Authors: John Auers and Elizabeth Hilbourn

“None of you can make the grade” are the repeating lyrics of the angst fueled alternative rock band Placebo in their song “Bionic.”  It is also a tune some aluminum producers are singing as shifts in the operations of some of their refiner suppliers negatively impact anode grade coke quality and/or volume. These shifts are taking place for a variety of reasons, most of which are region specific. In the U.S., the growth in Light Tight Oil (LTO) production and its increasing presence in the crude slates of refiners who produce anode grade coke is the biggest driver of these changes.  In China, the world’s most important aluminum and by association, anode coke market, a restructuring of the industry and changes in refinery configurations are having the largest impacts on the anode coke market. Important developments are taking place in other regions around the world as well.  Regardless of the reasons, a major trend that appears to be emerging is that anode grade coke production is not keeping up with demand and that this could lead to shortages in supply in the years to come.   In order to provide a better understanding of these emerging supply and demand patterns,  Turner, Mason & Company has teamed with AZ China and Cascade Resources, two well-respected consultants who specialize in the anode coke/aluminum markets, to develop a comprehensive deep-dive report titled, Anode Coke Outlook to 2025.  This report has just been completed and becomes available today (September 1).  In today’s blog, we provide some additional background on this study, along with a brief description of the analysis and forecasts contained in the report.

Anode grade petroleum coke is essential for making aluminum; however, production has not been rising fast enough recently to meet the increasing demand generated by growing aluminum production.  The three study partners analyzed the drivers for this, and how it could play out in the future.  Part of the data gathered for the report includes an exhaustive list of refineries around the world that produce anode grade coke and an analysis of how production at each of the facilities will change in the future.  Detailed in the report is a five-year history and a ten-year forecast of anode code production for each anode coke producing refinery.  The report looks at various factors that impact refinery production, including investment, changing crude slates, and new regulations. The forecast includes changes in the volume and quality of green coke which will be produced at each of the refineries.

Anode grade coke supply usually doesn’t change significantly year to year unless a new anode grade coker is built or an existing one is shut down.  In the past, existing anode grade cokers have continued in the business of selling anode grade coke, operating their cokers accordingly and purchasing crude oil feedstocks to support anode grade coke. This philosophy is changing, however, as cheaper crudes such as LTO are available, which refiners are choosing and is resulting in a reduction in anode coke production.  The demand for aluminum steadily increases but the forecasted supply of anode coke falls short.  Changing world environmental regulations will put low sulfur crudes in higher demand.

A couple of blogs ago, in “All in the Family”- What is Happening with the Bunkers, we addressed the changing bunker fuel market.  With the ramping down of sulfur in bunker fuel, the goal is to eliminate sulfur oxides and particulate matter pollution from ocean-going vessels.  This is primarily achieved by lowering the maximum sulfur content of the bunker fuel used to power these vessels and pushing resid-based fuels out of the pool in favor of lighter and easier to desulfurize diesel.   These regulations could also impact the anode coke market, as low sulfur crudes which are currently used to produce anode coke, could instead be diverted to make low sulfur bunker fuels in an environment where LS bunker prices increase in tandem with diesel prices.  Other regulations, particularly those that impose costs on the delayed coking process could also impact anode coke production.  Our report investigates all of these factors and others in analyzing future production levels.

Coking Units convert the heavier portion of the crude barrel to fractions that can be processed by other refinery units into transportation fuels.  This process unit thermally cracks (breaks apart with heat) the large fuel oil molecules into smaller molecules can be converted to make gasoline, diesel and other products.  Petroleum coke is a by-product of the coking process.  When refineries do not have a coker unit, they sell the vacuum tower bottoms mixed with distillate streams to meet gravity and viscosity specifications as a No. 6 fuel oil or, in some cases, into asphalt.  The majority of No. 6 fuel oil is sold into the bunker fuel market and some for electricity generation and numerous industrial applications. When the global bunker fuel specification changes from 3.5% S to 0.5% S in 2020, this will have a significant impact on the No. 6 fuel oil market. Many crudes can produce a resid which can meet the 3.5% sulfur specification, but few can meet the 0.5% sulfur specification.

The U.S. continues to lead the world in total coking capacity and is second only to India in coking capacity as a percent of crude unit capacity.

Coker capacity additions in the U.S. have been significant in recent decades, rising by 1.4 million BPD (a 101% increase) since 1987.  This trend is also prevalent in India and China.

The three most important coke quality issues relating to the ability to produce anode grade coke are the level of sulfur, six metals (vanadium, nickel, iron, silicon, calcium, and sodium) and the structure meaning the coke should be sponge, not shot. These parameters are critical to the smelting of aluminum using electrolytic reduction cells or “pots” as they are commonly referred to in the aluminum industry.  Low sulfur, metals and the proper Conradson Carbon to asphaltene ratio in the crude are prerequisites for anode grade coke production.  In general, the crude must have a sulfur level below 1% and be lower in asphaltene in order to produce anode grade coke.  The raw coke out of the coker is referred to as green coke.  In this context, “green” means unprocessed.  The green anode coke is calcined to remove residual volatile hydrocarbons and then baked to produce the anode coke.  Approximately 80% of coke produced is high in sulfur and metals and sold as fuel grade coke.  Fuel grade coke is used (as the name implies) for fuel, mainly for cement kilns and electric power plants.  It is over 90% carbon and has higher energy content than coal.

Anode grade coke commands a significant premium over fuel grade coke, often at twice or more the price; however, coke is still a byproduct of refining.  Crude oil is chosen on the most part in order to fill key refinery process units and to produce high value gasoline and diesel products.  Anode crude production is often a secondary consideration in that low sulfur and metal crudes are chosen to be processed first, for the economics of filling the units and not exceeding sulfur plant limits.  Sometimes a refinery will continually produce all anode coke in its Coker, but just as often a Coker will only intermittently produce anode coke and flip back and forth between anode and fuel grade.  Often an upgrade on a Coker unit will change the refinery economics from anode grade to fuel grade.  An example is Husky’s Lima, Ohio refinery where in 2018 they plan to install larger coke drums, which will allow for a higher throughput but, as a result, the crude slate will shift to heavier Canadian grades and yield only fuel grade coke.

Anode Coke Supply Outlook to 2025 and Beyond has just been completed and is available as a subscription product.  This definitive study carries the most in-depth look at anode coke supply available today.  To give you an idea of what areas are covered, we are making available a copy of the Table of Contents of the report. The attached PDF file also shows a list of the tables, figures and charts that will be in the report.  Click here to see the Table of Contents and the list of charts and figures.  If you would like more information about pricing or other details of the study, contact John Auers at Turner, Mason & Company (jauers@turnermason.com) or Paul Adkins at AZ China (paul.adkins@az-china.com).

Turner, Mason & Company monitors developments in all segments of the petroleum industry. We are in the business of analyzing downstream markets and assisting all segments of the oil industry in responding to changing market dynamics. In addition to Anode Coke Supply Outlook to 2025 and Beyond, we are also completing a comprehensive analysis of the changing dynamics in world crude oil markets, The Evolving New World Order. This is also a collaborative effort, as we have partnered with Schlumberger Business Consultants, combining their upstream expertise with our downstream coverage.  This report will be available in mid-September and you can read our prospectus by clicking here.  Our 2015 Mid-Year Update of the Crude and Refined Products Outlook was issued earlier this month. For more details about any of our publications, studies or other TM&C services, please visit our website, send us an email or give us a call.

Authors: John Auers, Elizabeth Hilbourn and Wei Li

We continue our focus on China this week as we further delve into the subject of China’s curiously named teapot refining industry. In Part 1, we explained what a teapot refinery is, gave some background on how they developed and began the discussion of their current status in the overall Chinese refining industry. Just to recap, eastern China’s Shandong Province is the center of the teapot world, with 80% of those refineries located in that region. Compared to Chinese state-owned refineries, teapots are much smaller, with capacities ranging between 20,000 b/d and 100,000 b/d (vs. 200,000 b/d plus for many of the Sinopec and CNPC plants). They are also less complex and generally less efficient than the larger refineries. Because they currently do not have the right to import crude, they have to process domestic crudes. The total capacity of the sector in this province is just over 4 million b/d, and the utilization usually averages below 40%. For years, teapots have been a gauge for the overall health of the domestic oil market in China. They have served a valuable function with their excess capacity called on (in times of tight markets) to act as the supplier of marginal product requirements, but what is their future? Will they be phased out as the industry modernizes? Or, as China’s demand for refined products continues to increase, can some of the teapots with underutilized capacity be effectively used to meet demand? How will new regulations impact their status and prospects? We will attempt to address these questions in today’s blog as we try to “read the tea leaves” on what the future holds for the teapots.

Guidelines Issued by the NDRC

In early 2015, the Chinese National Development and Reform Commission (NDRC), which is the top economic planner of China, set out a policy allowing teapot refiners to process imported crude, but without the authority to import the volumes directly.

Under guidelines issued by the NDRC in February 2015, a refiner must have crude distillation capacity of 2 million metric ton per year (mt/year) (around 40,000 b/d) or above in order to qualify for a crude import quota from the government. The NDRC also mentioned that refiners that want to apply for the quotas have to get rid of all crude distillation units (CDUs) with less than 2 million mt/year of capacity. The quota allotted to the refiners is linked to the crude processing capacity that it shuts down, but cannot exceed its existing processing capacity; however, there are no restrictions on the minimum quota a refinery can use for the year. The ministry will, instead, review all the refineries’ import reports at the end of the year before they apply for import quotas for the following year. Furthermore, independent refineries will need to sustain crude imports for three consecutive years after receiving import rights; failing which, the ministry will revoke their crude import licenses. Finally, refineries need to meet certain environmental requirements, as well as have at least five years of trading experience in the international oil business, and strong bank credit.

The NDRC also mentioned that refiners can get additional quotas if they build LNG, CNG, or underground storage tanks. Refiners have the freedom to acquire and shut down smaller refiners to get the quota they desire.

The NDRC has designated China Petroleum and Chemical Industry Federation (CPCIF), which started in the middle of May to review import quota applications submitted by independent teapot refineries in March, to handle the reviews and carry out side inspections. The NDRC will still be in charge of final approvals for the import quotas, including the volume allotted. According to the how-to-guide, CPCIF will carry out a field check on each qualified refinery that has applied for quotas, after reviewing all the documents submitted. After all the paper and field work is completed, CPCIF will release the names of all the qualified refineries on its website, which will remain for 10 days. If no issues are raised by the refiners, CPCIF will submit the results to NDRC.

Import Quota Requests

China grants crude import quotas under two categories: state trade quotas and nonstate trade quotas. The state trade quotas are allotted to a handful of state-owned companies for use by their own refineries and do not have a cap on volume. These companies are China National Petroleum Corp., Sinopec, China National Offshore Oil Corp., Sinochem and Zhuhai Zhenrong. The nonstate trade quotas are granted to privately owned or state-owned trading companies. This category has a cap on volumes, and the barrels imported must be sold to state-owned refiners for processing, though some companies have been granted permission to process the crude at their own plants. The award of new quotas has been widely anticipated by teapot refiners, as it gives them the option to diversify their feedstock and improve profitability.

The Chinese government already grants Dongming Petrochemical and Beifang Asphalt crude oil import quotas. According to CPCIF, the Chinese government is likely to grant Sinochem Hongrun, Kenli Petrochemical, and Lihuayi Petrochemical crude oil import quotas.

1. Dongming Petrochemical

Currently, PetroChina supplied Venezuelan Merey Crude to Dongming through a strategic alliance, which is around 80% of Dongming’s feedstock. Dongming also regularly runs some Middle Eastern crude, Russian ESPO, and Angolan grades. The Dongming Petrochemical utilization has averaged 51% this year, which is based on total capacity of 11 million mt/year.

To apply for the quota, Dongming planned to continue to run two existing CDUs with capacities of 5 million mt/year and 2.5 million mt/year and dismantle three CDUs totaling 3.5 million mt/year of capacity. Furthermore, to qualify for a higher quota, Dongming Petrochemical not only has proposed to build LNG storage infrastructure, but also to acquire another refinery with a capacity of 2.5 million mt/year, with the sole purpose of shutting down more processing capacity.

After getting the import quota in mid-July, Dongming Petrochemical has imported two VLCC cargoes of Oman crude, one VLCC cargo of Venezuelan Merey crude, and some small parcels of heavy crude, which is a total of 800,000 mt to 900,000 mt of crude.

2. Beifang Asphalt

PetroChina Fuel Oil, a subsidiary of PetroChina, currently supplies Venezuelan Merey Heavy crudes to Beifang Asphalt under a supply contract signed a few years ago. It currently processes around 3.5-4 million mt/year of crudes, 80% of which are supplied by PetroChina Fuel Oil. Furthermore, the refinery has a quota to process around 400,000 mt from PetroChina’s Daqing oil field and 200,000 mt from PetroChina’s Liaohe oil field, according to Platts.

To apply for the quota, Beifang Asphalt Fuel planned to keep running two existing CDUs with capacities of 3.5 million mt/year each and dismantle its aging 2 million mt/year and 1.5 million mt/year CDUs. It will acquire one CDU with capacity of 1.5 million mt/year and two CDUs with 500,000 mt/year capacity, with the sole purpose of shutting them down in order to qualify for a higher import quota. Because Beifang Asphalt Fuel produces the National Phase 5 emissions standard gasoil and gasoline, it will qualify for some additional quota volumes.

In less than 10 days, the refinery should get an approval from the Ministry of Commerce. Once the refinery gets the approval, it can import crude from international markets via state-owned trading companies.

3. Sinochem Hongrun

To apply for the quota, Sinochem Hongrun decided to keep two existing CDUs with capacities of 3.5 million mt/year and 2.2 million mt/year and has planned to dismantle its third 1 million mt/year CDU. This refinery also acquires one CDU with 600,000 mt/year, one CDU with 500,000 mt/year, and four CDUs with 300,000 mt/year capacities, with the sole purpose of shutting them down in order to get the import quota. Furthermore, in order to get a higher quota, the refinery not only proposed to build LNG storage infrastructure with capacity of 56 million cubic meters, but also agreed to produce National Phase 5 emission-standard gasoline and gasoil, which caps sulfur content at 10 ppm, by upgrading its units at the end of 2015.

4. Kenli Petrochemical

China National Offshore Oil Corporation (CNOOC) supplied domestic crude from its offshore fields to Kanli Petrtochemical. Kenli PetroChemical also runs some imported bitumen blend. Most of its oil products go to the local market.

To apply for the quota, Kenli Petrochemical decided to remove two crude distillation units (capacities 1.45 and 0.65 million mt/year), which will give it a base import quota of 2.1 million mt/year. After getting rid of the two old units, Kenli Petrochemical’s primary capacity will reduce to 3 million mt/year. The refinery promised to produce National Phase 5 emission-standard gasoline and gasoil, which caps sulfur content at 10 ppm, by upgrading its units at the end of this year; therefore, it will be awarded another 420,000 mt/year.

5. Lihuayi Petrochemical

Lihuayi Petrochemical currently processes Shengli and Tahe domestic crude. It has a quota to purchase Shengli crude 80,000 mt/year from Sinopec, and it can procure more at a slightly higher rate when supplies are available.

To apply for the quota, Lihuayi Petrochemical decided to get rid of the smaller CDU, giving it a base quota of 50,000 b/d. The CDU, that it selected to get rid of, is bigger than 40,000 b/d; therefore, the refinery will also be awarded another 10,000 b/d. Furthermore, this refinery will build a new 1.8 million mt/year fluid catalytic cracker (FCC) to produce low sulfur gasoil and gasoline by the end of this year, so it qualifies for an additional 10,000 b/d quota.

Lihuayi Petrochemical is interested in medium crudes with an API of around 28 degrees, and it can process crude with over 2% sulfur anode coke markets, (anode coke supply and demand outlook to 2025), a sector in which China is a particularly important player.   Due to be released very soon is an analysis of the changing dynamics in world crude oil markets, The Evolving New World Order, which we have partnered with Schlumberger Business Consultants to develop. To download the The Evolving New World Order prospectus click here. For more details about any of our publications, studies or other TM&C services, please visit our website, send us an email or give us a call.

Authors: John Auers, Elizabeth Hilbourn and Wei Li

Considering the growing importance of China to the energy markets and the recent and high profile developments and speculation about economic activity there, we continue our discussion on the “Sleeping Giant” (a nickname given to China by Napoleon). Today, we note that the 70th anniversary of Japan’s defeat in WWII, a conflict that took between 15 and 20 million Chinese lives, was celebrated in grand fashion recently (on September 3, 2015). You have to hand it to China, similar to the 2008 Olympics; they do everything extravagantly. The sky was blue and everything was new and modern. Many global leaders were distinguished guests; however, there was a marked absence of North American and European leaders. The attendance of President Putin was a given considering the two countries’ increasingly close ties, especially on a military and energy level. With fears of market instability creeping in, an event like this could build confidence and gain a little domestic support, at least for a very short while. Somehow, they even made the balloon release (shown in the middle picture) look like a graph of the stock market. It depicts a series of recent ups and downs with a final upswing. Energy markets have also been impacted by developments in the overall economy in China and these are playing a major role in global energy sentiment. EIA recently issued their September Short Term Energy Outlook and revised growth in global consumption for 2016 downward by almost 0.2 million b/d, compared with last month’s forecast, as China and other Asian economies continue to show signs of weakness. In the same report, China’s growth in oil consumption is expected to average slightly less than 0.3 million b/d in 2015 and 2016, below the 0.4 million b/d growth in 2014. But does EIA have it right – is China demand growth really slowing? Some real-time demand actually shows growth continuing at a strong pace. Today, we’ll cover some of the agreements coming out of Russia’s “Pivot to the East,” and how these might impact the energy environment; plus, we will also take a look at the conflicting signals regarding Chinese oil demand.

Energy Deals after the Parade

Russian President Vladimir Putin and troops joined China’s parade celebrating the victory over Japan 70 years ago. Vladimir Putin made use of his time in Beijing by meeting with Chinese President Xi Jinping after the celebration. They further enhanced their energy cooperation by initiating many energy agreements.

• Rosneft Signs ChemChina, Sinopec Deal

Russia’s top crude producer, Rosneft, made a general conditions agreement with China Petrochemical Corporation (Sinopec) on developing Western Siberia’s Russkoye field and East Siberia Yurubcheno-Takhomskoye field. Furthermore, Rosneft and China National Chemical Corporation, ChemChina, made a general conditions agreement on the planned purchase of a 30% stake in ChemChina Petrochemical Corporation (CCPC). Finally, a majority stake in Far-East Petrochemical Company (FEPCO) was proposed to be acquired by ChemChina in a memorandum of understanding.

Rosneft said that this deal means the Chinese group of companies has the right to acquire a 49% stake in East Siberian Oil and Gas Company (ESOGC) and Tyumenneftegaz, which hold the exploration licenses for Russkoye and Yurubcheno-Tokhomskoye fields. Because Rosneft, just like other Russian oil and gas companies, is unable to access U.S. and E.U. capital markets and technology, the deal with China will secure finances and technology for those field developments.

