you pick a line, you will get a single line for each day. How do we know which price this line is reflecting? Is it open, close, high, or low? By default, it is close.

We'll see this FX function that you can use to add other features to the chart. One very important thing that you want to have in the chart is the volume being traded. This is in the chart by default, but you can add it or remove it. I removed it because I didn't want too much information. I'm going to add this back again just to show you how you can add it and remove it.

You click on FX, and this gives you a list of items that you can add to the chart. That was just the volume, volume trades, and this is volume. Just click that, and you can see it will be added directly to the chart, and you can see it at the bottom of the chart. This tells you the activity in the market, and this can be very helpful to see what is going on in the market. And again, as you can see, as soon as the price dropped, there were so many trades going on that day. The color of these columns is extracted from the color of the bar. So, if that day had a downward trend, you will see the red color. If the day had an upward trend, you can see the green.

So, what is the actual volume of trading that day? Going up to the top left-hand side of the chart, you should be able to see these numbers. For example, you move the pointer to one day. This is March 19. At the top left of the chart, you can see the volume of trade. Sorry, the volume of trade is 1.192 million trades. You can see these different days, and as you move it, you will see these there. You can add other indicators, or you can hide these.

Moving average. You can add the moving average to the price, or you can add the moving average to the volume being traded. So, what is the moving average? This is simply the average of some days: five days, ten days, two weeks. It's up to you. You can decide how many days you include.

If some of you have done this before, you know that the moving average is you pick a window, you calculate the average of prices in that window, and you move this window every single day. You add the new price, you drop the oldest price from that window. We did this in the previous activity for the standard deviation. If you apply the average function, it will give you the moving average.

The idea behind moving averages is that the price tends to go back to the moving average. So, if the price goes above the moving average, it tends to go back to the moving average because every day we include that price and update the average for the new price. If the price is higher than the moving average, it can get back to the moving average. If it's lower, it tends to come back to the moving average.

We don't need to calculate that. We can just go and add it to the chart. For now, I'm going to just hide the volume, and we go to the moving average. I will add the volume back. I don't want too much information in your charts. I don't want it to be too complex. We go to the FX and we write "moving average." As you can see, there are many different types of moving averages. The simplest one is just the moving average. This moving average can be calculated exponentially or weighted, and so on. Let's skip that. We kind of learned about these weighted and exponential in previous lessons, but for now, let's keep things simple.

For now, I'm going to click on the moving average, simple moving average. As you can see, it is added to the chart. Closing it, and we can see, let me show it to you. Okay, so this is the moving average. How many days are being included in the moving average? The default of that is nine days. So, nine business days are included in each day's moving average, and this is the moving average tracking the price.

So again, as you can see here, for example, the price is below the moving average. Now we can see the price comes back to the moving average here. It is a price higher than the moving average, then it comes back to the moving average, and we can see the rest. So here, because the price drop is significant, the moving average is behind, but we can see the sharp drop in the moving average, and the price eventually will get back to the moving average. So, moving average includes the previous days, so you don't have any signal for the future. It tells you what has been the trend of the price in the last nine business days. So, by the time that these will go back to the price, the price will go back to the moving average. It means that the moving average will be updated with the new price data, and these two will merge.

Okay, things that you will need to do, and you don't need to calculate anything. We can just have the website do it for you. There are features in the moving average, not many but a few, that you can just conveniently use. Let's say you need nine days as a lot. You can just increase it or decrease it, and you can see, you can have it five days, you can have it for, let's say, 14 days. You can go up to as many days as you want. I think there was a max that, yeah, 100 days. I don't think you need that many averages, but in case you need, so the default is nine, and you can go with fewer days or more.

Okay, here are a few things that I want you to know. You can change this day, so this moving average is calculated based on the close price. You can change it to open, high, low, and any of those, or you can change it to the average of high and low divided by two, the average of high and low. This is the average of high, low, close divided by three, the average of these three. And this is the last one, the average of open, close, high, low divided by four. So, the chart provides these for you conveniently. You can just pick them from the chart. The default is close, and this is what everybody uses, but let's say for some project, for some reason, you need more, you need to include what happened during that day, so you can include that information as well.

You can also change the window that the moving average is calculated based on. You can increase it, or you can reduce the window. So, one thing that please pay attention to, what happens if I increase the number of days in the window, or if I shorten that to one day, right? What happens if the window is longer? If the window is wider, then the moving average is smoother, right? And it's kind of behind the price, right? It has a longer memory. The moving average has a longer memory. If you reduce it to fewer days, you can see it tracks the price closely because there are only two prices, today and yesterday, included in the moving average. So, it is not as smooth. It tracks the price very closely.

There are so many other parameters and indicators that you can add to the chart. You don't need to calculate any of these; you can just see the trends and make your decision, interpret and make your decision about the numbers and the chart behavior that you can see. There are so many of them. Many of them need some statistical background, many of them don't. We don't go into how to calculate these. We learn how to add them, how to use them.

Okay, the other day in the previous lesson, we learned about the Relative Volatility Index. I will repeat that again, but before that, I'm going to talk about another important trend or common trend indicator that the chart gives us, and it is going to be the Relative Strength Index. So, you just type "relative" and this pops up in the list. You click on that, and you can see this is added to the chart. I'm gonna close this, and this is based on the price behavior and how to interpret this.

