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California’s tough rules a blessing and curse for refiners: Fuel for Thought

Refiners operating in California expect a tough environmental regulatory permitting process. This has been a bit of a curse at times, causing long delays and restrictions on modifying their plants.

But it has also been a blessing. While the strict rules make the fuels more expensive to make, it also limits the number of suppliers who can supply the fuel to California, giving regional refiners virtually unlimited access to demand in a state where gasoline demand is greater than any other and growing.

Give this backdrop, it was interesting to see what may have been a brief loosening of restrictions in Southern California because of a personnel change open a window of opportunity for the restart of ExxonMobil’s Torrance refinery.

That reopening, which had been slowly moving through the environmental regulatory process before the ouster of the longtime head of South Coast Air Quality Management District, was necessary before ExxonMobil could sell its Torrance plant to East Coast refiner PBF Energy.

Long-time head of South Coast Air Quality Management District, Barry Wallenstein, was voted out in a 7 to 6 vote taken by the regulatory agency’s 13-person board during a closed session on March 4.

The vote to oust Wallenstein occurred after January’s appointment of two board members shifted the balance of power to the Republican camp, a move which was expected to result in “a loosening of requirements” and less rigorous air quality policies, according to sources familiar with the situation.

The timing of the board change will help facilitate the sale of ExxonMobil’s Torrance refinery to PBF, which is contingent on the proven performance of the refinery’s gasoline-making FCC unit, shut February 2015 after an explosion and a fire.

Wallenstein had headed the agency since 1997, and his removal caused dismay among environmental groups, who feared any loosening of regulations would bring back the nasty smog, which plagued the Los Angeles Basin for years.

In early April, following Wallenstein’s departure, agency approval was given to restart the 87,000 b/d FCC unit at ExxonMobil’s 149,500 b/d Torrance, California, refinery.

The restart was a bone of contention among Torrance residents, due in part to ExxonMobil’s failure to notify the community of a hydroflouric acid pipeline leak last September, an action for which it was fined by the state.

While the Torrance restart plan has multiple stringent and rigorous monitoring requirements, it expects refinery emissions levels would exceed permitted levels because it will not use pollution control devices known Electrostatic Precipitators (ESPs) during the restart process.

“This limitation on use is necessary to ensure the safety of the start-up procedure but will minimize excess emissions to the maximum extent feasible,” the agency’s order of abatement said, referring to not using ESPs continuously during the restart.

Personnel change doesn’t mean looser rules

Industry participants caution in assuming an agency change in Southern California means a loosening in the state’s environmental regulations.

“Our mandate is to ensure petroleum refining activities are done as safely as possible,” said Paul Penn, Emergency Management and Refinery Safety Program Manager at the California Environmental Protection agency.

The California Environmental Quality Act, passed in 1970, requires extensive review of project impacts, using 18 environmental factors to determine whether to issue permits.

Despite the personnel change in Southern California’s air quality regulatory body, the state’s strict guidelines are not under threat — and neither is PBF’s deal for ExxonMobil’s Torrance refinery.

The state’s strict CARBOB gasoline and diesel specifications make the fuels more expensive to produce, it also limits the number of suppliers who can sell the fuel to California drivers.

The higher production cost, combined with logistical issues such as lack of pipelines bringing in product from outside the region and the expense of fixing a Jones Act vessel from other US regions, give regional refiners the upper hand in supplying California and surrounding states like Washington and Arizona, who have opted in to using California spec fuels.

And while other refiners have said at various times they want to leave California, it helps explain why PBF’s iconic executive chairman, Tom O’Malley had been on the look out for a California refinery.

Source: http://blogs.platts.com/

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California’s tough rules a blessing and curse for refiners: Fuel for Thought

Refiners operating in California expect a tough environmental regulatory permitting process. This has been a bit of a curse at times, causing long delays and restrictions on modifying their plants.

But it has also been a blessing. While the strict rules make the fuels more expensive to make, it also limits the number of suppliers who can supply the fuel to California, giving regional refiners virtually unlimited access to demand in a state where gasoline demand is greater than any other and growing.

Give this backdrop, it was interesting to see what may have been a brief loosening of restrictions in Southern California because of a personnel change open a window of opportunity for the restart of ExxonMobil’s Torrance refinery.

That reopening, which had been slowly moving through the environmental regulatory process before the ouster of the longtime head of South Coast Air Quality Management District, was necessary before ExxonMobil could sell its Torrance plant to East Coast refiner PBF Energy.

