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.