Buying Ethanol Put Options to Profit from a Fall in Ethanol Prices

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High-Price Ethanol Credits Add to Refiners’ Woes

SUGAR LAND, Tex. — The oil-refining business has always been a tough way to make money.

Stiff competition, heavy regulation and high operating costs make for some of the lowest profit margins in the petroleum industry. And in the last year, profits have been even harder to come by because of the global fuel glut that has translated into bargain-basement prices for the gasoline and diesel that refiners produce.

But lately, the game has been tougher still for people like Jack Lipinski, chief executive of CVR Energy, an independent operator of two refineries in Oklahoma and Kansas. The problem involves a soaring cost that is outside of his control.

This year, on top of everything else, CVR Energy will have to spend as much as $235 million on credits for renewable fuels. That is nearly double what the company spent last year on the credits, and it exceeds the company’s total labor, maintenance and energy costs.

Mr. Lipinski blames the federal program that requires CVR to buy the credits, but he also suspects a role by unknown market speculators who may be driving up the costs of the credits.

“I have no way of fixing it,” Mr. Lipinski said in an interview at his headquarters in this Houston suburb. “It’s a black pool of speculation that could cause bankruptcies in our sector.”

The Environmental Protection Agency, which administers the credits, discounts charges of widespread abuse. And the issue may be only a short-term problem, as it was in 2020, when a speculative bubble drove the price of the credits to unsustainable heights before bursting.

But now, the profits and share prices of many independent refiners like CVR, PBF Energy and the HollyFrontier Corporation are slumping.

Valero of Texas, the world’s biggest independent refiner, has projected that the credits could cost the company as much as $850 million this year, compared with $440 million in 2020.

Small and medium-size refiners process roughly half the nation’s transportation fuels. Unless the price of credits falls significantly, refinery executives warn of a wave of consolidation that could concentrate refining in fewer hands, leading to higher prices for drivers at gasoline and diesel pumps.

The credits are part of a federal program put in place a decade ago by President George W. Bush and Congress. Refiners of gasoline and diesel fuel are required to add a certain amount of renewable fuel — corn ethanol or other biofuels — to each gallon of petroleum-based fuel they refine. The program was meant to trim oil imports, reduce greenhouse gas emissions and help corn farmers.

If a refiner cannot or does not want to add biofuels to its product — which is CVR’s situation — the company is required to buy a per-gallon credit from refiners that do.

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These credits originally sold for a few cents a gallon under the system supervised by the E.P.A. But as an unregulated trading market has emerged, the price has swung wildly for the credits, which are known as RINs, for Renewable Identification Numbers.

The ethanol RIN price approached $1.50 a gallon in the 2020 bubble before falling below 25 cents. And it recently spiked at nearly $1 before slipping back somewhat.

Ethanol is broadly unpopular in the oil industry, largely because biofuels compete with petroleum products for market share. And many say the policy to promote ethanol is antiquated after a six-year drilling frenzy in the United States that has resulted in reduced imports and cheap gasoline.

But the industry is divided on the question of who should be responsible for RIN purchases — those who refine gasoline, as is now the case, or those who blend gasoline with ethanol or other biofuels.

So far, the E.P.A. has declined to change the policy. And industry experts see little chance of any change, at least until after the November elections.

The independent refiners say they are penalized by the system, because their operations are equipped to process only petroleum products — not ethanol, which absorbs water and can cause damaging corrosion in pipelines and storage facilities.

The refiners could buy or construct special ethanol blending terminals, but the smaller players say such investments are not financially feasible.

RINs are simply numbered tags created when ethanol or another biofuel is produced. When the biofuel is blended with gasoline or diesel — usually at a terminal near the filling stations where it will be sold — the resulting RINs can be sold to anyone.

If the blender does not sell the credit to a refiner, it can sell it to a hedge fund or a Wall Street bank, which can save the credits or trade them, like commodities contracts. RINs are generally valid for a year, though refiners can retain up to 20 percent of their credits for the next year. Once an RIN has been submitted to the E.P.A., it is out of circulation.

Many refiners loathe the RIN system, but others in the petroleum industry benefit from high RIN prices.

Many big oil companies make money blending ethanol for their gas stations and from trading the credits. RIN sales are also a big profit maker for gasoline station chains like Murphy USA and RaceTrac that also blend ethanol. And higher RIN prices also indirectly help ethanol producers like Cargill and Archer Daniels Midland because they create more demand for fuel blending.

Jack N. Gerard, the top oil lobbyist as head of the American Petroleum Institute, opposes the federal mandates for renewable fuels. But this month, he took sides on the question of who should bear the burden, when he wrote a letter to the E.P.A. urging the agency to maintain the current requirement that puts the onus on refiners.

With any change, he wrote, “compliance plans, investments, and commercial agreements that were premised on the current structure would be disrupted.”

In some years, there is an excess of ethanol and RINs in the market, and the RIN price tumbles. But the high prices lately are evidently the result of investors and blenders stockpiling RINs in the expectation that the E.P.A. will raise the blending requirements in 2020.

