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February 11, 2013 Comprehensive, strategic intelligence helps you see beyond the news

WEEK IN FOCUS Wanted: A Strategy for US Shale/Tight Oil

Last year, US crude production averaged 6.41MM b/d and is expected to top 7.0 MM b/d in 2013. Bakken production in North Dakota will reach 1.03MM b/d and 1.76MM b/d by the end of 2013 and 2020 respectively. Likewise, Eagle Ford production in Texas will rise to 1.18MM b/d by the end of this year. By 2022, the Bakken and Eagle Ford fields alone are forecast to increase US oil output by 2.4MM b/d. While production from the Bakken and Eagle Ford shale fields in the US continues to grow, producers are said to be eyeing 2013 investments towards emerging plays such as Niobrara, Anadarko Woodford, Tuscaloosa Marine, and Utica.

In 2012, Niobrara output in Colorado was estimated at 116K b/d according to Turner Mason, and this figure is expected to rise to 138K b/d by the end of this year. The Anadarko Woodford Basin—which is thought to hold 102MM bbl of undiscovered conventional recoverable reserves and 393MM bbl of undiscovered recoverable shale reserves—located in Kansas and Oklahoma will also see increased drilling activity this year. Tuscaloosa Marine play in central Louisiana and southern Mississippi is said to hold "significant" amounts of oil with 7B bbl though to be accessible via horizontal drilling. Despite the uncertainty in the Utica field in Ohio, local refiners are already making preparations to receive and process and Utica crude. Marathon Petroleum Corp. has converted a tower at each of its refineries in Kentucky and Ohio to allow for the processing of condensate sourced from Utica. By 2020, production from Utica is forecast to be 120K b/d.

While these new plays are gaining attention from producers, Sandy Fielden, the director of energy analytics at RBN Energy cautioned, "(US crude) production is growing so fast, if you added another [Bakken-sized field] on top of it, it would be too much [for the US to] consume." The head of the Paris-based International Energy Agency (IEA), Maria van der Hoeven, echoed these sentiments saying that the ongoing shale boom within the US could be capped if the US does not allow producers to start exporting volumes given increasing production coupled with declining demand for refined products and growth in domestic refining capacity oriented towards processing heavier crudes. She stated, "Washington will need to address this misalignment, lest the great American oil boom goes bust." Finally, the collapse of natural gas prices caused by over-production of shale gas should send a wake-up call to companies in the tight oil business. Now, it is the time to formulate strategies to turn challenges into opportunities ahead of potential supply boom.

QUICK GLANCE AT GLOBAL FUTURES AND SPOT DATA Global futures and spot market price movements

Benchmark futures prices, Feb. 8a US WTI crude, $/bbl

% change from prev.

week

US RBOB, $/gal

% change from prev.

week US heating

oil, $/gal % change from prev.

week

UK Brent crude, $/bbl

% change from prev.

week UK gasoil,

$/mt % change from prev.

week 95.72 ↓2.10 3.06 ↑0.17 3.24 ↑2.46 118.90 ↑1.83 1,028.25 ↑2.26

Spot product prices, Feb. 8a

New York (US), $/galb

% change from prev. week

London (UK), $/mt

% change from prev. week Singapore, $/bbl % change from

prev. week Gasoline 3.07 ↓0.72 1,083.00 ↑1.03 131.50 ↑3.54 Diesel 3.29c ↑1.98 1,037.50 ↑2.57 132.33 ↑3.20 Heat. oil 3.26 ↑2.52 1,028.25 ↑2.47 N.A. N.A. Jet fuel 3.33 ↑1.76 1,114.25 ↑2.84 136.63 ↑3.53 Fuel oil N.A. N.A. 644.25d ↑1.18 661.40e ↑1.90 aPrices for Friday were used when available; otherwise, prices reported for the nearest days were used

bNew York Harbor market prices cUltra-low-sulfur diesel dHigh-sulfur fuel oil e180-cst fuel oil, $/mt

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Table of Contents

(Click the title to go to the section) Top Five News of the Week ................................................................................... p 3 Feature of the Month ............................................................................................... p 6 Refining & Marketing News ................................................................................... p 11 Refinery-Petrochemical Business Briefs ................................................................ p 36 Politics, Environment & Regulatory Legislation ................................................. p 39 Mergers, Joint Ventures, Acquisitions & Divestitures ........................................ p 40 Refiner Business, Strategy & Finance .................................................................... p 41 Industry Trends & Forecasts ................................................................................... p 44 Technology Developments & Commercialization .............................................. p 45 Biofuels, Alternative Energy & Carbon Management ........................................ p 46 Reference Sources & Abbreviations ...................................................................... p 47

Refinery Energy Management Report Latest Technologies and Strategies to Enhance Operational Economics

Energy usage represents 40%-60% of the overall refinery operating expense, excluding crude purchases. This report presents the most comprehensive view of the areas where refiners can improve energy efficiency to maintain profit margins.

Detailed discussions and analyses focus on:

• Major drivers for energy efficiency • Energy management programs implemented by the refining industry, with results of a direct survey of refiners

worldwide • Sources of refinery energy inefficiency in utility providers and likely solutions • Improving energy efficiencies of CDU, delayed coker, visbreaker, hydrotreater, hydrocracker, FCCU, catalytic

reformer, and alkylation unit • Role of energy management that connects profit margins, asset management, and compliance to environmental

regulations • Case studies with recommendations based on budget constraints and refinery configurations

For details or to place an order visit here.

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TOP FIVE NEWS OF THE WEEK

Heavy oil refiner makes investments to process light grades.

LyondellBasell Industries NV has long-term plans to run more heavy Canadian crude through its 265K-b/d Houston, TX (US) refinery, according to CEO Jim Gallogly. In the meantime, as adequate supply lines are not yet in place, the refinery plans modifications to allow it to process more Texas light crudes West Texas Intermediate and West Texas Sour, taking advantage of prices pressured downward by the US shale boom. The work should be completed in March, and will involve temporarily taking 80K b/d of capacity offline.

While the Houston refinery is moving away from the Latin American crudes that have nourished it in the past, the International Energy Agency (IEA) expects US refiners to continue relying on heavy crude from the region. IEA market division head Antoine Halff assured producers on Feb. 7 that Columbian and Venezuelan oil will continue to be in demand as US refiners, already outfitted to process heavy crude, will not be able to switch to North American feedstocks without undertaking expensive modifications. The US currently imports approximately 40% of the crude produced in Columbia and Venezuela.

Canadian oilsands seek solutions to alleviate supply glut.

Burgeoning supplies and insufficient infrastructure continue to depress the price of heavy crude from Canadian oilsands, leading to a C$6B ($6B) loss in tax revenue for the province of Alberta. Alison Redford, Alberta's premier, is keen to convince Canadians, as well as their neighbors due south, of the

importance of bringing the product to new markets, and to that end, she has appointed David Manning as Alberta's envoy in Washington, D.C. Manning's first project will involve working with US State Dept. officials to try to move Albertan crudes through the long-delayed Keystone XL pipeline project. Manning has not commented on what incentives he might bring to the table to promote the Keystone project,

though he has remarked that Alberta has "much more in our toolbox" when it comes to leveraging policy.

Keystone XL is not the only option for Albertan crudes. Along with New Brunswick premier David Alward, Redford has decided to support TransCanada Corp.'s plan to convert a natural gas pipeline to transport light crude to Québec, with addition arrangements to be made for crude to reach the Irving Oil's 300K-b/d St. John, New Brunswick refinery. The C$5B ($5.02B) project would reduce Canada's need to import additional light crude, and free up space in the country's pipeline system to transport more heavy crude southward. The news pushed the price of Western Canada Select (WCS) up by $1.20/bbl, to trade at a still substantial $29/bbl discount to US benchmark WTI, a significant improvement on the Dec 14 spread of $42.50/bbl. TransCanada CEO Russ Girling commented on the possibility, adding that if enough pipe can be laid to increase the system's capacity, export options for oilsands crude would broaden considerably. "Once you get on the tidewater, you can get anywhere," he said, adding that "you don't need a presidential permit to bring oil into the Gulf Coast".

Other possible routes to the sea include an expansion of midstream company Kinder Morgan's pipeline to the West Coast. According to market analyst John Kemp, a similar proposal by Enbridge to pipe crude through British Columbia may be the most sensible option, allowing product to reach alternative markets in Asia. So far, however, that project has been stalled by the objections of environmentalist and Native American groups.

European closures, flight to diesel leads to gasoline shortage.

According to the Union Francaise des Industries Petrolieres, European oil demand is slowing steadily, making it increasingly difficult for refiners to maintain their profit margins. At the present, France has eight working refineries, down from 24 in 1977. European refiners that are still in business are working hard to shift their product slates away from gasoline and toward diesel in response to motorists' preferences, but the market is beginning to indicate that the trend has gone too far, with too many gasoline-producing



refiners having gone under, and increasing demand for European imports overseas. Gasoline prices recently shot up as Hess announced its intention to permanently close its 70K-b/d Port Reading, NJ (US) refinery, and refinery explosions in Venezuela and Mexico have created additional strong import markets. The result has been high margins for gasoline refiners, even during the winter when the market usually slumps. "If demand is really strong now," one trader remarked, "there won't be a barrel left come the summer." According to JBC Energy, gasoline demand outside the OECD and China will grow by 200K b/d each year for the next decade, as developing regions acquire a taste for high-quality gasoline which they can't refine themselves, indicating that gasoline will likely retain a place on European refining slates for years to come.

Petit-Couronne deadline for bids pushed back to April.

Final bids for the purchase of Petroplus Holdings AG's 154K-b/d Petit-Couronne refinery in Normandy, France were due Feb. 5, but the deadline has been pushed back to April 16 after the French government deemed none of the bids received before the Feb. 5 deadline as valid. French officials extended the initial bidding window from Nov. as officials at the time were seeking Libyan sovereign fund

investment which ultimately failed to pan out. The facility has been in limbo since Petroplus submitted bankruptcy filings in Jan. 2012, and in Dec. concluded a subsequent six-month

tolling deal with former owner Shell, which kept the facility running through the better part of 2012. The extension was granted in an effort to find a buyer for the refinery and preserve the jobs of the 470 employees working at the site.

A French court in Rouen was considering five bids for the Petit-Couronne refinery before the deadline passed on Feb. 5. According to French Industry Minister Arnaud Montebourg, offers from Swiss

Terrae and Egyptian Arabiyya Lel Istithmaraat are considered serious, with demonstrated financing; Roger Tamraz's NetOil, which has submitted several rejected bids previously, has also resubmitted an offer. The French government has already ruled out the possibility that a bid from Iranian Tadbir Energy will be accepted, citing international sanctions. French officials have come out in support of the bid submitted by Arabiyya Lel Istithmaraat, who stated to Europe 1 radio on Feb. 6 that it was prepared to invest over $135.29MM in the refinery in order to keep all existing jobs. Montebourg noted this week that if a bid is accepted, the French government might acquire a minority stake in the refinery in order to provide the "large amount" of capital necessary to improve the refinery's profitability, but will not take over operation of the facility. The president of Arabiyya Lel Istithmaraat was to fly to Paris on Feb. 7 to discuss what exact role the French government was willing to play in helping to keep the refinery open. According to a representative of the company, "We have asked for the state to participate in the takeover."

Meanwhile, unionized Petit-Couronne workers have threatened industrial action should the court reject all existing bids, a circumstance which would likely result in the facility's liquidation and the loss of the 470 jobs. French Unions have also suggested that, in the event of liquidation, former owner Shell should be compelled to cover costs related to the facility's closure.

China to institute new fuel standards. The Asian country is expected to adopt Phase IV standards—comparable to Euro-4—mandating sulfur levels in refined fuels be below 50 ppm, nationwide as soon as possible, with a standard for gasoline currently being introduced and a complementary diesel standard to be implemented by the end of 2014 that will lower sulfur emissions from burning diesel fuel to about 1/7 of current levels. Besides sulfur levels, the new emissions standards on diesel will also lower emissions of PM2.5 by 80% and



NOX by 30%. Furthermore, by the end of 2017, the country will require Phase V standards which are similar to Euro-5 that require sulfur levels in diesel and gasoline to be below 10 ppm.

The transition, long in the works, has been delayed multiple times over the last few years due to availability concerns and reluctance by major oil companies PetroChina and Sinopec to make the necessary investments to produce higher-quality fuels. However, the push for tougher emissions standards has now been accelerated due to intensifying fears about Beijing's hazardous pollution levels, which many citizens attribute to poor quality diesel fuels being burned by buses and trucks. Currently, just over half of the country's 3.6MM b/d diesel consumption goes towards automotive diesel utilized in buses and trucks. In response to the rise in pollution levels, on Feb. 1 Beijing adopted Phase V standards, which mandate sulfur levels under 10 ppm and will also significant reduce PM2.5 and NOX emissions when running buses and trucks on diesel. Phase IV standards have already been adopted in many regions throughout the country including the Pearl River Delta, Shanghai, and Jiangsu. Throughout the rest of the nation, Phase III standards that were mandated in June 2011 reign supreme though gasoline that meets Phase IV standards is said to be widely available throughout the country now.

According to one analyst, rising fuel standards will prompt rising fuel prices, too; the Chinese government artificially controls diesel and gasoline prices, and may ramp up pricing reforms in-line with fuel specification changes. Specifically, the Chinese government noted that it will allow for price premiums for higher-quality fuels vs. lower-quality fuel in order to encourage refiners to more quickly invest in upgrading capacity that will allow for the production of higher-quality fuels. The government may also work with PetroChina and Sinopec on instituting tax breaks to help encourage greater production of higher-quality fuels.


FEATURE OF THE MONTH

Technology Update: Fluid Catalytic Cracking

Fluid catalytic cracking operators have witnessed some great changes in the past few decades. Tightening gasoline reformulation standards, regenerator emissions restrictions, LCO maximization strategies, propylene yield augmentation, increasing use of highly contaminated and heavy feedstocks, volatile catalyst prices, and major capacity shutdowns due to poor profits in certain regions of the world comprise a laundry list of issues that FCC-centric refineries have been forced to deal with over the past several years. Meanwhile, gasoline demand destruction in the US, gasoline surplus in Europe, and a general trend towards dieselization have put the FCCUs' primary purpose at risk, forcing many to make difficult decisions on how best to operate (or not operate) the unit moving forward.

Declining gasoline demand means FCCUs will need to emphasize LCO, propylene

Diesel demand to drive growth in transportation fuels consumption

According to the Dec. 2012 Oil Market Report, global diesel consumption totaled 23.6MM b/d, while global gasoline consumption represented 22.6MM b/d of demand. The Asian diesel market is forecast to grow most rapidly, at a rate of 150K bpd/y through 2020, with ownership of diesel cars rising in China, South Korea, and India and other developing countries. At the same time, North American consumption will expand by the substantial volume of 125K bpd/y with help from the growing popularity of diesel-powered vehicles. Looming GHG emissions regulations may also encourage more consumers in the US, Japan, and other countries to buy diesel vehicles for their better fuel efficiency. Analysts have also pegged the mandated increase in ethanol blending as a contributor to gasoline demand destruction, further pushing refiners to favor diesel production.