The deal on Rosneft’s purchase of a stake in ChemChina’s petrochemical arm CCPC is balanced with a 1.5 million barrels a year supply of Urals crude. A Memorandum of Understanding was signed to supply alternative crudes, such as ESPO or Sokol. The parties are to hold further negotiations for crude to be supplied over a three-year period.

• Novatek to sell Yamal LNG stake

Novatek made an agreement to sell a 9.9% stake in its Yamal LNG project to China’s Silk Road Fund (SFR). If the deal is approved, China’s CNPC will own 29.9% stake, France’s Total still holds a 20% stake, and Novatek’s share will drop to 50.1%. The Yamal LNG project in the Northeast of the Yamal Peninsula is one of the most prospective and competitive LNG projects in the world, according to SRF President Wang Yanzhi. According to Novatek data, the Yamal LNG project may be construction of an LNG plant with capacity of 16.5 million mt/year based on the feedstock resources of the South-Tambeyskoye field. By the end of 2014, the South-Tambeyskoye field contained 926 Bcm in proven and probable natural gas reserves.

• CNPC, Gazprom sign MoU on pipeline gas

Gazprom made a Memorandum of Understanding with CNPC on pipeline gas supplies from Russia’s Far East. This is a new way for Russian gas deliveries to China, the third in two years in row. Gazprom mentioned earlier this week it was proposing a new route of delivering around 15 Bcm/year of gas from Sakhalin in case the Vladivostok LNG project was canceled.

Will There be a Victory in the Market?

There are impending concerns over weakening economic growth in China and its surprise devaluation of its currency, as well as plunging commodity prices. Because all eyes have been on China since it has been an engine of growth for the global economy over the past decade, markets were rattled by signs that growth has slowed more sharply than expected. We originally explored the facts and myths surrounding Chinese petroleum demand in the August 11, 2015 blog, “Ancient Chinese Secret, huh?” As shown in the figure below, petroleum demand in China has been increasing at approximately the same rate since late 2010, with no “flattening” apparent yet. It should be noted that because of month to month variability, it is difficult to look at China petroleum demand on a real-time basis and this is why we plotted semiannual data along with sporadic monthly data. Data through the first half of 2015 (which is the most recent data available) indicates continued and perhaps even accelerating demand. This certainly contrasts with EIA’s recently released pessimistic views in their September Short Term Energy Outlook, which we suspect is based more on “feel” rather than hard data and trends. Others have expressed similar views as we have. Morgan Stanley analyst, Adam Longson of New York, said in an August 24, 2015, research report, “Despite poor headline macro-data, most China oil demand data points remain resilient.” The International Energy Agency posted in their September 11, 2015 Highlights, “We expect China to keep up its crude purchases despite the recent stock market collapse, currency devaluation and steady stream of negative macroeconomic news.” It is certainly very possible and in fact seems logical that petroleum demand in China could follow the negative trends that recent economic-growth indicators and stock market performance have shown in China and that EIA expects to materialize. However, actual demand data appears to be hanging tough and we wouldn’t discount the “Not So Sleepy Giant” yet.

As the Chinese economy and energy markets enter into what could be an important “transition period”, Turner, Mason & Company actually views the last several years as a transition period for the entire global market, one seeking a new equilibrium with regards to supply, demand and commodity prices. We analyze this developing equilibrium and the factors which will determine the outcome in a new study, The Evolving New World Order: Rebalancing Global Oil Supply in the Next Decade.  Turner, Mason & Company has collaborated with Schlumberger Business Consulting (SBC) on this report which seeks to provide an integrated perspective on liquids starting from upstream production and extending to downstream demand for different qualities of crude with the aim to inform all players in the energy arena as they attempt to make important investment and operating decisions. The prospectus and a subscription form can be found by clicking here and we are available to answer any questions directly by phone or email.

We have also explored these issues in our most recent edition of our biannual Crude and Refined Products Outlook (The 2015 Midyear Outlook). This report evaluates and discusses issues and drivers related to the global refining industry and provides an independent view of mid- to long-term supply and demand balances for both petroleum feedstocks and products. It includes a comprehensive price forecast for key regions around the world, with the goal to help industry participants in evaluating business strategies, capital investments and financial decisions. An Outlook brochure or subscription form can be obtained by clicking here.

We encourage you to log on to the web and watch a video of China’s Victory Day Parade. It was splendid and filled with pomp and circumstance. As the world’s markets continue their adjustments, Turner, Mason & Company keeps a constant watch on developments in all segments of the petroleum industry. For more details about any of our publications, studies or other TM&C services, please visit our website, send us an email or give us a call.

Authors: John Auers and Elizabeth Hilbourn

As in the 1994 song, “When the Wheels Don’t Move” written by Jay Farrar, “Going green a casino catch phrase, Ethanol’s made of smoke and mirrors,” increasing volumes of ethanol need to fit in a system which is not yet ready.  A July 2015 study conducted by NERA economic consulting for the American Petroleum Institute concluded the statutory biofuel mandates in the Renewable Fuel Standard are infeasible to achieve in 2015 and beyond and may harm U.S. consumers.  In 2012, NERA issued its first study of RFS2 and found that if the renewable volume obligation remained at the levels called for in the Energy Independence and Security Act (EISA) of 2007 that RFS2 would likely become infeasible in three to four years (2015 or 2016).  It feels a bit like déjà vu.  The question remains; how did we get to this point, and “who’ll explain it all” if (or when) the wheels stop going round?

In their latest report, NERA compared EPA’s RFS proposal to renewable energy consumption volumes in EIA’s latest energy outlook (see Table 1).  Assumptions were made in order to directly compare the EIA numbers to the EPA numbers.  For example, the cellulosic EIA number is based on cellulosic ethanol consumption; however, to-date only 2% of cellulosic Renewable Identification Numbers (RINs) have been generated from cellulosic ethanol, with the remaining 98% being landfill biogas used in transportation fuel. The bottom line is pretty clear.  The EIA does not expect any significant growth in renewable fuels in the short term; however, the EPA does.  It is a bit ironic that the EPA looks to EIA’s forecast of next year’s gasoline and diesel to set final RFS numbers; however, they do not come full circle by matching renewable fuel volume estimates to mandates.

When the Wheels Don’t Move

Besides looking at future EIA and EPA renewable fuel balances, one can take a close look at the last few years of history (see Table 2).  Starting with the RINs generated, we subtract the RINs retired other than for annual compliance (i.e., invalid RINS, spills, used in an application that is not transportation fuel, heating oil, or jet fuel, etc.).  Also, EIA lists the volume of ethanol and biodiesel exported each year. Subtracting RINs for those exports, the net RINs can be compared to the Renewable Fuel Standard.  Of course, this calculation assumes that renewable fuel exported and reported to EIA match that which is reported to the EPA.  The EPA is now able to keep closer tabs on renewable fuel exports since effective September 17, 2014; the regulation was changed to require a 30-day window for RIN retirement on renewable fuel exports.  Prior to September 17, 2014, RINs were not required to be retired for renewable fuel exports until two months after the end of the year, which followed the same compliance timeframe as obligated parties.

Table 2 shows that each year the net RINs generated and available for retirement is less than the renewable fuel standard.  Of course, one cannot obtain actual year-to-year balances since 2010 is not shown and there are some inherent estimates; however, the table is meant to show rough balances.  A difficulty in looking at year-to-year balances is that 20% of prior year RINs can be carried into subsequent years for compliance.  2012 was the last year which RINs were required to be retired and compliance reports submitted for obligated parties (by February 28, 2013).  Table 2 shows that there were some significant gaps in 2012 and 2013 and Table 1 shows that there will be another significant gap in 2017.  Since 2013 compliance has not yet occurred, 2013 RINs (and 2012 RINs if there any left) can still be traded.   Will 2013 come close to the musical chairs game where the music is stopped and we see who is left without a RIN?  The market is implying this as 2013 RINs are often reported at selling at a premium to 2014 and 2015 RINs.

“Bigger chariots didn’t save Rome”

Compliance for 2013, 2014 and 2015 is not until 2016 (January 31, June 1, and December 1 respectively).  It will be interesting to see how volatile the RIN market will be in 2016 when three years of compliance (2013-2015) are retired with four possible years of RIN data (2012-2015).  Only 2013 renewable fuel volumes have been finalized, while 2014 and 2015 are preliminary.  EPA intends to take final action on the proposal by November 30, 2015, which they hope will return the Agency to the program’s statutory timeline for issuing RFS annual rules.

The public hearing held on June 25, 2015 over the renewable fuel proposals was well attended.  More than 280 people showed up to testify.  Forty-three panels were formed with politicians, companies, organizations and individual citizens; however, the EPA has not indicated any decision based on the hearing.

“Easy money didn’t stay at home “

The renewable fuel standard has struggled since its inception.  RFS1 was from 2007 through the first half of 2010 at which time RFS2 began.  A key difference between RFS1 and RFS2 was that RFS1 only had one renewable fuel standard versus the four different types that exist today.  RFS1 faced problems with managing the RINs, which were paper-generated by the producer using a 38-digit number.

Fraudulent biodiesel producers began to be caught, but not until almost three years into RFS2, and on RFS1 RINs.  There were some variations, but for the most part the “producers” were generating RINs without ever having producing biodiesel.  In fact, suspicion arose with the first fraudulent producer, not because of RINs or biodiesel, but because of the number of fancy cars he was parking in his neighborhood.  So far, there are seven notices of violation (NOV) against biodiesel producers.  The problem with the notices is that they are issued several years after the RINs were generated.  The latest was New Energy Fuels Inc. who was issued a NOV in mid-2015 over 2010 RINs.  On February 22, 2013, Rodney R. Hailey, the owner of Clean Green Fuels, LLC and the first fraudulent producer caught, was sentenced to more than 12 years in prison for selling about $9 million in fraudulent Renewable Fuels Credits.

“They said the iron horse would always roam”

EPA’s solution for the fraudulent activity was a RIN Quality Assurance Program (QAP).  The RIN QAP program started retroactively on January 1, 2013 with A/B RINs, though the proposed regulation was not issued until mid-2013.  On July 18, 2014, the EPA published in the regulations its 2013 & 2014 interim period QAP program (A&B-RINs) and its final QAP program (Q-RINs).  Beginning January 1, 2015, after the interim period was over, the program consisted of a single QAP option, with its associated verified RINs referred to as Q-RINs.  There currently are five registered auditors and numerous registered pathways.  The voluntary quality assurance program’s purpose is to verify the validity of RINs under the RFS program.  In May 2015, the EPA issued a comment request for a RFS2 Voluntary RIN Quality Assurance Plan.  The Plan would be a continuation of the current QAP with an information collection request (ICR) submitted by regulated parties and producers involved in the QAP program.

Conclusion

The future of RINs and of the Renewable Fuel Standard program appears set to come to a head in 2016.  As the 2013, 2014 and 2015 compliance years come due throughout the year, we will watch closely at how RIN markets react, as parties are required to finally balance the books and retire the RINs once and for all.  What the EPA rules for 2015 requirements (tentatively) at the end of November will have yet another impact on the RIN market and total balance.  Moving through 2016 and beyond, will there be enough RINs available to satisfy the required demand, or will there be more capitulation and delays as future decisions on the program are dragged out?  Finally, what other surprises may lay in wait?

As the renewable fuel and energy markets enter into what could be an important “transition period,” Turner, Mason & Company continues to stay abreast of the market landscape.  We are in the business of analyzing downstream markets and assisting all segments of the oil industry in responding to changing market dynamics.  Turner, Mason & Company views the last several years as a transition period for the entire global market, one seeking a new equilibrium with regards to supply, demand and commodity prices.  We have analyzed this developing equilibrium and the factors which will determine the outcome in a new study, The Evolving New World Order: Rebalancing Global Oil Supply in the Next Decade.  In collaboration with Schlumberger Business Consulting (SBC), Turner, Mason & Company seeks to provide an integrated perspective on liquids from upstream production and to downstream demand for different qualities of crude, with the aim to inform all players in the energy arena as they attempt to make important investment and operating decisions.  The prospectus and a subscription form can be found by clicking here, and we are happy to answer any questions by phone or email.

Authors: John Auers, Elizabeth Hilbourn and Ryan Couture

What do diesel fuel and the “Fast and Furious” movie franchise have in common?  The easy answer is Vin Diesel, but there are other similarities as well. The fact is both are high energy, have had ups and downs over the past several years and like the F and F series (despite the impressive box office receipts of Furious 7), diesel may have seen its peak.  For the past several years, diesel has commanded a large premium to gasoline, as demand growth has been strong during a long period of economic recovery and refiners have hit production limits; however, a variety of recent developments, on both the supply and demand side, provide indications that the party might be over (or at least quieting down).  Sluggish global economic growth, a slowdown in oil drilling (which has been an important source of demand in the U.S.), and some headwinds for the future of diesel passenger cars are negatively impacting demand; while at the same time, significant new refinery production capacity is coming on line and increasing supply.  What will this mean for the diesel markets?   Will we be in for an action-packed next several years, or will diesel producers just have to take it a “quarter mile at a time”?  Read further to find out, as in this first of a two-part series we will address the supply side of the equation and cover demand issues next week.

“Life’s Simple, You Make Choices and You Don’t Look Back.” – “The Fast and the Furious”

Life used to be simple for refiners, you did all you could to make as much gasoline as you could and diesel was generally an afterthought.  That all changed over the last several years as strong demand growth for diesel has made it truly the premium product for refiners around the world.  Where in the past diesel sold for a discount versus gasoline, a large premium has developed and incentivized refiners to find ways to maximize production.  Their first efforts were to make modifications to existing equipment, operations and catalyst loadings to shift yields toward diesel and away from gasoline.  As demand has continued to grow, refiners began investing in hydrocrackers, and new refineries and expansions have and are being built with a bias toward diesel, in many cases targeting diesel production levels as high as 50%.  Table 1 and Table 2 below show some of the major world-wide refinery startups and upcoming projects to increase diesel production.

As refiners have adapted and many new projects have come online, diesel supply has steadily increased.  Since 2013, over 800 MBPD of incremental distillate capacity has been added.  Refiners globally are planning to add an additional 1.5 MMBPD of production capacity through 2021, with 460 MBPD of that slated for 2015 alone.  As fears of a slowdown in major growth markets such as China and Brazil solidify, worries are starting to develop that this furious surge of diesel will have nowhere to go. Keep in mind also that total world consumption of diesel is less than 30% of total petroleum demand, compared to the 40 to 50% being churned out by the new projects, and these fears of oversupply become particularly worrisome.

“I live my life a quarter mile at a time.  Nothing else matters.” – “The Fast and the Furious”

There are indications that the world is already awash in diesel.  Distillate inventories have continuously risen since the beginning of 2014 and are at the highest level since 2011.  The chart below shows distillate inventories in Singapore, the U.S. and Europe as posted by Bloomberg.  The shape of the chart below matches the U.S. East Coast distillate fuel inventory chart, but with an upper scale of 70 million barrels (versus 200 million barrels).  Inventories of distillate fuel oil in the U.S. East Coast are higher now than they have been in the previous three years, reaching 59 million barrels on September 18, 2015.  Heating oil, a type of distillate fuel oil, is used as a space-heating or water-heating fuel in about eight million U.S. households, almost all of which are in the Northeast.  In the Northeast, 27% of households use heating oil for space-heating, while nationwide only 6% of households use heating oil, based on data from EIA’s latest Residential Energy Consumption Survey.  The East Coast Region generally holds about 30% to 50% of the U.S.’s distillate fuel inventory.  The distillate inventory typically draws down in winter months and builds up in summer months.

Will inventories continue to build and are diesel markets headed for a serious fall?  What happens to demand will certainly be the most important determinant of that answer.  In the second part of this series, we will explore some of the major demand drivers, the main causes of the recent demand slowdown and what can be expected to happen in the future.   This will include a look at how the supply situation has impacted diesel prices relative to gasoline.  We will also look at the export markets, who are the major exporters of diesel, how much they are exporting and where those exports are going.  Europe has been an important part of the picture and we will explore how diesel became the transportation fuel of choice in Europe and the outlook for its future, particularly in light of the Volkswagen scandal and other developments.  Putting all this together might allow us to determine whether the world-wide expansion of diesel production has been “2 Fast and 2 Furious”?

Diesel is but one part of the overall energy picture, and as we enter into what could be an important “transition period,” Turner, Mason & Company continues to stay abreast of the overall market landscape.  We are in the business of analyzing downstream markets and assisting all segments of the oil industry in responding to changing market dynamics.  Turner, Mason & Company views the last several years as a transition period for the entire global market, one seeking a new equilibrium with regard to supply, demand and commodity prices.  We have analyzed this developing equilibrium and the factors which will determine the outcome in a new study, The Evolving New World Order: Rebalancing Global Oil Supply in the Next Decade.  In collaboration with Schlumberger Business Consulting (SBC), Turner, Mason & Company seeks to provide in this study an integrated perspective on petroleum markets, from upstream production to downstream demand with the aim to inform all players in the energy arena as they attempt to make important investment and operating decisions.  The prospectus and a subscription form can be found by clicking here, and we are happy to answer any questions by phone or email.

Authors: John Auers, Elizabeth Hilbourn and Ryan Couture

In “Oversupplying the Diesel Market, Part 1,” we talked about how strong diesel demand in recent years has driven a shift in the industry toward maximizing diesel production at existing facilities and investing in new diesel capacity.  These developments have taken place not only in the U.S., but around the world and have been driven by a variety of factors (strong economic growth in developing countries, dieselization policies in Europe, etc.).  But recent shifts in demand (and looming oversupply) are beginning to bring this logic (and supply balance) into question.  In the past months, prices at the pump have harkened back to the late 1990s and early 2000s, with diesel prices at or below their gasoline counterpart.  While the overall decline in crude prices has driven all prices down, this fall has helped increase gasoline demand, while economic weakness has kept diesel demand relatively soft.  Last week, we focused on the supply side of the equation.  This week, we will delve into what’s happening with demand, and the important factors to consider regarding future consumption.

“It don’t matter if you win by an inch or a mile, winning is winning.” – “The Fast and the Furious”

Diesel prices sank to unprecedented lows this past summer; well below gasoline prices.  Normally, in the summer when demand shifts toward gasoline, the price ratio drops close to 1.0.  In the winter months, as the demand for heating oil increases, the price ratio runs close to 1.1.  This year, from April through August, diesel prices were extremely low, with July having an unheard of diesel-to-gasoline price ratio of 0.82.  September is showing a diesel price recovery, as gasoline prices have fallen while diesel prices have remained flat.  Will this price relationship hold over the winter months?  Figure 1 shows the wholesale USGC ULSD to gasoline price ratio on a monthly basis.

