Summer gasoline blends are just around the corner... why does that matter?

I listened yesterday to an analyst who said, "rising ethanol stocks will put a damper on ethanol production profitability and probably lead to reduced runs.."

to wit I wondered why someone would comment on something they do not know about...??  Each winter the EPA relaxes vapor pressure requirements as winter approachs.. hence makers can put more volatile components in gasoline as they are less likely to evaporate in cooler weather.. as such.. gasoline prices seasonally fall.. and every spring these conditions reverse.. and you guessed it.. gasoline prices rise.

Robert Rapier has a good primer on the subject here..  ( http://www.energytrendsinsider.com/2013/10/08/why-gasoline-prices-a... )

Regulating Smog

Everyone knows that gasoline evaporates. What you may not know is that there are numerous recipes for gasoline, and depending on the ingredients, the gasoline can evaporate at very different rates. And because gasoline vapors contribute to smog, the Environmental Protection Agency (EPA) seasonally regulates gasoline blends to minimize emissions of gasoline vapors.

The way the EPA regulates these vapors is by putting seasonal limits on the Reid vapor pressure (RVP). The RVP specification is based on a test that measures vapor pressure of the gasoline blend at 100 degrees F. Vapor pressure is a measure of the tendency to evaporate; the higher the vapor pressure the faster the evaporation rate. Normal atmospheric pressure is around 14.7 lbs per square inch (psi) at sea level. Substances with a vapor pressure higher than normal atmospheric pressure are gases, and those with a vapor pressure lower than normal atmospheric pressure are liquids (assuming they are exposed to normal atmospheric pressure).

But vapor pressure is also a function of temperature. Under normal atmospheric temperatures water is a liquid because its vapor pressure is below 14.7 psi. It still evaporates (i.e. it still has a vapor pressure), but very slowly. As water is heated, its vapor pressure increases, and as the boiling point of water is reached the vapor pressure of water reaches that of atmospheric pressure and the water becomes a gas (steam).

The same phenomenon is true with gasoline. As the temperature increases, the vapor pressure increases. Thus, in summer it is important to keep the RVP of gasoline at a lower level than in winter. The specific limit varies from state to state (and tends to be more restrictive in congested areas and warmer locations), but 7.8 psi is a common RVP limit in much of the US in the summer months. After gasoline has been blended, it must be tested and it must be below the RVP limit for the month in which it will be sold.

Each year in September, the RVP specifications begins to be phased back to cold weather blends. In cold weather, gasoline can have an RVP as high as 15 psi in some locations. This has a big impact on the cost of producing gasoline. The reason for this is butane. How do I know this? Because I spent several years blending gasoline and I dealt with this transition twice a year.

More Butane, Cheaper Gasoline

Butane has an RVP of 52 psi, which means pure butane is a gas at normal pressures and temperatures. But butane can be blended into gasoline, and its fractional contribution to the blend roughly determines its fractional contribution to the overall vapor pressure of the mixture. As long as the vapor pressure of the total blend does not exceed normal atmospheric pressure (again, ~14.7 psi) then butane can exist as a liquid component in a gasoline blend.

But with a vapor pressure as high as 52 psi, butane can’t make a large contribution to summer blends where the vapor pressure limit is 7.8 psi. For example, if a gasoline blend contained 10 percent butane, butane’s contribution to the vapor pressure limit is already 5.2 psi and you would still have 90 percent of the blend to go. It isn’t feasible to blend much butane into gasoline when the vapor pressure requirement is low. But when the limit increases by 5 or 7 psi, it becomes feasible to blend large quantities of butane. 

Butane of course is a competitor to ethanol as an oxygenate as the amount of butane is reduced it can be replaced by ethanol.  True to form RBOB gasoline prices on the Futures are ( http://www.cmegroup.com/trading/energy/refined-products/rbob-gasoline.html )  $1.484 currently for the March contract but $1.7202 for the April which is the first month for the lower pressure limits.. a $.24 premium.

Why does this matter?  It's probably an over simplification to say that it is ALL Epa driven as US consumers utilize more gasoline in the summer months.. hence more demand equals higher prices but the two are somewhat related.. higher prices of a stricter to make product.. so both factors matter.

Anywho it matters as US domestic ethanol demand is also seasonal.. ( http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=w_epo... ) and picks up as EPA standards become more strict.. summer gas.. as well as more gasoline is consumed.. hence more ethanol is needed for blending.

Inversely we generally get a build in ethanol stocks over the winter.. due to GOOD ethanol exports it was a little bit later this year.. but we are FINALLY above year ago levels..( http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=W_EPO... ) The ethanol market is still a little squirrely and does not show this price bump but it normally occurs as users stock pile stocks in anticipation of demand..  ( http://www.cmegroup.com/trading/energy/ethanol/cbot-ethanol.html )  The ethanol market is
still a funny duck.. as it almost always seems to be inverted vs offering a carry as you would expect under such conditions...   ???