By 2016, diesel demand in the OECD Europe will account for 34.3% of the total product demand, an increase of 4.3 percentage points since 2010. This diesel demand figure is forecast to rise to 61% of total product demand by 2030. Moreover, the percentage of cars expected to run on diesel will increase by 19 percentage points to 51% by 2020 from 2007. Diesel demand in France, in particular, makes up 80% of the nation's motor fuel consumption, the highest percentage in the EU.

Moving forward, demand for diesel in Asia, led by China, India, and Australia, is expected to grow by 14% by 2015 to 9.8MM b/d. In order to help meet this growing demand, a number of Asian refiners are expected to switch from gasoline to more diesel production which will boost diesel yields by 250-300K b/d by 2015. However, even after Asian refiners switch from gasoline, the production of diesel will only grow 9.9% to 2015, meaning the diesel surplus pool will shrink from 500K b/d currently to 200K b/d by 2015. Meanwhile, exports to Europe, Africa, Australia, and Latin America are expected to grow 5% to 765K b/d by 2013.

Asia-Pacific to fuel demand growth for propylene

According to Intratec Solutions LLC, propylene will continue to be a major driving force in the global PC market moving forward with ethylene being the only olefin being seen as in higher demand in the future. Traditionally, propylene was produced as a by-product of naphtha-fed steam crackers as well as refinery fluid catalytic cracking units. However, as the shale gas revolution in the US has led to a shift towards ethane-based steam cracker capacity and refinery FCCUs have begun to lower rates as gasoline demand in the west continues to decline, propylene supply has become constrained.

In 2011, global demand for propylene was 81.9MM mt with polypropylene accounting for 63% of this demand, followed by acrylonitrile and propylene oxide at 7% each, cumene at 6%, acrylic acid at 4%, isopropanol at 2%, and other derivatives at 11%. Over the next several years, Nexant has forecast that demand for propylene will grow by 61% on the back of growing consumption in Asia and will reach 132MM mt by 2025. From 2015-2025, yearly



demand growth is anticipated to be 2.9%, and supply tightness is expected to occur as US production drops due to crackers utilizing lighter feeds. With demand growing and supply dropping, prices are expected to jump.

The Asia-Pacific region, in particular China, will drive the forecast growth in light olefins consumption. China consumed 14MM mt of propylene in 2011, and growth projections stated demand will rise by 12%/y and reach 22.2MM mt by 2015. As a result of this demand growth forecast, the country will look to add a large amount of on-purpose propylene production capacity from 2012-2014. In China, the focus will be on coal-based olefins production routes as methanol-to-olefins (MTO) and methanol-to-propylene (MTP) capacity within the country is expected to reach 5MM mt by 2016 with further projects scheduled to startup after this date. Propylene oxide demand is expected to fuel the uptick in propylene demand growth in Asia. Furthermore, The Japan Petrochemical Industry Assoc. (JPIA) remarked at the Asian Petrochemical Industry Conference (APIC) that the region's PC market should experience steady growth over the next two years as domestic consumption remains healthy, especially in emerging economies. According to CMAI, Asia could account for two thirds of global PC growth as regional economies expand, although political and social chaos in the Middle East could somewhat slow the pace of investment. Analysts see Asian propylene consumption rising to 98.3MM mt in 2015 from 77MM mt in 2010, while ethylene demand is forecast to increase to 146MM mt from 123MM mt over the same time period.

Rare earth prices have declined but are still above historical norms

Volatility in the price of rare earth metals, including cerium and lanthanum, is causing major problems for FCC catalyst producers. China, which supplies nearly all of the world's rare earth production (~95%), cut back exports 40% in July 2010 with the intent of keeping prices inflated while maintaining its supplies. Overall, Chinese exports of rare earth metals dipped to <25K mt in 2010 from ~57K mt in 2006. Meanwhile, refinery rare earth usage for FCC catalyst represented almost 50% of the market for these materials, and refiners have been increasing their use of rare earth oxides in FCC catalysts in recent years to counteract the intensifying presence of metal contaminants (i.e., nickel and vanadium) in heavy crudes derived from oilsands and other sources. According to Australian rare earth producer Lynas Corp., worldwide rare earth demand for FCC catalysts reached 18.4K mt in 2010. The 2010 demand figure represents a 23% increase since 2004. Other uses for rare earth materials that will compete with the refining catalyst market include hybrid vehicles, cellular phones, flat screen television, computers, and other hi-tech devices. As a result of the cut back in supply, export prices of rare earth from China averaged $109,036/mt in Feb. of 2011, up from $14,045/mt in July 2010 and ~$2.3K/mt in 2007. By June 2012, the price had dropped to $20.5K/mt and in Nov. 2012, the average La2O3 export price was approximately $13.5K/mt, well below the peak of ~$170K/mt seen in Feb. 2011 but sill above the historical average of around $5K/mt.

In response to the increase in rare earth prices, major FCC catalyst manufacturers Albemarle, BASF, and Grace have all looked at ways of lowering rare earth content within their catalyst offerings. Albemarle introduced a "Low Rare Earth" or LRT version of many popular offerings and Grace introduced the REpLaCeR line of catalyst which provides a full range of FCC catalyst and additive products (i.e., cracking, bottoms cracking, octane enhancers, RFCC, etc.). Although many of the "novel" offerings are based on previously developed technologies, Grace has also developed a new zeolite that can achieve high cracking activity and good hydrothermal stability without the use of rare earth elements. BASF has taken a slightly different approach to reducing rare earth materials. Although the company avoided the introduction of a specific line of low/zero rare earth technologies, it is notable that many of the existing offerings can be designed with a range of RE2O3 content. Evaluation of FCC process economics in terms of feed process, desired product slate, and catalyst formulation is recommended in an effort to reduce overall rare earth content. The company refers to the technical service offering involving evaluation, simulation, and optimization as the Rare Earth ALternative (REAL) solution.

Latest technology advances in FCC catalysts, processes, and hardware

Creating a more flexible FCCU is the focus of almost all modern technological developments. Dealing with varying feed qualities, swings in product demand, tighter product specifications, and more challenging unit emissions limits requires a



tremendously diverse piece of equipment. Moreover, because the unit is the center of most complex refineries, improvements to the FCCU play a significant role in overall refinery product slate and economics. Over the past few years, a drive to maximize diesel-range LCO streams was seen as on of the most frequently discussed topics in regards to FCC technology, catalysts, and operations. While LCO maximization remains a focus of refiners in certain areas, an emphasis on flexibility is notable in more recent works. Furthermore, the drive to maximize propylene output from the FCCU and improve the synergy of petrochemical production with FCCU operations has joined LCO maximization as a major discussion topic in published articles, conference presentation, and research efforts.

Dual reaction zones and second riser improve propylene yield

Several technology companies offer FCC-type units that are designed to operate at higher-severity conditions. Many of these offerings incorporate a second reaction zone or a second riser in which the higher-severity FCC process can take place. Axens, KBR, Lummus Technology, Nippon Oil/Saudi Aramco, Shell Global Solutions, Sinopec, and UOP all provide process technologies based on conventional FCC equipment and configurations that can enhance propylene production. Novel processing strategies to enhance light olefins production in the FCCU, revealed in the research and development work over the past two years, has similarly been oriented towards providing multiple reaction zones. One invention details the use of a downer reactor and a riser reactor in the same process to maximize the yield of both light olefins and middle distillates. Alternatively, several inventions were revealed that indicate single-riser processes with multiple reaction zones. Typically, the operating conditions including fluid velocity and cat.-to-oil ratio in each zone will be different, enabled by differing the riser diameter in each zone, and will create a higher-severity zone and a lower-severity zone. Additionally, the dual-zone risers may include multiple injection points to allow for naphtha recycle and/or interstage stripping to improve product quality and allow for better control of operating conditions. Operating a single riser with multiple reactions zones allows the refiner to achieve many of the benefits that are noted for a dual-riser operation while saving on both capital and operating costs.

Furthermore, a number of catalyst companies, including Albemarle, BASF, JGC C&C, Grace, Instituto Mexicano del Petroleo (IMP), Indian Oil Corp., INTERCAT (now part of Johnson Matthey), and Sinopec, offer ZSM-5-containing additives for increased propylene production from the FCC. Albemarle has indicated that maximum catalyst accessibility along with multiple cracking functions are needed to ensure maximum light olefins yields from the FCCU as high addition rates of ZSM-5 additives will lead to activity dilution and associated yield losses.

Bottoms cracking additives, operational adjustment preferred routes to boost LCO yield

Selective bottoms upgrading catalysts that contain an active matrix are the preferred catalytic route to increase FCC LCO production. However, these bottoms upgrading catalysts do have the undesirable side effect of increasing the yield of coke and dry gas which can cause the FCCU to become constrained by gas compression and metallurgical limits. Recent FCC catalyst development has mainly focused on improving catalyst selectivity for distillates (cycle oils). To maximize LCO yield while maintaining a low gas and coke make, the proper zeolite/matrix activity ratio (consistent with type of feedstock) should be used. The zeolite/matrix activity ratio is important since studies have found that heavy hydrocarbon molecules crack on the exterior of the zeolite and are then subsequently cracked inside the zeolite.

Refiners can also make operational changes to increase LCO make from the FCC. These operational changes include changing cut points, increasing feed preheat temperature, increasing HCO recycle, decreasing catalyst activity, and/or decreasing the riser outlet temperature. Refiners must be aware that while these operational changes will increase LCO yield from the unit, the changes may not necessarily increase unit profitability, as all of these operational changes will cause an increase in bottoms yield and a loss in some product volume.

Resid upgrading to dominate FCC capacity additions

According to the Shaw Stone & Webster (now part of Technip), virtually every new FCCU licensed in the last five years is designed to maximize the processing of resid feeds, maximize the production of light olefins, or a



combination of the two. In Asia particularly, new resid FCCUs (RFCCUs) are designed to produce ethylene and propylene for petrochemicals. The dwindling supply of light sweet crude throughout the world coupled with the large reserves of unconventional extra-heavy crude available in several regions around the globe will continue to fuel RFCC growth. Favorable economics associated with processing some resid in the FCC along with the decline in fuel oil demand will also fuel growth in resid upgrading. In order to process resid-containing streams, certain FCC equipment—i.e., feed injector, catalyst coolers, the riser termination devices, and product strippers—will need to undergo modification to ensure no reliability or maintenance problems occur. Feed injection technology is the most important factor, as proper feed injection must take place to ensure efficient vaporization of the liquid feed. The increased level of feed contaminants in resid could also cause problems including excessive coking and higher delta coke.

Commercially, there are several companies currently offering process solutions for resid feeds, including Axens, KBR/ExxonMobil, Lummus Technology, Petrobras, Shaw Stone & Webster, Shell Global Solutions, Sinopec, and UOP. Furthermore, Albemarle, BASF, Grace, INTERCAT, JGC Catalysts & Chemicals Ltd., Nalco, and Sinopec all market catalysts and additives for heavy feeds, including heavy metal passivation additives. For upgrading heavy feeds to liquid products, much commercial emphasis is placed on matrix mesoporosity and the ability to pre-crack large molecules before these molecules reach the zeolite surface. Processing heavier feeds will generally require larger pores for accessibility of larger molecules, smaller crystallites (i.e., nanocrystals), and better protection from contaminants (e.g., via the use of specialty aluminas). Additionally, some layered catalyst systems have become commercially available. BASF's multi-stage reaction catalyst (MSRC) technology is oriented toward the processing of highly contaminated feeds. Due to the fact that contaminant metals, and specifically Ni, typically only penetrate the outer layer of FCC catalysts, BASF has developed technology in which the outer layer of the catalyst is designed to passivate heavy metals with specialty alumina, while the inner layer is optimized to improve cracking activity and selectivity.

Technology developers also look at solutions for lowering stationary emissions from the FCC regenerator

With the recent enacting of more severe limits on emissions coming from refineries, there has been a greater focus placed on reducing refinery emissions. The issue poses a complex problem that currently encompasses at least four categories of pollutants: SOX, NOX, CO, and particulate matter. Catalysts with emissions-reducing functionality or catalyst additives are popular solutions as the cost of operating a caustic scrubber to reduce SOX emissions has become very expensive due to a drastic increase in the price of caustic soda. SOX reduction additives also require no capital investment and can reduce SOX levels to as low as 25 ppmv. The additives can be applied directly to the FCC catalyst inventory where the additive will adsorb any sulfur oxides in the regenerator and convert the sulfur oxides to sulfates. The sulfates are then desorbed as H2S in the riser. Albemarle, BASF, Grace, and INTERCAT, all offer SOX reduction additives. It is also notable that some commercial additives that provide for fuel sulfur reduction (e.g., Albemarle's SCAVENGER) or improved conversions with heavy feeds (e.g., INTERCAT's Cat-Aid) can also have a positive impact on SOX emissions from the regenerator by adsorbing sulfur species in the FCC riser.

CO and NOX emissions from FCC regenerators must also be monitored and controlled. CO combustion promoters are utilized to control CO emissions but the addition of CO combustion promoters has the negative effect of increasing NOX emissions from the FCC. Platinum was previously the most popular choice for combustion promoters, but due to increasing prices, many companies are developing alternatives. Pt catalyses the oxidation of intermediate nitrogen species such as NH3, leading to an increase in NOX emissions. New, non-Pt combustion promoters are being offered by Albemarle, BASF, Grace, and INTERCAT to reduce both CO and NOX emissions from the FCCU. COnquer is the newest non-Pt CO combustion promoter introduced by BASF that claims to lower NOX emissions from a FCC regenerator by up to 70% compared to traditional Pt-based combustion promoters while also helping refiners improve operational profitability by lowering the amount of combustion promoter needed by up to 15% compared to competitors products. COnquer also claims to lower afterburn-uncontrolled oxidation of CO to CO2 in the dilute phase by almost completely combusting CO to CO2 in the dense phase. In terms of hardware solutions, low NOX regenerators are offered by KBR and Shell Global Solutions.



Capitalizing on current trends and future opportunities

Speculations of the demise of FCC units may be premature. Although a number of factors would seem to support the declining importance of the FCC—there is a surplus of FCC capacity in Europe, the FCC gasoline share in the US blending pool is being undermined by mandated ethanol use and rising motor vehicle fuel efficiency, and a growing concern of global warming because of fossil fuel use—four major areas have been identified for which advancing FCC technologies can offer solutions to satisfy shifting market demand and environmental regulations.

First, despite the stronger growth seen for diesel demand, gasoline consumption remains significant in many areas around the world, including the US. Meanwhile, China is forecast to see an increase in gasoline consumption by 5%/y to 2015; gasoline consumption was pegged at 569MM bbl in 2009 and is estimated to grow to 755MM bbl in 2015 due to high vehicle sales. The production of high-quality gasoline streams will continue to result in positive margins for FCCU operators, while the more stringent fuel specification and emissions limitations will support the need for advanced catalyst and additives. Additionally, strong growth in demand for diesel and propylene will warrant some attention, and refinery strategies to optimize production of both of these products from the FCCU will remain an issue of interest for technology licensers and catalyst/additive producers.