The refiners point out that the credits are sold in private transactions that they say lack transparency. They argue that the E.P.A. is not equipped to supervise the market in the way that a financial regulator like the Chicago Mercantile Exchange would be able to.

“RINs should be trading at 20 to 30 cents and not 70 to 80 cents now,” said George J. Damiris, chief executive of HollyFrontier, which operates five refineries. “So any market premium above that cost of production is due to scarcity and speculation.”

E.P.A. officials say that they so far have found no sign of significant market manipulation, but they will continue to be vigilant.

“Industry and academic analysts have pointed out as recently as this summer that higher RIN prices are an expected outcome of rising R.F.S. requirements,” said Christopher Grundler, director of E.P.A.’s Office of Transportation and Air Quality, referring to the renewable fuel standards.

Some analysts say the high RIN prices will create incentives for more ethanol consumption. Several large independent gas station chains that blend biofuels, including RaceTrac, have announced that they will soon begin pumping more fuel with higher concentrations of ethanol to generate more RINs that they can sell.

Most gasoline now sold in the United States is 10 percent ethanol. But there are higher concentrations, like E-15, which is 15 percent ethanol, and even E-85, or 85 percent.

But gasoline containing ethanol is less efficient than gasoline without it. And only about 6 percent of the vehicles in the United States are so-called flex-fuel vehicles designed to run on biofuel concentrations as high as E-85.

The EPA granted a waiver for E-15 gasoline for use in all cars built since 2001, but several auto manufacturers have warned against its use.

Mr. Lipinski, of CVR Energy, expressed skepticism that the ethanol market would take off any time soon under current government policy.

“Nobody’s buying E-85,” he said, shrugging. “Who’s going to pay the same or more for a fuel that gives you 35 percent less gas mileage?”

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Feature: Brazilian ethanol import barriers increase structural deficit in NNE region

Sao Paulo — Anhydrous ethanol stocks in Brazil’s NNE region was recorded by the Ministry of Agriculture and Livestock, or MAPA, at 147 million liters as of December 31, a drop of 8.9% year on year and the lowest for the period since S&P Global Platts started to track it in 2009 as imports declined due to change in quota rules.

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The Brazilian North-northeast region is well known by its historical structural deficit of anhydrous ethanol, the one used in Brazil as a mandatory 27% blend in the Gasoline A. The region imports cargoes from US, the usual supplier, to cover its short production mainly in the first quarter of the year, when producers from Center-South Brazil are mostly out of the market due to the inter-crop season in the CS.

That market dynamic started to change in September 2020, when the Brazilian Foreign Trade Chamber (Camex) published a new set of rules for ethanol import quotas. The new rules increased import quota by 150 million liters, moving from 600 million liters per year to 750 million, however, restricted the access to the import license just for ethanol producers, which are allowed to request a maximum quota of 2,500 liters per producer.

Instead of 750 million liters/year divided equally into 187.5 million liters/quarter, volumes are now restricted to 200 million tariff-free liters during the North-Northeast crushing season (September to February). The remaining 550 million liters can enter tariff free between March and August.

“These new restrictions have hindered our import operations and the usual amount of ethanol we import per month. We are having to aggressively negotiate with mills with granted import quotas in the effort to combine quotas to fulfill a full cargo of ethanol,” said a Sao Paulo based trader.

The production and price reaction

A more restricted market encouraged regional producers to increase their anhydrous production to 775 million liters, a surge of 22% year on year in the period between August, 2020 to December, 2020, showed the latest data from MAPA. Despite that increased production it was not enough to meet the increased anhydrous demand in the region as gasoline prices remained more attractive than hydrous and imports are still needed.

In 2020 the Brazilian ethanol imports into the NNE region totaled 1.01 billion liters, a plunge of 25% from 2020. S&P Global Platts Analytics estimates that Brazil will import a total of 1.35 billion liters in 2020 with 300 million liters being imported in Q1 2020. If these estimates prove correct, Brazilian ethanol imports will decline by 8.8% year on year with a decline of 24% to Q1 2020 from Q1 2020.

“The new quota rules and trade restrictions for Brazil’s Northeast have not affected how much ethanol I am sending to Brazil. The only change has been that I am selling one cargo to multiple Brazilian buyers, but my volumes have not changed year over year,” stated a Houston based ethanol trader.

That short stocks and imports of anhydrous ethanol are already reflecting in a regional price spike. Platts assessed anhydrous ethanol DAP Suape on January 17 at Real 2,515/cu m a surge of 15.4% on the year. According to Platts calculations on January 17, despite that price spike the import arbitrage for companies without access to import quotas remained closed in Real 87/cu m, while producers who are managing to import their quotas had an open arbitrage of Real 334/cu m.

“Anhydrous ethanol price needs to increase in Real 100/cu m in Suape to trigger more imports,” said the international trader from an usual import company.

In addition to the current closed import arbitrage, the trader said that lack of tank capacity is also limiting further imports right now.

As the Brazilian gasoline has a mandatory blend of 27% of anhydrous ethanol any shortage of anhydrous could trigger a regional fuel supply issue, which would not be positive for the ethanol industry.

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