We know that taxes on diesel remain higher than gasoline throughout the U.S., in part due to the higher federal tax, but also higher state taxes in many places.  If we look at the ratio of diesel to gasoline price at the retail level, using EIA average retail prices from the mid-1990s to present, we see that the ratio since 2005 has seen a notable step change.  Despite the current dip we saw this past summer (falling below 1.0 for the first time since 2009), the ratio still remains higher than when compared to the era from 1995-2005, as seen in Figure 2, below.

On January 1, 2015, Emission Controlled Area (ECA) bunker specifications went to 0.1% sulfur, meaning ships near the coasts needed cleaner burning fuel.  The majority of ECA marine demand was filled by marine gasoil (MGO), which is effectively diesel.  This increase in MGO demand potentially shows up in ULSD price spikes from December 2014 through February 2015 (seen in Figure 1); however, despite growing demand of distillate for marine fuels, over the past several months there has been a noticeable slump in distillate demand.  Why is this?  Has the world-wide expansion of diesel production been “2 Fast 2 Furious”?

“This time it ain’t just about being fast.” – Furious 7

The same demand contraction is happening in Europe and Latin America; the prime destinations for U.S. diesel exports (see Figure 3).  Growing populations in emerging markets are opting for less expensive gasoline cars; while in developed countries, diesel is losing both the environmental and cost advantages over gasoline.  In Europe, U.S. exports face competition from Russian exports; half of Russia’s diesel is typically exported.  Diesel has and will continue to dominate in road freight transportation and other heavy equipment, but there is a rapid shift from diesel to gasoline cars.  Increasingly, governments are fostering the use of smaller electric-hybrid cars that typically use small gasoline engines.

Though Figures 1 and 2 showed a substantial decline in ULSD prices compared to gasoline from March to August in 2015, the EIA data through June shows that there has not been a significant decrease in diesel exports.  Is the world oversupplied with world-wide diesel consumption at approximately 26 MMBPD?

There is an increasing chance the diesel surplus may persist, as the scandal over Volkswagen AG diesel engine emission tests hurts demand growth in the longer term.  The German auto-maker admitted to using bypass software to adjust engine performance when being tested to reduce emissions.  This software was installed on 11 million vehicles across the VW, Audi and Skoda lines throughout Europe, Asia and North America.  While for years, European governments have incentivized diesel vehicles, leading to a large number in the domestic market, there are increasing reasons to rethink those policies – the scandal, the latest of those.  And with VW/Audi dominating the U.S. diesel passenger car market, the scandal threatens to mortally wound its chances of success.  The dieselization of Europe and subsequent potential impacts of this will be the subject of a future blog.

“This is where my jurisdiction ends.” – “Fast and Furious”

China has had record distillate net exports at 2.86 million metric tons through August of 2015 (88 MBPD), according to Platts’ data.  The net export number equates from 3.24 million tons of exports and 0.38 million tons of imports.  The Ministry of Commerce in late August issued the fourth batch of oil product export quotas comprising 8.8 million metric tons of distillate.  This means that export quotas for 5.59 million metric tons of distillate is unused, allowing the companies to increase exports for the rest of the year.  Diesel exports continue to rise amid higher crude oil processing to meet robust gasoline demand.  Crude oil processing in China has increased with recently issued crude import quotas granted to teapot refineries.  Keep in mind that though the China diesel export increase appears to be rather significant, it is still only 10-15% the level of diesel exported from the U.S.  However, it is the same story as in the U.S.; low petroleum prices are driving gasoline demand, but not diesel demand.

“I’ve got nothing but time.”  – “Fast and the Furious Tokyo Drift”

One future saving grace may come in 2020, when the demand for diesel is expected to see another step change as non-ECA area bunker sulfur level is regulated from 3.5% to 0.5% sulfur.  Depending on the outcome of a review to be concluded by 2018 (as to the availability of the required fuel oil), this date could be deferred to January 1, 2025.  Regardless, the European Union Directive 2012/33/EU mandates a maximum fuel sulfur content of 0.5% to be burned in ships in the European Economic Zone in areas outside of ECA’s, beginning in 2020.  Since most global crude oils could make a 3.5% sulfur resid, but not a 0.5% sulfur resid, we expect that much of the bunker market will be filled by diesel.

In order to put the January 1, 2015 ECA marine specification change and January 1, 2025 world marine specification changes in perspective, consider the volumes and the magnitudes.  The ECA marine volume is estimated at 20% or less of the total marine demand.  Also, the ECA marine specification change was from 1.0% to 0.1% sulfur while the world marine specification change will be from 3.5% to 0.5% sulfur.  We estimate that a greater volume of the 0.5% sulfur world marine fuel can be fulfilled by a heavier mix than that of the 0.1% S ECA marine fuel.  Regardless, the world will see an increase in marine distillate demand in 2025 as resid demand plummets.

“One last ride.”  – “Furious 7”

Strong diesel demand in recent years has driven a shift in the industry toward maximizing diesel production at existing facilities, while investing in increased capacity with a focus on diesel production across the globe.  But recent shifts in demand are beginning to bring this logic into question.  As we showed, prices at the pump resemble the late 1990s and early 2000s, with diesel prices at or below their gasoline counterpart.  The decline in relative crude prices has driven all prices down, but this fall in prices has increased gasoline demand while diesel, subject to the whims of the business economy, has remained weak.  Additionally, higher diesel costs in recent years have driven pushes toward alternatives such as hybrid cars and natural gas consumption.  Whether the shift away from resid in marine applications will be enough to buoy the otherwise softening market, or whether demand declines and continued (and possibly increasing) shifts away from diesel will keep prices nearer gasoline parity have yet to be seen.

As energy markets enter into what could be an important “transition period,” Turner, Mason & Company continues to stay abreast of the market landscape.  We are in the business of analyzing downstream markets and assisting all segments of the oil industry in responding to changing market dynamics.  Turner, Mason & Company views the last several years as a transition period for the entire global market, one seeking a new equilibrium with regard to supply, demand and commodity prices.  We have analyzed this developing equilibrium and the factors which will determine the outcome in a new study, The Evolving New World Order: Rebalancing Global Oil Supply in the Next Decade.  In collaboration with Schlumberger Business Consulting (SBC), Turner, Mason & Company seeks to provide an integrated perspective on liquids from upstream production and to downstream demand for different qualities of crude, with the aim to inform all players in the energy arena as they attempt to make important investment and operating decisions.  The prospectus and a subscription form can be found by clicking here, and we are happy to answer any questions via phone or email.

Authors: John Auers, Ryan M. Couture and Mike Leger

The recent death of Yogi Berra at age 90 on September 22 not only marked the passing of a baseball legend, but also one of the most memorable and lovable personalities in sport history. Yogi was known as much or more for his “Yogi-isms” as he was for his 3 MVP’s and 10 World Series titles.  As I read about his funeral (held on September 29), which was attended by a who’s who of the baseball world, I thought about how well the strategy behind one of those Yogi isms worked, despite the flawed logic – “Always go to other people’s funerals, otherwise they won’t come to yours.”  Another Yogi-ism, perhaps his most famous one, came to mind the very next day when the announcement came of the sale of ExxonMobil’s Torrance, CA refinery to PBF Energy.  That action comes hot on the heels of PBF’s June definitive agreement to acquire ExxonMobil’s Chalmette, LA refinery.  Once completed, these transactions will bring PBF’s total refining capacity across its five facilities to nearly 900 MBPD, giving them national scope and moving them into the top ranks of the U.S. refining industry (6^th in total capacity).   This rapid ascension (PBF was only formed in 2008) is eerily similar to a period over two decades ago.  That’s when PBF’s founder, Tom O’Malley, a New Yorker as legendary in the refining industry as Yogi is in baseball, really began the transformation of the business from one dominated by integrated majors to independent operators; or as Yogi would say, “It’s déjà vu all over again.”

“You can observe a lot by just watching.”

Tom O’Malley has certainly been down this road before.  Long involved in the energy business, Mr. O’Malley began his pioneering moves into refinery ownership in the late 1980’s.  Starting with the single 166 MBPD Avon Refinery in Martinez, CA, O’Malley transformed Tosco into one of the country’s largest independent refiners in the U.S. at the time.  O’Malley began his career as a mailroom employee and rapidly advanced with Salomon Brothers and Phibro where he became involved with and ultimately led their oil trading groups.  He eventually founded Argus Investment where he began making trades on his own.  He worked a deal to purchase 26% of Tosco stock in the late 1980s and led the company through an aggressive expansion decade.  His business model was geared around capitalizing on opportunities to pick up refineries that big oil was looking to shed, as they refocused on “core assets.”  Beginning with Exxon’s Bayway refinery in 1992, Tosco acquired seven refineries with total crude processing capacity in excess of one million BPD by 2001.

Figure 1 chronicles O’Malley’s build-up of Tosco. Following the Exxon Bayway acquisition came BP refineries at Ferndale, Washington, Marcus Hook, Pennsylvania, Unocal’s San Francisco and L.A. refineries and Equilon’s Wood River, Illinois refinery.

Evaluating these purchases, one thing was clear, O’Malley was a bargain hunter.  Looking only for distressed assets, the purchase prices on his first six refinery acquisitions averaged approximately 10% of replacement cost, or as I believe he was once quoted, “for 10 cents on the dollar.”  He then purchased BP’s Belle Chase, LA refinery in 2001 at slightly over one-third of the cost to build it at that time.  Taking each facility and turning it around, Tosco became not only viable, but profitable.  Under O’Malley’s leadership, Tosco successfully turned a group of undervalued refineries into a successful refining conglomerate, complete with an extensive retail network of gas stations and convenience stores.  Tosco emerged as the modern independent refiner, and O’Malley as a trend-setter and pioneer in the industry.

 “When you arrive at a fork in the road, take it.”

With over 1.3 MMBPD of refining capacity, and an increasingly profitable outlook, it was time to sell.  Tosco first sold the Avon refinery in 2000 to Ultramar Diamond Shamrock for $725 MM, which we estimated was ~30% of replacement cost at the time.  The next year, Tosco sold the remainder of its assets to Phillips Petroleum for $7.36 billion, which we estimate was between 25-30% of replacement.  At the time, Tosco was the nation’s largest independent refiner.

 “I just want to thank everyone who made this day necessary.”

But the sale of Tosco certainly did not mean that O’Malley was done with refining.  In fact, by 2002, O’Malley was back in, becoming chairman and CEO of Premcor (previously Clark Refining & Marketing).  In short order, he led the company through two refinery acquisitions in Memphis, TN (2003), and Delaware City, DL (2004), before selling one to ConocoPhillips (Hartford, IL, 2003) and the remaining four (Delaware City, Lima, Memphis and Port Arthur, 2004) to Valero.

“It’s so crowded no one goes there anymore.”

O’Malley took a brief hiatus from the U.S. refining industry after the sale of Premcor, leaving the field to others such as Valero, Tesoro, Frontier, Western, Holly and others, who generally followed his game plan of assembling independent refining systems.   But it wasn’t too long before he got back in the fray, forming PBF Energy, together with partners Blackstone and First Reserve, and taking the helm as Executive Chairman.  Beginning in 2010, PBF began buying refineries from Valero and Sunoco, including the Delaware City, DE refinery that was sold to Valero during his time at Premcor and was subsequently shut down in late-2009.  In addition, PBF bought the Paulsboro, NJ refinery from Valero and Toledo, OH refinery from Sunoco, all at fractions of replacement costs.

This year, two more pending acquisitions were announced.  PBF in June announced the deal to purchase the Chalmette Refinery from ExxonMobil and PDVSA.  And last week, the planned purchase of ExxonMobil’s Torrance refinery was announced.  This will bring the PBF system up to five refineries.  The timeline below lays out the order of events.

Looking at these transactions in more detail, it really does seem to be a bit of déjà vu.  Once again, O’Malley is buying refinery assets for approximately 10 cents on the dollar.

“If you ask me anything I don’t know, I’m not going to answer.”

The key to trading is timing.  And O’Malley seems to have a keen sense of timing refinery trades. Figure 3 contains a bar chart showing transactions that took place during each year over the past three decades. The bar for each year reflects the percent of replacement cost paid in all refinery transactions from 1987-2015, weight averaged by year.  The Tosco acquisitions took place in 1992, 1993, 1995, 1997 and 2000 (blue).  Tosco assets were sold in 2000 and 2001 to Equilon (Shell/Texaco) and Phillips, respectively.  Under O’Malley’s leadership, PBF is following a similar trend, with three refinery purchases in 2010 and two in 2015 (in green).

“Even Napoleon had his Watergate.”

As the famous proverb says, nothing ventured, nothing gained.  While O’Malley has had tremendous success in the U.S., not everything he has touched turned to gold.  After his tenure with Premcor, O’Malley joined Petroplus and proceeded to acquire eight refineries throughout Europe over several years, before the company lost their credit line in December 2011.  This ultimately led to bankruptcy filings in January 2012 after defaulting on their bonds.  Today, half of those refineries remain closed, with two still operating under Gunvor and two under Vitol.

“The future ain’t what it used to be.”

So what does the future hold regarding refinery sales and valuations, and can clues be had from comparing O’Malley’s past transactions with his latest moves?  Yogi had it right to a large extent, comparing refinery transactions from decades ago may not be very consistent with what is taking place today.  In recent years, the logistical assets associated with specific facility or company downstream operations have become the target of MLPs bringing high multiples of revenues tied to throughput and limited exposure to refining margins and other commercial risks.  This leaves much less for allocation to the refinery hardware component in the overall transaction.  In several recent transactions, analysts have estimated the refinery hardware was acquired for little or nothing. It should also be noted that refinery transactions in any given year or at a particular time, although an indicator of the general environment for refining is not necessarily representative of the values of the majority of refining assets in the markets served by those that traded.  In many instances, transactions occur involving marginal facilities or as a result of special circumstances which can significantly skew the valuations.   As a result, every refinery transaction and/or valuation is very unique and complex and requires significant analysis to truly understand how it compares with past transactions and what it means for future valuations.

Turner, Mason & Company is continually monitoring global refining markets and analyzing developments which drive the industry.  We have been involved in assisting both buyers and sellers of refining assets in various roles.  We also develop reports and studies which analyze and forecast industry trends.   In our most recent study, we teamed with Schlumberger Business Consulting to develop a comprehensive assessment and forecast of what can be expected in global markets and what those trends will mean for production levels, demand, prices, differentials and other key parameters.  We are pleased to announce the release of this publication, The Evolving New World Order: Rebalancing Oil Supply in the Next Decade.  For more information about this publication or other consulting services TM&C can provide, please visit our website or give us a call.

Authors: Ryan M. Couture and John Auers

A few weeks back we did a two part series discussing recent developments in the diesel market (“Fast and Furious”, Part 1 and Part 2) and how they have impacted the diesel supply/demand balance.  One of the developments we mentioned in those blogs was the recent Volkswagen scandal, which is important enough to warrant its own series of blogs.  As we study the situation, we are reminded of the words of infamous “Wolf of Wall Street” himself, stockbroker Jordan Belfort, “If you give people a good enough ‘why’ they will always figure out the ‘how’.”  Just as that philosophy led to Mr. Belfort’s rise and fall, they also describe the impetus that drove Volkswagen into not only becoming one of the leading diesel automobile manufacturers, but also into the crisis they now face.  The ‘why’ incentives to creating an inexpensive diesel engine that could meet very stringent U.S. emissions standards led to the ‘how’ of an elaborate defeat device that allowed Volkswagen to apparently do what other automakers found economically and technically infeasible.  The resultant admission of such a scheme has sparked a scandal which will stretch on for years in courts around the globe.  VW’s stock price has plummeted, it has become the butt of late night comedians’ monologues, and two of the most respected automotive engineers in the business could face serious criminal charges.  As details continue to unfold, among the latest tidbits of news is the announcement that two movie studios (including Leonardo DiCaprio’s) secured the movie rights to a proposed book on the subject.  It’s certain the prospective movie will focus more on the powerful personalities behind the scandal rather than larger market impacts, possibly using literary license to replicate the outrageous and hilarious behavior we saw portrayed by DiCaprio in his depiction of Belfort.  This has even led to the suggested catchy title for the movie, which we have used for our blog (credit goes to Matt@ShiftCarBlog).  Rather than getting into that, we will focus more on how this event might impact the market for diesel fuel.  It is increasingly apparent that “The German Wolf” may have damaged consumer diesel vehicle confidence and the ultimate diesel vehicle future, the question is by how much?

Coming “Clean”

While “dieselgate” may  have first made international headlines on September 18, 2015, when the U.S. EPA issued a Notice of Violation of the Clean Air Act to Volkswagen AG, the road to this point has been years in the making.  Volkswagen and Audi had appeared as wizards to many in the industry, producing a small diesel engine that was able to meet emissions without requiring the costly selective catalytic reduction systems others required to meet U.S. standards.  GM ex-CEO Bob Lutz said in an interview after the news broke “I kept asking our engineers: ‘What’s wrong with you guys?  VW seems able to do it, are they magicians or something?’  The engineers said they couldn’t answer that question.”  As VW and Audi marketed their “Clean Diesel” mantra, they won over groups of environmentally conscious U.S. (and global) consumers, selling millions worldwide.

As the truth has come out, the reality has gotten increasingly worse for VW.  Facing rejection of approval for their 2016 TDI, VW finally admitted that nearly half a million vehicles in the U.S. and 11 million worldwide contained the “defeat device.”  The “device” was in the form of emissions-cheating software installed in the car that was able to adapt the car’s performance depending on whether it was being tested.  As the story grows, the situation has turned from what was initially viewed as a flagrant violation of U.S. law into a full-fledged international crisis for VW.  Spanning across their brand portfolio (Volkswagen, Audi and Skoda), their admittance has triggered government investigations across much of North America and Europe as well as parts of Asia and South Africa thus far, while triggering a shakeup in the management ranks.

In the wake of the news, the waves have impacted other manufacturers, both directly and indirectly.  In the days after, BMW stock plunged amid news of potential issues with their diesel vehicles.  While the company promptly denied any allegations that such defeat devices were in use, it did not stop the skittish market from pummeling the stock 12%, before ultimately staging a rebound.  Other diesel manufactures such as Mercedes, Fiat Chrysler and Ford came under scrutiny as well, although to date only Volkswagen is under investigation.  While these companies may have done nothing wrong, they will face fallout from “dieselgate.”

Das Auto
For over two decades, Europe has led the world in diesel passenger car use.  What exactly drove this surge in Europe, while it struggled to take off elsewhere?  As moves toward efficiency and concerns about global warming grew in the 1990s, and a focus on CO2 emissions increased, paths diverged on the correct path to combatting the situation.  While Japan focused on hybridization, Europe chose the diesel path, a path that the EU had begun to question prior to the emissions scandal, but which has become a priority since.

When it comes to the U.S., there are several factors which impacted the slow dieselization of the passenger car market.  The first attempt into “consumer” diesel engines in the late 1970s and early 1980s in response to the Oil Crisis by Detroit was a flop.  Diesels became synonymous with noisy, dirty and unreliable.  That consumer memory proved hard to erase, and for a time, domestic diesel passenger cars all but disappeared from the U.S. market.