Second, many refiners are looking to process resid feeds in FCCUs and/or expand the amount of resid that they can feed to existing RFCCUs. In the future, feedstocks for upgrading will become heavier and sourer as light sweet crudes become pricier despite recent shale oil boom in the US. The increased level of contaminants in resid feeds can lead to excessive coking and higher temperatures on the unit. Shale oil from Bakken and Eagle Ford fields in the US is known to carry catalyst poisons such as alkali metals, arsenic, calcium, and iron which can shorten FCC catalyst life and render poor product yields. Future R&D work will focus on catalysts and operations that can alleviate catalyst poisoning.

Third, countries around the world are mandating the use of renewable feeds to produce transportation fuels in an attempt to reduce GHG emissions and improve energy security. FCC technologies that convert a renewable feed and coprocess a renewable feed with a conventional hydrocarbon stream are currently in various stages of commercialization; however, wide-scale implementation is limited. Meanwhile, R&D work focused on this technology area continues.

Finally, reducing refinery emissions (i.e., NOX, SOX, CO, particulate matter, and most recently, CO2) will be another main focus for FCC operators and technology developers going forward. To reduce catalyst costs, the development and use of non-Pt combustion promoters has been another focus of FCC catalyst vendors. Attrition resistant catalysts have been a major focus of recent R&D work to help curb particulate matter emissions from the FCCU. Reducing GHG emissions from the FCC regenerator will mainly result from improvements in unit energy efficiency.

[This article was prepared from excerpts of Hydrocarbon Publishing Company's 4Q 2012 Worldwide Refinery Processing Review covering Fluid Catalytic Cracking and Gas Processing technologies.]

http://www.hydrocarbonpublishing.com/store10/product.php?productid=B21204&srchkey=


REFINING & MARKETING NEWS

Futures Markets

US oil futures ease while UK oil builds strength on economic data. US crude oil futures prices dipped in the week to Feb. 8, easing back from recent highs posted in the previous period as a stronger dollar and higher inventories softened the market. Prices for the UK benchmark, however, continued to trek higher, hitting a nine-month peak, amid positive economic reports and geopolitical tension. Also, the US heating oil contract was underpinned as a large winter storm moved into the US Northeast on Friday that was expected to dump much snow in areas over the weekend.

Early in the week, UK Brent found strength as purchasing managers' indices in Europe were seen improving, bullish data emerged for the US services sector, and better-than-expected earnings reports sparked a rally on Wall Street. Later in the period, China released robust trade data for Jan., pointing to a rebound in economic activity and rising oil demand, underpinning Brent prices. Goldman Sachs stated that Brent's current and recent strength is "less driven by supply shocks and instead by improving demand… Global oil demand has surprised to the upside in recent months, consistent with the pick-up in economic activity." Also injecting bullishness was Iran's rejection of a US offer for bilateral talks concerning Tehran's nuclear program. Brent prices typically are more sensitive to geopolitical tensions in the Middle East than the US benchmark is.

On the other hand, US WTI failed to latch on to the bull factors as a bearish inventory report pressured down prices. The US EIA's weekly inventory report showed that stocks of crude oil rose 2.6MM bbl to 371.6MM bbl as refinery utilization slipped 0.8 percentage points to 84.2% of total capacity. "I think what we've got there is a situation once again where crude oil is going to be backed up because we'll be producing more than we're refining," said Price Futures Group analyst Phil Flynn. Gasoline stocks also climbed, while middle distillate inventories eased back from recent builds.

US West Texas Intermediate (WTI) on the NYMEX dropped $2.05/bbl over the trading week to Feb. 8 to end at $95.72/bbl, while European Brent on London's ICE closed $2.14/bbl higher, at $118.90/bbl. The US/European arbitrage widened by $4.19/bbl to end at negative $23.18/bbl. For the five trading days ending Feb. 7, OPEC's basket of 12 crudes gained $1.37/bbl to close at the period's high of $113.67/bbl; the period's low of $112.62/bbl was seen on Feb. 1. (As of the time of publication, OPEC had not posted its basket price for Friday, Feb. 8.) The first chart shows NYMEX and ICE crude futures, OPEC spot crude prices, and the WTI/Brent arbitrage.

US RBOB on the NYMEX increased 0.52¢/gal to close Friday at $3.0588/gal, as its profit over WTI expanded by $2.27/bbl to $32.75/bbl. US heating oil on the NYMEX was up by 7.78¢/gal to $3.2384/gal, and its crack to WTI jumped by $5.31/bbl to $40.29/bbl. European gasoil on the ICE climbed 7.22¢/gal to $3.2643/gal ($1,028.25/mt), while its spread over Brent closed 89¢/bbl higher, at $18.20/bbl. On the CME Group Exchange, the front-month ethanol futures contract closed 5.7¢/gal lower on the week, at $2.412/gal. The second and third charts show (1) NYMEX refined products futures, ICE gasoil futures, and CBOT ethanol futures; and (2) the crack spreads between NYMEX and ICE refined products and their corresponding crude benchmarks.



Crude Futures Prices (NYMEX WTI and ICE Brent) and Spot Prices (OPEC Basket)

92

99

106

113

120

01/14/13 01/16/13 01/18/13 01/22/13 01/24/13 01/28/13 01/30/13 02/01/13 02/05/13 02/07/13

Crud

e pric

es, $

/bbl

-26.00

-23.00

-20.00

-17.00

-14.00

Arbit

rage

, $/bb

l

WTI Brent (Spot) OPEC Crude Transatlantic Arbitrage

Product Futures Prices (NYMEX RBOB and Heating Oil; ICE Gasoil; CBOT Ethanol)

2.3

2.55

2.8

3.05

3.3

01/14/13 01/16/13 01/18/13 01/22/13 01/24/13 01/28/13 01/30/13 02/01/13 02/05/13 02/07/13

$/gal

RBOB Heating Oil Gasoil CBOT Ethanol

Product Crack Spreads (NYMEX RBOB and Heating Oil over WTI; ICE Gasoil over Brent)

15

22

29

36

43

01/14/13 01/16/13 01/18/13 01/22/13 01/24/13 01/28/13 01/30/13 02/01/13 02/05/13 02/07/13

$/bbl

RBOB Crack Heating Oil Crack Gasoil Crack

(Feb 4, 5, 6, 7, 8)



Spot Products Markets

US spot prices mostly rise but gasoline weakens in NYH. Spot product prices mostly climbed in the week to Feb. 8 as the futures benchmarks increased, despite weaker crude costs. However, gasoline and RBOB prices in the New York Harbor (NYH) fell as a flurry of shipments were on their way from Europe and as the US Northeast braced for a potentially crippling winter storm.

Gasoline differentials in the Midwest's Group Three hub climbed on Wednesday amid reports that the 36.9K-b/d FCCU at CVR Refining's 116K-b/d Coffeyville, Kansas plant was taken offline. A trader noted that the unit could be down for up to two weeks. The outage could coincide with planned maintenance at Marathon Petroleum's 233K-b/d Catlettsburg, Kentucky refinery, which could limit supplies in the region. Differentials were driven higher the next day after Magellan Midstream Partners adjusted the minimum amount of material shippers must keep within the system. The minimum requirement tends to rise during months that see higher lifting volumes, and differentials generally climb as shippers comply, traders noted. Sentiment was bearish on the West Coast, where prices tumbled at mid-week after the US EIA's weekly inventory report showed another increase in the PADD 5 region that added to the West Coast's supply overhang. Also, the imminent restart of Tesoro's 166K-b/d Martinez, California refinery from work applied downward pressure on the market.

Middle distillate inventories slid 1.0MM bbl to 129.7MM bbl, bucking the upward trend seen in recent weeks but in line with forecasts. ULSD found support in the Midwest amid expectations of rising demand from the agricultural sector. Diesel and heating oil prices in the NYH edged higher as weather forecasters warned of a large, winter storm that could blanket parts of the US Northeast with snow over the weekend. Jet fuel prices climbed in the NYH despite fundamentals that softened as demand came off and output rose, traders pointed out. [Note: in the following four charts, prices for Fridays were used when available; otherwise, prices reported for the nearest days were used.]

NYH Spot Product Prices

2.74

2.89

3.04

3.19

3.34

01/18/13 01/25/13 02/01/13 02/08/13

$/ga

l

Regular Gasoline RBOB blendstock ULSD Heating Oil Jet Fuel



Gulf Coast Spot Product Prices

2.62

2.79

2.96

3.13

3.30

01/18/13 01/25/13 02/01/13 02/08/13

Date

$/gal

Regular Gasoline ULSD Heating Oil Jet Fuel

Midwest/Chicago Spot Product Prices

2.53

2.73

2.93

3.13

3.33

01/18/13 01/25/13 02/01/13 02/08/13

Date

$/gal

Group Three Regular Gasoline Chicago Regular Gasoline Group Three ULSD Chicago ULSD

West Coast Spot Product Prices

2.63

2.82

3.01

3.20

3.39

01/18/13 01/25/13 02/01/13 02/08/13Date

$/gal

Ethanol-blend CARBOB unleaded (L.A.) Ethanol-blend CARBOB unleaded (S.F.)

Jet Fuel CARB Diesel

(Feb 4, 5, 6, 7, 8)



European spot prices continue their relentless rise. Spot product prices rose across the board in the week to Feb. 8, adding to week after week of recent increases. The markets mostly borrowed strength from the East and the US, as well as from a buoyant futures complex that helped lift prompt prices.

The ULSD barge market was bearish, amid muted regional consumption, high lofty ICE gasoil futures prices, and wide backwardation. The economic malaise across the EU has tempered consumption, which might not recover until steady economic growth returns, market watchers said. Similarly, heating oil sentiment has suffered amid declining use in Greece, where a tax hike aimed at increasing revenue for the financially struggling country reportedly has driven down heating oil demand by 70%. Jet fuel margins found support as firm consumption in Asia capped East-West flows. The jet fuel markets are still riding high on winter strength in Asia, where kerosene is used as a heating fuel. Also, European refiners were seen increasing production as Asian firms were scrambling to build stocks ahead of refinery maintenance that threatened to further tighten inventories.

Gasoline prices climbed as the rally that commenced in the previous week carried over, but cracks suffered as Brent crude prices soared. Rising gasoline prices and falling stocks in the US had resulted in a sharp jump in transatlantic arbitrage bookings, which cooled off by the end of the week. "The US is a bit weaker now with all the cargoes going there, cash values are coming off and I am seeing a bit of a dip in demand," a trader said. About 550K mt (4.7MM bbl) of material was booked through the arb window for Feb., a trader said at the start of the week. The European market is expected to remain bullish going forward, however, as the spring brings refinery turnarounds that keep inventories in check and then the summer ushers in stronger demand in the US. Exports from Europe to West Africa were also seen. Naphtha cracks borrowed strength from the gasoline market, as demand from blenders remained healthy.

Fuel oil prices increased, with the LSFO grade outpacing its HSFO counterpart, resulting in the widest hi-lo spread in quite some time. Although consumption in Europe was relatively weak, demand from Asia continued to pull barrels. [Note: in the following chart, prices for Fridays were used when available; otherwise, prices reported for the nearest days were used.]

European Spot Product Prices

600

730

860

990

1120

01/18/13 01/25/13 02/01/13 02/08/13

$/mt

10-ppm-S Gasoline barges Naphtha cargoes 10-ppm-S ULSD bargesJet Fuel barges Heating Oil barges LSFO bargesHSFO barges

(Feb 4, 5, 6, 7, 8)

Asian spot prices float while inventory levels sink. In the week to Feb. 8, gasoil and jet-kerosene margins and prices were supported by falling inventories, as stocks held in Singapore dropped to a five-week low; gasoil margins climbed to a nine-month high by Friday. The



stockdraw was due in part to fewer diesel shipments arriving from Taiwan, amid an unexpected hydrotreater outage at Formosa Petrochemical's Mailiao refinery/PC complex, as well as heavier flows from Singapore to Indonesia, Malaysia, and Hong Kong. Prompt gasoil demand was also seen from Africa, while China Aviation Oil continued to pick up jet fuel cargoes, adding to its hefty volumes for Feb. and March. The declining inventories come at a time when market players are expecting a tighter market going forward, as many refineries across the region and in the Middle East plan to shut down for seasonal turnarounds during Feb.-April. Although, traders noted, once the plants return from maintenance fundamentals may sour as demand is not expected to increase fast enough to offset a sharp rise in supplies. Similarly, diesel production capacity in China is seen soaring in the months ahead, but with China's economic growth not strong enough to soak up the extra material diesel exports from the country are slated to climb, boosting availability and weighing on prices. Adding to the potential downside, Vietnam, one of Asia's top importers, may leave more product on the market as Petrolimex is expected to skip its annual term imports of gasoil due to ample domestic supplies.

Gasoline margins were driven higher as the short supply side, which is due to upcoming refinery maintenance, was exacerbated by the hydrotreater outage at Formosa's plant. Industry sources noted that production at the 540K-b/d Mailiao facility might be impacted into the following week. Singaporean inventories of light distillates, which mostly consist of gasoline, slid to a six-week valley. Naphtha prices and margins jumped to a 10-month high and an 11-month peak, respectively, as the market tightened further. "There is a serious impact on the naphtha market due to India and the Middle East exporting fewer cargoes," a trader remarked. Additional shipments are expected to arrive from Europe, but not soon enough to placate petrochemicals makers, which are snapping up barrels at high premiums to feed crackers that are running at near full tilt. In addition to the high rates, the PC firms may be stocking up ahead of the refinery turnarounds, market sources suggested.

Fuel oil sentiment improved. The 380-cst differential climbed into positive territory on Thursday to its highest in one month, and by Friday strong demand for the 380-cst grade helped squeeze the prompt viscosity spread to its narrowest in nearly three and a half years. Singaporean inventories tumbled to a two-week low, due in part to easing Western arbitrage arrivals, which had been strong since Oct. About 3.9MM mt (26.2MM bbl) of Western material is slated to end up in East Asia in Feb., down nearly 26% on the month, according to brokers. The Singaporean drawdown was also due to increased exports to South Korean utilities and Chinese teapot refineries; however, these shipments are expected to fall, as demand from North Asian utilities eases with the end of winter and consumption at teapots get supplanted with crude feedstock. Also, bunker fuel prices rose alongside those for fuel oil. [Note: in the following chart, prices for Fridays were used when available; otherwise, prices reported for the nearest days were used.]

Asian Spot Product Prices

102

111

120

129

138

01/18/13 01/25/13 02/01/13 02/08/13

Date

$/bbl

631

639

647

655

663$/m

t

92-octane Gasoline, $/bbl Naphtha, $/bbl 5K-ppm-S Gasoil, $/bblJet Kerosene, $/bbl 180-cst Fuel Oil, $/mt 380-cst Fuel Oil, $/mt180-cst Bunker, $/mt 380-cst Bunker, $/mt

(Feb 4, 5, 6, 7, 8)



Crude & Products Inventories

US crude stocks continue to climb; product inventories end split. Combined EIA crude and product inventories increased over the week ending Feb. 6 by 3.3.MM bbl to 735.3MM bbl. Inventories of crude oil rose 2.6MM bbl to 371.6MM bbl, in line with analysts' expectations, as refinery utilization slipped 0.8 percentage points to 84.2% of total capacity.