Long-time head of South Coast Air Quality Management District, Barry Wallenstein, was voted out in a 7 to 6 vote taken by the regulatory agency’s 13-person board during a closed session on March 4.

The vote to oust Wallenstein occurred after January’s appointment of two board members shifted the balance of power to the Republican camp, a move which was expected to result in “a loosening of requirements” and less rigorous air quality policies, according to sources familiar with the situation.

The timing of the board change will help facilitate the sale of ExxonMobil’s Torrance refinery to PBF, which is contingent on the proven performance of the refinery’s gasoline-making FCC unit, shut February 2015 after an explosion and a fire.

Wallenstein had headed the agency since 1997, and his removal caused dismay among environmental groups, who feared any loosening of regulations would bring back the nasty smog, which plagued the Los Angeles Basin for years.

In early April, following Wallenstein’s departure, agency approval was given to restart the 87,000 b/d FCC unit at ExxonMobil’s 149,500 b/d Torrance, California, refinery.

The restart was a bone of contention among Torrance residents, due in part to ExxonMobil’s failure to notify the community of a hydroflouric acid pipeline leak last September, an action for which it was fined by the state.

While the Torrance restart plan has multiple stringent and rigorous monitoring requirements, it expects refinery emissions levels would exceed permitted levels because it will not use pollution control devices known Electrostatic Precipitators (ESPs) during the restart process.

“This limitation on use is necessary to ensure the safety of the start-up procedure but will minimize excess emissions to the maximum extent feasible,” the agency’s order of abatement said, referring to not using ESPs continuously during the restart.

Personnel change doesn’t mean looser rules

Industry participants caution in assuming an agency change in Southern California means a loosening in the state’s environmental regulations.

“Our mandate is to ensure petroleum refining activities are done as safely as possible,” said Paul Penn, Emergency Management and Refinery Safety Program Manager at the California Environmental Protection agency.

The California Environmental Quality Act, passed in 1970, requires extensive review of project impacts, using 18 environmental factors to determine whether to issue permits.

Despite the personnel change in Southern California’s air quality regulatory body, the state’s strict guidelines are not under threat — and neither is PBF’s deal for ExxonMobil’s Torrance refinery.

The state’s strict CARBOB gasoline and diesel specifications make the fuels more expensive to produce, it also limits the number of suppliers who can sell the fuel to California drivers.

The higher production cost, combined with logistical issues such as lack of pipelines bringing in product from outside the region and the expense of fixing a Jones Act vessel from other US regions, give regional refiners the upper hand in supplying California and surrounding states like Washington and Arizona, who have opted in to using California spec fuels.

And while other refiners have said at various times they want to leave California, it helps explain why PBF’s iconic executive chairman, Tom O’Malley had been on the look out for a California refinery.

Source: http://blogs.platts.com/

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As Chinese steel starts to call its own

With Chinese steel prices on a steady recovery since the Lunar New Year holidays, supply and production allocations have swung firmly towards serving the domestic market.

Buyers overseas have meanwhile found it hard to play catch up with Chinese offers, as delays or attempts to be coy with sellers are usually met with unwelcome news the next day that prices have climbed even higher.

Feedback from participants on both sides of the market suggested that they did not think this bout of price increases is showing any signs of losing steam just yet.

For Chinese suppliers, who have been blamed for everything from dumping to the demise of the UK steel industry, the past few months have perhaps seen them undergo a coming of age of sorts, as they realize the tremendous influence they exert on global markets.

This was in plain view at a recent industry conference, where at least two speakers pronounced Chinese steel’s position as global price setter, by virtue of the nation being the biggest producer, consumer and exporter, as well as its futures exchanges, home to the most liquidly traded steel contracts.

“There’s no need to look at overseas demand,” declared an official at a government think tank in his speech. “Once domestic prices go up, global prices go up.”

Another official from the Shanghai Futures Exchange boasted how they have recently been swarmed by visits from the CME, LME and SGX, all keen to understand the reasons behind the explosion in volumes traded in its hot rolled coil contract.

In the physical market, those who have cried foul against unfair trade have moved to establish formidable barriers to Chinese exports. But it is ironic to note how overseas buyers are now starting to bemoan the disappearance of Chinese offers in the market.

This is particularly evident in markets such as galvanized sheet in Europe where the disappearance of Chinese offers of thin gauge material has resulted in severe shortages in the market.

