Posted on 01/08/2013 7:23:43 AM PST by thackney
Ethane in Mont Belvieu posted at 22.5 cnts/gal on Friday, continuing the NGL’s descent into the abyss that started mid-2012. The last time we saw ethane at this level was back in 2002. With natural gas prices hanging in there above $3.00/MMbtu, there is no doubt about it. We are deep into ethane rejection economics. Not just for the Conway market like we had last summer. But wide spread, across the board, knock-out-the-ethane style rejection, unlike anything we’ve seen in the last five years. In fact, this is something new. Impending widespread rejection in the world of shale…a world of ultra-rich gas, deep ethane cuts, and constrained infrastructure. Today we’ll drill down deep into the numbers. It’s enough to make you crazy.
First let’s put where we are in perspective. As we show in today’s Spotcheck “Ethane to Henry Hub Gas Ratio” graph, the price of ethane on Friday was only slightly above the price of natural gas on a BTU basis – a ratio of 1.03. But if you adjust the ethane price for the cost of transportation and fractionation (T&F) to get the value back to the plant level it gets a lot worse. Assume 10 cnts/gal for T&F and the ethane price is more like 60% of the BTU equivalent price of natural gas at the plant tailgate. These are serious ethane rejection economics for plants feeding Mont Belvieu. And of course, Conway is worse with pricing at 19.9 cnts/gal. Way above the prices this summer, but still in ethane rejection territory.
Processing economics – Eagle Ford plant example: Base case
We’ve talked about ethane rejection many times before, both from the perspective of the math involved (Computing NGL Quantities, BTU Content and GPM) and the market impact of rejection (It Don’t Matter to Me, Nowhere to Run, Frac Spread Cliff). Today we’ll pick up an example of an Eagle Ford plant that we examined back in How Rich is Rich? – Gas Processing Economics Part 3: Computing NGL Quantities, and analyze the consequences of ethane rejection at this plant.
Table #1 lays out the basic data for our representative plant. It is a fully loaded 200,000 Mcf/d plant (Blue, Cell B9) running 5.65 GPM gas (Green, Cell C9), which is fairly typical for Eagle Ford. The Mole percentages of each component of the feed gas are shown in Column A, which yields a 1,258 BTU content of the feed gas stream (pink, Cell F7). This is a relatively new plant, so the recovery percentages are good - 99% for all liquids except ethane, which is 90%. This means that the extraction process leaves 10% of the ethane and 1% of the other NGL products in the residue gas stream. Crunch all those parameters through the RBN Processing Plant Model and we see that total liquids production is 26,893 barrels per day (Cell D7), with ethane making up 56% of the barrel (Column E). Again, if you really want to know more details, all of these calculations are described in mind numbing detail in How Rich is Rich.
The RBN Processing Model also tells us a few other important numbers about this plant not shown in this part of the spreadsheet. Shrinkage is 42 MMcf/d. We know that the plant receives 200 MMcf/d. After extracting 26.9 Mb/d the residue (output) gas stream is thus reduced to 158 MMcf/d. Not only has the volume been reduced, the BTU content of the gas has also been reduced significantly, from 1,258 Btu/cf down to 1,024 Btu/Mcf, lower by 234 Btu/cf or about 19%.
Table #2 below shows the economics of the numbers described above, valued using OPIS Mont Belvieu non-TET NGL prices from Friday (Column B), and for natural gas using the closing CME/NYMEX prompt month natural gas price (Cell A1). In Column C we deduct 10 cnts/gal for an estimated price after T&F - so ethane for example has a 12.5 cnts/gal value at the plant tailgate (Column C). Using these prices and the NGL volumes in Table #1, the model yields daily product revenues of $688,158 (Cell E7).
Note that of the $688,158, only $79,227 of that total or 11.5% of the revenue comes from ethane. Although ethane is by far the largest volume produced at this plant, it is a relatively small piece of the revenue pie. The largest part of that pie is propane, at $196,214 or 28.5%. Even with propane prices low, propane revenues are still sizeable.
Column G shows the theoretical value of the plant inlet stream. We say theoretical, because this assumes that our 1,258 Btu/cf stream could be sold at natural gas prices. In reality, this stream is much too rich for sale and would never come close to meeting the quality specifications of natural gas pipelines. Nevertheless we can calculate the theoretical value of the stream by multiplying the inlet volume in MCF times the BTU value per MCF times the price of gas per MMBTU, yielding $827,035.
The outlet (residue) stream is well within pipeline quality specs with a BTU value of 1,024 Btu/cf. Again multiplying the volume times the BTU value times price, the outlet stream is valued at $532,090. Sum the value of the liquids and the outlet stream, then deduct the value of the input stream and the total value per day at our sample plant is $393,231, still a very attractive gross margin for any gas processing plant.