Gasoline stocks also climbed, rising 1.7MM bbl to 234.0MM bbl; analysts had expected stock levels to stay flat on the week. On the other hand, middle distillate inventories slid 1.0MM bbl to 129.7MM bbl, bucking the upward trend seen in recent weeks but in line with forecasts. The following chart shows US inventory levels, as reported by the EIA.

US Inventories

360.3 369.0 371.6

235.0 233.3 232.3 234.0

132.5 133.0 130.7 129.7

363.1

0.0

735.3

1/16/2013 1/23/2013 1/30/2013 2/6/2013

MM bb

l

Crude Gasoline Middle distillates

(Feb 6)

European product stocks climb to highest since Aug. Total ARA product inventories rose over the week ending Feb. 8 by 158K mt to 4.482MM mt, due largely to sharply higher light distillates. Recent strong demand from the US and West Africa for gasoline shipments encouraged firms to stockbuild the motor fuel, as well as naphtha for blending, in preparation for additional exports. Jet fuel inventories also swelled, but stocks of gasoil and fuel oil dipped. The following chart shows ARA inventory levels, as reported by Reuters and Bloomberg.

ARA Inventories

2,220 2,424 2,350 2,308

748 673 734 843

891 806 820 725

335 323 322 370

23698163160

0

4482

1/18/2013 1/25/2013 2/1/2013 2/8/2013

K m

t

Gasoil Gasoline Fuel Oil Jet Fuel Naphtha

(Feb 7)



Singaporean product stocks tumble; Japanese inventories rebound. International Enterprise's weekly inventory report for Singapore showed that total onshore inventories dropped 3.163MM bbl to 39.796MM bbl in the week to Feb. 6, as can be seen in the following chart. Fuel oil inventories decreased by the greatest amount, settled at a two-week low, due to increased exports to South Korea and China. Light distillates also posted a hefty drop, hitting a six-week valley amid firm demand for gasoline and naphtha. Additionally, middle distillate inventories fell, albeit not as sharply. Demand for exports pulled down stock levels to a five-week low.

Singapore Onshore Inventories

18,427 17,637 20,645 19,427

10,870 11,33211,500 10,673

11,055 11,11410,814

9,696

0

42,959

01/16/13 01/23/13 01/30/13 02/06/13

K bb

l

Fuel Oil Middle Distillates Light Distillates

Japan's product stocks increased 110K kL in the week to Feb. 2, to 10.07MM kL (63.34MM bbl), as can be seen in the following chart. Most products posted marginal to moderate stockbuilds, but gasoline inventories fell to their lowest level in 11 months. Meanwhile, overall refinery utilization slipped 0.2 percentage points on the week to settle at 82.3%, according to data from the Petroleum Assoc. of Japan.

Japanese Inventories

2,340 2,290 2,360 2,350

2,220 2,160 2,100 2,180

2,030 2,060 2,040 1,970

1,830 1,890 1,820 1,880

850 850 870 900

740 720 770 790

0

10,070

01/12/13 01/19/13 01/26/13 02/02/13

K kL

C-Fuel Kerosene Gasoline Gasoil A-Fuel Jet Fuel

(Feb 6, 7)



Retail Market, Fuel Trends, & Biofuels Blending

US EIA retail gasoline price spikes amid stronger crude. According to the US Energy Information Administration (EIA), the national average retail price for regular gasoline was $3.538/gal on Feb. 4, an 18.1¢/gal jump from the Jan. 28 price. The PADD 4 (Rockies) region's $3.144/gal was the lowest price for gasoline, while Los Angeles, California's $4.038/gal was the highest price. RFG's national average settled at $3.678/gal—an increase of 19.4¢/gal on the week. Houston, Texas' $3.341/gal was the lowest price for RFG, while the highest was Los Angeles, CA's $4.038/gal.

Meanwhile, the national average diesel price climbed 9.5¢/gal on the week to $4.022/gal; CA had the highest-priced diesel, at $4.242/gal, while the Rockies had the lowest-priced diesel, at $3.844/gal. Also, heating oil's national average price settled 5¢/gal higher, at $4.063/gal. The District of Columbia saw the highest price of $4.593/gal, and Nebraska had the lowest price of $3.505/gal. The following chart represents national average retail prices reported by the EIA.

Retail Fuel Prices, According to the EIA

3.30

3.50

3.70

3.90

4.10

1/14/2013 1/21/2013 1/28/2013 2/4/2013

$/gal

Gasoline (all grades) Reformulated Gasoline Diesel Heating Oil

MasterCard Advisors's SpendingPulse report showed that US consumption of gasoline dropped 1.6% in the week to Feb. 1, amid higher pump prices. Compared to the same period last year, however, demand was up 2.8% and the four-week moving average was up 0.1%. "The four-week year-over-year metric began to turn to positive territory,…the first growth rate since the week ending Sept. 21, 2012, and only the second time in over a year," the report stated, suggesting that demand may be stabilizing following declines throughout 2012. (Feb 4, 5)

India's fuel import duty change may have consequences for domestic refiners. The decision by India's Finance Ministry to potentially remove the 2.5¢/gal import duty on diesel and gasoline to match the lack of an import duty on crude could be a "death knell" to some of the country's domestic refiners particularly those located in the middle of India. Furthermore, private refiners like Essar Oil and Reliance Industries could look to export even more of the refined products from their facilities. Arguing against the abolishment of the import duty the Petroleum Federation of India (Petrofed) wrote, "While a change from trade parity pricing to export parity pricing may benefit fiscal management of the government in short term by lowering its subsidy burden but it would render a serious blow to the domestic refineries." (Feb 5)



Crude Market and E&P Activities

WTI begins to close discount to Brent with pipeline expansions. After selling at a deep discount to the Brent benchmark over the past few years, with a spread as high as $30/bbl in Sept. 2011, WTI is finally beginning to realign with its international counterpart. The price spread between the two benchmarks fell from $25/bbl at end-2012 to just $18/bbl on Jan. 31, with the price of WTI rising 6.1% month-on-month to $97.49/bbl alongside Brent's 4% increase to $115.55, and constituting WTI's most successful Jan. performance since 2006. Analysts have suggested that the Jan.11 completion of Enterprise Product Partners LP's Cushing-to-Gulf Coast Seaway pipeline expansion, increasing its capacity from 150K b/d to 400K b/d, has contributed to WTI gains, as the expansion is set to move up to 7.5MM additional bbl/month out of the product-swamped Midwest, where supply gluts have contributed to an ongoing devaluation of the US crude grade. Although the Seaway pipeline has experienced some storage hiccups since bringing its new capacity into service, Enterprise expects the completion of an associated lateral pipeline in 3Q or 4Q to fully alleviate bottlenecking along the stretch. And although it won't be able to drain the Midwest entirely of its oversupply, Seaway is just the first of numerous pipeline projects, including the contentious Keystone XL, which have been proposed to increase the movement of WTI to refineries and thus restore its value. Pipeline infrastructure expansion is expected to further narrow the Brent/WTI spread going forward, with WTI prices to rise as a result and Brent prices to remain comparatively steady.

Goldman Sachs noted that it expects the spread between WTI and Brent to average $21/bbl in the 1Q due to higher fuel demand from emerging countries coupled with declining growth in Canadian oilsands production and reduced exports from Saudi Arabia and Iran. According to the investment back, "We expect the global market to remain tight throughout the first quarter, and the risks to our forecast have shifted to the upside over the past weeks. The recent rally has been driven by improving fundamentals rather than by an increasing risk premium." However, the bank believes that within six months time the WTI-Brent spread will narrow to $5/bbl. (Feb 4, 8)

US cash crude prices end mixed as arbitrage widens. In the week to Feb. 8, spot crude prices were mostly split, with inland grades falling but waterborne crudes rising amid support from a wider transatlantic arbitrage spread. Prices for the US WTI benchmark slid, but UK Brent jumped, giving Brent a $23.18/bbl premium to WTI by Friday's close.

Prices for LLS rose 20¢/bbl to $117.47/bbl, while HLS increased $1.20/bbl to $118.17/bbl. Prices for WTI (Midland) slid $1.05/bbl to $94.22/bbl, while WTS dropped $3.20/bbl to $89.72/bbl. Also, prices for Mars slipped 85¢/bbl to $111.27/bbl, and ANS increased $2.51/bbl to $114.58/bbl. [Note: in the following chart, prices for Fridays were used when available; otherwise, prices reported for the nearest days were used.]

US Spot Crude Prices

80

90

100

110

120

1/18/2013 1/25/2013 2/1/2013 2/8/2013

$/bbl

Light Louisiana Sweet (GC) Heavy LA Sweet (GC) WTI at Midland (GC)West TX Sour (GC) Alaskan North Slope (CA) Mars (GC)

(Feb 4, 5, 6, 7, 8)



WCS crude prices rally to narrowest discount since Oct. In the week to Feb. 8, Western Canada Select crude prices jumped after several bear factors—including downed refinery capacity and pipeline shipping constraints—that have plagued the crude in recent weeks and months eased back, allowing prices levels to begin to normalize. WCS closed at $71.47/bbl, a discount of $24.25/bbl to the US benchmark, which settled lower on the week at $95.72/bbl. Prices for US Bakken crude and Canadian Syncrude followed the benchmark down. Bakken ended at $92.72/bbl, a $3/bbl discount, and Syncrude closed at $96.97/bbl, remaining above the benchmark with a $1.25/bbl premium. [Note: in the following chart, prices for Fridays were used when available; otherwise, prices reported for the nearest days were used.]

US Bakken and Canadian Crude Prices

$57

$68

$79

$90

$101

1/18/2013 1/25/2013 2/1/2013 2/8/2013

Price

, US$

/ bbl

Bakken (MN, US) Canadian Synthetic Crude (Edmonton, AB)Western Canada Select (AB) West Texas Intermediate (US)

(Feb 7, 8)

US Gulf Coast may stop importing light crude next year. Increased supply of light crude from Bakken and Eagle Ford tight oil fields will likely displace imports to the Gulf Coast by 2013, according Bank of America's Sabine Schels. The area currently processes about 500K b/d of imported light crude, which may be unnecessary once infrastructure to transport tight oil to the coast is in place. Imports of heavier crudes are unlikely to be affected because of their high middle distillate yields. (Feb 4)

Production declines in Alaskan oilfields. Crude output from the US state's North Slope fell 7.9% year-on-year last month, from 626.2K b/d in Jan. 2012 to 576.9K b/d in Jan. 2013, a decline from this past Dec., as well, when output averaged 582.2K b/d. According to Alaskan experts, this aligns with natural declines which have been ongoing since 2002, with existing wells yielding consistently less crude and no new wells being drilled. The state's Valdez marine terminal saw feedstock inventories fluctuate between 2.49MM bbl and 4.97MM bbl through Jan., averaging 3.58MM bbl for the month. Shrinking output from Alaska's North Slope has driven West Coast refiners including Phillips 66 and Tesoro Corp. to ramp up investigation of Midwest crude shipments, in search of new feedstock sourcing, while Flint Hills Resources LLC has taken a North Pole, Alaska refinery crude unit offline. (Feb 1)



Imperial oil to begin production at Kearl River as oilsands output fell in Jan. The Canadian oil major, a subsidiary of ExxonMobil, announced on Feb. 1 that bitumen production at the company's Kearl River oilsands project, located in Alberta, Canada, will begin in March; production was expected to start up by end-2012, but weather conditions forced a schedule shift. The project is expected to produce 37K b/d initially, and 100K b/d by year's end, with Imperial Oil noting amidst a major regional production glut and corresponding record WTI and Brent discounts that it will be able to utilize the entirety of the project's output at its own refineries, although it may choose to sell product should conditions prove appropriate.

In Jan., production at Suncor Energy Inc.'s oilsands operation near Fort McMurray, Alberta dropped by 10% to 346K b/d. This number does not reflect Suncor's stake in Syncrude Canada Ltd., a joint venture which had also suffered a production drop of 5% to 277K b/d in the same month. (Feb 1, 4, 5)

China, Chevron stall loan-for-oil talks with PDVSA. According to anonymous sources, Venezuelan state oil company PDVSA has had difficulty in talks seeking $6B in loans from China and oil firm Chevron. China has lent Venezuela upwards of $36B in the past several years, and has been repaid with oil shipments. This time around, problems cropped up as the Chinese wanted modifications to the deal that Venezuela would not accept, but one source reported that the difference was in the process of being cleared up, and the Chinese are expected to extend another $4B to the South American OPEC member.

In talks with Chevron, it was PDVSA that wanted to modify the $2B arrangement, with the oil major resisting. Both companies refused to comment on the talks, and any progress has not been made public. It is possible that some of the difficulties are due to uncertainties regarding the status of Venezuelan President Hugo Chavez, who has made no public appearances since undergoing surgery for cancer in Dec. (Feb 1)

LUKoil argues for Adam Smith's capitalism in Russia. CEO Vagit Alekperov of the private Russian energy firm argued recently that increased competition would spur innovation in accessing Russia's Arctic resources. Warning that Russian expertise might fall behind that gained by US producers, Alekperov called for "civilized, equal competition," claiming that current regulations restricting the country's Arctic continental shelf to state-controlled organizations will handicap the country's ability to compete on a global scale. While current regulations exist, however, LUKoil will content itself with investing 300B RUB ($10B) in the Caspian Sea's Korchagin and Filanovsky fields. (Feb 4)

Saudi to reduce crude prices to Asia for March delivery. As a result of wanting to maintain its market share and an expected drop in demand due to refinery maintenance season in North Asia starting, Saudi Arabia dropped the price on its Asia-bound grades by $1.30-2.10/bbl resulting in the lowest premiums seen since Oct. Saudi's key export grades to Asia, Arab Light and Arab Medium, saw prices drop by $1.50/bbl and $1.35/bbl, respectively, to a premium of $1.95/bbl to Oman/Dubai for Arab Light and a discount of 15¢/bbl to Oman/Dubai for Arab Medium. Arab Super Light saw its price drop by $2.10/bbl to a premium of $5.95/bbl to Oman/Dubai. The price for Arab Extra Light declined by $1.90/bbl to a premium of $3.75/bbl to Oman/Dubai. Finally, Arab Heavy saw a price drop of $1.30/bbl to a discount of $2.40/bbl to Oman/Dubai. Furthermore, the Saudis may continue to lower prices over the coming months as demand is expected to remain subdued throughout the refinery maintenance season. Commenting on the drop in prices a trader noted, "I think [the prices] are good. [The cuts are] within expectation. But some [traders] were expecting [cuts of] over $1.50/bbl [in the differentials]." (Feb 5, 6)

Saudi Arabia to supply Japan with "emergency" crude supplies. The two nations will sign an agreement on Feb. 9 or 10 to allow Japan to make emergency requests to Saudi Arabia for additional supplies of crude, though it is not known exactly how much additional supply the world's third largest



oil-consuming nation can request. Under the agreement, an emergency telephone hotline will be established between the two countries that will allow Japan to quickly call on Saudi Arabia for additional oil in the event extraordinary circumstances arise such as a terrorist attack. Japan pressed for the deal in light of Saudi Arabia stating it will start to lower crude exports from its current level of 9.05MM b/d due to growing domestic consumption and expanding refining capacity within the country. Commenting on the deal an analyst at oil consultancy Energy Aspects stated, "If true, it shows how nervous importers are due to the fragility in the Middle Eastern situation, particularly Asian buyers," adding that ongoing western sanctions related to Iran's nuclear program has lowered the amount of Iranian barrels on the market, further exacerbating fears over a sudden loss in crude supplies. (Feb 7)

Turkey imports Iranian oil despite sanctions; India encounters insurance issues. A new round of US sanctions against Iran that went into effect on Feb. 6, intended to further pressure the OPEC member to abandon its nuclear ambitions, will target banks that allow Iran to convert earnings from crude sales back into Iranian currency. In some cases, the sanctions will have no effect; for example in Japan, Iranian oil is already paid for in yen at Iran's request. Likewise, according to Turkish officials, its sole refiner Tupras will not be affected by its continuing purchases of Iranian crude. According to shipping sources, Tupras received a 150K mt (1.11MM bbl) Iranian crude cargo at the country's Aliaga port, and two 140K mt (1.02MM bbl) cargos at Tutunciftlik, contributing to 100K b/d of Iranian imports through Jan. and, in turn, maintaining a streak of consistent import volumes which have persisted since Sept. of last year. Turkish imports from Iran have been halved since an early 2012 peak of 250-280K b/d by western sanctions; the country received a June 2012 waiver from sanctions after cutting 20% of its Iranian imports, and in Dec. received a 180-day waiver renewal. At present, Turkey is transporting the imported crude via Iranian NITC tankers in order to avoid EU marine insurance sanctions first implemented in July 2012. Turkey stands with South Korea, India, Japan, and China as major persistent Iranian buyers; all have received sanction waivers, but continue to contribute to overall Iranian crude export volumes, which rose to a six-month high of 1.4MM b/d in Dec.

