Natural Gas Regulation & Rates

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.