Make the ethane go away: Rejection case
We labored through all of the numbers above for one reason – so we can compare this Base Case with an ethane Rejection Case. Table #3 shows the changes in our key input variable – Cell B2 goes from 90% to 0%. That drops total liquids production to 11,802, a decline of 15,091, the volume of ethane produced in the Base Case.
We don’t show it in this part of the spreadsheet, but shrinkage drops from 42 MMcf/d to 18 MMcf/d since all the ethane stays in the gas. That means that the residue stream increases in volume from 158 MMcf/d to 182 MMcf/d an increase of 15% in the gas coming out of the plant. And not only is there more gas, the gas has a higher BTU content due to the presence of the higher BTU ethane molecules. The residue gas stream BTU content increases from 1,024 Btu/Mcf in the Base Case to 1,120 in the Rejection Case. Put these two factors together and the BTU quantity of the residue stream increases by 42 MMbtu/d, or 26%.
Table #4 below shows the economic impact of ethane rejection using the same OPIS and CME/NYMEX prices used in the Base Case. Obviously there is no revenue from ethane, so the NGL product value per day drops from $688,158 in the Base Case to $608,931 in the Rejection Case, a decline of $79,227. There is no change in the inlet gas stream value. But check out the change in the outlet gas stream. It is UP $137,287 due to the higher volume and higher BTU content of the gas. Thus the net per day for the plant increases by $58,060 in the Rejection Case versus the Base Case. That is what we should expect. The plant goes into rejection because it makes more money rejecting ethane than recovering the ethane. So the plant should make more money in the Rejection Case.
Conclusions
Our representative Eagle Ford plant detailed above is only one possible example of rejection at a modern 200 MMcf/d facility processing rich shale gas. But this example does provide insight into what wide scale rejection will mean in today’s processing market. Gas processing economics remain quite lucrative, regardless of ethane pricing. Propane, butanes and natural gasoline prices remain several multiples of natural gas prices, which means that processing margins continue to be strong even with ethane prices below natural gas on a BTU basis.
Rich gas plants with high ethane percentages will throw significant volumes of natural gas back into the market when ethane rejection kicks in. In our example plant, the residue gas stream volume increased by 15% and the heat content quantity by 26%. That’s a lot of gas volume hitting an already oversupplied market. Of course there are a lot of plants running much leaner gas, so you can’t extrapolate a market-wide impact from our example plant. In a later blog we’ll estimate what the overall increase in supply might be.
Similarly, when one of these big ethane producers goes into rejection, it takes a lot of ethane volume off the market. In our example, 15 MB/d of ethane disappears from the market at this one plant. With numbers this big, it would seem that widespread ethane rejection could rebalance the market in fairly short order. And that behavior will define the ethane market for many years to come, until new petrochemical plants are completed and demand catches up with the capacity of gas processors to produce ethane. It’s going to be a roller coaster. In our example, there was not much of a problem with the residue gas stream BTU content. There has been a lot of concern about potential pipeline gas quality problems coming from massive rejection. But the residue BTU content was only 1,120 in the Rejection Case. While this is above the specs of most gas pipelines, when other factors are taken into consideration (dew point, Wobbe index, etc.) there would probably be no problem with this gas stream into many pipelines. That is not the case for older plants that lose some propane into the gas when they reject ethane. The rejected ethane plus the inadvertently rejected propane can kick the gas well out of spec. But at the new plants with clean-cut ethane rejection this is much less of a problem.
The above point does not imply that the gas pipelines are not going to have quality problems. There will still be a lot of BTUs shifting into the gas stream, which may result in issues for plants downstream of other plants already rejecting significant volumes. That is particularly true for plants way downstream – for example, Marcellus plants without ethane take-away capacity, accustomed to blending their ethane laden residue gas with lean gas from the U.S. Gulf. If that U.S. Gulf gas is not so lean, that will be a problem. Last week a Platts article quoted a recent report from US Capital Advisers, saying that “We see the potential for gas shut-ins in the Northeast as pipelines pull their BTU waivers, and sub-spec gas just doesn't have a home.” We’ve not done the analysis on this at RBN, but it is certainly possible.
Most other downstream plants with ethane take-away capacity will be able to resolve any problem with a high BTU residue gas stream by simply producing ethane at negative margins. It may take a few dollars out of the plant’s processing margin, but with attractive margins on the other NGL products it makes a lot more sense than shutting back the plant, potentially impacting gas flows into the plant.
The model
Usually when we take a deep dive into the numbers like we did today we include the spreadsheet model along with the posting. We are making an exception to that rule today because we have yet to explain the detailed calculations of the model’s residue gas module. It was on our list after How Rich is Rich? and we just never got back to it. Without that explanation, the model would be difficult to follow. And the explanation should be a blog to itself. Given the timeliness of ethane developments we elected to cover market impacts and conclusions today, and get back to the math next week for you die hard processing geeks. And that’s what we’ll do. Promise!
At least we’re not burning it off like we used to.