India, on the other hand, may have to stop payments made in widely accepted euros, and instead increase payments in rupees in order to avoid repercussions. The Asian nation intends to reduce Iranian imports by a further 10-20% in FY 2013 to about 15MM mt (300K b/d), with deeper reductions anticipated if the cost of Iranian imports remains high due to just enacted tighter US-led sanctions. In Dec., the US renewed a 180-day waiver that allowed India and eight other countries to continue importing crude from Iran so long as those import volumes continue to decline. Commenting on the situation an analyst with FACTS Global Energy stated, "India has no choice but to show the US it is cutting down crude imports from Iran if it wants to keep the exemption from sanctions. It's also in India's interest to look at other options from where they can source oil." For example, Mangalore Refinery and Petrochemicals Ltd. (MRPL) may import 3.8MM mt (76.3K b/d) of Iranian oil in FY2013, down from its previous term contract of 5MM mt (100.4K b/d). Based on a 20% reduction figure (60K b/d) in imports, Iran stands to lose $2.5B in crude sales to India.

Additionally, reinsurers have begun refusing coverage to Indian refineries utilizing imported Iranian crude, posing a major problem for refineries, with Indian insurers unable to cover domestic refineries alone due to the extent of industry expenses. India's sole reinsurer, GIC Re, recently clarified its inability to recover claims from Iranian crude-processing facilities in a communication release, saying: "We had recently received a request from MRPL for a cover for their SPM on discharge of Iranian crude…During the deliberations it emerged that apparently the refinery processing Iranian crude would also be out of the ambit of any cover and losses would not be payable by the reinsurers on the protection program of the companies…It also dawned on the insurers that this fact had not been made clear to them that they were uncovered while processing Iranian crude owing to the sanctions clause. It is therefore felt that the General Insurance Council should organize for a discussion of the insurers to identify the issues involved and attempt to find out possible solutions." (Feb 1, 3, 5, 6)



Iran claims record oil exports income in 2011-2012. The National Iranian Oil Co. (NIOC) claims that the country made $110B on oil exports in the 2011-2012 Iranian year that ended March 29, 2012, a record for the Middle Eastern nation despite ongoing western sanctions over Iran's nuclear program. According to NIOC, improvements in efficiency and increased investments in upstream projects to boost production levels allowed for the record earnings in oil exports. (Feb 6)

Iraqi oil output soars, analysts look ahead. With Iraq having produced 3.4MM b/d of crude in Dec., and set to continue increasing output after years of relative inactivity, analysts including the International Energy Agency (IEA) have begun to contemplate the country's future role in the global oil market. According to the IEA, Iraq could increase crude output to 6.1MM b/d by 2020, and further to 8.3MM b/d by 2030, which would position the country to provide 45% of new oil demand through 2035; but in order to meet those targets, Iraq will have to invest approximately $530B in crude production and storage infrastructure, along with supporting electrical, water, and natural gas systems, as it works to repair the damage which long years of political turbulence and neglect have brought on its oil fields. Such an investment would require Iraq to contribute approximately 10% its $115B/y oil export revenue to industry upgrades, with approximately 75% of revenue already being used to fund basic government services and restoration. But the gains could be enormous, totaling $5 trillion in revenues through the next decade.

According to IEA executive director Maria van der Hoven, Iraq could overtake Saudi Arabia to become the world's most prolific oil producer, assuming appropriate investments, and will likely send the bulk of its crude output to China, India, and other emerging Asian markets, where oil demand is increasing exponentially as major providers such as Saudi Arabia and Russia push the limits of their production capacity of easily-accessible oil. Iraq, alternatively, has vast stores of so-called "cheap oil", that is, crude which can be easily extracted with the use of inexpensive technology. Iraq contains proven reserves of 143MM bbl of crude, the world's fourth-largest, with just 30-40% of the country having been explored thus far. Still, Iraq may experience many obstacles as it attempts to transform itself into one of the world's largest oil exporters, especially as oil industry investment remains fraught and uncertainty due to ongoing disputes between Baghdad and Kurdish governments regarding control of the country's northern reserves. According to Platt's Iraq Oil Report editor Ben Lando, "They have to decide whether to invest in Kurdistan or the rest of Iraq. It's really a political issue more than anything else." (Feb 4)

Shale Plays

Development of non-toxic fracking fluids promising, usage still uncertain. Oil and gas industry technology developers including Halliburton Inc. have been developing non-toxic fluids for use in hydraulic fracturing in order to alleviate concerns about the possible environmental effects of fracking; however, it is unclear as yet how widespread use of such fluids will become. Halliburton's CleanStim product is manufactured wholly with food-industry ingredients, something specialists have identified as an optimal end goal for drillers, but the company's CleanStim production manager Nicholas Gardiner has declined to comment on how many customers are using the product, which Halliburton awarded a perfect score on its own fluids-scoring system, noting only that, "The customers who do use it certainly like the material." Although environmental groups have reacted positively to CleanStim and products like it, many have been careful to note that fracking fluid chemicals hardly constitute the process's sole environmental issue, pointing to wastewater, air pollution, and the possibility of fracking fluid migration and surface spills as additional concerns. Use of new, non-toxic fluids may be mitigated by technical and cost issues, and affected by geological variance which dictates the use of different injection fluids according to the type of shale rock being drilled. (Feb 3)



Benchmark price for Eagle Ford oil is forthcoming.

The development within shale plays throughout the US has led some to speculate that a new crude benchmark could emerge once new pipeline capacity along the Gulf Coast allows greater movement of crude from the Midwest to the region. Specifically, talk has emerged of an Eagle Ford benchmark that would be priced in connection with Enterprise Product Partners' 750K-bbl Echo Terminal in Houston, TX. Commenting on the potential for a new Eagle Ford benchmark, Sandy Fielden, the director of energy analytics at RBN Energy added, "More likely a Houston quote for WTI will emerge. There will be an Eagle Ford quote or index, but it won't be as important as WTI. After more pipeline capacity comes online, WTI will make its way to the Gulf Coast from both the Permian Basin and Cushing." He did go on to state that he expects crude prices in the Gulf Coast and Midwest to move closer over the course of the year. (Feb 8)

EPA: US oil and gas production becomes major GHG emitter. In a recent report on climate change and emissions, the US Environmental Protection Agency (EPA) identified oil and gas production as the second largest stationary emitter of greenhouse gasses in the country. In 2009, emissions from drilling operations and leaks from product pipelines amounted to 225MM mt of carbon dioxide equivalents. That amount is surpassed only by the power generation industry, which exceeds upstream emissions by an order of magnitude.

Among oil and gas producers, the top emitters noted were ConocoPhillips' San Juan basin project, and operations by Apache Corp. in the Permian basin. According to the Council on Foreign Relations' Michael Levi, this "is an area where we have the technological answers to our problems . . . we just need to make the decision to do it." (Feb 6)

Tesoro may reverse North Dakota pipeline system. The company is considering a reversal of its High Plains pipeline system in North Dakota, which currently transports Bakken crude from north of the state's Lake Sakakawea to Tesoro Logistics's own 70K-b/d Mandan, ND refinery, located south of the body of water. According to Tesoro, a reversal would capitalize on transportation disparities between the state's northern and southern regions: north of the lake, an abundance of rail terminals and outbound pipeline capacity provide a combined 610K b/d transport capacity out of the state, dwarfing the region's 400K b/d drilling production. Meanwhile, south of the lake there exists 340K b/d of takeaway capacity but 350K b/d of production, with production in both regions expected to grow as the shale boom rages on. According to Tesoro vice-president of logistics Rick Weyen, "We're working hard with a lot of rail facilities to come up with connection agreements…We think rail is long term, it's going to be the way Bakken crude is moved…the pipeline is there to serve and help the shippers get the crude from the production area to the rail facilities." (Jan 31)

US shale gas boom draws European industry. In 2012, the US displaced Russia as the world's leading natural gas producer, driving down energy prices and making the US an attractive location for energy-intensive industries. While Russian Energy Minister Alexander Novak expressed confidence that Russian gas would find a more than adequate market in Asia, concerns have risen in Europe as high energy costs have driven European companies to relocate to the US. While Europe possesses extensive natural gas reserves, environmental regulations have delayed their use. France holds the largest gas reserves in Europe, estimated at 180 trillion cf (5.1 trillion m3), but has imposed a ban on hydraulic fracturing, meaning that the gas remains locked deep within the earth. Environmentalists oppose fracking out of concerns for groundwater contamination and seismic activity, but policy-makers may have to rethink their approach as cheap energy in the US draws business away from an economy that is already struggling to recover from the Great Recession. (Feb 3)



Shale gas prospects and politics in former Russian allies. The US State Dept.'s Special Envoy Coordinator for International Energy Affairs said the US will partner with the Ukrainian Energy Ministry to provide the Eastern European nation with technologies that allow for the ecologically safe production of shale gas. The Ukrainian government is seeking to reduce gas imports from Russia to improve its energy security. The deal with the US comes a week after Royal Dutch Shell signed a $10B contract to develop the Yuzkovy shale gas field, with commercial production from the field expected by 2015.

After a long period of inactivity due to a national shale gas drilling moratorium which expired in Dec. 2012, Chevron has finally been granted eastern Romanian shale exploration zoning certificates, with local authorities noting, "We have delivered the certificates because this is what legislation requires us to do." The US oil major must still be granted a construction permit before drilling can commence, and has emphasized that it will comply strictly with Romanian, EU, and industry standards going forward, with the practice of hydraulic fracturing still driving controversy in the region due to potential environmental concerns including groundwater contamination and drilling-induced seismic activity. Drilling was temporarily banned in Romania after a new center-left coalition came to power in May 2012, overturning existing approvals from the prior center-right government. According to a US Energy Information Administration (EIA) study, Bulgaria, Hungary and Romania may possess combined 538B m3 (19 trillion cf) of shale gas reserves; Chevron will attempt to begin drilling in H2 2012.

Meanwhile, Chevron has also received presidential support for similar shale exploration plans in Lithuania, where lawmakers and citizens have experienced some contention over the possibility of shale drilling. Nevertheless, Lithuanian President Dalia Grybauskaite has emphasized the necessity of investigating alternatives to continued dependence on Russian natural gas, which the country currently purchases from Gazprom. Lithuania's recoverable shale gas reserves are estimated at 180B m3 (6.4 trillion cf), which could fulfill approximately 60 years of domestic demand; the country's reserves are also located just 1.2 miles (2 km) beneath the surface, significantly more accessible, and more cheaply accessible, than those in the neighboring country of Poland. Chevron in Oct. purchased a half stake in domestic LL Investicijos UAB, and will assist that company in pursuing seismic exploration and well design under shale exploration rights purchased in a Jan. auction. (Jan 31, Feb 5)

BP continues to explore Oman's tight gas reserves. The British energy major just completed drilling its 13th well in Oman's tight gas fields. So far, BP has invested $650MM in a five-year appraisal program focused on assessing the possibility of producing high quantities of gas from the country's Khazzan and Makarem tight gas fields. Asked about the ongoing appraisal program, the company's CEO Bob Dudley stated, "The results as we go through this appraisal are important for discussion of the gas price, so the negotiations continue." If the program is deemed successful, BP will begin commercial gas production in Oman of 1B cf/d (10.3B m3/y) in 2016. (Feb 5)

Refinery Shutdowns & Throughput Changes

IIR: US refiners to take more capacity offline. According to IIR Energy, US refineries are expected to take 1.715MM b/d of refining capacity offline in the week ending Feb. 15, up from the 1.570MM b/d idled in the previous week, as can be seen in the following chart.



US Refinery Offline Capacity

0.75

0.95

1.15

1.35

1.55

1.75

01/04/13 01/11/13 01/18/13 01/25/13 02/01/13 02/08/13 02/15/13

Offli

ne C

apac

ity (M

M b/

d)

(Feb 8)

US refiners schedule maintenance for the coming months. The following table shows refinery and/or unit closures and restarts that were announced or updated between Feb. 1 and Feb. 8.

Refinery location/capacity Details Glitches, unplanned outages, and interruptions (in chronological order of initial event)

Monroe Energy's Trainer, PA, US/185K b/d

The catalytic cracker which has been shut since Dec. was restarted on Feb. 5. The unit was down for repairs to address the issues with a slurry oil circuit for 10 to 14 days. The 52K-b/d FCCU is preparing to restart. The unit has been down since Feb. 2.

Phillips 66's Westlake, LA, US/ 239K b/d

The 60K-b/d CDU was restarted on Feb. 1 after being offline since Jan. 27, but remains below normal operating levels. The 53K-b/d VDU has returned to normal operations as well.

Coffeyville Resources's Coffeyville, KS, US/114K b/d

The 36.9K-b/d FCCU was shut. Excess emissions were observed from the FCCU’s EDP on Jan. 29 and Feb. 3.

PBF Energy's Toledo, OH, US/170K b/d

An FCCU was shut after a fire erupted on Jan. 30. Some units are running at reduced rates and other units on standby.

