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!
Big Oil is soooooo much more evil than Big Agriculture. Cow farts are innocuous!
Actually, it can be. Have to convert to ethylene first, of course, then make ethanol from that. I think that route is actually cheaper than the corn derived EtOH one, but the EtOH made by from natural gas is not considered "renewable".
It's been some years since I looked at the economics of the two, and it things have undoubtedly changed, so the NatGas to EtOH may no longer be less expensive today.
Please to explain.
I like that explanation ... Now I can go back and read the original article intelligently (to the extent that I can do anything intelligently).
It may help to read post #24 first to understand how “ethane rejection” is used in this market.
Some other posts in the thread help explain portions. I will try to answer other questions you may have.
Right, thanks.
Here’s an interesting research tidbit concerning natural gas (specifically methane) that was in today’s “R&D Magazine” email daily research review.
will help develop...
if successful could...
Their proposal——won a $4.8 million Advanced Research Projects Agency – Energy (ARPA-E) award from DOE.
Let me know when it is an economic commercial industry rather than a taxpayer funded attempt that claims to reduce global warming.
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