Alrighty, I admit it...I can’t understand a word of this. I don’t know what NGL is, something about natural gas? Does the article mean we have lots of gas but no one is buying it? Why is someone rejecting shale gas and who are they? Please, just a little help for those of us who are not conversant with terms of the petroleum world.
Extended natural gas flaring is getting quite rare in the US. It still goes on during initial well running before facilities get built out.
But regulations in most locations only allow it for an initial period. And many modern mineral royalties contracts now charge the producer for any gas that is removed from the reservoir. If they flare it or sell it, they still have to pay the royalty.
NGL = Natural Gas Liquids. The upshot of the article is that the cost of fractionation and transportation of ethane pretty much eats up any revenue the midstream operator may derive from it, so they’re saying “No, thanks!” to ethane streams. (Subject to revision and extension by others, of course. ;-) )
NGL is Natural Gas Liquids: Ethane, Propane, Butane, etc. It is not the same as LNG, Liquid Natural Gas which is methane cooled down to -260°F to make it liquid.
Does the article mean we have lots of gas but no one is buying it?
No. We do have a lot of new Natural Gas supplies hitting the market and holding down prices. Additional consumption of Natural Gas like Electric Power Companies have switched more to Nat Gas over coal and raised the consumption.
However, the article is talking about the NGLs, specifically ethane which often goes to the production of plastics. New manufacturing chemical facilities are being built but the supply of ethane from "wet" (with liquids) natural gas wells has risen faster than the plants have been built, driving down the price for ethane.
Why is someone rejecting shale gas and who are they?
It is not that type of rejection and it is not rejecting shale gas. It is talking about the production of liquids in a natural gas processing plant.
Please, just a little help for those of us who are not conversant with terms of the petroleum world.
I will be glad to answer questions as I can. I primarily posted this article in response to another comment talking about how natural gas production was affecting manufacturing in the US. These low prices are driving the building of chemical plants that use NGL's as feedstock to product polymers and the like used to make plastics.
bump
What gasses make up LNG?
What gas or gasses are extracted from shale? ...all that's in your chart?
Our marketing folks are hot on propylene right now; prices are good and the propane fraction in the Eagle-Ford is quite good.
Good thing about NGLs, material focus is highly flexible.
:: These low prices are driving the building of chemical plants that use NGL’s as feedstock to product polymers and the like used to make plastics. ::
Tru dat! We are building another 4 ethane trains in the Mont Belvieu area to add to the 6 we already have operating.
| Typical Composition of Natural Gas | ||
| Methane | CH4 | 70-90% |
| Ethane | C2H6 | 0-20% |
| Propane | C3H8 | |
| Butane | C4H10 | |
| Carbon Dioxide | CO2 | 0-8% |
| Oxygen | O2 | 0-0.2% |
| Nitrogen | N2 | 0-5% |
| Hydrogen sulphide | H2S | 0-5% |
| Rare gases | A, He, Ne, Xe | trace |
In its purest form, such as the natural gas that is delivered to your home, it is almost pure methane.
http://www.naturalgas.org/overview/background.asp
LNG, liquid natural gas is pure methane chilled to -260°F.
Depending on the shale formation we can get everything from crude oil, natural gas liquids to dry methane. Different shales have different mixes just like traditional fields can be nearly all oil, all natural gas or a mix with other liquids often referred to as condensate or NGLs.
So should I take from this that the low cost of raw material is causing a boom in the American plastics industry?
Five years ago while on a mission trip to rural Mississippi south of Memphis, I saw hundreds, if not thousands, of units of idle railroad rolling stock, virtually all of it bulk plastic containers. I assumed it was idle because the plastics industry was going overseas. Does this also mean that a good deal of that rolling stock will be reactivated?
Just what gases make up the gas that is piped into our homes and businesses?
- Mostly methane (96-98%) then ethane, propane and butane.
What gasses make up LNG?
- Ethane (C2) to Hexane (C6+) and “heavies” (>C6)
Rich gasses are extracted from shale Some shales yield richer gasses than others. They are fractioned into their constituent products using temperature and pressure changes (Midstream processing). Methane is sent to NG pipeline companies Like Kinder Morgan and TransCanada or sent to refracting companies like Valero for final “polishing” and delivery to chemical companies like Dow Chemical or BASF.
There is a big growth coming in the production of the feedstocks, making the polymers and plastic pellets that are used to make film/bag as well as harder injection molded plastics. I expect it will lower the price of those items.
Does this also mean that a good deal of that rolling stock will be reactivated?
I don't know the status and demand of the rolling stock.
Sorry, you are describing NGL, not LNG.
Thanks, reading too fast while at work.
I suspect you probably answered the question the poster meant to ask.
Those two are confusing even when spelled out.
Thanks for quick lesson in Natural Gas gentlemen.
Of course, all the polyethylene producers are "loving it" with their feedstock costs dropping like a rock.
Is this a trick question?
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