Phillips 66's Rodeo, CA, US/ 120K b/d

An equipment failure occurred on Feb. 1.

Philadelphia Energy Solutions' Philadelphia, PA, US/330K b/d

A reformer unit was shut the week ending Sat Feb. 2.

Husky Energy's Lima, OH, US/161.5K b/d

An incinerator malfunctioned on Feb. 2.

Tesoro's Golden Eagle, Martinez, CA, US/161K b/d

The refinery reported that a major unit that was down has been restarted on Feb. 6. The hydrocracker was shut on Feb. 2 will be shut for three weeks due to a leak.

Alon USA Energy's Big Spring, TX, US/70K b/d

A fire in a vacuum tower was quickly extinguished on Feb. 3. The fire was caused by a leak from the bottom of the tower which was in the process of being shut for planned work.

BP's Whiting, IN, US/ 384.8K b/d

Brief elevated flaring occurred on Feb. 4.

North Atlantic Refining’s Come By Chance, Newfoundland, Canada/ 115K b/d

A power outage shut down the refinery on Feb. 4. The power had been restored on Feb. 5, but the refinery was still down to assess damage from the outage.



Refinery location/capacity Details Deer Park Refining's Deer Park, TX, US/327K b/d

A pinhole leak on the sour gas feed forced an evacuation of the area on Feb. 5.

Valero Energy's Corpus Christi, TX, US/200K b/d

Flaring occurred due to a power outage on Feb. 6. A 12K-b/d hydrocracker was restarted on Feb. 7 after it was shut due to the power outage.

PDVSA's Amuay, Venezuela/ 640K b/d

The Flexicoker was shut on Feb. 6 and is expected to be down for a week. There is a partial obstruction in the pipeline.

Valero Energy's Port Arthur, TX, US/310K b/d

Flaring occurred due to the shutdown of a saturated gas recovery unit on Feb. 6. The unit was repaired on the Feb. 7.

Phillips 66's Ponca City, OK, US/187K b/d

The gasoil hydrotreater has been shut for short term repairs that will take the coker out of service on Feb. 7.

Marathon Petroleum's Garyville, LA, US/436K b/d

Flaring occurred at the refinery on Feb. 7. Operational issues are suspected as the cause.

Citgo Petroleum's Corpus Christi, TX, US/156.8K b/d

A release of butanes was reported after a pressure safety valve was opened on Feb. 7. The line was isolated to stop the release.

Planned shutdowns and maintenance (in chronological order of event) Note: *** marks new planned work. Monroe Energy's Trainer, PA, US/185K b/d

On Feb. 2 the refinery was preparing to restart the 52K-b/d FCCU. Work began on Jan. 1 and was expected to take two weeks.

Valero Energy's Corpus Christi, TX, US/200K b/d

An FCCU was expected to be down for maintenance from Jan. 13-Feb. 24.

Philadelphia Energy Solutions' Philadelphia, PA, US/330K b/d

Planned maintenance on the 200K-b/d CDU and the 52.4K-b/d VDU in the Girard Point section started on Feb. 2.

Suncor's Edmonton, Alberta, Canada/135K b/d

Flaring occurred on Feb. 3 due to operations process work.

LyondellBasell's Houston, TX, US/280.4K b/d

The small crude section has been shut for planned work on Feb. 5. The units shut include the 130K-b/d CDU and the 95.5K-b/d VDU. Work is expected to be completed by the end of March.

Valero Energy's Wilmington, CA, US/135K b/d

An Alkylation unit and FCCU were shut down on Feb. 5 for two weeks for work.

Marathon Petroleum's Catlettsburg, Kentucky, US/212K b/d

Planned work is scheduled for late Feb. The 24K-b/d catalytic reformer is expected to be down until the end of March. The alkylation unit will be shut Feb. 9 and expected to restart Feb. 28. The ADS unit will shut on Feb. 10 and restart March 20. The hydrogen unit will shut on Feb. 11 and restart March 4. The SDA unit will shut Feb. 18 and restart March 24. The FCCU will shut Feb. 18 and restart March 9. The SRU will shut Feb. 25 and restart March 11. ***

BP's Whiting, IN, US/ 384.8K b/d

The restart of a 260K-b/d CDU will be delayed until July. The unit was expected to restart before May. A 120K-b/d delayed coker and a 120K-b/d gas oil hydrotreater should be started in December.

BP's Carson, CA, US/ 252.2K b/d

The refinery reported planned flaring to take place Feb. 9-16 as the refinery restarts a FCCU and an alkylation unit.

Phillips 66's Wood River, IL, US/306K b/d

The refinery plans to take down two CDUs with a combined capacity of 290K-b/d on Feb. 24 for 34 days of planned work. A 38K-b/d hydrocracker will be out the first week of March for 34 days of maintenance. A 15K-b/d reformer and a diesel hydrotreater will also be shut the first week of March for two weeks of planned work. ***

Motiva Enterprises's Norco, LA, US/236K b/d

The refiner might shut down an FCCU for a period in 2013 to conduct maintenance on the unit, according to trade sources. ***

BP-Husky Refining's Toledo, OH, US/152K b/d

The refinery will close for a month of planned maintenance on an alkylation unit in April. ***

Tesoro's Kapolei, HI, US/ 93.7K b/d

Refinery to be shut down permanently and turned in a terminal in April. ***



Refinery location/capacity Details Husky Energy's Lloydminster, Saskatchewan, Canada/ 25K b/d

A planned 45 day turnaround is scheduled for mid-May. A complete shutdown will last for 28 days during this time. An 82K-b/d heavy oil upgrader will start in the Fall. Separately a 25 day shutdown will occur in April. ***

Husky Energy's Prince George, British Columbia, Canada/12K b/d

A planned 30 day turnaround is scheduled for mid-May. ***

Phillips 66's Linden, NJ, US/ 238K b/d

The refinery plans to perform a major overhaul of a FCCU Sept. 2013. ***

(Feb 1, 3, 4, 5, 6, 7, 8)

Eastern Europe, Middle East plan to conduct refinery turnarounds. The following table shows refinery and/or unit closures and restarts that were announced or updated between Feb. 1 and Feb. 8.

Refinery location/capacity Details Glitches, unplanned outages, and interruptions (in chronological order of initial event)

Essar Oil's Stanlow, UK/ 272K b/d

The repairs to the furnace that was hit by a fire on Jan. 12 were completed and the unit has been restarted. The cause of the fire is still under investigation.

ExxonMobil's Rotterdam, Netherlands/191K b/d

Elevated flaring occurred on Feb. 1. There has been partial cooling in the 41.5K-b/d Flexicoker. The 20.5K-b/d gas oil hydrotreater and the 24.5K-b/d coke naphtha hydrotreater remain decreased since Feb. 2.

Planned shutdowns and maintenance (in chronological order of event) Note: *** marks new planned maintenance. Total's Donges, France/ 230K b/d

The refinery was expected to be shut down for a six-week turnaround from Feb. 4.

Saudi Aramco's Riyadh, Saudi Arabia/120K b/d

The refinery has been shut for a month of planned maintenance on Feb. 4.

Caltex Oil's Cape Town, South Africa/110K b/d

The refinery will close on Feb. 18 for scheduled maintenance. Work is expected to last until mid-March.

Bayernoil's Vohburg, Germany/120K b/d

The plant will undergo a partial, three-week turnaround starting end-Feb. ***

Ceska Rafinerska's Litvinov, Czech Republic/110K b/d

The refiner plans to conduct maintenance work at an HCU during March. The refiner plans to conduct maintenance again on the HCU in October which will last for four weeks. ***

INA's Rijeka, Croatia/90K b/d The refinery will be taken offline for a turnaround in spring 2013. *** Kuwait National Petroleum's Mina al-Ahmadi, Kuwait/ 466K b/d

The refinery will be undergoing a two month turnaround in early April. ***

Repsol's Bilbao, Spain/ 220K b/d

The refinery plans a 40-day maintenance shutdown of a reformer and a CDU, beginning in April. ***

Tamoil's Collombey, Switzerland/72K b/d

Refinery to shut down for maintenance in May and June. ***

Petrom's Ploiesti, Romania/ 90K b/d

The refinery will conduct general maintenance for 30 days in Jan. 2014. ***

(Feb 4, 5, 6, 7)

NNPC successfully rehabs, upgrades Port Harcourt. Following its nitrogen plant being down for over a year, Nigerian National Petroleum Corp. (NNPC) is reporting that is has successfully rehabilitated and upgraded its 210K-b/d Port Harcourt refinery following recently completed maintenance work. In addition to bringing the nitrogen plant back online, NNPC also completed upgrades at the



refinery's cat reformer and naphtha hydrotreater. Despite the successful unit restarts and upgrades, the company is continuing to voice concern over ongoing disruptions to the refinery's crude supply and product evacuation conduits by vandals, resulting in less than optimal capacity utilization. (Feb 5)

Asian refiners plan to carry out big turnarounds. The following table shows refinery and/or unit closures and restarts that were announced or updated between Feb. 1 and Feb. 8.

Refinery location/capacity Details Glitches, unplanned outages, and interruptions

Formosa Petrochemical's Mailiao, Taiwan/540K b/d

A secondary unit was unexpectedly shut on Feb. 7. A hydrotreater was shut on Feb. 4 and is expected to be down for 7-10 days.

Planned shutdowns and maintenance (in chronological order of event) Note: *** marks new planned maintenance. CPC Corp.'s Kaohsiung, Taiwan/270K b/d

The 100K-b/d CDU is scheduled for planned work sometime between March 1 and April 9. ***

Kyokuto Petroleum Industries's Ichihara, Chiba, Japan/171.5K b/d

The refinery will be offline while maintenance is conducted on the CDU from March to April. ***

GS Caltex's Yosu, South Korea/750K b/d

The refinery plans to shut the 330K-b/d CDU and the 60K-b/d HCU for one month of maintenance in March. ***

SK Energy's Ulsan, South Korea/817K b/d

The refinery plans to close two CDUs for maintenance in H1 2013. The 110K-b/d crude unit will go down for about one month of work from mid-March. A timeframe for the second unit was not identified. ***

PetroChina's Dalian, China/800K b/d

And unspecified unit will be down for maintenance in April. ***

Sinopec's Guangzhou, Guangdong, China/210K b/d

CDU to be shut down starting in April. The unit is planned to be offline for 45 days. ***

Formosa Petrochemical's Mailiao, Taiwan/540K b/d

The refinery plans to shut the No. 1 and 2 RDS units in 2Q. Units to be offline for 35-40 days. The CDU will also be offline in the 2Q for 45 days. ***

Indian Oil's Koyali, Gujarat, India/296.5K b/d

An FCCU is slated for maintenance during 2Q, according to trade sources. ***

Shell Eastern Petroleum's Palau Bukom, Singapore/462K b/d

The refinery plans to perform maintenance on one of its three CDUs in April and May. Unit to be offline 30-40 days. ***

Thai Oil's Sriracha, Thailand/193K b/d

The refinery will shut a CDU for 2-3 weeks in May. Maintenance will be performed on an HCU as well. ***

Cosmo Oil's Chiba, Japan/228K b/d

The 100K-b/d No. 1 CDU is expected to restart the end of April. The unit has been down for maintenance since May 7. ***

Sinopec's Fujian, China/240K b/d

The refinery will undergo a 50 day overhaul and upgrade in the 4Q of 2013. ***

PTT's Bangchak, Bangkok,Thailand/120K b/d

The refinery plans to shut a CDU for 40 days in the 1Q of 2014. After the shut down the refiners capacity would rise from 120K-b/d to 140K-b/d. ***

JX Holdings's Muroran, Japan/180K b/d

The company plans to shut a VDU, RDS, GOH, and a CDU in March 2014. The refinery will shut for planned reorganization. ***

(Feb 4, 5, 7)



Refinery Expansion, Upgrades & Construction Activities

BP's Whiting refinery to see upgrades take full effect in 2014. The company's 405K-b/d Whiting, IN (US) facility continues to undergo $4B worth of upgrades intended to increase its current 80K b/d heavy crude capacity to 350K b/d, with its 225K b/d Pipestill 12 crude distillation unit, having gone offline in Nov., expected to come back online mid-year. Full upgrades will not come online for six to nine months thereafter, with units including a gasoil hydrotreater, a sulfur recovery unit, and a coker to return to service in sequence following the CDU's restart. BP officials have suggested that the refinery will not begin functioning at full capacity until 2014, placing further pressure on Canada's oversupplied Alberta region, which has seen it crude benchmark experience severe devaluation as a result of increased production and insufficient transportation out of the area. BP's project will allow the company to utilize greater amounts of Canadian oilsands, but as Energy Aspects Ltd. chief oil market strategist Amrita Sen points out, "This is more bearish for Canadian crude…They thought they were going to be able to send their crude down to Whiting in [3Q], now it's going to be 2014."

As BP focuses on ramping up Canadian and inland US crude processing at its Northern Tier facilities, the company is set to conclude the $2.4B sale of its 400K-b/d Texas City, TX refinery to Marathon Petroleum. and, pending regulatory review, the $2.5B sale of its 266K-b/d Carson refinery in Los Angeles area to Tesoro. (Feb 5)

Continental restarts small Kentucky refinery. A small refinery in Somerset, Kentucky has reopened after a three year closure, having been purchased and upgraded by Continental Refining Co. According to owner Demetrios Haseotes, the facility is currently running only at about 40% capacity, but should reach full output of 5.5K b/d during the summer. It is processing local sweet crudes, provided by Sunoco Partners Marketing and Terminals LP and Regal Fuels. Continental intends to invest $60MM in upgrades to the plant in coming years. (Feb 4, 6)

Bakken refinery a low priory for environmental lobby. Calumet Specialty Products Partners, L.P. and MDU Resources Group have formed a partnership to build a 20K b/d diesel refinery near Dickinson, North Dakota, in order to capitalize on tight oil from the Bakken shale formation. So far, the public comment period, which will end on Feb. 11, has not excited any discussion. The same was true of Dakota Oil Processing's earlier air quality permit for a similar project.

"We're forced to pick and choose," said Sierra Club spokesman Wayde Schafer, commenting on the organization's insufficient resources to address every environmental concern that crops up. And truth be told, environmental groups really do have "bigger fish to fry." The North Dakota refineries, more properly known as topping plants, will be relatively insignificant polluters, extracting diesel and kerosene through simple processes. The Calumet-MDU facility will produce approximately 160K mt/y of greenhouse gasses, an amount which pales in comparison to the millions of tons produced at nearby coal-burning power plants. Moreover, emissions will be offset by shortened supply routes for tanker trucks. Byproducts of the plants' processes will be sent out of state for further refining.

Construction of the j.v. facility is expected to begin in 2Q 2013, with completion in 4Q 2014. The joint venture, which will be called Dakota Prairie Refining LLC, will create about 100 jobs and cost approximately $300MM. Calumet will cover a quarter of the expense up front, and arrange for another quarter through a loan, to be paid off by the j.v. MDU will supply the remaining $150MM. (Feb 5)

ABB wins contract for Eni upgrade. As of 4Q 2012, the group was awarded a $40MM contract to provide engineering, procurement, and construction (EPC), project management, and pre-commissioning services for a planned project at Eni's Taranto refinery in Italy.