Europe also experimented with diesel during the same time.  Diesels remained a small, but not insignificant minority in Europe through the 1980s and early 1990s.  European manufacturers became world leaders in small diesel engine design during that time.  As popularity grew and technology advanced, these brands (VW, Audi, Mercedes and BMW) introduced limited diesel options to the U.S. market.  These vehicles were more expensive to both purchase and maintain than their typical gasoline counterparts, and while they offered higher fuel efficiency, the low overall U.S. fuel prices and higher diesel taxes made economics more difficult to justify.  They filled a niche in the market, but never gained the same foothold.

After the Kyoto protocol, as countries looked for ways to reduce CO2 emissions, European governments (with a push of lobbying from European auto manufacturers) embraced diesel vehicles as the solution.  With the technology advancement of preceding years, by the early 1990s, diesel engines had improved dramatically.  Due in large part to advancements in fuel injection, diesel passenger cars became increasingly more efficient than their gasoline counterparts.  Owing to their increased efficiency, they produced less CO2 per mile than gasoline vehicles, just what the legislators were looking for.  Europe was able to increase the number of diesel passenger cars from around 10% in the early 1990s to over 35% in 2013, through a combination of lower taxes on diesel fuel and lower tax and registration fees on diesel passenger vehicles.  Combined with the generally high fuel taxes (and prices) in Europe, this led to incentives to purchase diesel vehicles despite their higher upfront cost.  With the increased volume of sales and revenues, it also enabled European manufacturers to master their craft of diesel small engine production, or so it was thought.

With the increasing focus on environmental consciousness in the recent years, auto manufacturers have touted the benefits that different technologies provide.  European manufacturers have marketed the better fuel economy and longer range of their diesel vehicles to customers willing to pay a premium for what was thought to be both a convenience and reduced environmental footprint.  Some U.S. manufacturers also began to add diesels back into the lineup.  At the same time, Japanese manufacturers marketed hybrid vehicles for much the same reason.  The modern diesel engine finally began to erase the memories of “your grandma’s diesel,” growing market share to 2.9% today.  While nowhere near the numbers in Europe (or hybrids, for that matter) the number of registered diesel cars has climbed by 50% since 2010.

Conclusion

The VW admission will undoubtedly cost the company billions of dollars, but the potential effects reach well beyond VW itself.  After cultivating the belief over several years that diesel cars offered an environmentally conscious alternative to hybrids, that reality might be, at least for VW, it was just smoke and mirrors.  While it is very difficult to predict how governments, the media and ultimately the greater public react to this development, it is certainly not good news for the diesel automotive market and by extension diesel producers.  Does it mean we have seen the beginning of the end for the growth of diesel passenger vehicles, at least in the U.S. and Europe?  How about the rest of the world?  While it is too early and the possibilities are too complex to definitively answer those questions, we will explore the implications and address the potential impacts that they will have on diesel supply/demand balances, prices, and refiner options in the next installment.

As news events unfold, Turner, Mason & Company continues to analyze what they may mean for the industry at large.  We are constantly monitoring how changes in market dynamics can impact all segments of the oil industry.  The changes in demand in regions throughout the world promise to change the landscape of the global refining market, seeking a new equilibrium with regard to supply, demand and commodity prices.  In response to the changes from both a supply and demand side, we have analyzed this developing equilibrium and the factors which will determine the outcome in a new study, The Evolving New World Order: Rebalancing Global Oil Supply in the Next Decade.  In collaboration with Schlumberger Business Consulting, Turner, Mason & Company seeks to provide in this study an integrated perspective on petroleum markets, from upstream production to downstream demand.  The prospectus and a subscription form can be found by clicking here, and we are happy to answer any questions by phone or email.

Authors: Ryan M. Couture and John Auers

It seems as if there are new developments every day in the story of how Volkswagen circumvented U.S. emissions regulations.  In our blog last week, we began our own look at the VW scandal and potential implications, focusing first on the roots of the targeted push toward dieselization in Europe in response to the Kyoto protocol and concerns over global warming.  European governments decided that diesel was to be a key component of the push to reduce carbon intensity and global warming, and European carmakers like Volkswagen went all out to produce better and more efficient diesel engines.  In many ways they were very successful in this pursuit and the diesel engines they developed have many advantages over gasoline engines, even for use in relatively small passenger vehicles.  But they also have some structural limitations and disadvantages, particularly when it comes to meeting certain emissions standards, and this is what led to Volkswagen’s troubles.  In this week’s blog, we will discuss some of these issues; particularly the technical challenges that diesel engines face causing them to be fundamentally worse NOx emitters.  In addition, we will look at some key aspects of emissions regulations, including what hurdles legislators have when developing emissions programs, outline a brief history of other cases of emissions cheating and identify some important differences in the U.S. and EU emissions regulations.  Altogether, this should provide us some clues as to what circumstances inspired the actions that led to the indiscretions perpetrated by the “Wolves of Wolfsburg.”

Diesel and NOx

The modern diesel engine is a true engineering feat, evolving from a dirty, noisy and rough “oil burner” into a modern, refined, quiet and compact package.  By the nature of burning hydrocarbons, all internal combustion engines produce some levels of emissions, in the form carbon monoxide, nitrogen oxide (NOx), particulates (PM), and unburnt hydrocarbons.  Today’s gasoline engines can meet even the strictest emissions regulations through the use of relatively inexpensive and easy to operate conventional catalytic converters.  Engines burning heavier diesel fuel, on the other hand, naturally produce higher quantities of certain pollutants, particularly NOx and PM.  This has to do with the way a diesel engine operates.

Gasoline engines mix fuel before it enters the combustion chamber (with the exception of newer direct injection engines), compress the air and fuel mixture, and use an outside ignition source (spark plug) to ignite the fuel mixture.  The mixture is typically run close to the optimal air/fuel ratio, so there is little excess oxygen.  Diesel engines operate differently, compressing the air and then injecting fuel into the cylinder at the top of the stroke.  The heat generated from the compression of air works to ignite the fuel.  Diesel engines therefore have to run much higher compression ratios and leaner air/fuel mixtures, both of which lead to the production of more NOx and PM.

There are ways to reduce the PM and NOx.  NOx production in diesel engines can be reduced by adjusting the amount of fuel that is burned (as the amount of air cannot be adjusted, it is based on the volume in the cylinder).  But by increasing the amount of fuel, thus consuming more of the available oxygen, performance and fuel economy are impacted.  In addition, by increasing the fuel, you also tend to increase the PM that is produced.  PM emissions are reduced using a form of ceramic catalyzed particulate filter.  These filters are in common use on vehicles today, although their use increases backpressure on the engine and reduces engine efficiency.

The software “defeat device” VW used was able to manipulate the amount of fuel that was burned (as well as selectively using NOx traps in the emissions system), to minimize NOx while being tested, albeit at the expense of fuel economy and engine power.  In order to produce the most efficient diesel engine that meets emissions, manufacturers typically have to use a selective catalytic reduction (SCR) system.  An SCR is a type of catalytic converter, similar to what is used on a gasoline automobile but requires the use of urea (sold as Diesel Exhaust Fluid, or DEF).  The DEF is held in a separate tank and injected into the exhaust before the SCR.  The catalyst is then able to convert the NOx to nitrogen and water.

SCR systems are common on larger diesel engines, but are costly, bulky, and require DEF levels to be monitored by the user.  The DEF (mostly urea) smells very bad, and in addition to the already messier diesel fuel (which doesn’t dry like gasoline if spilled, but leaves an oily residue), tends to be off-putting to most consumers.  The DEF fluid can freeze in cold temperatures (requiring a tank heater) and the SCR systems add a lot of cost to the vehicle, which is harder to recoup in the smaller, cheaper consumer vehicle market.  In addition, like most emissions systems, the additional weight and backpressure does reduce engine efficiency and power.

The U.S. has more stringent standards on NOx emissions than the EU under the Euro 5 regulations.  Euro 6 regulations, which took effect for passenger vehicles in September 2014, help to close that gap, as shown in Table 1.  Because of these fundamental limitations of diesel engines, it is expected that in order to meet emissions in the U.S. without dramatically impacting fuel economy, a selective catalytic reduction system would need to be installed on each vehicle, a complicated and expensive process.  In Europe, where the emissions are not as strict under Euro 5 (which many of these vehicles were sold under), software upgrades may allow for continued operation as-is, albeit with slightly reduced performance or decreased fuel economy.

Testing Inaccuracies

Automotive manufacturers have for years “designed to” the emissions testing, and over the decades, several have been fined for various violations.  In 1973, Chrysler, Ford, GM, Toyota and VW were required to remove ambient temperature sensors which affected emissions at low temperatures.  The companies claimed no wrongdoing, and were handed modest fines.  In 1996, GM was fined $11 million for ECU software that was programmed to disengage emissions controls when not under testing (when the heater or air conditioner was on) since that was not part of the test.  In 1998, both Honda and Ford saw fines, for disabling of misfire monitoring device and for disabling emissions controls during normal highway cruising, respectively.  In addition, several heavy truck manufacturers programed trucks to keep NOx emissions low during testing cycles.

Still, to date, none were as egregious as VWs, or as widespread.  Independent testing of other diesel vehicles in Europe, by a large group of manufacturers, turned up vehicles that in real world driving exceeded the NOx emissions by up to 10x, despite passing the emissions tests.  Moves toward focusing on real-world testing of emissions is in the works, and the VW scandal has only expedited the move.  Only four months before the news broke, the EU’s three largest countries, UK, France and Germany, lobbied to carry over loopholes in car tests from the 1970-era NEDC test to the new World Light Vehicles Test Procedure (WLTP), which was to replace it in 2017.  These loopholes helped to reduce measured emissions, or reduce measured numbers by several percent, in order to give manufacturers extra leeway.  In the aftermath of the VW news, the EU lawmakers have voted for this legislation with no loopholes, showing that there is a shift in mindset.

The U.S. EPA and California Air Resources Board (CARB) have had stricter requirements in place for passenger vehicle emissions.  While the EPA does regulate NOx and particulate emissions more strictly than Europe (as well as regulating carbon monoxide, formaldehyde and various hydrocarbon measurements), it does not directly regulate CO2 emissions.  Instead, the EPA regulates the Corporate Average Fuel Economy (CAFE) standards for individual manufacturers.  The U.S. and Canada, on average, have much larger vehicles, and thus produce more CO2.  California and other states that follow CARB regulations have begun to pass stricter regulations.  This has become a battle in the courts, but as CAFE and CARB regulations tighten down, manufacturers will be forced to build increasingly smaller and more efficient engines.  The ultimate question is: Will consumers, who are accustomed to large SUVs at a time of low fuel prices, want them?

Conclusion

While diesel engines may produce less CO2 than gasoline engines, the fundamentals of diesel engines put them at a disadvantage from an emissions standpoint when it comes to both particulates and NOx.  While it is technically feasible to make such engines compliant with even the most stringent emission standards, it becomes cost-prohibitive versus gasoline and non-hydrocarbon alternatives for small, low-cost passenger vehicles.  Coupled with the push toward more “real world” emission testing schemes that better define the emissions during normal driving, instead of the prescribed tests that automakers have “designed to” for decades, increasing use of hybrid and electric vehicles will come into use.  This will ultimately bring in increased competition and lower prices for consumers across the globe.  We will look next week at what the impact of these higher emissions standards has had on smog and what impacts they will have on diesel demand as it becomes a more difficult fuel to use for passenger vehicles.

Turner, Mason & Company takes into account these market and policy shifts as we look to the challenges the petroleum industry will face in the coming years.  Events such as the VW emissions scandal feed into our long-term forecasting, and our analysis is also applied in our consulting engagements and multi-client studies.  In addition to our Crude and Refined Products Outlook released at the end of August, we recently released a new study, The Evolving New World Order: Rebalancing Global Oil Supply in the Next Decade.  As part of a joint collaboration with Schlumberger Business Consulting, we look at how current and future price environments will affect crude production, trade flows and refining activities on a global basis.  The prospectus and a subscription form can be found by clicking here, and we are happy to answer any questions by phone or email.

Authors: Ryan M. Couture and John Auers

Over the last two weeks, we’ve looked at how the “Wolf” has brought to the forefront the “dieselization” of passenger vehicles and the potential problems with that strategy.  The reported admission by VW of “cheating” on emissions testing for 11 million of their diesel vehicles worldwide has brought into question not only Volkswagen, but the credibility of diesel as a “green” alternative and the emissions testing programs themselves.  The latest report on November 2^nd is the U.S. EPA has expanded their investigation to include the VW 3.0 liter diesel engines for potential violations as well (VW has denied the allegations).  These engines are used in larger cars and SUVs across the VW, Audi and Porsche lines.  The expansion broadens the scandal, potentially impacting an additional 10,000 vehicles in the U.S. and many more worldwide, showing this story is still unfolding.  While the modern diesel engine may produce less CO2 and as a result appear to be greener than gasoline, diesel produces other, potentially more environmentally harmful pollutants.  In this final installment, we will take a look at what some of these unintended consequences have meant, with our focus on Europe since it has moved the farthest along the path of dieselization.  We will also examine what the revelations mean for dieselization and how the potential shift away from diesel passenger vehicles could impact both product markets and balances. Will the “Wolf” be able to blow down a diesel market made out of “sticks or straw,” or is it made out of “bricks” and will be able to withstand the “Big Bad Wolf of Wolfsburg?”

The Diesel Impact

European countries have been struggling to meet their air quality requirements in recent years.  With many major European cities out of compliance, the negative impacts of dieselization can be felt (and often seen).  Diesel engines not only produce more NOx, but also tend to emit substantial amounts of particulate matter.  Both of these are major contributors to smog and the negative health effects it can have.

Paris is a posterchild for the smog that EU cities face.  As Paris has struggled with crippling smog, lawmakers have, for several years, looked for ways to reduce emissions.  Before the scandal in December 2014, France’s PM Manuel Vallis said, “In France, we have long favoured the diesel engine.  This was a mistake, and we will progressively undo that, intelligently and pragmatically.”  At the time, France announced they would introduce plans to raise the diesel tax (2 euro cents/L to start), and institute a 10,000 euro credit for diesel cars that were traded in towards an electric vehicle.

Paris is not alone, however.  The EU has 4000 testing stations across the continent monitoring air quality.  The last full data set from 2013 had areas from many of Europe’s major cities at double the maximum levels considered healthy.  An example is London, with areas downtown at an annual average of 85 µg/m3, or Stuttgart at 89 µg/m3 (the worst in the dataset), versus New York City, at 42 µg/m3.  The maximum safe limit is considered 40 µg/m3.  While diesel cars may produce less CO2 (the original reason for incentivizing diesel use), the unintended consequences of the policy on air quality have been negative.

The Impact on Demand

The ramifications for “dieselgate” on diesel cars, and subsequent diesel demand both in the U.S. and elsewhere, should not be discounted.  While it is clear VW did significant damage to their brand (a bit ironic that in the U.S., Audi’s slogan is, “Truth in Engineering”), the impacts have sent ripples throughout the diesel car industry.  The claims regarding the “clean” diesel engines of today have been thrown into doubt, with the public linking diesel engines with emissions cheating and false environmental assertions.  Just as what happened in the 1970s and early 1980s when GM, through their Oldsmobile diesels, tainted the U.S. market for diesel passenger vehicles for decades, VW’s “dieselgate” threatens to do that again.

The impacts in Europe, because of the scope of diesel usage on the Continent, could be even more substantive than in the U.S.  While diesel passenger vehicles may be a common part of the culture, it is driven, in large part, by government incentives.  Even before the revelations, countries were realizing the impact that diesel vehicles were having, and taking steps to move away from them.  Since the announcement, those plans have been expedited.  France has already taken steps; the aforementioned increase in diesel tax and EV benefits.  In addition, France, the country with perhaps the biggest diesel love affair, announced they would wind back tax benefits over the next five years.  In true political fashion, however, it must be done slowly.  Struggling with unemployment, France is reticent to do it too quickly, for fear of impacting Renault and Peugeot, whose diesel cars account for more than 60% of their total sales.  The results can be seen in road fuel demand for various countries, shown in the figure below.  In the U.S., on the other hand, is the inverse, with about 70% of road fuel sales as gasoline.  The move to electric and hybrid will take place for European automakers, making the landscape more competitive, but the transition will likely be more abrupt and costly than they first anticipated.

From a demand standpoint, it is likely that it marks a tipping point in the shift away from diesel and toward hybrids and electrics for passenger cars.  Despite the impetus, shifts in overall automotive makeup are notoriously slow to take place, with millions of vehicles already on the road.  In the long term, as diesel demand shifts away from passenger cars, demand will increase in the bunker fuel market.  As we discussed in a previous blog, the shift to lower sulfur bunker fuels for ships through 2020-2025 will require increasing amounts of low sulfur diesel fuels to be required.

It is worth noting that the transition from diesel will be in the passenger car market, but not in the larger vehicle segment.  In the EU, the changes in incentives for purchasing diesel cars will gradually be phased out, resulting in consumer shifts toward other vehicles.  Trucks and industrial equipment will continue to use diesel engines.  The cost and size associated with the more advanced emission systems required to meet current emission standards does not pose the same challenge as it does for low cost passenger vehicles.  Alternatively, the power required for trucks, heavy equipment and large ships (in many cases) cannot be easily replaced by other fuels.

In addition to bunker fuel demand, overall petroleum demand has been steadily growing worldwide.  While there have been slowdowns in demand (especially for diesel, which is more closely linked with economic activity), long-term projections show demand on the rise.  Demand for petroleum in the advanced economies (U.S., EU, Japan) have been falling for years, and the shift from diesel cars to what will likely be hybrid cars is expected.  The economies of the developing world, on the other hand, still have room to grow.  The economies of China and India in particular are still in early stages of their auto revolution.  As more people move to higher standards of living, the demand for vehicles, goods and services will increase.  This economic growth will continue to drive increases in diesel demand.

Conclusion

Over the last three blogs, we have taken a detailed look at the Volkswagen emissions cheating scandal and potential implications for the global diesel market.  The effects of “Dieselgate” will impact more than just the costs Volkswagen will have to endure in the form of fines, vehicle recalls and brand impact.  It is entirely possible that as we look back, it will mark a major turning point away from diesel as a fuel for passenger vehicles.   This impact will be felt particularly in Europe where major cities across the Continent are struggling with poor air quality.  Even before the crisis, many politicians on the Continent were beginning to point out the downsides of dieselization, but equipped with the scandal and shift in public opinion, it will make legislation easier to implement.  Hybrid and electric vehicles will begin to displace diesels, although the change will be gradual, as millions of vehicles currently on the road serve out their useful life and are retired.  In the U.S., where diesel vehicles make up a much smaller portion of passenger vehicles, the impacts will be less noticeable, but the potential opportunities for growth have definitely been damaged.  It is important to point out that despite the decline in prospects as a passenger vehicle fuel, diesel will remain an important and growing part of the refined products market.  Its dominance in heavy-duty vehicle applications has yet to be seriously challenged, and as developing economies continue to grow rapidly, consumption in this sector will increase accordingly.  Other applications, including use as a replacement for resid in the bunker fuel market, will also contribute to diesel demand growth.