So, this RSI or Relative Strength Index, this is a number from 0 to 100. What does it tell us? And again, as you can see, you can play around with it, and you can see this kind of area that is selected between 70 and 30. So, it is very important the time that this RSI goes beyond this pink area. If this number being calculated is below this pink area, which is between 30 and 70, if this line goes below this 30, it gives us the signal that the situation is the commodity is oversold in the market. If this line goes above 70, if this line goes above this pink area, it tells us that the market is overbought.

So, let's look at the chart here. As we can see, when the price dropped, the market was very, very significantly bearish. So, everybody was selling, right? Because everyone was selling, we can see this sharp drop to below 30, and this is a signal that the market situation is oversold. And if it goes above 70, which there were some days here where we can see maybe in some very small incident here as overbought.

Index. How do I do that? I go to the indicator and I just write "Relative Volatility Index," click it, and it is added to the chart, or RVI. This is a number calculated from 0 to 100. We learned that if RVI is higher than 50, it is an indicator of volatility in the market. So, if this number is higher than 50, it gives us an indicator for a bullish market. So, the market is bullish, we buy. If this number is lower than 50, it is an indicator for a bearish market. If this number is higher than 70, it's a strong indicator of a bullish market, and if it's below 30, it's an indicator of a strong bearish market.

We can see it here when the price dropped in early March, this significant sharp drop. You can see this number is showing us that this number dropped below 30, and it is a signal that the market is bearish.

In this lesson, we're going to talk about some of the more advanced financial derivatives. Now, you'll find some pretty extensive notes in the actual lesson content page, so I'm going to do a summary here with these slides. And the first financial derivative that we're going to talk about is a swap.

Now, a swap is an exchange of payments between two parties. It can be a form of hedging, it can also be used for outright trading, so speculative traders can use swaps to try and make some revenue. These are generally known as over-the-counter. That is, they're not traded on an official exchange, such as NYMEX, but you do find them on electronic platforms, such as NYMEX's clear port or the Intercontinental Exchange. And then, also, swaps can be had by dealing with the so-called Voice Brokers-- literally a broker that you call up and arrange for a swap transaction. Now, these are strictly financial. In most cases, there is no physical commodity involved. You're strictly swapping out price.

Now, there are two pieces in a swap agreement. One is a fixed price and the other is a floating price. So, we refer to swaps as fixed for floating. One party will pay a fixed price at the time that the swap is actually entered into. And the other pays the floating price, and that's the price that is not known at the time. You have to wait till settlement of the respective underlying contract.

Now, we talk about the NYMEX look-alike because it's the most commonly used swap. It's a Henry Hub financial swap, and one party buys or sells at the current market, which would be the fixed or known price, in other words, whatever the NYMEX is currently trading at. And then the counterparty buys or sells, so the opposite party is going to take the opposite position. They'll buy or sell based on the NYMEX settlement. Now, this is your floating price, and it's unknown at the time of the swap transaction. So, in other words, the price floats as we know every day as NYMEX changes.

So, you set a price on the day that you enter into the swap for the specific month and the commodity that you are interested in. And then, in essence, the two counterparties, you and your counterparty, are going to wait until the NYMEX contract settles. And then, you're going to go ahead and true up, see who owes who money. And again, it's financially settled every month.

And then, we've also addressed the basis swaps. Again, there's more detail and specific examples in the lesson content. But really, in the case of a basis swap, we're looking at the current market value.

Now, the current market value you can find on NYMEX's clear port system. Or, if you have access to the Intercontinental Exchange, you will see natural gas basis swaps quotes for the various cash locations that we have reviewed in the publications, such as Platt's. And then, we have to come up with the second part of this, in other words, the floating price. We can fix the price based on the values on those electronic platforms I mentioned. But then, to settle with our counterparty, we have to wait until the settlement of the basis. Now, we know when a NYMEX final settlement occurs, and so we'll have that piece of the basis swaps settlement, but then we're waiting for the cash prices to come out. So, in other words, Platt's has their monthly price guide, or as I noted, it's more commonly known as the Inside FERC postings. So, those are the first-of-month cash prices for the respective location. And when you take the NYMEX settlement, and you find that cash location, that difference becomes what we call actual basis. It is the settlement price for the basis swap for that particular location.

Moving on to the next part of our discussion of advanced financial derivatives, we're talking about spreads. Again, I've got some extensive notes and some examples in the lesson content, but we'll review these concepts here in these slides.

OK, Spread trading itself-- here we're talking about trading-- it's a technique that takes advantage of the relative price movement between futures contracts. Arbitrage, that's a simultaneous purchase and sale of similar or identical commodities in two different markets in hopes of gaining a profit from the price differential. Now again, with spread, we're not dealing so much with price as we are dealing with the price differences. Margin requirements are considerably lower than the requirements on single futures contracts, because again, the exposure is the spread difference-- the difference between the price is not one singular price. So that also makes them less risky than outright futures positions. You're exposed to this movement in the spread, either the spread widens or the spread gets tighter, as opposed to the price of the futures contracts themselves.

Here are some simple rules. This is for trading spreads for speculative purposes. Rule 1 is, if you think spreads are going to narrow, you buy low, and you sell high currently. So, you buy the lower price, and you sell the higher price to set a spread. And then, when the prices do, in fact, narrow based on your expectations, you'll be able to go ahead and liquidate that spread at some profit. Otherwise, if the spreads are expected to widen, you expect the price difference to get greater, you will buy the high contract now and sell the lower of the two.