The Italian refiner will upgrade and extend the facility's attached export terminal in order to improve its connection via underground pipeline to the country's Tempa Rossa oil field production facility. Eni will upgrade an existing pier to a 3K m3/h (456 b/d) transfer capacity, with ABB to supply new electrical equipment and systems. The project will conclude in Aug. 2015. (Feb 4)

Porvoo refinery to produce high-octane gasoline with new isom unit. In 2008, Neste Oil decided to equip its 206K-b/d Porvoo refinery (Finland) with a 14K-b/d isomerization unit, but subsequently decided to delay the investment until the market recovered from the financial crisis and recession. Now the Finnish refiner has announced that it will begin construction on the unit this year, to be completed in spring 2015. The new unit will increase the refinery ability to produce high-octane gasoline for export. (Feb 4)

Comico cannot pay up; abandons project. After repeatedly failing to remit payment for a 652MM CSD ($7.93MM), 99-year land lease from the city of Smederevo, Serbia, Comico Oil will have to look elsewhere to build its planned $250MM refinery. City officials, in the meantime, will look for other investors to develop its industrial zone. (Feb 5)

Sinopec and PetroChina to upgrade refineries to meet new fuel standards. According to Sinopec chairman Fu Chengyu, "If [emissions] standards do not increase, upgrades and modifications to facilities will not happen." He noted that Sinopec's refineries were set to complete desulfurization upgrades by year's end, and to begin producing Phase IV fuels on schedule in 2014; specifically, Sinopec's Zhenhai, Guangzhou, Hainan, and Maoming facilities are currently outfitted for Phase IV gasoline production, an undertaking expected to cost CNY 150-250/mt ($24-40/mt) more than Phase III production, with the CNY 200-300MM ($32-48MM) cost of installing a gasoline hydrogenation unit constituting a large factor in the price hike. Sinopec's Gaoqiao refinery has also begun producing Euro-V standard RON 92 gasoline. According to Sinopec, upgrading its facilities to produce Phase III fuels cost the company CNY 492MM ($79MM) between 2005 and 2010, and the company expects to spend CNY 30B ($4.8B) to produce Phase IV fuels.

Meanwhile, fellow refiner PetroChina is also in the process of upgrading its refineries ahead of tightened regulations—the company has brought a new 3.5MM-mt/y (72K-b/d) diesel hydrogenation unit online at its Lanzhou refinery, which is presently capable of producing Phase IV fuels, and will install a similar 2.25MM-mt/y (46.3K-b/d) unit at its Dalian refinery before April. Commenting on the new fuel standards PetroChina stated it would, "push forward upgrading of fuel quality, and supply clean, good quality and diversified products." (Feb 5)

Indonesian refinery planned in joint venture with Saudis. Saudi Aramco's subsidiary Saudi Aramco Asia Co. and Indonesia's state oil company Pertamina are in the planning stages of constructing a 300K-b/d refinery in Tuban, East Java, Indonesia. The two companies recently signed a memorandum of understanding (MOU), establishing their intention to conduct feasibility studies of the endeavor. If completed, the refinery would be combined with a petrochemical facility and provide a variety of products to Southeast Asian markets. (Feb 5)

Double or nothing for Vietnamese refinery. A refinery under construction in Phu Yen, Vietnam, has received approval to double its planned capacity to 160K b/d, according to government officials. UK Technostar Management Ltd. has been contracted to overseas the work for $3.1B. PetroVietnam has plans underway to upgrade the 130K-b/d Dung Quat facility to 200K b/d, and has additionally contracted to have a new 200K-b/d facility built south of Hanoi. Once online, the additional capacity at all three refineries should make Vietnam a net exporter of refined products. (Feb 5)



Pipeline & Terminal Activities

Colonial, Buckeye to link up East Coast pipelines. A connecting line between the Colonial Pipeline and Buckeye Pipe Line systems will enter service in Paulsboro, New Jersey (US) during Feb., to facilitate the transport of Gulf Coast refined products from Colonial's 825K-b/d Line 3—originating in Greensboro, North Carolina and receiving its oil products via the company's 1.3MM b/d Line 2 and 1.2MM b/d Line 3 from Pasadena, Texas—to locations in Pennsylvania and New York. The two systems were both already linked to PBF's 180K-b/d Paulsboro, NJ facility, where they will soon work together to convey refined products to Pennsylvania's Malvern and Macungie terminals via Buckeye's Paulsboro line, and thereafter to Lancaster, Harrisburg, and Scranton, Pennsylvania; as well as Buffalo, Syracuse, Utica, and Rochester, New York. Colonial expects to connect itself to Yorktown, Virginia's Western Terminal and Philadelphia's Eagle Point terminal as well. Said Colonial CEO Tim Felt, "Tying together critical infrastructure like this is a great way to extend the safe, reliable and cost-efficient supply of fuel to additional parts of our country."

In the meantime, Colonial said the third and fourth phases of expansions to its main gasoline line should be completed by 2Q. The pipeline operator stated that 100K b/d of capacity will be added to Line 1 and 60K b/d will be added to Line 3. Line 1 should be operational at some point in the 2Q while Line 3 should be back up by mid-Feb. (Feb 1, 7)

PBF to bring Delaware City rail terminal into service. The US East Coast refiner has completed a rail terminal expansion project at its 182K-b/d Delaware City, DE refinery which will increase the facility's offloading capacity to 110K b/d, of which 40K b/d will consist of Canadian heavy crude and 70K b/d of Bakken light crude. Crude-laden railcars will begin delivering product in the week to Feb. 9.

PBF expects the shipments to deliver a significant cost advantage, with crude from Canada and the US Midwest to replace higher-priced imported Brent crude; the majority of pipeline infrastructure currently being installed to distribute lower-priced Canadian oilsands and Bakken shale oil will transport those products to the Gulf Coast, rather than East Coast locations, which have been forced to beef up rail infrastructure. Fellow East Coast refiners Phillip 66 and Delta Air Lines are both pursuing similar crude-by-rail strategies, with Phillips 66's New Jersey refinery to receive 50K b/d of North Dakota crude under a five-year agreement, and Delta to test Bakken crude runs at its Trainer, PA facility during 1Q 2013. PBF has purchased 2K railcars for transport of heavy oil and 500 general use railcars, in addition to 1.6K owned or leased prior. The company also expects to expand its heavy crude offloading capacity again to 80K b/d by year's end, at a cost of $50MM. (Feb 4)

Increased transport capacity to serve Baton Rouge refinery. Genesis Energy LP has announced that it will expand its Port Hudson, LA (US) terminal on the Mississippi river, nearly doubling its capacity to 416K b/d. To transport crude from the terminal to ExxonMobil's 502K-b/d Baton Rouge, LA refinery, the company will construct an 18-mile (29-km), 350K-b/d pipeline to a tank farm at the refinery site. According to Genesis CFO Bob Deere, the new infrastructure could in the future serve other refineries connected to the tank farm. The $125MM project should be completed in 2Q 2014. (Feb 4)

Capline could be reversed says CEO. The head of Plains All American Greg Armstrong said its 633-mile (1,019-km) Louisiana-to-Illinois Capline pipeline could be reversed to move inland US crude production to the Gulf Coast. Furthermore, Mr. Armstrong state that Capline could be utilized to move condensate produced in South Texas north to meet growing condensate demand from Canada. As for what exactly the future holds for Capline, Mr. Armstrong remarked, "I don't think it is



really prudent to try and forecast any particular trend as to what is going to be shipped on that because I think the margin will change constantly." Currently, Capline only operates at 30-35% of its nameplate capacity.

Plains also stated that it will construct a 55-mile (86-km), 75K-b/d extension to its existing Mississippi Lime pipeline to allow crude to move from Comanche County, Kansas to Alfalfa County, Oklahoma. The extension is expected to be operational by 4Q 2013. Furthermore, the company's j.v. 140-mile (225-km) 350K-b/d crude and condensate pipeline that will connect Plains Gardendale gathering system in LaSalle Country, Texas with the Corpus Christi and Three Rivers markets in Texas should be operational in March. An additional 35-mile (56-km), 350K-b/d line from Three Rivers, TX to Lyssy, TX should be online in Aug. (Feb 7)

Magellan to install new Texas crude transportation. The company has announced a $50MM pipeline installation and terminal expansion project at its Galena Park, Texas terminal which will allow for the transport of crude to Magellan Midstream Partners' Gulf Coast system, which distributes crude to Houston and Texas City regional refineries. These new systems will enter service in mid-2014, with long-term transport commitments to support the project's cost.

Magellan also noted that it will begin filling its reversed 225K-b/d Longhorn Pipeline with crude starting in mid-March and reach a capacity of 75K-b/d by mid-April before reaching full capacity on the line at some point in the 3Q. The reversed line will allow for the transportation of West Texas crude to refineries throughout the Houston area. (Feb 4, 5)

Imports & Exports

US gasoline exports to, crude imports from Venezuela remain high. According to US Energy Information Administration (EIA) data, the US exported 85K b/d of gasoline to the South American country in Nov., up from 39K b/d in Oct. and 68K b/d in Sept., continuing a trend of monthly exports stretching back to Dec. 2011. Venezuelan officials, however, maintain that the country is receiving only imports of gasoline additives including MTBE, having received 25K b/d of the product from US traders in Nov. The US has been shipping MTBE to Venezuela since 2005. The trade relationship between Venezuela and the US has shifted significantly since the advent of the US shale boom—where once the US was a net importer of gasoline, importing volumes from Venezuela among other countries between 1993 and 2011, the country has been a net exporter since 2009, selling approximately 352K b/d of gasoline abroad in Nov. 2012, down 18% from 452K b/d year-on-year, and also down from a Dec. 2011 high of 556K b/d.

Increased US production has been complemented by reduced domestic gasoline demand growth. The US has also become a net exporter of distillate fuels, selling 872K b/d to countries including Brazil, the Netherlands, and Mexico in Nov., a drop from 960K b/d in Oct. but an 8.3% increase year-on-year. However, the country also imported 8K b/d of Venezuelan distillate in Nov., following net exports of 29K b/d in the opposite direction through Oct. and Sept. Meanwhile, the US continues to experience reduced crude imports thanks to major shale play output, with overall imports down 6.8% year-on-year to 8.724MM b/d in Nov. alongside a 14% domestic production increase to 6.893MM b/d. In the same month, the US saw imports of Venezuelan crude reach an over-three year high, rising 46% year-on-year to 1.03MM b/d, with many US refineries still outfitted to process heavy sour crudes not being produced by domestic shale plays. Venezuelan crude imports for Jan.-Nov. 2012 averaged 893K b/d, a 20K b/d increase from the same period in 2011. (Feb 1)



Iran increases gasoline production, plans to become net exporter. The Islamic Republic has entered the second stage of the third phase of upgrades to a National Iranian Oil Co. gasoline unit at the company's Abadan Oil Refinery. The project is expected to increase the facility's production capacity to 6MM L/d (37.7K b/d) with the addition of 2MM L/d (12.6K b/d) of 94- and 95-octane gasoline production capacity, which will meet Euro-4 standards. Another Iranian news source estimated a higher new production capacity, at 15MM L/d (94.3K b/d). According to a previous announcement, Iran will also increase domestic gasoline production via projects at its Shazand and Lavan refineries set to conclude before March 20 this year; overall, upgrades at all three refineries are expected to increase premium gasoline production from 12MM L/d (65.4K b/d) to 25MM L/d (157.2K b/d), and total domestic gasoline production to 70MM L/d (440.3K b/d). According to the country's Oil Minister Rostam Qasemi, these will constitute sufficient gasoline production increases to transform the country into a net exporter of the product in the Iranian year to begin March 21. In the past, Iran imported up to 40% of gasoline for domestic use, but purports to have rectified this shortfall with capacity expansion; according to June 2012 reports, it has shipped gasoline to the UAE, Iraq, Armenia, and Afghanistan, despite US and EU sanctions. (Feb 1, 3)

China to export diesel as supply outpaces demand. With 840K b/d of new capacity online in 2012, and a comparable increase anticipated in 2013, Chinese refiners are faced with a considerable surplus of diesel fuel, as domestic consumption has failed to keep pace with supply. According to the China National Petroleum Corp. (CNPC), refinery capacity will rise by 7% in 2013, over 8% increases in 2012, while diesel demand this year is likely to grow by only 4%. Unusually cold weather this winter has led to diminished economic activity in China, resulting in further reductions in demand. All factors considered, China is expected to export a surplus of 60K b/d in 2013, a 500% increase from 2012. (Feb 6)

Trafigura continues to send gasoline to Iraq. Despite not being allowed to move gasoline to Iraq as a result of being blacklisted by the government for buying crude from the Kurdistan region, trader Trafigura is continuing to indirectly supply the country with gasoline via another firm called Sima, an Iranian-Azeri company that won part of contract last Nov. to supply Iraq with 1.56MM mt (13.2MM bbl) of gasoline. Sima loaded two vessels booked to deliver gasoline in Jan. to Iraq's southern Khor al Zubair terminal from storage tanks at Jebel Ali in the UAE owned by Trafigura. (Feb 6)


REFINERY-PETROCHEMICAL BUSINESS BRIEFS

Light Olefins

Lyondell backtracks on US metathesis unit expansion plans. After announcing a 4Q 2012 net profit of $623MM, up from a $218MM loss year-on-year, the company further announced that it will cease to pursue a plan first announced in Dec. 2011 by which it would construct a metathesis unit at its Channelview, TX (US) facility. LyondellBasell is one of just two US olefins producers which currently produces propylene by way of the metathesis process. The company intends instead to undertake debottlenecking of ethylene units at its LaPorte, Channelview, and Corpus Christi, Texas facilities, with LaPorte upgrades to conclude in late 2014 and details on Channelview and Corpus Christi projects to be announced in March. Debottlenecking at LaPorte and Channelview will create an anticipated 600K mt/y of ethane production capacity. (Feb 1)

European olefins output down in 4Q. Compared to the same period in 2011, output of ethylene, propylene, and butadiene was down in Europe in 4Q 2012 due to declining demand and the poor financial performance of domestic PC producers. Ethylene output was 4.497MM mt in the quarter down 5.15% from year-ago levels, propylene production was down 4.9% to 3.429MM mt, and butadiene saw production levels decrease by 2.3% to 500K mt. For all of 2012 European ethylene production was 18.874MM mt (down 3.5%); propylene production was 14.287MM mt (down 1.33%); and butadiene production was 2.054MM mt (down 1.58%).