Turner, Mason & Company continues to analyze how market shifts may impact the industry at large.  We apply this constant analysis to our work, through both independent client studies and our multi-client publications.  In addition to our biannual Crude and Refined Products Outlook, we recently released a new study, The Evolving New World Order: Rebalancing Global Oil Supply in the Next Decade.  In collaboration with Schlumberger Business Consulting, Turner, Mason & Company seeks to provide in this study an integrated perspective on petroleum markets, from upstream production to downstream demand.  The prospectus and a subscription form can be found by clicking here, and we are happy to answer any questions by phone or email.

By: John Auers and Ryan M. Couture

After seven long years, the continuing soap opera around the Keystone XL (KXL) approval process seems to have finally come to an end; or has it?  On Friday morning, citing a “recommendation” from U.S. Secretary of State John Kerry, President Obama formally announced his rejection of the application for the KXL pipeline.  To explain his decision, the President stated that the pipeline would neither lower oil prices nor improve America’s energy security.  The announcement comes on the heels of a flurry of news earlier in the week, first with TransCanada requesting a delay in the State Department permit review until it could finalize plans for the pipeline’s path through Nebraska (the final state needing approval), followed by the subsequent denial of that request.  The rejection by President Obama comes ahead of a major UN climate conference scheduled to begin at the end of this month in Paris, and surprised no one, based on previous comments from the administration.  Stating it would “undercut America’s leadership” on the environment, the denial of a permit for KXL is meant to boost Obama’s legacy and “bonafides” in the war against climate change.  While this move certainly gives the President a soapbox to stand on, the real impact is unlikely to be as earth-shattering as either he or anti-KXL environmentalists had hoped.  What’s more, TransCanada’s decision to essentially withdraw its application certainly put the Administration on the defensive, and makes the rejection seem both reactionary and political.  It also, in our opinion, provides an opportunity to potentially resurrect the project at a more opportune time, depending on 2016 election results and future crude oil supply/demand developments.

“This pipeline would neither be a silver bullet for the economy, as was promised by some, nor the express lane to climate disaster proclaimed by others.” – President Obama

We actually agree with the general substance of the quote above from the President as he made his rejection announcement (although we do see tangible economic plusses in both the short and long term).  Despite this, there is little doubt it was not either the real economic benefits or even the potential environmental risks which played the overriding role in the KXL permit denial, but rather the political agenda of the Obama Administration.  For our part, let’s look beyond the politics and one-upmanship and instead examine the facts.  One of the primary driving forces for the construction of KXL was the rapid growth of crude oil production from Western Canada’s oil sands.  The decline in oil prices over the past year, coupled with a shift of politics in both Alberta and at the national level in Canada, makes the future growth rate of this production less clear.  Already, companies have cut back investment, including Shell’s recent announcement that they were abandoning the Carmen Creek project.  The $2bn write down for Shell is just the latest in a series of setbacks for the oil sands, after Total, Statoil and several other major Canadian companies have halted plans for new projects or expansions within the last year.  This begs the question on whether production growth will continue and as a result, what is the real need for KXL.

Forecasts for Western Canada production varied significantly even before the drop in crude prices.  As they have continued to decline, the forecasts have become even more uncertain.  From current levels of 3.7 MMBPD this year, the Canadian Association of Petroleum Producers (CAPP) had forecast that production would rise to 4.6 MMBPD by 2020 and to 5.6 MMBPD by 2025 in their June 2014 annual publication.  A year later, having seen oil prices drop by over 60%, they have dropped that forecast to 4.4 MMBPD in 2020 (a decrease of 0.2 MMBPD) and 4.8 MMBPD in 2025 (a decrease of 0.8 MMBPD).  TransCanada itself has publicly revealed a more conservative forecast, estimating that production will only grow by 500 MBPD through 2020, about 0.2 MMBPD below the most recent CAPP forecast.  There are more optimistic forecasts; Platts quoted a Bentek Energy forecast in a November 4^th article calling for Western Canadian Production to increase to as much as 5.8 MMBPD by 2025.

We recently completed a study in conjunction with Schlumberger Business Consulting which examined worldwide crude supply and demand fundamentals.  The regional crude production forecasts which were developed in this study (The Evolving New World Order) are based on relative production costs and the crude price necessary to achieve equilibrium between supply and demand on a global basis.  Our forecast for Western Canadian production (which is shown in Figure 1, below) is more conservative than either CAPP or TransCanada, with production only growing by 400 MBPD by 2020 (to 4.1 MMBPD) and 600 MBPD by 2025 (to 4.3 MMBPD).

If You Build it They Will Come (and Crude Will Flow)

All along the assumption (by both proponents and opponents) has been that KXL was necessary to move growing crude production out of Western Canada, and if it wasn’t built, the crude would stay in the ground.  However, in addition to the lower expected growth rate of production due to the change in the price environment, the logistical landscape has changed as well, as the KXL permit process dragged out.  Others, most notably Enbridge, have stepped into the breach, completing projects that have actually provided excess pipeline capacity out of the region, making the need and even utility of KXL in doubt, at least until production growth accelerates again.

Today, nearly 3.5 MMBPD of pipeline capacity exists to move production out of Western Canada.  When you factor in rail capacity, which sits at around 550 MBPD, alongside the 400 MBPD of refining capacity in Alberta, the total is greater than current production levels.  Canadian producers and midstream operators have gotten creative, using a combination of rail and the repurposing existing pipeline infrastructure to move crude to market.  Looking at projections of capacity out of the region, there is ample to satisfy the production rates for the next several years, even if some projects, such as the controversial Energy East, never come to fruition.

The benefit of KXL was not only having a large capacity line, but that it took a more direct route to access Gulf Coast refiners.  Existing pipeline routes go through Wisconsin and down through the Midwest.  KXL drew a near straight line from Edmonton down to Steele City, NE, where it would have linked in with the existing Keystone pipeline.  Along its route, it also passed through Eastern Montana, where it would pick up a portion of Bakken crude oil as well.  Without Keystone, crude is forced to take a longer route through Wisconsin and Illinois, before making its way to Cushing and ultimately the USGC.  While KXL was continually delayed, Enbridge was able to expand capacity through their existing system to move increasing volumes down.  Expansions of the Mainline System (Line 61 and Line 67) increased capacity from 450 MBPD to 800 MBPD from Edmonton into Superior, WI, and by up to 1.2 MMBPD from Superior, WI, to Flanagan, IL.  With the construction of the Flanagan South pipeline running parallel to the existing Spearhead pipeline, an additional 600 MBPD of crude can be moved from Flanagan, IL, to Cushing, OK (a total of 775 MBPD of combined capacity).  While not as direct of a route as KXL, it ultimately gets the crude into Cushing and onto the USGC.

The reversal of Line 9, which is scheduled to be completed in the coming weeks after receiving final regulatory approval this fall, will allow for up to 300 MBPD of crude, including bitumen, to reach the Eastern Canadian refiners.  This will help increase demand; something producers are hoping will help the currently depressed prices for WCS, while allowing for domestic refiners more crude optionality.  The two Quebec refiners, Valero and Suncor, have both anxiously awaited the ability to access oil sands crude.  Valero has invested $200M in their refinery and terminal in anticipation of the pipeline’s ultimate approval.

The denial of KXL does not mean the project will never get built.  While it is certain the project will not see a reversal of fortunes soon, TransCanada has several potential options moving forward.  The most likely is to wait for the outcome of the next U.S. election.  Should a Republican win the election, it is near certain they would have a much easier time getting approval with a second application.  A second, more brazen (and less likely) option, would be to sue the U.S. for violating NAFTA.  A third option would be to work some political solution between the U.S. and Canada, although that may be an increasingly more challenging proposition.  The elections in Canada this year marked a shakeup, which have sent some of the pro-industry candidates packing.  Both in Alberta and Ottawa, elections marked a shift away from the Conservative mindset of ex-PM Stephen Harper.  While the new PM, Justin Trudeau expressed disappointment at the denial of the KXL pipeline permit, it is unlikely this administration will be as critical of the Obama administration as was the last.  Regardless of the path forward, TransCanada still owns the right-of-ways, and maintains the ability to construct pipeline along the routes approved by the individual states.

Conclusion

While the rejection of the KXL permit is certainly a setback for TransCanada, it is hardly a devastating blow to the industry at large, or even the final word on KXL.  The drop in prices over the last year has and will have a far more significant impact on the oil sands, triggering numerous setbacks as companies pull back on plans for new projects or expansions.  The long lead time for oil sands projects mean these setbacks will ultimately delay the need for KXL.   While KXL was being delayed, multiple alternate pipeline options to move oil sands to refining centers have been developed and others are moving forward.  There is little doubt that when oil prices again rise, the oil sands in Canada, some of the most prolific petroleum deposits on earth, will be further developed.  The question remains as to whether the U.S. will ultimately want to allow for Canadian bitumen to be efficiently transported to domestic refiners who are held to some of the highest environmental standards in the world, or see it exported to the growing markets in Asia, where it may not face the same scrutiny.

Turner, Mason & Company is continually monitoring developments in the global petroleum markets and assessing how they will impact the industry.  We utilize this analysis to assist both individual clients and also to develop reports and studies which we provide on a multi-client basis.  In our most recent study, we teamed with Schlumberger Business Consulting to develop a comprehensive assessment and forecast of what can be expected in global markets and what those trends will mean for production levels, demand, prices, differentials and other key parameters.  Earlier in this blog, we referenced the Western Canadian production forecasts from this study, The Evolving New World Order: Rebalancing Oil Supply in the Next Decade.  The study contains significant detail and analysis of crude production and flows for all regions of the world.  For more information about this publication or studies and other consulting services TM&C can provide, please visit our website or give us a call.

By Andy Hill and John Auers

(Spoiler alert!)  Frank Underwood (D-SC) has held high political ambitions for many years.  Using a ruthless political strategy, he ascended into the world’s most powerful office.  Collecting political enemies (both red and blue alike) along the way, he has always been arguably successful in passing his agenda.  To top it off, he did it all with the public only seeing his southern charm.  Real life proponents of removing the restrictions on U.S. crude exports have not been nearly as successful in their quest; however, it’s not a fair comparison.  The fictitious Underwood uses highly manipulative, arguably psychopathic behavior to advance his cause.  The proponents of the export ban removal (most of whom are Republicans) are simply trying to pass a bill which President Obama won’t veto, and are handicapped by a rather disorganized caucus.  Frank may have stated it best for the current crude export climate: “Proximity to power deludes some into thinking they wield it.”  Republicans may have control of both the House and the Senate, and have even gotten buy-in from some oil state Democrats, but they have found that passing landmark legislation on crude export policy still remains out of reach.  In today’s blog we examine some of the recent developments in the policy debate, and also look at the changes that have taken place in the crude supply/demand environment which are impacting the very dynamics behind the desire for policy change.

Evolving Congressional Efforts

The collective effort to pass a bill allowing oil exports has gained plenty of steam over the last year or two as the industry became increasingly worried that crude production gains might be constrained by the four-decade-old policy restricting exports.  With the price crash which began in the second half of 2014, the perceived impact of the existing crude export policy lessened as producers cut budgets and crude production has begun to decline.

Despite this, proponents of policy change have continued to move forward, and even accelerated their efforts to remove the crude export restrictions.  In fact the lower price environment has made it less politically risky for legislators to come out in favor of this controversial position.  But this has not changed the strong opposition that President Obama and most Congressional Democrats have voiced in opposing the changes, supported in most cases by consumer, labor, environmental and certain refining entities.

Sen. Lisa Murkowski (R-AK) was one of the first strong proponents of changing crude export policy; at one point, publishing a white paper on the subject back in mid-2014.  Since then, there has been much discussion and debate, within industry and U.S. politics.  Even foreign countries have gotten involved, as consuming countries in both the EU and Asia have petitioned the U.S. for export policy liberalization, while producing countries express fear increased competition from U.S. exports.  Intensity has stepped up a notch in the last couple months, and the House of Representatives passed a bill in early October to overturn the ban by a vote of 261-159.  Although impressive, this margin still fell 29 votes shy of the 2/3ds majority necessary to override a promised veto by the President, and it does not appear that there is enough support for the 2/3rds majority in the Senate either.

With the House bill having little-to-no chance of becoming law, a last ditch effort was made in early November to attach it to the must-pass Federal Highway Spending Bill.  While some analysts viewed it as a quality opportunity as the bill included provisions favorable to Democrats, the ban repeal amendment was killed on November 5^th, and that probably was the last gasp for this session.  While it appears unlikely that anything will happen during the next session due to election year politics, proponents still hold out hope that some “horse-trading” can be done, as opponents use it for bargaining purposes to force concessions on other policies (i.e., climate change, alternative fuels, etc.).

Other Pathways for Exports

While Obama’s threat of a veto has been enough to block the reality of a major legislative change, the Administration has allowed for some alternate and less comprehensive pathways for exports within the last 24 months.

First, batches of processed condensate were allowed to be exported by the Bureau of Industry and Security (BIS) in mid-2014.  Since then, these exports have increased up to 120 MBPD, with Enterprise, Plains, BHP, Shell and BP all involved.  The rationale given was that lightly processing the condensate changes its designation to an allowable “product” from a restricted “crude.”  Although the volumes were relatively small, the industry gladly welcomed this news as it was seen as the first “crack in the wall” and could lead to more substantive changes.

Although this hasn’t happened yet as detailed earlier, a second pathway has recently been opened in the form of crude swaps with Mexico.  Roughly 12 months after the condensate rulings, it was announced that some U.S. crude oil and condensate could be exchanged for heavy Mexican crude, which is routinely imported in significant volumes to the U.S.  A swap of this type is provided for in current export policy as long as it meets certain criteria and is approved by the BIS through a specified application process. This is a strategic benefit for Mexico, as its refineries are better configured to run the lighter crude, and the country wants to boost gasoline production to meet growing demand, which is facilitated by a lighter crude slate.  The initial approved volume of crude swaps are 75 MBPD, beginning in October, 2015, and continuing for 12 months, at which point the application will have to be revisited.

In addition to these relatively new pathways, export policy has provided for certain preapproved outlets for years.  The most significant of these was exports to Canada, but also included limited volumes of California production, ANS crude using U.S. flagged vessels and some other minor avenues.   Until the last couple of years, these were employed in only very limited situations, primarily some small volumes of cross-border crude going to Canada.  As domestic production boomed, the Canadian outlet became a critical safety valve and has reached levels as high as 500 MBPD over the two years, as shown in Table 1 below:

The Changing Supply/Demand Environment

So what caused the crude export policy debate to become so hot?  In two words, it was the LTO boom (okay, I cheated by using an acronym).  It started just a few short years ago, and caused domestic production to climb ever faster from its trough in 2008.  Initially, with significant volumes of light crude imports, it was simple enough for the growing volumes of LTO to just displace those barrels in refiners’ crude slates, and domestic crude prices retained their traditional premium to international prices, based on import parity.  Eventually, as light crude imports disappeared, accelerating production of LTO began to outstrip refiners’ abilities to readily process those volumes, particularly the lightest barrels.  With no export “relief valve,” and running out of options, producers were forced to discount the crude to incentivize refiners to displace cheaper, lower quality international grades, resulted in an ever widening “domestic discount.”  Although refiners invested in some facilities to process additional volumes of the discounted domestic light crude, it was anticipated that if production continued to grow, the domestic discount would blow out to double digits when all ready homes in domestic or allowable export markets became exhausted.  Thus producers sought export policy changes in anticipation of such an event, which they expected would cause them to have to significantly back down on production.

However, with the drop in crude prices over the past year, the environment has radically changed, as domestic production has fallen and the urgency for crude exports ban relief has gone away.   The world crude market remains oversupplied and prices are anticipated to stay low for some time. The domestic discount has substantially gone away, and in fact LLS has traded above Brent for a significant amount of the time this year.  Waterborne imports have actually increased, and in the near term, even if the ban on crude exports was lifted, we would not anticipate any significant increase in exports or shift in prices.   Figure 2 below shows the roller coaster ride that U.S. crude production has taken, with the last year highlighted in the close-up.

Conclusion

While this issue may not be at the top of any of the political debates over the next 12 months, the removal of the crude export ban will continue to remain an important policy goal for producers.  At the same time opponents will remain adamant in opposing any changes.  At this point it does not appear that major changes will take place during the last part of Obama’s tenure, however, the political landscape after next November’s election could significantly change the dynamic.   If we see a new party in the Oval Office, change could take place in short order, perhaps even before it happens through Congress due to the Executive Branch prerogative allowed within the current law.  In our next blog, we will consider the implications of such a change, by providing a brief summary of our Crude Export Destinations study published in September, which looks at where U.S. light crude would go should export restrictions be relaxed.

Turner, Mason & Company is continually monitoring developments in the global petroleum markets and assessing how they will impact the industry.  We utilize this analysis to assist both individual clients and also to develop reports and studies, which we provide on a multi-client basis.  In our most recent study, we developed a comprehensive assessment and forecast of what can be expected in global markets and what those trends will mean for production levels, demand, prices, differentials and other key parameters.  Earlier in this blog, we referenced the Western Canadian production forecasts from this study, The Evolving New World Order: Rebalancing Oil Supply in the Next Decade.  The study contains significant detail and analysis of crude production and flows for all regions of the world.  For more information about this publication or studies and other consulting services TM&C can provide, please visit our website or give us a call.

By: John Auers

As many of you begin preparations for a week of family get-togethers, turkeys (or turduckens), football, Black Friday craziness, and all the other things associated with the U.S. version of Thanksgiving, we have decided to take a break from industry topics this week to have a blog dedicated to that special day.  While market developments over the past year certainly seem to make it easier for some industry participants (refiners) to give thanks than others (producers), the fact is we all have much to be grateful for.  Despite challenges in many areas, from an uncertain industry environment to a downright scary post-Paris attack world, it is important to remember the blessings that we have received in 2015.

The giving of thanks, whether to each other, or most importantly to the Creator, is a key ingredient in allowing us to weather the challenges that we will always face, whether as individuals, companies, entire industries or nation states. In this light, we, at Turner, Mason & Company want to thank all of you, our clients, subscribers, blog readers and fellow industry mates for the opportunities you have provided us throughout this past year; not only to serve you, but to hopefully inform you.  We wish each of you a relaxing, safe and fulfilling (in more ways than just from the turkey) week and hope this blog provides some context to the original reason we have a National Day of Thanksgiving.