Different types of spreads-- one is the Inter-market. Now, this is the simultaneous purchase and sale of different, but related, commodities that have a reasonably stable relationship to each other. So, inter-market, keep in mind, inter-market means different commodities, not the same commodity. So, we have some different types of spreads and these are the commonly used terms for these spreads.

We have what's known as a Crack Spread. OK, this would be crude oil versus unleaded or heating oil. Now, if you think back to the lesson on crude refining, you have a process by which you are actually cracking the hydrocarbon molecules and then reforming them into these other products, so that's why you get this name here. Crude being the feedstock, and the refined products being unleaded and heating oil. And all three of these trade on the New York Mercantile Exchange. Therefore, these can be used to hedge the spread that refiners are exposed to.

A Spark Spread, it's natural gas versus electricity. Again, this would pertain strictly to natural gas fired power plants. Heating oil versus gas oil-- again, this one can be broken down into another, so we can use this spread. NYMEX versus ICE. Now, this is on crude oil spreads. Here, we have a situation where we're actually using inter-markets. The markets are the different trading platforms. So, savvy traders can sit there and look at NYMEX prices and Intercontinental Exchange Prices for crude oil, and they can take advantage by buying one and selling another, or selling one and buying another electronically.

And then we have a Frac Spread, and this is not to be confused with fracking, which is a completion method for oil and gas wells. What we're talking about here is, again, if you think back to the lecture on processing, the processing plants take natural gas and convert it to natural gas liquids or the so-called fractions using a fractionation tower. And so, that's where we break down and get the ethane, propane, butane, isobutane, natural gasoline, and condensate. So, since natural gas is the feedstock for a processing plant, and the natural gas liquids are the output from that plant, we can put on a frac spread to hedge those differences.

The other type of spread is Intra-market, and this is also known as an intra-commodity spread. The idea here is we are using the same commodity, but we are trading things like time or location. So, a time spread is the simultaneous purchase and sale of futures contracts on the same commodity for different delivery months. So, for example, we could buy August 2015 natural gas contracts and sell the January 2016 natural gas contracts. This would be a storage spread, because the idea would be we would buy the August contracts, put that gas in the ground in August, and then turn around and sell the January contracts, and take the gas out then. So, that difference in price between August and January represents our storage spread.

Then we also have Locational Spreads. This would be the simultaneous purchase and sale of futures contracts for different locations. So, for instance, in terms of crude, we could use the WTI versus the Brent crude pricing. And for natural gas, we could use Henry Hub versus, say for instance, New York City. And here's an example of an intra-market spread for natural gas. Again, as I've mentioned right here, in this example, we're going to talk about August 2015 versus January 2016 at these respective prices.

So, if you think spread's are going to narrow, in other words, we start up $2.90 versus $3.25, so we have a $0.35 spread, if you think that that spread is going to become less, you're going to buy the low, which is the $2.90 and sell the $3.25, which is the high. And then, if you think spread's is going to widen, that is that the price difference between these two months is going to end up being greater than for $0.35, you're going to sell the lower priced, $2.90, and you'll buy back the $3.25. Now, again, keep in mind this is for speculative trading, trading for pure profit. This is not a hedging type of plan or scenario.

The last advanced financial derivative we're going to talk about are options. And again, I've given you pretty extensive notes and some good examples of what options are and how they're utilized and how they're valued. So, these slides just represent pretty much an overview of the notes from the lesson content. Well actually, we'll talk about the definition, the types of options, some of the terminology, the benefits and risks of using options, what happens when options expire, how options are valued, and then we'll just have a summary of the key learning points.

Options are another type of financial instrument used to manage risk and/or to speculate. An option contract gives the holder the right but not the obligation to buy or sell futures contracts at a specified price at any time in the future prior to the expiration of the option contract. Now keep this in mind, this is an important point. If you're buying an option-- in other words, you're the holder of the option-- you have the right but not the obligation to either buy the underlying contracts or sell them. You do not have to.

Types of options contracts-- there are two types, the Call, and the Put. A Call is an option to buy. In other words within the option, you have a designated commodity and the number of contracts and a specified price. Your option position is long. So, once you buy a call option, since you have the right to buy the contracts, your option position is considered long.

So, many times the holder is short the underlying commodity. In other words, let's say a crude-oil refiner would want to buy a call option for crude-oil contracts, thus having the right to buy the crude-oil contracts at a certain price-- again, not the obligation. So. while their physical position is short, their options position is long.

On the flip side, we have the Put option. This is an option to sell the underlying contracts. Again, the option position here is short. Why? Because they have the right to sell. Many times the holder is long the underlying commodity.

So, for example, a crude-oil producer may want the right to sell their crude or to sell contracts in the financial marketplace at a predetermined price which is stated in their option. So, again, to the extent that they exercise, they have the right to sell. We consider their option position to be short because their physical commodity position is, in fact, long.

The most popular type of option is the Futures option or the Commodity option. It is an exchange-traded option calling for the delivery of futures contracts. However, options can be traded in the over-the-counter market and, at times, can call for physical delivery.