The complaints of end-users who are no longer able to secure cheap Chinese steel will surely sound insignificant against the macroeconomic backdrop of governments and central banks worldwide, scrambling to avert a seemingly inexorable deflationary spiral.

But who really knows what might come next, or when the release valve might open again if Chinese domestic demand falters?

As the international markets await the faltering of Chinese domestic demand, what appears certain is that the world should get used to working with the whims and fancies of Chinese Steel.

Source: http://blogs.platts.com/

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RIN generation is up, but more biofuels mandates are on the way

With the latest batch of EPA Moderated Transaction System data due to be released in the next few days, giving some insight into RIN trading in the US, now seems like an appropriate time to take a dive into the current RIN situation.

US renewable fuels and RVOThe 2016 Renewable Volume Obligation under the Renewable Fuel Standard calls for 18.11 billion gallons of renewable fuels to be blended into US transportation fuel stocks. Each of three categories of renewable fuel has their own individual mandates within that overall mandate, with the remaining allotment generally taken by ethanol.
Last year, the biofuels industry produced 16.72 billion gallons of renewable fuels, generating 17.88 billion RINs. (Under the RFS, each gallon of biodiesel generates 1.5 RINs; hence the discrepancy between volume produced and RINs generated.)
Through the first two months of 2016, 2.844 billion total RINs have been generated on 2.687 billion gallons of renewable fuel. Compared with the same time frame in 2015, RIN generation is up 5% year on year.
The biggest gain, percentage-wise, comes in D4 biodiesel RINs, which have increased 40% year on year through February. What’s most interesting is that, traditionally, biodiesel production and RIN generation is typically lowest in January and February. That could indicate that there could be quite a plethora of RINs by the end of the year, if previous production trends continue.
US D4 RIN generation, 2014-2016
Since D4 biodiesel RINs can be used to satisfy three different portions of the RVO – the biodiesel, advanced biofuel or renewable fuel mandates – they are particularly useful in the RIN market. Hence, they’re priced higher compared with D5 and D6 RINs.
That robust RIN generation could be sorely needed. D5 advanced RINs are currently behind last year’s pace, at approximately 8 million RINs compared to last year’s 9.7 million through February. That’s most likely a reflection of the decrease in sugar cane ethanol imports into the US through the early part of the year. But the advanced mandate this year calls for 1.48 billion gallons of advanced fuel outside of the cellulosic and biodiesel mandates. Last year, advanced RIN generation came in at 146 million RINs, far below the 2016 mandate.
Meanwhile, ethanol RIN generation is ahead of last year’s pace, 2.426 million RINs compared with 2.333 million RINs in 2015. But February RIN generation fell to 1.18 billion RINs, below the 1.2 billion RINs per month needed to meet the 14.5 billion gallon mandate. But February usually is the lowest month for RIN generation as ethanol plants begin to shut down for maintenance.
US ethanol production, 2014-2016
Of course, the RIN market will be affected by more than just RINs generated this year. There’s still a large amount of RINs left over from 2015 that can be used to comply with up to 20% of this year’s RVOs. Published reports have placed the number of these “carry-over” RINs at 544 million D4 RINs and 1.46 billion D6 RINs.
Two key questions, though, will have an impact on RINs for the rest of the year.
First, will biofuel production and RIN generation continue at its current pace or slow down? At its current clip, biofuels RIN generation will come about substantially short of the required mandates. A large chunk of that deficit is in the advanced mandate, and certainly some of the robust biodiesel RIN generation can satisfy that burden. If production slows, however, obligated parties will have to tap into those banked “carry-over RINs,” taking away some of their flexibility.
Second, what will the EPA propose for its 2017 mandates for cellulosic, advanced and renewable fuel in June? (The EPA already released its 2017 biodiesel mandate, at 2.0 billion gallons.) The most volatile time for RIN prices comes in June and November, when the EPA publishes its proposed and final RVOs. If the 2017 mandates continue to climb, and if the number of carry-over RINs is liquidated to cover 2016 RVOs, it seems inevitable that RIN prices would be affected.

Source: http://blogs.platts.com/

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Qatar’s OPEC MAX meeting and the oil price rout that wasn’t

There was much gnashing of teeth as Qatar’s grand meeting of oil producers failed to reach agreement April 17 to freeze production at January levels.

Commentators predicted a collapse in oil prices and some discerned the demise of OPEC itself.

But since then the expected rout in prices has yet to materialize, stock markets have been unfazed, and the outcome from the point of view of OPEC’s dominant Arab Gulf members may not be unsatisfactory.