With all the sensory overload that goes into the way Americans have come to celebrate Thanksgiving, it is easy to forget its original purpose.  Between the preparation of the traditional feast, the countless football games (not to mention basketball and hockey), and all the effort required to host/visit with numerous friends and family members, carving out time for reflection and gratitude is often difficult, if not near impossible.  Add to this the new phenomenon of Black Friday sales events (that start on Thanksgiving Day and don’t seem to end for an entire week), along with the all the Christmas preparation we feel obligated to begin as soon as the turkey is cleared away; and by next Monday, we will be exhausted and perhaps not much in the mood for giving thanks (unless of course our team is still in the running for the BCS playoffs).  Thanksgiving wasn’t always this way.  In fact giving thanks, despite tough times, and in a communal way, was the whole purpose of the holiday.

 When thinking about the origins of Thanksgiving, if you are American, the Pilgrims feasting with their Native American neighbors in 1621 in the Plymouth Colony certainly springs to mind.  In reality, while that is thought of as the “First Thanksgiving,” it just followed a tradition that people from many cultures had been practicing throughout the world for untold numbers of years; to give thanks to a Higher Authority for a good harvest.  It wasn’t even the First Thanksgiving held by Europeans in the New World, as Canadians can trace the origins of their Thanksgiving to a ceremony held in 1578.  And while the Plymouth feast did lead to regular “Thanksgiving” celebrations in the fall, first in American colonies and later the United States, it took over 200 years before Thanksgiving Day was made into a national holiday with a specified scheduled date in late November.

Abraham Lincoln’s Thanksgiving Proclamation

The year was 1863 and the U.S. was in the middle of the bloodiest war in her relatively short history.  The country was split; the war showed no end in sight and the whole concept of a “United States” was seriously in question.  But out of these dark days came a proclamation which set the precedent for America’s first true national day of Thanksgiving. During his administration, President Lincoln issued many orders similar to this. For example, on November 28, 1861, he ordered government departments closed for a local day of thanksgiving, but it was not until two years later that a permanent holiday was established.

Sarah Josepha Hale, a 74-year-old magazine editor, wrote a letter to Lincoln on September 28, 1863, urging him to have the “day of our annual Thanksgiving made a National and fixed Union Festival.” She explained, “You may have observed that, for some years past, there has been an increasing interest felt in our land to have the Thanksgiving held on the same day, in all the States; it now needs National recognition and authoritative fixation, only, to become permanently, an American custom and institution.”

Prior to this, each state scheduled its own Thanksgiving holiday at different times, mainly in New England and other Northern states. President Lincoln responded to Mrs. Hale’s request immediately, unlike several of his predecessors, who ignored her petitions altogether. In her letter to Lincoln, she mentioned that she had been advocating a national Thanksgiving date for 15 years as the editor of Godey’s Lady’s Book. George Washington was the first president to proclaim a day of thanksgiving, issuing his request on October 3, 1789, exactly 74 years before Lincoln’s.

The document below sets apart the last Thursday of November “as a day of Thanksgiving and Praise.” According to an April 1, 1864, letter from John Nicolay, one of President Lincoln’s secretaries, this document was written by Secretary of State William Seward, and the original was in his handwriting. On October 3, 1863, fellow Cabinet member Gideon Welles recorded in his diary how he complimented Seward on his work. A year later the manuscript was sold to benefit Union troops.

Washington, D. C.

October 3, 1863

 By the President of the United States of America

A Proclamation

The year that is drawing towards its close, has been filled with the blessings of fruitful fields and healthful skies. To these bounties, which are so constantly enjoyed that we are prone to forget the source from which they come, others have been added, which are of so extraordinary a nature, that they cannot fail to penetrate and soften even the heart which is habitually insensible to the ever watchful providence of Almighty God. In the midst of a civil war of unequaled magnitude and severity, which has sometimes seemed to foreign States to invite and to provoke their aggression, peace has been preserved with all nations, order has been maintained, the laws have been respected and obeyed, and harmony has prevailed everywhere except in the theatre of military conflict; while that theatre has been greatly contracted by the advancing armies and navies of the Union. Needful diversions of wealth and of strength from the fields of peaceful industry to the national defense have not arrested the plough, the shuttle or the ship; the axe has enlarged the borders of our settlements, and the mines, as well of iron and coal as of the precious metals, have yielded even more abundantly than heretofore. Population has steadily increased, notwithstanding the waste that has been made in the camp, the siege and the battle-field; and the country, rejoicing in the consciousness of augmented strength and vigor, is permitted to expect continuance of years with large increase of freedom. No human counsel hath devised nor hath any mortal hand worked out these great things. They are the gracious gifts of the Most High God, who, while dealing with us in anger for our sins, hath nevertheless remembered mercy. It has seemed to me fit and proper that they should be solemnly, reverently and gratefully acknowledged as with one heart and one voice by the whole American People. I do therefore invite my fellow citizens in every part of the United States, and also those who are at sea and those who are sojourning in foreign lands, to set apart and observe the last Thursday of November next, as a day of Thanksgiving and Praise to our beneficent Father who dwelleth in the Heavens. And I recommend to them that while offering up the ascriptions justly due to Him for such singular deliverances and blessings, they do also, with humble penitence for our national perverseness and disobedience, commend to His tender care all those who have become widows, orphans, mourners or sufferers in the lamentable civil strife in which we are unavoidably engaged, and fervently implore the interposition of the Almighty Hand to heal the wounds of the nation and to restore it as soon as may be consistent with the Divine purposes to the full enjoyment of peace, harmony, tranquility and Union.

In testimony whereof, I have hereunto set my hand and caused the Seal of the United States to be affixed.

Done at the City of Washington, this Third day of October, in the year of our Lord one thousand eight hundred and sixty-three, and of the Independence of the Unites States the Eighty-eighth.

By the President: Abraham Lincoln

Next week we will resume our discussion of industry issues with the 2^nd part of our series on the U.S. crude export issue as we analyze where those exports might go if federal restrictions were removed.  Until then, please remember and give thanks for all your blessings, without regards to how the turkey tastes, whether your team made the right play call on 3^rd down or whether you were able to snag that last “super discounted” HDTV on Black Friday.

By: Ryan M. Couture and John Auers

In our blog two weeks ago (Nov. 17^th – House of Cards), we discussed the changing political landscape that surrounds the crude export debate.  While recent developments in Washington make it very unlikely that there will be any changes to the current policy banning crude oil exports (with a few specified exceptions) during the current legislative session, this debate will not go away.  The fact remains that the Light Tight Oil (LTO) boom has drastically changed the market dynamics which led to the current policy in the first place, which does require a reexamination of that policy.  Although the recent sharp drop in crude prices and decline in domestic production has decreased the imminent need to find foreign markets for U.S. LTO exports, that has not changed longer term supply/demand forecasts, which still expect that those outlets might be necessary, depending on an the level of future production growth and other key factors.  In today’s blog we won’t get into the prospects for policy change or even the implications or economic impacts associated with the policy.  Rather, we will attempt to answer the question of where U.S. crude imports would go if, indeed, all restrictions were removed.

There have been a number of studies released over the last couple of years which discuss the impacts of a change in crude export policy.  These studies, which have been sponsored by both proponents and opponents of export liberalization, have assessed the impacts on crude production, both crude and gasoline prices, overall economic growth, jobs and a variety of other economic factors and indicators.    What these studies have not addressed in any quantifiable manner has been where crude exports would go if restrictions were removed.   This has not stopped advocates or politicians of one side or another of making speculative claims on this subject, generally to support their positions.  Opponents of policy change have often claimed that U.S. crude would end up going to China, a geopolitical and economic rival, supporting their claims by China’s supposedly unquenchable thirst for crude oil.    Instead of speculating, and to fill the void that previous studies have left on this subject, Turner, Mason & Company has recently performed a detailed quantitative evaluation to answer the question of on what destinations U.S. crude exports would likely end up if allowed, and published the results in a “White Paper.”

Slow Boat to…

Because of the quality of LTO and the appetite of U.S. refineries for heavier grades of crude, our analysis focused on exports of light crude, which would be the type of crude most likely to be in surplus in a production growth scenario.  The rise in light crude production in the continental U.S. in recent years had brought total U.S. production above 9.5 MMBPD by mid-2015, an increase of over 90% from the low in 2008.  While low prices have taken their toll and domestic crude production has begun to decline over the last few months, it remains above 9.0 MMBPD.  As production grew, it created a mismatch, which at times severely depressed domestic crude prices relative to international benchmarks.  The ability to export some light crude and in turn import additional heavy barrels, taking advantage of the higher values that light crudes yield on the market, is the impetus for the relaxation of crude export restrictions.

Based on the analysis of our report, we conclude that a majority of crude exported from the continental U.S. into an open market environment would stay in the Atlantic Basin.  The crude would flow to refineries in Europe and Latin America.   The primary factors driving U.S. exports into these markets revolve around compatibility with existing refinery configurations and replacement or alternative cost economics.

For the analyzed Atlantic Basin destinations, U.S. light crudes “fit” existing refinery configurations and are both cheaper and more efficient to transport to those markets than to markets farther away (primarily Asia).  U.S. crudes make a good replacement for declining or stagnating production of similar types of regionally produced crudes in the North Sea, Africa and Latin America.  Noneconomic factors, including geopolitical concerns, were also considered in our analysis and provide further support to our conclusions.  The reality is, all the crude isn’t going to take “a slow boat to China.”

Across the Pond

U.S. LTO is the primary source of U.S. incremental crude production.  U.S. refineries, after decades of investment, are better equipped to process heavier crudes than other worldwide refining centers.  Because of this, any crude exports would be predominantly LTO.  Refining centers in both Europe and Latin America are generally simpler facilities, designed to process lighter grades of crude.  U.S. LTO “fits” well into those facilities.  The limited U.S. exports today, to Canada (and most recently, Mexico), highlights this.  Exports of U.S. LTO to these destinations is efficiently and economically displacing other less economic supply options.

While a region’s ability to process the crude is a critical factor, transportation costs also play an important role in determining the destinations.  Due to the location of the largest LTO basins and existing pipeline infrastructure in place, U.S. LTO exports will almost exclusively come out of U.S. Gulf Coast ports.  From the USGC, transportation costs to European and Latin American destinations vary from $1-3+/bbl.  This is much lower than the $5-7/bbl to access the key Asian refining centers.

In addition to the cost, time also plays a role in determining where crude may end up.  Crude in transit represents inventory that cannot be accessed, and longer delays can mean less flexibility for refiners.  Transit time is much shorter, with most deliveries in under 20 days (and for areas in the Caribbean, only a few days), versus 30+ days to Asia.  The “swing” producers in the Middle East have similar transportation advantages when selling to Asia as U.S. refiners do when selling to the Atlantic Basin, making it logical that Asia will continue to import crude from the Middle East.

Production Factors

Production from existing suppliers of light crude to the Atlantic Basin has been in decline in recent years.  For Europe, North Sea production has been a key source of light, sweet crude supply for European and other Atlantic Basin refiners.  Unfortunately, production has declined by more than 50% since 2000, at less than 3 MMBPD today.  African production, another key source for European imports, has seen a decline of nearly 2 MMBPD since 2008.  Major disruptions in Libya, coupled with declines in Algeria, Angola, Nigeria and Sudan/South Sudan have all contributed to the decline.

The decline in global crude prices can be expected to continue impacting supply.  Costly deepwater African production will likely see deferrals or possible cancellation until the market improves.  In Latin America, the decline in crude prices has also impacted projects.  While overall production in Latin America has continued to rise in recent years, the production of light crude has generally declined, while their refining infrastructure remains dependent on volumes of light crude to maximize efficient operation.

What, Where and How

Comparing the quality and sources of crudes from various locations into Europe and Latin America by country and refining region, our analysis showed that as much as 1.7 MMBPD of U.S. crude exports would most profitably go to Europe and Latin America.  Northeast Europe, the largest of the European refining regions, could absorb an estimated 1+ MMBPD of crude.  Latin America has room for about 400 MBPD, while Mediterranean and Eastern European regions could process an additional 200+ MBPD.  While the analysis does not mean all exports would go to these markets, the analysis shows these markets are economically advantaged versus alternate destinations.

When comparing those volumes to U.S. production forecasts, we do not see exports climbing to the 1.7 MMBPD level.  Based on aggressive production forecasts we had in mid-2014 (before the price collapse), we forecast maximum U.S. production at 11.7 MMBPD in 2020.  The result was <1 MMBPD of U.S. Lower 48 exports (ex. Canada) in 2020.  Given the current price scenario, current forecasts are well below this.

Other Factors

In addition to crude matches and logistical drivers, there are a variety of other factors that further support U.S. crude movements into the Atlantic Basin.  Geopolitical factors are important, especially the evolving and continuing tensions between NATO and Russia, which is the largest current supplier to NATO and other European countries.  U.S. crude exports can serve as a critical alternate supply source, helping to offset some Russian barrels, thereby limiting their ability to pressure our allies.  Currently, total Russian crude imports to Europe are over 3 MMBPD, nearly 1/3 of total crude imports to the region.  A majority of these Russian barrels are light and could be replaced by U.S. LTO.

Potential U.S. crude exports are also a more secure source of supply to Europe than many other major suppliers.  With conflict in Africa and the Middle East, disruptions to crude flow are common.  Libya, Iraq, Nigeria and other producers have experienced sudden and prolonged outages due to local and regional conflicts.  The U.S., on the other hand, is stable, with transparent markets and reliable supplies.

Israel could also benefit from U.S. access to crude.  Since many Middle Eastern producers refuse to provide crude to Israel (with the exception of semi-autonomous Iraqi Kurdistan), U.S. LTO could play a part in supplying Israel’s 250 MBPD of crude imports.

Conclusion

The fear of U.S. crude sailing to Asia in the event of crude export liberalization is largely unfounded.  While it is possible (and probable) that some cargoes will make their way there, a vast majority would work to supply Atlantic Basin refiners.  China has become the world’s largest crude importer, but is also a major economic competitor to the U.S.  The likelihood of China wanting to become even more dependent on the U.S. is unlikely.  U.S. exports would only serve to strengthen the U.S. presence in the Atlantic Basin, providing stability to our allies while allowing U.S. oil markets to reach a new equilibrium.  For a more detailed assessment, read our report U.S. Light Crude Oil Exports: Likely Destinations which can be found on our website.

Turner, Mason & Company is continually monitoring the global refining industry, to see how upstream developments may impact current and future trends and flows.  We utilize this knowledge to assist both individual clients on specific projects as well as publish reports and studies which we provide on a multi-client basis.  Our Outlook products take a look at crude and refined products developments over the next decade, while conducting an analysis of individual relevant industry topics.  In addition, we recently developed a comprehensive assessment and forecast of what can be expected in global crude markets and what those trends will mean for production levels, demand, prices, differentials and other key parameters.  The Evolving New World Order: Rebalancing Oil Supply in the Next Decade contains significant detail and analysis of crude production and flows for all regions of the world.  For more information about this publication or studies and other consulting services TM&C can provide, please visit our website or give us a call.

By: Tom Hogan and John Auers

For all of the folks waiting with bated breath for the renewable fuel standards that were supposed to be set one to two years ago, they have arrived!  While they are not earth- shattering, they have been seen by both the petroleum industry and the renewable fuel producers as significantly less than optimum.  This sounds like a bit of deja-vu all over again.  What does this final rule mean for refiners?  Read on to find out.

The final rule was announced by the EPA on the afternoon of November 30, 2015, the last possible day allowed by the consent decree requiring the EPA to set the standards.  The final rule generally followed the pattern set in the proposed rule with total renewable fuel increasing 0.35, 0.63 and 0.71 billion gallons in 2014, 2015 and 2016, respectively.  These are relatively small changes from the June 10, 2015 proposed levels which portend a potentially large problem.  Some important points are listed below:

1. The 2014 and 2015 obligations appear to be set higher than the actual/projected RINs available. The only way to meet these shortfalls is to reduce the RIN inventory;
2. The 2016 obligation appears to be set at a level where gasoline would need to contain on the order of 10.8 volume percent ethanol. The only way to achieve those levels would be to increase E15 or E85 sales;
3. The 2016 problem could also be solved by higher biodiesel/renewable diesel usage; however, it seems unlikely that higher volumes of diesel alternatives could be manufactured on such short notice;
4. The prior year, RIN carryover from 2013 appears to be about 3.3 billion RIN-gallons; and
5. Assuming the 2014, 2015 and 2016 shortfalls are all met by drawing down RIN inventory, the balance is shown in the table below:

The 2016 inventory draw is similar to what was expected in 2014 and which resulted in the two-year delay in setting an RVO.  It also resulted in very high RIN prices which were only alleviated when the EPA suggested that they were going to recognize the ethanol blendwall and reduce the obligation.

Since 2016 is upon us, it is unlikely that the E15 and E85 markets, or the amount of other biofuel volumes blended, can be increased enough to eliminate the inventory drawdown.  It is likely that RIN prices will increase significantly in 2016, which could again precipitate action by the EPA to modify the program.

Refiners must choose between purchasing RINs today to assure a maximum RIN carryover from year-to-year in anticipation that these RINs will be cheaper than buying future RINs, or delaying purchase of more expensive RINs on the hope the EPA will again intervene if the RIN prices become more expensive than the EPA desires.  The refiner’s risk is either high-cost RINs that lose their value if EPA modifies the program, or even higher-cost RINs if the refiner does not prepurchase RINs and the program stays as currently promulgated.

The Obligation

The final renewable volumes are generally significantly less than the volumes in the legislation as shown below:

The actual cellulosic requirement is the primary change from the Clean Air Act obligation.  Cellulosic biofuel cannot currently be produced in large volumes economically.  The reduction in the cellulosic biofuel obligation rippled through the other categories because the obligations are “stacked.”  That is, the cellulosic biofuel and the biomass-based diesel are included in the advanced biofuel and the advanced is included in the renewable fuel.  The shortfall of cellulosic biofuel has been recognized in the program from the outset and the obligations have been set accordingly.  What is different in the final rule is that in the early years of the program, when the cellulosic availability did not meet the Clean Air Act volume, the EPA did not reduce the advanced or renewable volumes to reflect the lower cellulosic obligation.  The petroleum industry challenged this interpretation in court and the EPA’s interpretation prevailed.  The 2016 obligation is the first prospective obligation that has been set less than the Clean Air Act obligations.

Although the EPA sets a target volume, the regulatory requirement is translated into a percentage and the percentage requirements become the actual standards for the regulated parties.  Therefore, if the actual volumes of gasoline and diesel produced or imported are greater or less than the gasoline and diesel assumed by the EPA in setting the percentages, the volume of renewable fuel added to the transportation pool will be more or less than the volumes shown above.

After three tables, that is a lot of numbers.  What do they all mean?

How to Comply

The first question is how to comply.  For 2014 and 2015, the answer is essentially set since all but one month of activity is complete.  Compliance for 2014 and 2015 will be made through retiring RINs generated in the two years, plus RINs from 2013 that can be used for up to 20% of the 2014 obligation.  RINs generated from the production or importation of renewable fuel in 2014 and 2015 are shown below.