And then note my footnote. Having the options contract means you have the right-- you have contracts or can sell contracts. The Premium, this is the price of the option. The premium value reflects the risk of the underlying commodity, and its value is made up of two components. In other words, this is the price you'll have to pay. Just as in the lesson notes, I talked about car insurance and you have a premium. The premium is what it will cost you to have this type of risk insurance.

And there are two pieces, the Intrinsic and the Extrinsic. When you think of the intrinsic, think of the embedded value. As soon as you execute the option, you're going to have a strike price, and there's going to be a market price or what we call the asset price. So, it's the positive difference between the strike price and the price of the underlying commodity.

So, for example, if you, in your contract, you set a strike price of $52 and the current market is $50, the intrinsic value of that is $2.00. So, we know that the premium would be at least $2.00. At $2.00, the writer or seller of the option you're dealing with isn't going to make any money.

Part two of the premium then is what we call extrinsic, which is the time value of money. So, think about it this way. You enter into an options contract on a particular day, but that particular underlying contract won't expire until some point in time in the future. Well, every single day with market changes in price, volatility, and those types of things as well as the time that gets closer and closer to expiration, the value of that option changes. So, in other words, the premium that the writer of that option would then charge you is going to change every day, and this is reflected in what we know as the Greeks, the theoretical models that calculate the various differences in the extrinsic value.

So, when you have the premium and you know what the intrinsic is, all remaining value other than the intrinsic is the extrinsic, and it consists of the components that we talk about as the Greek values. So, for the example above, if the premium for this particular option of $52 was $2.50, we know, based on the fact that the intrinsic is $2.00, that the extrinsic part of the premium or the time value of that premium is $0.50.

The Strike Price, that's the buy or sell price as detailed in the options contract, also known as the exercise price. Expiration, which again, it's the date by which the outcome of the options contract, whether it's sold, exercised, or just abandoned, has to be determined. Now, the options expire typically one to three days prior to the expiration of the underlying futures contract. So, for natural-gas options, as an example, it's one day prior to the expiration of the underlying contract. And we know that the underlying contract for natural gas on NYMEX expires three working days prior to the first of the month. Therefore natural-gas options expire four working days prior. So, they have to be executed or they just go ahead and settle.

And the Greeks, these are the theoretical values projected from mathematical models that are used to measure the sensitivity of an options price to quantifiable factors. When we refer to the Greeks, we're talking about delta, gamma, theta, vega, and rho. And again, I'm not going to hold you responsible for these, but these are the definitions of the Greeks themselves.

Benefits of an option-- the option premium is a fraction of the cost of the underlying commodity. So, think about the fact that, say again, you're a crude refiner and you want to go out and you need to secure some crude supplies in the future. You could buy the contracts outright or you could buy a call option where you have the right to purchase those at a certain price level if, in fact, you need to exercise it, but it's only costing you the premium upfront. You're not buying the contracts unless the price exceeds your option price and then you want to enter into those contracts.

And because of that, you can potentially control a large number of futures contracts for a relatively small cost. So, you could hold several contracts of crude oil, and rather than buy them outright, you're paying the premium on a call option. This gives you a considerable amount of leverage in the marketplace. Now the option buyer's risk is known and limited to the amount paid for the option premium. So, again, your exposure as someone who buys the option is strictly what you paid. You can't lose any more than the premium.

Now the Risk-- the risk is that these are time-sensitive investments. Basically, the value of the options can tend to deteriorate from the time at which they're exercised until the actual expiration date. Now the Option Seller is the writer of the option. That's the other term we use for them, and they are at risk to unlimited potential losses. If you're buying a call option, you're buying a ceiling price. You will never pay more than the strike price in your agreement. Well, the seller of that option or the writer of that option has that exposure if the price runs right through that.

When options expire, they can expire worthless. In other words, you never executed the option. They can be sold for the intrinsic value if one is in an option-buyer position where the option is purchased for its intrinsic value if one is in an option-seller position. So, in other words, as we talked about the intrinsic value, as the options come up anytime between the time they're executed and the time that it expires, if there's value in that, someone trading options could, in fact, cash that in or settle it and make some money on it, or the option gets exercised sometime before expiration, or it automatically is exercised on expiration.

How do they come up with premiums? Well, options are generally valued using pricing theory and/or pricing models.

One of the more popular models used for option evaluation is the Black Scholes model. Now, some of the large firms that actually buy and sell options or they'll write options, they may have some proprietary models that were developed by some quantitative analysts.

Here is what the inputs look like on a Black Scholes model. 

As an example, one can evaluate an option's value at contract expiration. As previously stated, at expiration, the contract has no time value and one would expect the options value to be solely intrinsic.

So, if you have a model-- and I've put a spreadsheet, Excel spreadsheet, out in Canvas under the lesson resources. It's an example of the Black Scholes model. And these will be the inputs.

The asset price-- that's the current market price. In this scenario, the current market price for crude oil was $50, the desired strike price for the option was $55. So, in this particular case, this would be a call option. The time to expiration-- in the spreadsheet, you enter in the number of days to expiration in the one cell, and it automatically calculates this fraction.

The risk-free rate-- you have to put in an interest rate because the idea is, you are paying the premium at the time that you execute the options contract. So, there's cash sitting out there, which could be drawing interest as an alternative. So, this is your so-called opportunity cost. And then, the volatility-- you're going to get that from the marketplace-- the daily implied volatility.