No doubt some delegates found it annoying to needlessly spend 12 hours cooped up in a five-star hotel in Doha, albeit with a visit to pay their respects to the emir of Qatar, Sheikh Tamim bin Hamad Al Thani.

The failure of the talks was an embarrassment and will be felt by OPEC’s weakest nations, particularly Venezuela, which is in a state of crisis and badly needs oil prices to rise.

That prices did not immediately fall more than a couple of dollars owed something to a strike by oil workers in Kuwait, which caused the country’s production to fall initially to just 1.1 million barrels per day, barely a third of normal levels.

In the aftermath of the talks, Russia, which had invested much effort trying to broker a deal, indicated it would continue pumping at record levels, above 10.8 million b/d, helping to cap prices.

Amidst the failure to agree a freeze and Russia’s determination to boost output, there were reasons for markets not to panic, at least for the time being.

Markets had after all not given much credibility to the proposed production freeze. And production prospects are now depressed not only for Venezuela, but a number of countries worldwide.

Some observers are starting to doubt Iran has much more to offer the market for the time being than the increase it has managed since sanctions against it were lifted in January – generally estimated at 300,000-350,000 b/d.

Investment bank Tudor Pickering Holt said April 18 that further significant increases from Iran would require more capital expenditure, which was “not likely in the current environment.”

More fundamentally, the economic impetus for a production freeze has somewhat waned since the idea was first proposed in February. Back then, prices were around $10/b lower than when the April 17 meeting came round, and had recently hit $27/b, amid generalized worries about the global economy and China in particular.

Since then, the outlook for the world economy can’t be said to have transformed. But in terms of oil demand, some of those jitters have eased, as documented by successive monthly reports from the International Energy Agency.

In February the agency was talking of a “false dawn” for oil prices, in March this had changed to “light at the end of the tunnel.”

By this month it was predicting oil markets would come “close to balance” in the second half of this year, with supply exceeding demand by just 200,000 b/d in the third and fourth quarters.

Oil demand in China, India and Russia has been robust, the IEA added. Why then sweat to get a deal in Doha?

The question was pertinent for OPEC’s core Arab state members and above all Saudi Arabia, which had given mixed signals about the proposed freeze.

Saudi Arabia has cast doubt on the desirability of oil prices rising much further, sometimes framing the issue in terms of diversifying its economy.

In terms of oil markets, one question is how far prices can rise without causing a rebound in US shale oil production. The answer, with hundreds of US shale wells drilled but sitting idle – uncompleted and waiting for prices to rise – may be not much.

“As things get back into the $40-45 range then we would start completing the drilled but uncompleted wells,” James Volker, chief executive of Whiting Petroleum, which has around 150 such wells in the Bakken and Niobrara shale, said in February.

But the April 17 meeting in Qatar was about more than prices. For some participants the idea of sealing a major pact on supply management outside of normal OPEC boundaries – brokered by Russia, with help from rising regional power Qatar – may not have been attractive.

Granted, the collapse of talks was a blow to participants’ prestige, but what might have been worse for some would have been a deal that effectively replaced OPEC and its six-monthly meetings in Vienna, and put Russia in the driving seat of a larger, more nebulous group, with the Gulf Arab states’ control diluted.

Qatar’s rise as a diplomatic force, financed by the latest big thing in energy markets, liquefied natural gas (LNG), has raised hackles among some Gulf states.

Probably more significantly, Russia’s flexing of its muscles in the Middle East has not made for comfortable viewing for a Saudi regime that has made clear where its international focus lies. That is not Russia. Saudi Arabia’s Deputy Crown Prince Mohammed bin Salman made this evident in an interview with Bloomberg ahead of the April 17 talks, saying: “America is the policeman of the world, not just the Middle East. It is the number one country in the world and we consider ourselves to be the main ally for the US in the Middle East.”

Tellingly for those heading to Qatar, he added: “I don’t believe that the decline in oil prices poses a threat to us.”

Source: http://blogs.platts.com/

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Electric vehicles: The impact on oil and electricity

Ross McCracken, managing editor of Platts analytical monthly newsletter Energy Economist, has been analyzing global crude markets since 2001. Using this experience, he looks ahead in this post to assess what could be the most profound shock both to global oil and electricity markets in their history: the electrification of road transport.