The shortfalls in 2014 and 2015 are about 0.31 and 0.53 billion RIN-gallons, respectively.  This shortfall could be made up by using prior year RINs.  The program allows up to 20% of the current year obligation to be met with prior year RINs.  Typically, there have been enough RINs unused in any given year to satisfy 20% of the next year’s obligation.  RINs can only be carried over for one year and therefore if enough RINs are not generated in a specific year, prior year RINs can make up the deficit, but there will be less than 20% of the next year’s obligation carried over.  Therefore, if the shortfalls in 2014 and 2015 are made up by prior year RINs, the carryover into 2016 will depend on the 2013 through 2015 RIN carryover.  The RIN carryover is described below:

2013 carryover into 2014 = 2013 obligation X 20% or about 3.31 billion RINs (16.55 X 0.20)

The 2014 obligation that can be met by 2013 RINs is 3.31 billion gallons.  Since the 2014 obligation is 16.28, the total 2014 available to carryover to 2015 is about 3 billion gallons (3.31-(16.28-15.97)).

The 2015 obligation that can be met by 2014 RINs is 3 billion gallons.  Since the 2015 obligation is 16.93, the total 2015 available to carryover to 2016 is about 2.47 billion gallons (3-(16.93-16.40)) which is only about 13.6% of the 2016 obligation.

Once the RIN inventory is used up, the renewable fuel obligation will need to be met by current RIN generation.

What Happens to RIN Prices?

At the beginning of the renewable fuel program, RIN pricing began with an abundant surplus of RINs and very low RIN prices of a few cents per RIN-gallon.  RIN prices spiked in early 2013 when people realized that if the program were not modified, it would be very difficult to obtain enough RINs to meet the demand.  The RIN prices eased when the EPA indicated that at least for then, it recognized the gasoline blend wall and intended to reduce the obligations.

The final rule is likely to push RIN prices higher as the RIN inventory decreases.  Neither the 2014, 2015 nor the 2016 obligations are likely to leave the petroleum industry with an insolvable obligation since the RIN inventory can cover any shortfall; however, without knowing what the obligation might be for 2017 and beyond, the industry is likely to assume the worst and RIN prices could again increase.  Indeed, the ethanol RIN market price increased by a little less than 100% on the first two days after the final rule was announced.

Conclusions

The renewable fuel obligations set by the final rule are not likely to disrupt transportation fuels in the United States.  It is likely that the price of RINs will increase, but they are not likely to skyrocket in the near future.  It appears that some of the obligation will need to be met by reducing the prior year RIN inventory.  If the prior year RIN inventory falls significantly, it is likely we will see RIN prices as high as, or higher than, those seen in early 2013, over $1.00 per RIN gallon.

Politics will continue to be a consideration in the renewable fuel program.  The final rule for 2017 does not need to be set until November 2017, after the presidential elections.  As a result, it is unlikely that the administration will allow the program to significantly impact the supply or pricing of transportation fuels before the election.

A section on regulatory initiatives will be included in our 2016 Crude and Refined Products Outlook, scheduled to be issued in early February.  Also included in this report will be detailed forecasts of supply, demand and prices for refined products, both in the U.S. and throughout the world.  The impacts alternate fuels have on the refined products markets will be incorporated into the forecasts.  We also use this analysis, which we update on a regular basis in our other industry studies and work products.  For more details about any of our publications, studies or other TM&C services, please visit our website, send us an email or give us a call.

By John Auers and Elizabeth Hilbourn

“This is the song that never ends, it goes on and on my friends, some people started singing it, not knowing what it was, and they continued singing it forever just because this is the song that never ends, it goes on and on my friends…”

By now, you know that you are reading what is known in children’s songs, computer programming, and the push of cellulosic biofuel as the Infinite Loop.  This is a song, program or push which loops endlessly, either due to the loop having no terminating condition, having one that can never be met, or one that causes the loop to start over.  Cellulosic ethanol has been pushed for years, particularly since the start of RFS2 in 2010, and yet there are essentially just drops of it in the market in comparison to other renewable fuels.  Like the song that never ends, cellulosic ethanol is given government money, tested on a bench-scale basis, pushed annually in the renewable fuel standards, then given more government money, tested on a larger pilot plant basis, and on and on in the Infinite Loop.  Even with large government subsidies, it never seems to become economical enough for significant commercial plants to be constructed.  Last week, we discussed EPA’s November 30, 2015 announcement of the 2014-2016 renewable fuel standards.  The aggressive standards made quite a stir in the market, with RIN prices increasing by 15% and 60% for biodiesel and ethanol, respectively.  2014 and 2015 obligations appear to be set higher than the actual/projected RINs available; and, therefore, should reduce RIN carryover levels.  The 2016 obligation appears to be set at a level where gasoline would need to contain approximately 10.8 volume percent ethanol. It seems fitting that we should continue discussing renewable fuel standards, and in particular, the category anticipated to grow the most, cellulosic biofuel.

The EPA believes that the RFS program can and will drive renewable fuel use, and as an important subset, cellulosic biofuel use.  Numerous cellulosic ethanol bench scale, pilot, and demonstration plants have been built in the U.S.  Some of the pilot and demonstration facilities are listed below.  Commercial plants have just begun entering the scene beginning in 2013, with the latest 2015 startup being known as the largest in the world, the Dupont Nevada, Iowa cellulosic ethanol plant.  Just as numerous and significant as the existing plants, are the ones who have closed or bailed.  Even the December 7, 2015 issue of Ethanol Week announced Abengoa layoffs at its Hugoton, KS cellulosic ethanol plant. Valero’s exit in 2013 and BP’s exit in 2014 has been noted.

The figure below shows the cellulosic RINs produced to date.  There are two categories of cellulosic RINs, cellulosic biofuel with a D3 RIN and cellulosic diesel with a D7 RIN.  Cellulosic diesel is made with the Fischer-Tropsch process.  Diesel fuel produced from cellulosic feedstocks that meets the 60% GHG threshold could qualify as either cellulosic biofuel or biomass-based diesel, and an obligated party is allowed the flexibility to apply a RIN with a D code of 7 to either their cellulosic biofuel renewable volume obligation (RVO) or their biomass- based diesel RVO.  Cellulosic RINs have topped 100 million gallons in 2015 and have grown substantially since 2013 when less than 1 million gallons were generated.  In 2014, the EPA also determined that compressed natural gas (CNG) and liquefied natural gas (LNG) produced from biogas from landfills, municipal waste-water treatment facility digesters, agricultural digesters, and separated municipal solid waste (MSW) digesters were eligible to generate cellulosic RINs. This determination led to a significant increase in cellulosic RIN generation beginning in late 2014, as fuel that previously had been qualified to generate advanced biofuel RINs could now generate cellulosic RINs.  Consequently, less than 2% of cellulosic RINs to date have been produced from ethanol as shown by the green bar in the chart below.

Cellulosic Waiver Credits

In 2015, EPA clarified which data sources will be used in the cellulosic waiver credit (CWC) price calculation.  The price of a CWC is determined using a formula specified in the Clean Air Act (CAA). The cellulosic waiver credit price is the greater of $0.25 or $3.00 minus the wholesale price of gasoline, where both the $0.25 and $3.00 are adjusted for inflation.  The table below lists all the cellulosic waiver prices to date. One important point in comparing cellulosic waiver credit prices to cellulosic RIN prices is the nesting of cellulosic RINs.  Any renewable fuel that meets the requirement for cellulosic biofuel or biomass-based diesel is also valid for meeting the advanced biofuel requirement; however, a cellulosic waiver credit cannot be applied to an advanced biofuel requirement.  So, essentially, when market-driven and when both cellulosic waiver credit and cellulosic RINs are made available, a cellulosic RIN should equal the price of a cellulosic waiver credit plus the price of an advanced biofuel credit.

Cellulosic biofuels are required to have 60 percent or greater greenhouse gas (GHG) emission benefits on a lifecycle basis than the petroleum-based fuels they replace.  The cellulosic biofuel industry continues to transition from research and development (R&D) and pilot scale operations to commercial scale facilities.  RIN generation from the first U.S. commercial scale cellulosic biofuel facility began in March 2013.    As shown in the table below, the EPA hoped that almost one-half of the renewable fuel requirements by 2022 be met by cellulosic biofuel, or more specifically, 16 of the total 36 billion gallons.  Again, this requirement is significantly different than both the 2014-2016 final rulemaking and the cellulosic RINs generated to date.  Also, the 230 million gallon cellulosic requirement in 2016 appears small in comparison to the statuary levels, but it is over twice the volume that has been produced in a year’s time.

Why is it so difficult to make cellulosic ethanol economically?

The production of ethanol becomes more difficult when starting with more complex carbohydrates from corn grain or other plant materials.  Researchers are looking for more efficient, less expensive ways to easily separate the cellulose from the lignin and also to find less expensive enzymes that efficiently chop the cellulose into smaller pieces of glucose for fermentation.  The National Renewable Energy Laboratory (NREL) is the U.S. Department of Energy’s main national lab for research and development on renewable energy and energy efficiency. NREL has been working on cellulosic ethanol since 1980. Over the past decade, NREL has reportedly brought down the cost of cellulosic ethanol from about $10 a gallon to a reported $2.15 a gallon, primarily by bioengineering better enzymes.  Besides high enzyme costs, cellulosic ethanol has high capital and feedstock costs. In contract to cellulosic ethanol, the starch in corn kernels easily converts into simple sugars, with the enzyme catalyzing this process costing a mere 0.03 cents per gallon.

A glimpse of the tax support

It is not realistic in the scope of this blog to tally up all that has been paid by U.S. taxpayers toward cellulosic ethanol development; however, consider the following.  U.S. taxpayers footed more than $100 million of POET’s Emmetsburg, IA facility. Abengoa reportedly received $229 million from taxpayers for its project in Hugoton, KS.  For this, the combined plants are running at an annualized capacity of 1.7 million gallons of ethanol, which would sell on the spot market today for $2.6 million.  In addition, the Abengoa plant is currently under such a financial crunch that it currently is laying off workers.

A section on alternative fuels will be included in our 2016 Crude and Refined Products Outlook, scheduled to be issued in early February. Also included in this report will be detailed forecasts of supply, demand and prices for refined products, both in the U.S. and throughout the world.  The impacts alternate fuels have on the refined products markets will be incorporated into the forecasts. We also use this analysis, which we update on a regular basis in our other industry studies and work products.   For more details about any of our publications, studies or other TM&C services, please visit our website, send us an email or give us a call.

As crude prices continue to languish and even turn lower, it might be tough this Christmas for some of you to recognize the “Tidings of Comfort and Joy” that come with the Season.  While the refiners among you did have a very good 2015, truly for all segments of the petroleum industry 2016 looks to be a challenging and potentially scary year.  We at Turner, Mason & Company have experienced our own “rough spots”, but despite this, both individually and collectively, we are extremely thankful for the many blessings that were bestowed upon us over the last year.  We are also grateful to all of our clients for the opportunities they have afforded us and to the readers of this blog for the time they have devoted to consider our thoughts and ideas.  Regardless of your particular faith, this is a special season and calls for a special blog.  Therefore, I would like to share two short pieces which provide context to the true “Reason for the Season” for many us.  Many of you have probably either seen or heard one or both of these over the years, but I offer them again to you.   We extend to all of you our Best Wishes for the coming year and hope y’all enjoy time with family and friends during this Holiday Season.

-John R. Auers, P.E.

One Solitary Life – by James Allan Francis

An excerpt from a sermon delivered by Dr. Francis in July 1926.  It has been widely distributed since then and is most often circulated during the Christmas season.

Here is a man who was born in an obscure village as the child of a peasant woman.

He grew up in another obscure village.

He worked in a carpenter shop until he was thirty and then for three years was an itinerant preacher.

He never wrote a book.

He never held an office.

He never owned a home.

He never had a family.

He never went to college.

He never put his foot inside a big city.

He never traveled two hundred miles from the place where he was born.

He never did one of the things that usually accompany greatness.

He had no credentials but himself.

He had nothing to do with this world except the naked power of his divine manhood.

While still a young man the tide of popular opinion turned against him.

His friends ran away.

One of them denied him.

Another betrayed him.

He was turned over to his enemies.

He went through the mockery of a trial.

He was nailed upon the cross between two thieves.

His executioners gambled for the only piece of property he had on earth while he was dying, and that was his coat.

When he was dead, he was taken down and laid in a borrowed grave through the pity of a friend.

Nineteen wide centuries have come and gone and today he is the center of the human race and the leader of the column of progress.

I am far within the mark when I say that all the armies that ever marched, and all the navies that were ever built, and all the parliaments that ever sat and all the kings that ever reigned, put together, have not affected the life of man upon the earth as powerfully as has this one solitary life.

The Parable of the Birds – by Louis Cassels

Written in December of 1959 and distributed through print and radio.  Most notable broadcasts were by Paul Harvey in his daily radio program during the Christmas season.

Now the man to whom I’m going to introduce you was not a scrooge; he was a kind, decent, mostly good man. He was generous to his family and upright in his dealings with other men. But he just didn’t believe all that stuff about God becoming a man, which the churches proclaim at Christmas time. It just didn’t make sense, and he was too honest to pretend otherwise.

“I’m truly sorry to distress you,” he told his wife, “but I’m not going with you to church this Christmas Eve.” He said he’d feel like a hypocrite and that he would much rather just stay at home. And so he stayed, and they went to the midnight service.

Shortly after the family drove away in the car, snow began to fall. He went to the window to watch the flurries getting heavier and heavier. Then he went back to his fireside chair to read his newspaper. Minutes later he was startled by a thudding sound. Then another and another — sort of a thump or a thud. At first he thought someone must have been throwing snowballs against his living room window.

But when he went to the front door to investigate, he found a flock of birds huddled miserably in the snow. They’d been caught in the storm and, in a desperate search for shelter, had tried to fly through his large landscape window. Well, he couldn’t let the poor creatures lie there and freeze, so he remembered the barn where his children stabled their pony. That would provide a warm shelter, if he could direct the birds to it.

Quickly he put on a coat and galoshes and then he tramped through the deepening snow to the barn. He opened the doors wide and turned on a light, but the birds did not come in. He figured food would entice them. So he hurried back to the house, fetched breadcrumbs and sprinkled them on the snow. He made a trail to the brightly lit, wide-open doorway of the stable. But to his dismay, the birds ignored the breadcrumbs and continued to flap around helplessly in the snow.

He tried catching them. He tried shooing them into the barn by walking around them and waving his arms. Instead, they scattered in every direction, except into the warm, lighted barn. And then he realized that they were afraid of him. To them, he reasoned, I am a strange and terrifying creature. If only I could think of some way to let them know that they can trust me — that I am not trying to hurt them but to help them. But how?

Any move he made tended to frighten and confuse them. They just would not follow. They would not be led or shooed, because they feared him.

“If only I could be a bird,” he thought to himself, “and mingle with them and speak their language. Then I could tell them not to be afraid. Then I could show them the way to the safe warm barn. But I would have to be one of them so they could see and hear and understand.”

At that moment the church bells began to ring. The sound reached his ears above the sounds of the wind. And he stood there listening to the bells pealing the glad tidings of Christmas. And he sank to his knees in the snow.

“Now I understand,” he whispered. “Now I see why you had to do it.

Have a Merry Christmas, Feliz Navidad, Priecigus Ziemassvetkus, Frohliche Weihnachten, Joyeux Noel, Zalig Kerstfeest, Buon Natale, Merii Kurisumasu, Milad Mubarak, Feliz Natal,Gledelig Jul, Hristos Razdajetsja!

The Parable of the Birds is Copyright © 1959 by United Press International/Louis Cassels. All rights reserved. Note that the original story was not available. When it was first distributed, editors of newspapers and radio programs freely altered the title and the text in literally hundreds of media outlets across the country. The above version is one that is widely circulated today.  This version taken from CelebratingHolidays.com.

By: John Auers and Elizabeth Hilbourn

For our final blog of the year, it seems appropriate to discuss the still small, but rapidly growing market for renewable diesel.  The Scottish phrase, “Auld Lang Syne,” which most of us will sing as we say goodbye to 2015 on Thursday, loosely translates to “times gone by.”  Renewable diesel, which is produced with used cooking oil or animal fats as a feedstock, in many ways harkens back to the pre petroleum days when whale oil and other similar animal or plant derived materials were important parts of the energy mix.  In our blog two weeks ago, we talked about cellulosic biofuels and related it to the “Song That Never Ends.”  The EPA anticipated that 16 of the 36 billion gallons of renewable fuel in 2022 would be met by cellulosic biofuel; however, only 0.1 billion gallons has been produced this year.  To top it off, less than 2% of the cellulosic biofuel RINs have actually been generated by cellulosic ethanol, the remainder coming from CNG or LNG with landfill feedstocks.  The void left by the slow progress of cellulosic ethanol, however, is being filled by renewable diesel, so it is certainly justified that “we’ll take a right good-will draught, for this auld lang syne” fuel.

Renewable diesel has been a growing subset of biomass-based diesel RINs, comprising 20% of D4 RIN generations, as shown in the figure below.  Currently, 500 million D4 RINs are generated from renewable diesel.  Across the world, renewable diesel is often considered an advanced biofuel.  The International Energy Agency, in their Tracking Clean Energy Progress, refers to renewable diesel as advanced biodiesel.  Renewable diesel is marketed as hydrotreated vegetable oil (HVO) abroad.  Renewable diesel is also called hydroprocessed esters and fatty acids (HEFA).

In recent years several major facilities have been built and more are planned to produce renewable diesel fuel.  The largest renewable diesel facility in the U.S. was constructed in 2013, the Diamond Green Diesel plant, located adjacent to the Valero Norco refinery.  In 2014, the Venice, Italy ENI refinery was converted to a renewable diesel facility; and this year, part of the Paramount, California refinery is being converted to a renewable diesel facility.  Plans are in order for 2016 to be the last year to process crude oil at the Total La Mede, France refinery, where a renewable diesel facility is currently being built.  The Bakersfield, California refinery has processed tallow through its hydrotreater with petroleum to generate an advanced biofuel RIN (D5).

Renewable Diesel versus Biodiesel

Typical biodiesel that is not distillated at the back end has an amber appearance, whereas renewable diesel is crystal clear in color (see figure below).  Properties of HVO are considered superior to biodiesel.  Cetane is notable, with HVO having a cetane greater than 70, whereas soybean oil biodiesel typically has a 47 cetane.  Specific gravity of HVO is lower than biodiesel at 0.77 to 0.79 versus biodiesel’s 0.82 to 0.85.  HVO has higher energy content than biodiesel; the majority of U.S. HVO is given a 1.7 equivalence value for RIN generation versus the 1.5 for biodiesel.  This means that 1.7 D4 RINs can be generated for every gallon of renewable diesel generated.  Measured contaminants are lower for HVO than biodiesel.  Cloud point and cold flow properties of HVO are superior to petrodiesel and especially biodiesel, particularly when isomerization is used in the renewable diesel production process, since it creates branched alkanes.  HVO fuel quality is equal to the synthetic Fischer-Tropsch BTL and GTL diesel fuels.