D1 and D2-- those are deltas. Do not worry about those.

But you can see what it spits out are call values and put values. So, a call value-- it's going to cost you $0.72 to get a $55 call in a $50 market with those other parameters that you've entered into it.

From the put side-- and again, remember, the put allows you to sell at a certain price level. Well, if we look at this, if you want to sell at $55 and the market is $50, well, obviously the intrinsic value is $5. So, at a minimum, it's going to cost you $5. And in this scenario, though, the extrinsic value of it is $0.72 as well.

One could also anticipate the value utilizing basic understandings. The purchaser of a call option is anticipating the price of the underlying security to increase. So, one would expect the call option's value to increase with an increase in commodity prices. If the strike price were higher than the actual commodity price, the option should have little to no value.

So, some of the learning points of these things-- the purchaser of a call option expects the price of the future contract to increase. OK. So, their sentiment or their outlook is that they're bullish on the underlying commodity. If they think prices are going to go up, they would enter into a call option.

The purchaser of a put option expects the price of the future contract to decrease. So, their sentiment is bearish on the underlying commodity. They expect prices to fall. And as a result, they want to establish a floor price. OK.

Options are referred to as being asymmetrical. It's a right, but not an obligation for the buyer of the option.

Options are financial in nature. Delivery of the physicals is relatively rare. And options premium typically moves in concert with an option's valuation. That only makes sense because you're going to put a value on the option and the premium should be the result of those calculations.

At expiration, the time value portion of the premium is equal to zero. So, in other words, on the day of expiration, all you've got left is intrinsic value. What's the strike price in the options contract versus the asset or market value at that time?

And then, options trading is a zero-sum game. We talked about this with the underlying futures and forwards contracts. For every buyer, there's a seller and vise versa. Same thing here-- if you want to buy an option, there has to be a seller in the marketplace.

Options rights and obligations-- so, let's break this down a little bit. In terms of call options, the actual buyer has the right to buy a futures contract at a predetermined price on or before a defined date. They expect prices to rise. They want to establish a ceiling price, a price at which they're guaranteed to purchase the underlying contracts.

The seller, on the other side, they're granting that right to the buyer. So, they have the obligation to sell futures at the predetermined price at the buyer's sole option. In other words, the seller of the option can't call up the buyer and say, hey, I would really like you to go ahead and exercise these. It is up to the buyer.

In terms of a put option, this gives the buyer the right to sell futures contracts at a predetermined price on or before a defined date. Why? Because their expectation is that prices will fall and they want to establish a floor price, a guaranteed minimum price.

The seller then grants the right to the buyer. So, they've got the obligation to potentially have to buy futures at a predetermined price, which is the price stated in the contract, the strike price, at the buyer's sole expectation.

The seller, in this case, they're expecting neutral or rising prices. So, in other words, if they sell a put option, their hope is that the prices don't ever fall. If they stay the same, they're going to collect the premium and they won't have to pay anything out. But if prices rise, the same thing happens as well. They're not going to have to purchase contracts in a falling marketplace.

OK. Again, here is just the determinant of options prices themselves.

If there's an increase in the underlying price, that's going to increase the value of the call and it'll decrease the value of the put. OK. If there's an increase in the strike price, that's going to lower the call value and increase the put value.

If volatility increases, both the value of the call and the put are going to increase. I mean, as you can imagine, if there's volatility in the marketplace, then those models, like the Black Scholes and others, are going to reflect that added volatility. So, the risk or the exposure by the writers of the options is going to increase.

Time to expiration-- the further the time out from the time you enter into the options contract until expiration, both the put value and the call value could also increase. And then, interest rates-- if there's an increase in the interest rate, both the call value and the put value are going to decline.

DAVID HARPER: Hi. This David Harper at Bionic Turtle with a very brief overview, just selected highlights for one of the key case studies for the FRM candidate. This concerns the German company that goes by this name (Metallgesellschaft) that I will abbreviate to MG so as to not mispronounce the proper German name for the company.

And the case is about the very public disaster experienced by the company in the early 1990s. It starts with the initial positions in which MG offered fixed-price, long-term contracts to deliver or supply heating oil and gasoline to its customers, independent wholesalers, and retailers. So, these initial positions were short positions in long-term forward contracts with maturities of 5 to 10 years.

How did the company hedge its exposure? It did this with what is called or by employing a stack and roll strategy, or a stack and roll hedge. And so, in this hypothetical example, each barrel might represent 10,000 barrels of oil.

Let's say at the beginning of the year in January, the company enters into short-term futures contracts-- long positions. So, that is to purchase 120,000 barrels of oil.

And then, we go forward only a single month-- let's just say, from January to February. And right before expiration on those long positions in futures contracts, MG, the company, closes those out and enters into a new stack, a new set of short-term futures contracts where it takes a long position.

And so, in this way, the company could go, say, month-to-month with this stack and roll. That is to say, buy it, go long a short-term stack, close that out, enter into another short-term stack, and keep doing that month-to-month. And so, you can see the short position in these long-term forwards is hedged to a degree but not perfectly by these long positions in short-term futures.

So, notice that if oil prices or oil spot prices are increasing gently, then these short positions are losing money on the forwards. However, they are hedged by the profits that are made on the long positions in these futures contracts.