The number of electric vehicles (EVs) on the world’s roads hit the one million mark in third-quarter 2015 and sales are growing fast. If, and it is still a big if, EVs demonstrate an exponential rate of deployment, similar to solar PV panels, it could have a profound impact on both oil and electricity demand, and by extension the very basis of world primary energy supply.

Recent forecasts have suggested that at a 30% annual growth rate in EV sales would result in as much as 2 million b/d of oil demand being displaced by 2028, while at the same time adding 2,700 TWh to electricity demand globally by 2040.

An EV, which means plug-in hybrid vehicles (PHEVs) and battery-only vehicles (BEVS), uses 0.3 kWh of electricity per mile. So the total electricity demand in a year equals the number of EVs times the number of miles travelled annually times 0.3.

The amount of oil demand displaced in barrels/day equals the number of EVs times the number of miles travelled in a year divided by the average miles per gallon of internal combustion engines (ICE) divided by 365, divided by 42, the number of gallons in a barrel.

As such, the critical variables are the growth in the number of EVs on the road, the evolution of mpg and the number of miles each EV is assumed to travel.

Fuel efficiency is expected to rise in both high and low EV penetration scenarios driven by regulation, from somewhere around 17-24 mpg in 2015 to 45 mpg in 2040. So, although a major variable, there appears to be a rough consensus about its evolution.

The number of miles travelled is more contentious and has a huge impact on the expected outcome. In a recent report by Bloomberg New Energy Finance, the miles travelled per EV is assumed to rise on average from 8,700 a year in 2015 to 22,420 in 2040. BNEF sees all ICE Light Duty Vehicles travelling 23,500 miles a year in 2040.

This huge increase in miles travelled comes about as a result of autonomous driving, ride sharing services and other new mobility business models, according to BNEF. However, it is a big assumption; the trend is in fact down not up. The number of miles driven per car per year in the UK, for example, fell from 9,200 miles in 2002 to 7,900 in 2014, according to the RAC Foundation.

The number of EVs on the road is also open to question. Oil major ExxonMobil – a conservative counterpoint to BNEF’s enthusiasm for all things renewable – sees 50 million EVs on the road by 2040, compared with BNEF’s 400 million. Exxon’s assumption still represents growth in the number of EVs of about 14% a year on average out to 2040. The oil company assumes widespread adoption of conventional hybrids as the most economic option for consumers.

As a result, the range of possible outcomes is huge. If mileage is assumed to be flat then under Exxon’s scenario, oil displaced by EVs in 2040 amounts to a meagre 0.83 million b/d. At the other extreme, if BNEF’s high growth rates/high mileage assumptions are adopted then the figure comes out at a headline grabbing 13 million b/d.

The impact on global electricity demand would be again be minor in Exxon’s scenario, and much larger in BNEF’s at 2,700 TWh in 2040, equivalent to 11.4% of global electricity generation in 2014.

If a compromise is reached – say flat mileage of 11,500 in line with current LDV usage in the US, and BNEF’s high growth rate is adopted – the impact is 6.7 million b/d of oil displaced in 2040 and an additional 1,385 TWh of electricity consumed.

However, even this does not provide the whole picture. BNEF considers only LDVs, but there is a lot more to transport than that – heavy-duty vehicles , trains, planes and ships. Moreover, Exxon says this is where the growth in energy demand for transportation will come from, not from the LDV sector.

Global GDP will double by 2040 based on fairly conservative economic assumptions, so there will be a huge expansion in commercial transport. Exxon does sees electricity and natural gas making inroads, but not sufficiently so to overcome the increase in demand for oil from the growth in commercial transport.

If this part of the forecast proves correct, then the impact on oil demand of higher EV sales, even combined with higher mileage assumptions, could be swallowed up by the overall expansion in transport so that oil use continues to grow. EV growth and fuel efficiency will both retard oil demand, but they do not necessarily mean that oil demand will contract.

EV sales and driving patterns are clearly key variables to watch. As the cost of lithium-ion batteries falls, regulatory support grows and consumer sentiment shifts, they could produce the kind of exponential growth curve that other disruptive clean technologies have shown.

This would provide a new area of electricity demand growth for an industry sorely in need of one, at least in the OECD. It would create a massive amount of storage capacity. And it would put a significant break on oil demand growth. But as to the overall impact, it is better not to leap to conclusions just yet.

A fuller analysis of both the ExxonMobil and BNEF scenarios for the transportation sector is available in the April 1 edition of Energy Economist.

Source: http://blogs.platts.com/

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