The same feedstocks are used today to produce both HVO and biodiesel.  In the production of HVO, hydrogen is used to remove oxygen from the triglyceride vegetable oil molecules and to split the triglyceride into three separate chains, thus creating hydrocarbons which are similar to existing diesel fuel components.

Renewable diesel has more connection to the refining process than any other renewable fuel.  The hydrotreating process is a process utilized by petroleum refineries today to remove contaminants such as sulfur, nitrogen, condensed ring aromatics, or metals. In this process, feedstock reacts with hydrogen under elevated temperature and pressure to change the chemical composition of the feedstock. In the case of renewable diesel, hydrogen is introduced to the feedstock in the presence of a catalyst to remove other atoms such as sulfur, oxygen and nitrogen to convert the triglyceride molecules into paraffinic hydrocarbons. Since this process is currently used by many petroleum refineries, renewable diesel blends can be produced with existing refineries by co-processing the feedstock with petrodiesel; however, if renewable diesel is co-processed with petroleum products, it can only generate an advanced biofuel RIN (D5) and not a biomass-based diesel RIN (D4), which is typically generated for renewable diesel.

The equipment and process are very similar to the hydrotreaters used to reduce diesel sulfur levels in petroleum refineries.  This allows for blending in any desired ratio without any concerns regarding quality.  Biodiesel is made by the transesterification process, whereby the added alcohol (commonly methanol) is deprotonated with a base to make it a stronger nucleophile.  HEFA fuels are hydrocarbons, rather than alcohols or esters, and can be used in diesel engines without the need for blending with petroleum diesel fuel.  Below is a list of current producers registered with the EPA to produce a D4 1.7 EV renewable diesel.

Starting in 2013, with the Green Diamond renewable plant and the Valero Norco refinery, renewable diesel plants have begun to be co-located with refineries.  Next was the ENI Venice, Italy refinery.  The latest is the Alon Paramount refinery which utilized some idle equipment to put its renewable diesel plant on line this year.  The latest announcement has been the Total announcing the conversion of their refinery in La Mede, France, to produce renewable diesel.

Market Experience

Premium EN 590 diesel fuel containing at least 10% of HVO was sold in Finland publicly from 100 service stations year-round since 2008, even in severe winter conditions, with good experience.  The highest blending ratios utilized were about 30%, and it did not contain any biodiesel.  In July 2015, UPS announced that it will buy as much as 46 million gallons of renewable diesel over the next three years, helping the company reach a goal of displacing 12% of the petroleum-based fuels in its ground fleet by 2017. In June 2015, United Airlines announced a $30 million investment in a large producer of aviation biofuels, and in July 2015, Red Rock Biofuels announced that it would produce about three million gallons of renewable jet fuel each year for FedEx, with delivery to begin in 2017 and run through 2024.  Renewable diesel can drop in directly and replace diesel completely without any kind of blend-wall.  Much of Neste’s renewable diesel goes to California and is marketed through Propel Fuels as ‘Diesel HPR’, a 100% renewable diesel product.  In August 2015, Propel Fuels launched Diesel HPR (High Performance Renewable) and reported a 15X jump in per-outlet sales of renewable fuel for diesel engines compared to the B20 (20% biodiesel) it replaced.  Diesel HPR is recognized as ‘CARB diesel’ by the California Air Resources Board even though it contains no petroleum.  This U.S. marketing of renewable diesel will be greatly curtailed if the biodiesel tax credit (as introduced this month) is passed.

Biodiesel (Renewable Diesel) Tax Credit

There was a big push from organizations, notably the National Biodiesel Board, to make the biodiesel tax credit for 2015-2016 into a producer rather than a blender’s credit.  Just this month the tax was passed through the House and Senate as a blender credit.  The biodiesel tax credit allows blenders of biodiesel (and renewable diesel) to claim a credit of $1 per gallon against their U.S. federal tax liability.  If the tax was limited to just a producer credit, it would have affected renewable diesel in the U.S. since only 20% of worldwide renewable diesel capacity is located in the U.S. and an estimated 35% is imported.  The result would have meant fulfilling the renewable fuel standards for 2016 and would have been even more difficult since over 20% of D4 RINs come from imports.

A section on alternative fuels will be included in our 2016 Crude and Refined Products Outlook, scheduled to be issued in early February.  Also included in this report will be detailed forecasts of supply, demand and prices for refined products, both in the U.S. and throughout the world.  The impacts alternate fuels have on the refined products markets will be incorporated into the forecasts. We also use this analysis, which we update on a regular basis in our other industry studies and work products.   For more details about any of our publications, studies or other TM&C services, please visit our website, send us an email or give us a call.  In the meantime, we thank you for the times we enjoyed together in 2015 and wish everyone a safe and prosperous New Year!

“And surely you’ll buy your pint cup!  And surely I’ll buy mine!

And we’ll take a cup o’ kindness yet, for auld land syne.”

By: John Auers and Elizabeth Hilbourn

Long live the planet!  I would hazard to say that most everyone (with the possible exception of ISIS, Lex Luther, Dr. Evil, or some other real or fictional crazies) supports that statement.  Last month, most of the 196 nations in attendance at the Paris Climate Conference put that sentiment into writing by signing the Adoption of the Paris Agreement, a treaty meant to reduce greenhouse gas emissions on a global basis. In many ways the agreement raises more questions than it provides answers.  For instance, what does the agreement really mean and will there be any real, quantifiable consequences?  Who is responsible for protecting the climate, anyway?  Will this put an end to fossil fuel and coal?  It seems fitting to include a blog on climate change after devoting the last three blogs to alternative fuels.  Last week in “For Auld Lang Syne, My Dear, Let’s Take a Cup of Cooking Oil and Turn it into Diesel Fuel”, we detailed how renewable diesel is making its move as a “planet-friendly” fuel.  As we learned, twenty percent of all biomass-based diesel RINs are now generated from renewable diesel.  Despite this significant growth, we also learned that it, along with the other “green” alternative fuels discussed in previous blogs are still very minor players in the energy world, with petroleum and natural gas still the lead actors, and expected to stay that way for quite some time.  Will the developments at the Paris conference change this or was it “Much Ado about Nothing?”  Although it is way too early to provide a definitive answer to this or the questions we posed earlier, we will attempt in this blog to provide some commentary on what led up to the developments in Paris and highlight some of the key provisions of the agreement which was implemented.

“Long live the planet.  Long live Humanity.  Long live life itself.”

The international political response to climate change began at the Rio Earth Summit in 1992, where the ‘Rio Convention’ included the adoption of the UN Framework Convention on Climate Change (UNFCCC).  The first Conference of the Parties (COP) took place in Berlin in 1995, and significant meetings since then have included COP3 where the Kyoto Protocol was adopted, COP11 where the Montreal Action Plan was produced, COP15 in Copenhagen where an agreement to succeed the Kyoto Protocol was unfortunately not realized and COP17 in Durban where the Green Climate Fund was created.  This year marked the 21^st annual Conference of Parties (COP21) also known as the 2015 Paris Climate Conference.  Its aim was to achieve a legally binding and universal agreement on climate, with the goal of keeping global warming below 2 degrees Celsius.  The chart below shows four potential scenarios for the course of global emissions.

The two-week conference included almost 200 nations, 50,000 participants, and 25,000 official delegates. Ahead of the agreement, 186 countries submitted plans detailing how they plan to reduce their greenhouse gas pollution through 2025 or 2030.  The U.S. concentrated its efforts in its clean power plan described below.  The agreement requires all countries to submit updated plans that would ratchet up the stringency of emissions by 2020, and every five years thereafter.  The deal requires countries to monitor, verify and report their greenhouse gas emissions using the same global system.  The agreement gives countries leeway in determining how to cut their emissions.  Every five years, nations will be required to assess their progress toward meeting their climate commitments, and to submit new plans.

Is the Agreement Binding?

For the agreement to have legal force, it must be ratified by at least 55 of the 195 countries that adopted it.  Those 55 countries must represent at least 55% of all global-warming emissions.  The agreement, if ratified, is binding in some elements like reporting requirements, while other elements (such as setting emission targets for any individual country) are nonbinding.  On the front page of the 32-page Adoption of the Paris Agreement are the words, “Adoption of a protocol, another legal instrument, or an agreed outcome with legal force under the Convention applicable to all Parties.”  Many believe the power resides in the countries “show of face” during the next milestone in five years.

Some Highlights of the 32-page Agreement

• Temperature Increase– page 22

“Holding the increase in the global average temperature to well below 2 °C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5 °C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change.”

• Reach Global Peaking of Greenhouse Gas Emissions ASAP– page 22

“In order to achieve the long-term temperature goal set out in Article 2, Parties aim to reach global peaking of greenhouse gas emissions as soon as possible, recognizing that peaking will take longer for developing country Parties, and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of equity, and in the context of sustainable development and efforts to eradicate poverty.”

• Preservation of Forests– page 23

“Parties are encouraged to take action to implement and support, including through results-based payments, the existing framework as set out in related guidance and decisions already agreed under the Convention for: policy approaches and positive incentives for activities relating to reducing emissions from deforestation and forest degradation, and the role of conservation, sustainable management of forests and enhancement of forest carbon stocks in developing countries; and alternative policy approaches, such as joint mitigation and adaptation approaches for the integral and sustainable management of forests, while reaffirming the importance of incentivizing, as appropriate, non-carbon benefits associated with such approaches.”

• Addressing Loss and Damage– page 26

“Parties recognize the importance of averting, minimizing and addressing loss and damage associated with the adverse effects of climate change, including extreme weather events and slow onset events, and the role of sustainable development in reducing the risk of loss and damage.”

 Transparency– page 28

“In order to build mutual trust and confidence and to promote effective implementation, an enhanced transparency framework for action and support, with built-in flexibility which takes into account Parties’ different capacities and builds upon collective experience is hereby established.”

 Establish a Climate-Related Financing Goal– page 8

“…shall set a new collective quantified goal from a floor of USD 100 billion per year, taking into account the needs and priorities of developing countries.”

 U.S. Clean Power Plan

As a lead up to COP21 to show it’s good intentions, the Obama Administration announced in early August the Clean Power Plan (CPP), a policy to reduce carbon pollution from power plants, the nation’s largest source.  The effective date of this initiative was December 22, 2015. Fossil fuel-fired power plants are by far the largest source of U.S. CO₂ emissions, making up 31% of U.S. total greenhouse gas emissions. When the CPP is fully in place in 2030, carbon pollution from the power sector is targeted to be 32% below 2005 levels.

 The Show

Other nations are talking about implementing programs similar to the CPP and addressing transportation fuels as well, while proposals for more green energy will surely be pushed further at both the state and federal levels in the U.S. in coming years with the goal to meet the targets set forth at COP21.  Whether these will come to fruition and change the energy environment is unknown.  What we do know is that the delegates in Paris sure make a show of being “green”. Keeping with the theme of the conference, all the food at United Nations Environment Programme (UNEP) events was sourced from rescued food, resources that would otherwise have been destroyed.  They used recyclable cups and handed out USB keys instead of printing documents.  300 electric cars were provided by Renault-Nissan to anyone seeking a ride.  10,000 loafs of bread were baked on site to avoid having them trucked in.  But then they all flew back to their home countries on planes powered by petroleum derived jet fuel – oh well.

A section on regulatory initiatives will be included in our 2016 Crude and Refined Products Outlook, scheduled to be issued in early February.  Also included in this report will be detailed forecasts of supply, demand and prices for crude and refined products, both in the U.S. and throughout the world, with our measured assessment of how all these will be impacted by changes in the regulatory environment.  We also use this analysis, which we update on a regular basis, in our other industry studies and work products.  For more details about any of our publications, studies or other TM&C services, please visit our website, send us an email or give us a call. 

By John Mayes and John Auers

As those of you who drive cars calling for higher octane gasoline can attest, the relative price of premium gasoline (91-93 octane, compared to regular 85-87) has increased significantly, particularly in the last year or two.  This is a dramatic acceleration of a trend which began in 2011, and which came on the heels of a time when growing ethanol volumes had decreased octane values to historically low levels.  In the first decade of this millennium (2000 to 2010), the USGC differential between wholesale premium and regular gasoline averaged about 10 cents per gallon (cpg), equating to premium prices just 6% above regular.  The ever increasing volumes of high octane ethanol being mandated into the gasoline pool, along with decreasing consumer demand for premium both played a role in suppressing octane prices during this period.  Things have changed in the last few years, though.  Premium demand has picked up as new vehicles increasingly require higher octane fuel, and ethanol volume growth has slowed as it bumps against the “blend wall.”  In the 2011 to 2014 time period, the premium differential increased to average almost 10% and exceed 25 cpg.  The sharp drop in petroleum prices over the last 18 months has provided another bump to premium demand as consumers opt to buy more of the now much cheaper premium grade, and this has resulted in an even larger relative premium differential, averaging almost 15% in 2015.  So what does the future hold?  Increasing vehicle mileage mandates (leading to more cars requiring premium grades), the push toward lower sulfur gasoline, and the growing abundance of low octane gasoline components will all tend to increase either premium demand or octane costs, pushing differentials higher.  On the other hand, the possibility of substantively higher ethanol consumption (if the blend wall can be breached) has the potential of offsetting these factors and even reducing the premium differential in the longer term, as could the return to higher overall prices result in discretionary consumer switching away from the more expensive grade.  Taking all these into consideration, will premium spreads continue to do like the “Little GTO” – “Turn it on, Wind it up, Blow it Out,” or will they fall back with the “Gassers and the Rail Jobs” to pre-2011 levels?  We’ll provide some thoughts on that in today’s blog.

The increase in gasoline prices in the 1970’s resulted in the end of the “muscle car” age and the ushering in of smaller cars with a lesser appetite for octane.  Even more important was the development of computerized engine technologies which prevented “knocking” even when less than optimum octane gasoline was used.  This resulted in a long term decline in premium gasoline sales as a percent of total gasoline sales in the U.S., beginning in the mid 1980’s.  As noted earlier this trend began to reverse, and consumers are now buying increasing quantities of higher octane grades.  Since February of 2010, premium gasoline sales have increased from slightly below 9.0% of total sales to a current level of over 11.3%.  While the lower absolute price of premium gasoline is certainly a component of the higher demand, the greater factors driving this shift appear to be from longer term forces.

The primary cause of this reversal is attributed to the ongoing Corporate Average Fuel Economy (CAFE) program. CAFE is requiring increasingly higher mileage standards for new vehicles, forcing automobile companies to adopt a series of technologies to achieve compliance.  One of the most significant of these is the growing use of turbocharged engines.  Turbocharging has the ability to not only improve fuel economy but also engine performance; but at a higher initial vehicle purchase price.  Manufacturers of turbocharged engines generally require higher octane fuels.  Those that do not; generally recommend their use to achieve the full capabilities of the engine.

In 2009, Ford introduced its 3.5 liter V6 EcoBoost engine as an option for a number of its auto lines.  While turbocharged engines had been available for decades, the higher costs of the engines generally restricted their use to sports cars and higher-end foreign models.  With additional engines introduced in 2010 and 2011, Ford began utilizing this technology in increasing numbers of its U.S. sales.  By 2013, nearly 80% of Ford’s vehicle lines had the option for EcoBoost engines.

The primary global provider for turbocharging technology is Honeywell Transportation Systems.  Honeywell is forecasting continued growth for turbocharged engines, not just in the U.S., but also in numerous other countries, such as China.  Within North America, Honeywell indicates that turbocharged vehicles sales have grown from only 2% in 2008 to 21% in 2014 (this includes turbocharged diesel engines).  Honeywell expects this to jump to 38% in 2019.  In China, Honeywell forecasts turbocharged engine sales will rise from 23% in 2014 to 41% in 2019.  Globally, 43% of 2019 engine sales are forecast to be turbocharged which would equate to 49 million vehicles.  As a result of this initiative, it would seem likely that premium gasoline sales will continue to rise through the near future and place continued pressure on the regular/premium gasoline price differential.

Premium gasoline sales vary significantly between regions within the U.S.  Sales in PADD II are the lowest at 7.5% of total gasoline sales while PADD V has the highest at 17.1% (more than twice the PADD II level).  The U.S. average in 2015 was 11% of total gasoline sales.

The shift to higher octane fuels is not just occurring in North America but in many other regions as well.  Driven by the same desire to improve fuel economies, much of eastern Asia is adopting the European standard of 95 RON gasoline.

Complicating the octane balance for U.S. refiners will be the introduction of Tier III gasoline requirements in January of 2017.  These new regulations will reduce the sulfur content of gasoline from 30 ppm to 10 ppm.  Most refiners will achieve these levels by treating the dominant source of sulfur in the gasoline pool, catalytic gasoline from the FCC unit.  While not a major obstacle for most refiners, catalytic gasoline treating effectively reduces sulfur levels but also reduces the octane of the product by converting olefin molecules into paraffins.

An additional complication for refiners will be the growing pool of low octane light naphthas.  Natural gasoline production in the U.S. has been increasing for several years and much of this is processed by refineries.  As more refineries adapt to processing shale crudes, the light naphtha streams are also increasing.  Even as the supply is increasing, demand for these low octane naphthas in the U.S. has declined in recent years.  Ethane has now replaced light naphtha as the primary feedstock for ethylene production in steam cracking.  The net result of these shifts is a rapidly growing abundance of low octane gasoline components at a time when premium gasoline demand is rising.

The major potential offsetting factor impacting the octane balance relates to the future use of ethanol.  Ethanol has an exceptionally high octane with research values generally in excess of 120 and motor values generally in excess of 100.  Higher levels of ethanol blending into the gasoline pool could alleviate future octane limitations.  The current path of the EPA in setting renewable fuels targets through 2016 indicates a desire to push ethanol blending volumes higher while at the same time acknowledging actual structural limitations, i.e. the “blend wall.”  When facing these same conflicting issues in the past, the EPA has backed away from aggressive ethanol blending volumes in recognition of actual blending capabilities.  As a result, ethanol growth in the gasoline pool has stalled in recent years.

Even if the EPA forces greater volumes of ethanol into the gasoline pool, a potential octane shortage may not be averted.  If E85 becomes the preferred path, the additional octane from the ethanol will not be fully utilized.  Typical E85 has an (R+M)/2 octane much higher than premium and results in an inefficient use of the octane supply.  If E15 becomes the preferred path, the additional octane will be more efficiently used and would more likely offset the additional strains developing in the gasoline pool.

While the future may be uncertain, there is currently an ability to produce octane in surplus to market requirements.  Existing ethanol levels have caused most refineries to either operate their reforming units at reduced severities or to blend naphtha directly into gasoline.  As a result, initial increases in octane demand can be met easily without major capital expenditures.

As a result of these conflicting market forces, the future trend of the premium/regular price spread is clouded.  At Turner, Mason & Company we continually evaluate the effects of governmental policies, shifts in consumer demand patterns and driving styles to forecast not only gasoline demand but also the future value of gasoline octane.  This topic is discussed in greater detail (with future pricing forecasts) in our 2016 Crude and Refined Products Outlook which will be published in February.