And so, generally, the strategy had relied on the continuation of backwardation in the marketplace-- that is to say, where the forward price is lower than the spot price or where long-term forward prices are less than near-term forward prices. As long as backwardation persisted, this hedge is generally effective.

However, the market shifted to contango. Contango is when the forward price is greater than the spot price or the long-term forward is greater than the near-term forward. And now this was the company's undoing.

Because what happens if we focus here at the start of the curve-- this is the spot price. The spot price here is dropping rapidly relative to the forward price. And these long positions in short-term futures contract are being rolled over with losses.

And in this case, the long-term forwards are hedged by short-term futures. So, there is a timing and maturity mismatch, which exposes the very significant basis risk at play.

But also, just as significantly, notice the short positions in long-term are forwards. But the hedges are with futures. And under the German accounting rules that existed, at least at the time, these futures were being marked to market on a daily basis.

So, these hedge instruments were losing as they were rolling over into the lower spot prices. The losses, owing to the fact they are futures, were being marked to market and recorded as losses immediately.

However, the forward contracts, owing to the fact they are forwards are not futures, had to await settlement for their gains to be realized. So, their losses here, in theory were, to some extent, being offset by the forward contracts. After all, there was something of a hedge in either direction.

However, only the futures were marked to market. And so, only the losses were realized. So, this triggered reported losses and margin calls and a loss in faith by the counter-parties. So, even accounting here exacerbated the basis risk in the first place.

And so, we have a number of minor risks here. But my vote for the big three would be, first of all, basis risk. As I've said before, basis risk always attaches to a hedge instrument on another underlying, simply because they aren't the same asset. And in this case, they're clearly different, given the fact we had long-term forwards and short-term futures. So, there was significant basis risk to the strategy.

Second, liquidity risk was obviously very significant given the fact that losses would be realized on the futures contract immediately. But the offsetting gains would have to await long-term settlement. And finally, operational risk refers to the fact that the accounting standards themselves played a role in the problem.

This is David Harper of the Bionic Turtle. Thanks for your time.

In this lesson, we're going to talk about risk controls in energy commodity trading. Now you've seen my notes out there on the lesson content page, as well as the-- hopefully, by now, have read the case studies. But I'm going to walk you through the origins of risk control within the energy commodity business and then some of the recommendations and risk measures themselves.

In today's market environment, controls for financial trading have probably never been as important as they are today. The case studies illustrate the history of very huge losses by traders who really didn't know what they were doing, and there were no controls in place. And then, Enron, when they collapsed back in 2001, it was the largest bankruptcy of its time.

And of course, it resulted from their financial trading group and some false trades that basically were going on behind the scenes. But it's still occurring today, unfortunately. There are still people out there making huge mistakes by making decisions and taking speculative positions. And there's no real oversight over these people to, basically, realize what's going on and try to stem those losses.

As we've seen throughout the semester, and especially in terms of your own little speculative trading in the simulator, there is extreme volatility these days in energy commodity prices. We've talked about the fact that we are in a global commodity. Crude trades definitely is a global commodity.

And pretty soon, we will be trading natural gas as a global commodity as well. And we know that the geopolitical climate is sort of an ever-changing landscape, and it has a direct impact on the perception of future energy prices. So this volatility, this constant rapid movement up and down makes the oversight of financial derivatives and energy commodities even that much more important.

We've also seen a situation with the credit crunch, as the banks fell into the problems back in 2008. Not as many banks are involved in supporting the financial derivative markets as they used to be. And then, of course, from the standpoint of margin requirements, if you don't have sufficient credit, you're not going to be able to meet your margin requirements. And this will impact the cash flow of companies. Some companies either don't have or don't wish to put the cash out to cover a margin. That's going to limit the number of positions that can be taken, as we all know, in financial derivatives.

And then of course, weather. Weather can be extremely volatile, as we know. And weather is a key driving factor in terms of supply and demand for natural gas and for crude oil. And so we have events such as La Niña, El Niño, there are issues of global warming, and then we have unpredictable hurricane seasons. As we know, that can be a huge factor in terms of the interruption of supply for both natural gas and crude oil in the Gulf of Mexico and the United States.

Financial risk types-- these types, actually, several of them are what any particular company may face at any given point in time. Of course, the market risk-- what is going on in the market? Do you have a need for the commodity and you're exposed to higher prices? Are you a seller of the commodity, and therefore exposed to lower prices?

Operational risk-- if there's an interruption in operations, you may not be able to perform under the financial derivative obligations that you've entered into. Liquidity-- a lack of counterparties. In other words, if you wish to go out and hedge a commodity for a certain period of time at a certain volume, are there enough counterparties out there these days to get that particular transaction done?

Exchange interruptions-- although rare, exchange interruptions can occur. We've seen power outages. We have seen hacking. Back on 9/11, the New York Mercantile Exchange itself was shut down for several days. So it is a possible liquidity risk that's out there.

And then of course, the speed of the transactions-- we've addressed electronic trading. There is trading going on 24 hours a day, in essence. And you've got platforms like the Intercontinental Exchange, ICE Future Europe, NYMEX, GLOBEX, NYMEX's Clearport, and other international ones. So the fact that you can trade almost 24 hours a day but that you're trading electronically means that you can potentially lose more money faster than you could in the past.

Other types of risks-- legal, enters into this because you're going to enter into contracts, OK? The ISDA is the contract for financial derivative transactions. And that's the predominant contract there. It's a base contract. The NAESB is the North American Energy Standards Board. That's a bilateral or buy-sell agreement for the natural gas business.