Anywho.. now you know.

One other comment on the Crude Oil market.. again from Rapier who takes on the expectations that US Crude Oil is going to just bounce back.. the rig count is higher.. so US producers are responding to higher prices.. however what will the impact be to production?  The Bakken peaked out over two years ago in December of 2014 when 8,950 producing wells kicked out 1.164 myn bbls per day.  The most recent data of November has almost 2,000 more wells at 10,927 and yet the AVERAGE Production has FALLEN by about 183,000 bbls per day..  what gives?!?  ( https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf )

Again.. (it's my story and I'm sticking to it..) the production from the average well has fallen from 130 bbls per day to 90.. thus when 8,500 wells FALL by over 40 bbls per day.. EVEN WITH the ADDITION of another 2,000 new wells.. TOTAL production has declined...  "Wait.. WHAT?!?"

which is what Shale production does...

Yes the US rig count is rising.. but.. it's a drill baby drill problem to solve.. will we bend US production higher?  probably.. but it probably will not come as easily as some expect.. but we are only getting started so.. ??   I'm on record as saying we will see $70 crude by July of 2018.. and that prediction stands.. it will be close as to whether I'm right or the bears.. but this chart from Rapier gives you an idea of the battle of production vs decline rates..  as well as a good read  ( http://www.energytrendsinsider.com/2017/02/06/can-u-s-shale-oil-offset-opec-production-cuts/#more-19585 )

In an earlier article - Why OPEC’s Announced Cuts Are A Really Big Deal - I addressed some of the skepticism around the recent production cuts enacted by OPEC. Today I want to consider in more depth the notion that U.S. oil producers might swiftly negate the impact of these production cuts.

To review, in November OPEC announced that it would enact 1.2 million barrels per day (bpd) of production cuts on January 1st. OPEC also announced that certain major non-OPEC members – most notably Russia – would cooperate with the production cuts, pushing the total amount of targeted cuts to 1.8 million bpd.

Some analysts cite two factors that could render OPEC’s cuts ineffective. The first is simply that OPEC members will cheat, as they have historically done. Certainly some members may overproduce their quotas, but OPEC is going to monitor global crude inventories. Those inventories had already begun to come down from record highs prior to the OPEC announcement, partly in response to declining U.S. shale oil production.

Further, a new Reuters survey has determined that OPEC’s compliance with the cuts in January was 82%. Tanker-tracker Petro-Logistics has estimated that crude oil shipments from OPEC countries were down by 900,000 bpd in January. So, early indications are that even if some cheating does occur, substantial cuts have taken place.

But the second factor cited by skeptics is beyond OPEC’s control, and that is that U.S. shale oil producers will simply ramp up production as oil prices rise, negating the OPEC cuts. That’s a reasonable concern, so let’s delve a bit deeper.

At the height of the shale boom, U.S. producers were adding more than a million bpd of oil production each year. At that growth rate, the production cuts could indeed be offset in a couple of years. But a look at the relationship between the number of oil rigs drilling for oil and oil production at first glance implies that a rapid turnaround is unlikely:

Between about 2000 and 2008, U.S. oil rigs doubled from around 200 to 400, but oil production hardly responded (though that was before the spread of modern shale drilling technology.) The rig count plunged in 2008 along with oil prices, but once oil rallied the rig count began a steep climb. Production did eventually respond, but there was a lag of more than a year between the start of the rig rush and a meaningful increase in oil production.

However, if you look at the last six months of the above graph, you will notice that the rig count began to climb again after bottoming last May. Meanwhile, oil production, which had been steadily falling since about mid-2015 reversed course and began to climb in October 2016.

This rapid turnaround is likely a result of a backlog of drilled but uncompleted wells (DUCs), which can be brought online faster than a new well can be planned, drilled, and completed. Data from the Energy Information Administration shows an uptick in completions over the past year in the four oil-dominant regions of the Bakken, Eagle Ford, Niobrara, and Permian Basin, where the DUC inventory in December stood at 4,509 wells. This uptick in completions helps explain why recent oil production responded more quickly than during the previous rig surge that began in 2009.

Considering this data, how soon might the U.S. manage to offset 1.8 million bpd of production cuts? If the impressive production gains since early October could be maintained, it would amount to ~1.5 million bpd over the course of a year. It’s going to be very important in coming months to see if these fast gains were a short-term response to $50 oil, or if they are sustainable.

My opinion is that the DUCs that are being completed with oil prices at $50/bbl will be among those with the highest production rates. After all, higher production rates are what enables a well to be economic to produce at lower prices. Thus it is likely that the most promising wells are being completed first, and that completion of additional DUCs is unlikely in my view to maintain that production growth for an extended period of time.

However, if by mid-year U.S. producers have added another half million bpd, OPEC may once again find themselves facing the difficult decision of responding with another round of production cuts.

We will see..  Chow baby.