And then, of course, within contracts, we have force majeure language. Again, force majeures is sort of an out. If any of a very long list of events occurs, then one of the parties may not have to perform under the contract. These can be things that are weather-related, acts of God, interruption of, let's say, the pipeline movements, freezing of gas or gas lines, et cetera. There's just a host of them. And of course, any one of those, if it excuses the counterparty, that represents a risk for the other counterparty to that transaction.

Credit-- I mentioned, this goes along with the counterparty liquidity issue. In the post-2008 economic collapse, where the banks found themselves in trouble-- and the banks then entered the marketplace after Enron and others had exited. And they were providing the financial liquidity that was otherwise going to be lacking. Well, as the banks exited the business over the last several years, that does, in fact, influence and impact counterparty liquidity. There are a few partners out there with which you can get financial derivatives executed, which is going to impact hedging.

And then counterparty solvency-- you have companies that you may be trading with or companies that you may be going through to execute hedge positions, and you may find out that, all of a sudden, that company becomes insolvent. The question then becomes, what happens to your positions?

Why risk controls? As I mentioned you guys already hopefully read the case studies. And then you've got an activity on those. Because of that, we have to put risk measures in place. Energy commodity trading in all its forms.

Basically the SEC and the CFTC came in at one point, and said that publicly traded energy companies will in fact have to institute some type of a risk control program. We'll talk about the types of controls. And then last, we're going to talk about some recommendations. If you were to sit down with the company, and make some recommendations for a risk program for them, I've got a list of things that you might want to be able to say to them or recommend to them.

And we talked about these case studies already. I added a fourth one down there. You can see as late as 2006, there was another trading company-- Amaranth-- and they lost $6 billion trading NYMEX futures. Again, not enough oversight.

Common issues throughout all of these, I think hopefully you have picked up on these in the case studies. They're really the single or multiple rogue traders. When we say rogue traders, we're talking about people who did things on their own. They made decisions on their own.

They were dealing in risky derivatives. These were not people dealing simply in the underlying derivatives. In some case, we know that we're doing option swaps, exotic options, and some other things.

Little or no accountability, this is the big one. OK, there's really no line of accountability where there's oversight. In several of these cases, in fact in the three case studies that you had, there was a total control over the paper trail. As we saw in the case study with the Nick Leeson, he actually controlled all of the accounting. So he controlled the executions through settlement, and then had his phony account set up.

And this is one of the issues-- this next point-- the lack of understanding and recognition by the executives of financial derivative trading and the risks involved. To this day, I still believe there are executives over companies where energy commodity trading exists-- financial derivatives are used-- where the executives truly don't understand the risks that the company is taking on with the various forms of transactions. Even if they're presented with a daily report from a risk control group, I don't know that they fully understand and can interpret those reports properly.

So some risk measures. These are standard risk measures. One of the most common ones, and one that hopefully is most well known is mark to market. Now that's the value of the portfolio at the close of the day based on the settlement crisis.

Now in FACTSim, the simulator, if you watched your position every day, if you had open positions, the simulator valued those based on the prices at the end of the day. So that is the mark to market. You are taking all of your open positions, because you have not yet closed them. And it's marking them against the settlement prices for the markets closing that day and putting a value on it.

Then we evaluate risk. This is a much more complicated risk measure. I don't expect you to understand it in its entirety. But it's what's known as the theoretical maximum loss on a total book for a given period of time, at a given confidence level, a defined holding period, at expected market conditions. Now I realize that's quite a mouthful.

There's a single number that comes out. What happens is, there is a first step in calculating value at risk. The mark to market calculations run on the entire book.

So you'll have a mark to market number. And then what'll happen is, that will be compared to historical prices. Then also within the value at risk system-- and again, this is a calculation that's done by software. It's not a hand calculation. There will be a Monte Carlo simulator.

And a Monte Carlo simulator is really a random number generator. So in essence the Monte Carlo simulator will come up with literally thousands of potential price scenarios, and those will get compared against the actual mark to market values for that particular day that the value at risk is run. And so this comparative analysis comes up with a single number, and that single number represents, again a theoretical maximum one day loss on the book as it exists.

Now the parameters-- because this is a form of statistics. It's a statistical analysis. The parameters are that basically the result is saying, OK, the maximum loss on the book as it exists today, comparing mark to market to these prices that have been generated by Monte Carlo simulator, the company could lose as much as $10 million. The confidence, the statistical confidence, in this case, on this VaR calculation is 98%. And then there also has to be what's known as the holding period. In other words, the VaR calculation is done at the end of the day on the book as it currently exists, with the mark to market as it was calculated for that day.

However, in the VaR calculation, there has to be an assumption of how many days you could hold those positions open. So you'll have the single dollar value, which represents the maximum loss, a level of confidence. And 98% usually would be the one to use because then you've only got 2% outliers on the other end. But you might have one-day, two-day, three-day, four-day, five-day holding period. That's up to the company to determine.

But the holding period that's chosen also represents, or should represent, the reality when it would come to liquidating the position. So in other words, it would be unrealistic to have a single holding day period because you can't liquidate your entire book within one day. To do that would then adversely impact the prices in the marketplace on that day, which in turn would adversely impact the mark to market at the end of that day.

Other risk measures, profit and loss. Now once you've calculated the mark to market, you're going to have unrealized gains or losses. And so at the end of that day, the profit or loss total is going to be the mark to market value. And what you normally do is it becomes a cumulative number each day as you go through the month. So the mark to market gain or loss on day one is added to the mark to market daily loss on day two, and so on. So you have this running total.

And then you also need to figure out the volumetric position. You want to know, from a contractual standpoint, what is your exposure. So this is the total of all the derivative contracts that you have out there that are straight up contracts. Maybe they're futures, maybe they're swaps. But then also, we touch briefly on the options delta effect. In other words, getting back to the options, if an option writer, let's say, writes a put or writes a call, they immediately have some exposure, which is quantified in the number of contracts that they might have to buy themselves or sell in order to fulfill the obligations under the options contracts if executed.

So this has to be quantified. There's a certain number of contracts that are represented when the delta calculation on the options is run. So for the true volumetric position of a particular book, it's all the open derivative contract volumes, in other words, again, things like swaps, forwards, futures, and then what the options delta calculation ends up being in terms of contracts. You have to add all of those together. Now you know the volumetric position for the book itself.

In terms of energy commodity trading, obviously, we know in April 1990 a natural gas contract was launched. In 1983 the Crude Oil Contract was launched. We know, too, that provider price transparency and market liquidity, you were now able to hedge your price risk. But it also added some more instruments for speculative trading. It led to the proliferation of various financial derivatives, as we know, options such as puts and calls, more exotic options, and then swaps, both Henry lookalike swing swaps and basis swaps

Now the Securities Exchange Commission and the Commodities Futures Trading Commission had mandated that publicly traded energy companies have to implement a risk control program effective with their fiscal year for 2001. So what happened here is they had to report their mark to market value under their earnings. So in essence, at the end of every day, they had to go in and calculate to the mark to market value of their open positions.

Well, the federal government then said that represents revenue. You've either got unrealized gains or unrealized losses, and you have to report those in earnings. Well, for Enron, that basically gave them the license to steal. Why? Because what Enron did was set up various shell companies, paper companies, and then they would calculate the mark to market earnings every day on these little companies. And basically those would show gains, and the more earnings that all of these companies were making in terms of in total showed up on Enron's books. And so this was leading to a higher share price.

So the state-- now also, the other problem that happened was the traders now have a large stake in mark to market. They want to manipulate the prices, set these forward curves, forward prices that we know are in the marketplace. Well, they were setting them for certain price categories for which they were reporting to the publications and others. So you can see they were starting to try to influence the cash marketplace, the cash publications, which was direct market manipulations.

Then another thing they would do is roll positions forward and backwards to gain mark to market value. So they had positions that could be liquidated and they could draw cash in, and then turn around and put those same positions back on. They would do this. Again, we're talking about fluffing books up so that the books really were not a true reflection of actual earnings or cash positions of the companies.

In the post-Enron world-- in essence, a little more than a year after Enron collapsed-- what had been the top five energy trading companies in the United States were gone. Wall Street became very leery of energy trading companies. You'll find more companies today that are named energy service companies. And Wall Street analysts, when they want to look at a company now, they're going look at the book size, in other words, total volumetric open positions, and then the mark to market related to that.

They don't really put much confidence in value at risk. They're not as interested in that because again, as I mentioned earlier, it's sort of theoretical. Also more and more companies adopted FAS133 hedge accounting, and what this did was allow them to shrink their speculative book. In other words, positions are not open if you can tie them to a physical transaction. And then, of course, there was the adoption of Sarbanes-Oxley. Sarbanes-Oxley is an extremely invasive and intensive procedures and recording of pretty much every single transaction, even down to the keystrokes in some cases.

And here's where I mentioned recommendations. If a company doesn't have a risk policy in place and they have to implement one, to me, first and foremost, executive training. They need to understand what energy commodity derivatives are and the various types and the types of risk exposures that are out there trading them. They have to establish risk policies and procedures. And within the policies and procedures, there has to be, number one, a statement of the purpose of hedging activity. What is it that you have that exposes you to price and market risk? Therefore you state why are you going to hedge.

Also, then, you start to establish risk measures and limits. What's the daily maximum mark to market loss that you're going to allow the trading company to have? What's the maximum VaR? You need oversight. There needs to be a risk control desk, and you need to have set positions within that desk and responsibilities for each one of them. There needs to be a risk oversight committee. This is usually comprised of an executive panel.

Trading policies have to have violation penalties in them. In other words, there has to be a situation where if a trader violates it, there is a penalty that they're very much aware of that's going to happen, which can include termination. Specific procedures, things like deal sheets, daily check outs, and those types of things.

And as I mentioned, adopt FAS133 hedge accounting. Educate both internal and external auditors. It's kind of an odd thing, but from time to time, you find auditors who don't really understand financial derivatives either, and yet they come into audit the books of companies that have financial derivatives on their books.

And then, of course, Sarbanes-Oxley. You have no choice but to implement Sarbanes-Oxley, even, as I mentioned, as complicated procedurally as it is.

This is a flowchart. Power plant generation > transformer which steps up voltage for transmission > transmission lines carry electricity long distances > neighborhood transformer steps down voltage > distribution lines carry electricity to houses > transformers on poles step down electricity before it enters houses.