In Jan., cracker rates in Europe have started to increase from an average of 75-80% in Dec. to 80% as demand has begun to pickup from 4Q levels as restocking activities commence. Furthermore, the unplanned shutdowns of crackers operated by Borealis in Stenungsund, Sweden and Naphtachimie in Lavera, France have tightened supply in the market. Better-than-expected economic data from China in Dec. has further boosted sentiment within the European PC market. While conditions have improved from 4Q, the ongoing Eurozone debt crisis coupled with continuing lackluster demand has led many in the market to remain cautious moving forward. (Feb 5, CB/Jan 21-27/p 13)

BTX

Rise in aromatics propels Jan. IPEX higher. According to the Jan. ICIS Petrochemical Index (IPEX), global chemical prices rose by 1.5% in Jan. from Dec. as the Jan. IPEX rose from 323.86 to 328.68. Aromatics were cited as the main reason for the higher IPEX with global aromatics prices up 3%. Europe saw aromatics prices rise by 4.2% while Asia and the US reported rises in aromatics prices of 3.6% and 1.2%, respectively. Specifically, higher prices for benzene and styrene in Asia and Europe coupled with higher toluene prices in Asia and the US propelled aromatics upward. Overall, Asia reported 2.1% growth in Jan. across all its PC product sectors with Europe reporting a price gain of 1.7% and US prices staying relatively flat. (CB/Jan 21-27/p 19)

Higher European benzene price mute phenol demand. After the Jan. benzene contract in Europe settled up by $93/mt from the Dec. price, the contract price for phenol also rose by the same $93/mt to settle at $2,289-2,343/mt FD NWE, pressuring phenol producers as demand from downstream derivatives such as nylon has dropped significantly due to the price increase in both benzene and phenol. As a result of sluggish demand from downstream derivative, phenol plant operating rates throughout



Europe remain low. Commenting on the situation one major PC producer stated, "We are very concerned about the benzene increase. It will kill demand. It's terrible—it's going to be very difficult because we can't pass this on." (CB/Jan 21-27/p 19)

Saudi Aramco to raise benzene, PX output. By 2017, the Saudi energy major will bring 2.6MM mt/y of new paraxylene (PX) capacity online and 820K mt/y of new benzene production. Saudi Aramco said these new capacities will be spread among five new refining and petrochemical complexes that will be started up in the country over the next four years. Specifically, Saudi Aramco Total Refining and Petrochemical Co.'s (Satorp) 400K-b/d Jubail refinery will come online in 3Q 2013 with 700K-mt/y of PX capacity and 140K-mt/y of benzene capacity; Yanbu Aramco Sinopec Refining Co. (Yasref) will include 700K-mt/y of PX output and 140K-mt/y of benzene capacity at a new refining complex it is building at Yanbu that will startup in 2014; PetroRabigh, a j.v. between Saudi Aramco and Sumitomo Chemical, is bringing 1.35MM-mt/y of additional PX output and 170K-mt/y of additional benzene production online when it completes the second phase of its petrochemical complex in 2015; 1.2MM-mt/y of PX output and 285K-mt/y of benzene output will be commissioned when Saudi Aramco brings its 525K-b/d Ras Tanura facility online at the end of 2016; and Aramco's 400K-b/d Jazan refinery that will start operations in 2017 will include 650K-mt/y and 85K-mt/y of PX and benzene capacity, respectively. (Feb 5)

Following record high, Asian benzene prices continue to fall. Following benzene prices hitting an all-time high of $1,480-1,490/mt FOB Korea in Dec. 2012, prices have started to decline falling $105/mt to $1,375-1,385/mt in Jan. The giveback in prices has resulted from traders looking to offload inventories to take advantage of the high prices coupled with ongoing price uncertainty in the US benzene market. Furthermore, a weakening of the styrene monomer (SM) price in downstream markets is putting further pressure on benzene. According to one southeast Asian producer, "We were hoping that benzene prices [will] get support from SM, but SM started to plunge as well." (CB/Jan 21-27/p 18)

Asian solvent-MX prices see decline in Jan. Rising stocks of solvent-grade mixed xylenes (MX) in China coupled with declining demand in the winter off-peak season resulted in solvent-MX prices in Asia declining by 3.1% from the Dec. price to average $1,231/mt FOB Korea in Jan. Traders expect the decline in prices to be short lived as solvent-MX demand is expected to pick up starting in March following the Lunar New Year holidays in China. (Feb 6)

Dragon Aromatics' sees PX project delays. Startup of the company's 800K mt/y Gulei city, Fujian paraxylene (PX) plant may be delayed as the result of a Chinese Environmental Protection Bureau inquiry into feedstock usage at the facility, over environmental concerns related to the use of condensate instead of heavy naphtha. According to a Jan. 29 Platts report, condensate would be utilized in conjunction with isomer-grade mixed xylenes (MX), with Dragon Aromatics to purchase 30K mt/month of the substance, including 10K mt/month purchases from domestically-operated PetroChina and Sinopec. The Environmental Protection Bureau on Jan. 21 requested that the company delay the PX plant's startup until late Feb. in order to accommodate an investigation, with one trader noting that, "If the Chinese government does not approve the usage of condensate as feedstock, the commercial operation [of the plant] in March will likely be delayed to [2Q]." Another Shanghai trader agreed that the scheduled March startup remains uncertain; if so, this would be the latest in a series of delays related to construction issues, difficulties in procuring feedstock, and regulatory complications. According to alternative market sources, however, Dragon Aromatics' schedule will remain unaffected, with the company having paid a CNY 200K ($31.8K) penalty already, concluding the issue. (Feb 5)



Naphtha & LPG

Iranian LPG exports stopped under sanctions. As a result of tighter western sanctions placed on the Islamic republic over its ongoing nuclear program, exports of liquefied petroleum gas (LPG) have essentially stopped. Iran claims that it is now using the LPG it traditionally exports for domestic power generation during the winter months, when demand reaches 600MM m3/d (21.2B cf/d). However, once the winter period ends in March Iran is expected to see a glut of LPG supply as the country historically exported around 300K mt (3.49MM bbl) of LPG per month to Asia. Even before the tighter sanctions went into place at the end of Dec., Iran was only exporting two to three cargoes of LPG per month with a majority of these exports going to China.

Japan ceased importing LPG from Iran last year. South Korea's E1 and SK Energy stopped importing Iranian LPG in Oct. Taiwan's CPC Corp. and Formosa Petrochemical Corp. did not include any Iranian LPG volumes in its March tenders. Commenting on the situation one trader stated, "I don't think anything is going (to Asia) these days." Traders said that the problem with importing LPG from Iran is finding vessels to carry volumes, as the last tanker booked to carry LPG from Iran to Asia occurred in Nov. (Feb 6)

Backwardation in Asian naphtha market hits record high on firm demand. The physical backwardation in the Asian naphtha market hit an all-time high of $42/mt on Feb. 8 as a result of firm demand coupled with short supply. Crackers are running at full rates due to strong demand and margins in downstream PC markets and lower supply from India and the Middle East coupled with a closing arbitrage from the west has combined to keep supplies tight. Naphtha supply from India declined by 100K mt (848.7K bbl) in Feb. to 500K mt (4.2MM bbl) while supply from the Middle East has been muted due to domestic producers utilizing more product to blend into the gasoline pool. Furthermore, regional production of naphtha is expected to drop in March and April due to turnarounds at South Korean refineries, so consumers have been looking to secure supplies now in anticipation of the production losses. (Feb 8)

Petrochemical Plant Activities

PTT to bring new condensate splitter online in Timor. The Thai energy announced that it will partner with petroleum company Timor Gap to construct and operate a $168MM, 40K-b/d condensate splitter. Under the terms of the deal, PTT Int. will own 70% of the splitter while Timor Gap will own the remaining 30%, with PTT using a portion of the splitter's production to supply its PC production facilities. (Feb 6)

htha


POLITICS, ENVIRONMENT & REGULATORY LEGISLATION

Climate Change Legislation More efficient vehicles more promising than alternative fuels. California's new Low Carbon Fuel Standard (LCFS) is under fire as unrealistic, with industry representatives arguing that the technology simply doesn't exist to sufficiently reduce gasoline's carbon footprint. The California Air Resources Board (CARB) maintains that US ethanol producers are up to the task, but Chevron Corp. VP Rhonda Zygocki pointed out that producing ethanol from corn releases too much carbon dioxide, insisting that the only way to comply with the law's demands is through massive imports of Brazilian sugarcane ethanol, which has a smaller footprint than corn-derived ethanol. Brazil is expecting a bumper crop of sugarcane this year, but plans to increase domestic ethanol consumption as well. Instead of trying "to design a new fuel," Zygocki went on, we should work "to improve the fuel economy of the passenger vehicle. And in this nation, we're doing that."

The market appears to confirm at least some of Zygocki's claims. General Motors biofuel implementation manager Coleman Jones has commented that consumer demand simply doesn't justify the production of more flex-fuel vehicles in the US, and uncertain ethanol supplies only increase the risk of the venture. Increased fuel efficiency in standard gasoline vehicles, on the other hand, continues to be an obtainable goal. According a study by Univ. of Michigan researchers, the average fuel efficiency for new cars in the US in Jan. 2013 was 24.5 miles-per-gallon, up one mile-per-gallon year-on-year. In Jan. 2011, the average was an additional one mile-per-gallon lower. The monthly study began in Oct. 2007, when average fuel efficiency was 22% lower than current rates. (Feb 5, 6, 7)

Canada to slash government spending on fossil fuels. As part of an international deal to curb greenhouse gas emissions, Canada will be rolling back tax breaks and subsidies for oil and coal. According to the International Energy Agency (IEA), eliminating subsidies for fossil fuels would reduce greenhouse gas emissions by 1.7K mt over the next 7 years. C$1.47B ($1.47B) in tax breaks, mostly to promote oilsands exploitation, will be repealed. (Feb 5)

Fuel Regulations & Other Mandates

Biofuel production to relieve palm oil glut. According to Tan Sri Bernard Dompok, Malaysia's Plantation Industries and Commodities Minister, production of B10 biodiesel should begin next year, providing a much needed outlet for the country's burgeoning crude palm oil supplies. Most of government's blending facilities are expected to be online by the end of 2013, and B10 biodiesel, which will consist of 10% palm methyl ester and 90% diesel, should be available a few months later. The country's high palm oil stocks should find additional support in export markets as well, as export duties on the product were canceled last month. (Feb 4)


MERGERS, JOINT VENTURES, ACQUISITIONS & DIVESTITURES

Valero to spinoff retail outlets in 2Q. In a webcast on Feb. 6, CEO Bill Klesse announced the spinoff of Valero Energy's fuel station business under the name of CST Brands. 1,880 stations are involved in the split, 848 in Canada and 1,032 in the US, the majority of which are located in Texas. (Feb 6)

Pasadena refinery for sale, not on sale. The Brazilian state oil company is planning $15B in divestments in the near future, with the 117K b/d Pasadena, TX (US) refinery one of the assets to be sold. CEO Maria das Gracas Foster made it clear, however, that Petrobras was not making a panic sell, and would be happy to take its time finding a favorable deal. She also indicated that the company might invest in upgrades to increase the facility's value. (Feb 5)

Trafigura to expand in Australia as the country's refining capacity shrinks. The Dutch oil trading company's Puma Energy unit will acquire Australian Neumann Petroleum and Ausfuel for A$65MM ($68MM) and A$625MM ($652MM) respectively, positioning itself as the country's major independent fuel seller in the wake of multiple domestic refinery closures expected to result in significant fuel import increases. Royal Dutch Shell last year took its Clyde refinery offline, while Caltex Australia Ltd. shuttered its Sydney refinery and will cease activity at its Kurnell refinery in late 2014. As a result of the shuttering of a number of domestic refineries, analysts believe Australia will overtake Indonesia and become the world's largest importer of refined products, with 650K b/d of refined product imports possible by 2015.

Through its acquisition of Neumann, Puma Energy, a unit of Trafigura Beheer BV, will take control of 120 service stations and a Port of Mackay, Queensland storage and import terminal, with plans to construct further such facilities throughout the country. Through its acquisition of Ausfuel, Trafigura will take control of 110 Gull-, Peak-, and Choice-branded retail stations. Commenting on the deal Trafigura CEO Pierre Eledari stated, "The closing of refineries and the growing volume of imports into Australia have opened up a great deal of opportunity…to invest into the Australian market." While the sentiment expressed by Mr. Eledari is shared by many, others warn that the import volumes into Australia will be nowhere near as large as presently forecast due to slower economic growth and lower investments in mining. (Feb 4, 5, FT/Feb 4/ p 13)


REFINER BUSINESS, STRATEGY & FINANCE

Chevron reports 4Q profits. On Feb. 1, the US oil company reported a net income increase from $5.1B in 4Q 2011 to $7.2B in 4Q 2012, with oil and gas production earnings up 20% at $6.9B, and refining profits improved year-on-year from a $61MM loss in 4Q 2011to a $925MM gain in the last quarter of 2012. Contributing to the increase was a $1.4B deal with Royal Dutch Shell, by which Chevron agreed to exchange its Australian Browse LNG project shares for Shell's Australian field interests. Chevron's upstream production increased from 2.64MM boe/d in 4Q 2011 to 2.67MM boe/d in 4Q 2012, despite ongoing reduced capacity at its fire-damaged Richmond, CA (US) refinery. Chevron's full-year profit fell slightly from $26.9B in 2011 to $26.2B in 2012. (Feb 1, FT/Feb 2/3/p 8)

Exxon sees record earnings thanks to refining business. The oil major posted 4Q 2012 profits of $9.95B, up 5.9% from $9.4B year-on-year, while full-year profits rose 9% year-on-year to $44.8B, leading many analysts to suggest that the integrated model favored by Big Oil may have merit as the industry continues to undergo significant reshaping. The model stands in contrast to decisions from fellow majors like Marathon Oil Corp. and ConocoPhillips to spin off refining operations over the past few years. In the fourth quarter, ExxonMobil's capital and exploration expenditures rose 24% from the same period in 2011 to $12.4B, coming to $39.8B for the full year. While the company's profits were supported by a major Japanese divestiture and a cheap-gas induced boost to petrochemical and fuel-making revenue—thanks to shale gas abundance, chemical earnings rose from $543MM in 4Q 2011 to $958MM in 4Q 2012—its $25B acquisition of XTO Energy Inc., completed in 2010, likely continued to pull profits down, as natural gas production suffered from oversupply and rock-bottom prices. This demonstrates, at least, the balance of ExxonMobil's diverse ventures, with Raymond James analyst Pavel Molchanov noting, "One of the arguments for having an integrated model is that it provides a natural hedge."

Over the course of the year, the company dispensed capital project investments of $39.8B, while upstream investment increased from $2.4B in 4Q 2011 to $4B in 4Q 2012. ExxonMobil saw $1.77B in refinery earnings during 4Q 2012, four times the $425MM posted during the same period in 2011, but processed 7.9% less crude year-on-year, approximately 4.8MM b/d; success in this arena mitigated a 12% decline in oil and gas earnings, which came to $7.76B in the last quarter of the year as output fell 5.2% year-on-year in the fourth quarter, to an average 4.29MM boe/d. Meanwhile, crude production dropped 2.1% from 2.25MM b/d during 4Q 2011 to 2.2MM b/d during 4Q 2012. (Feb 1, 3, FT/Feb 2/3/p 8)

Valero realizes advantage in converting shale oil to middle distillates. The company's CEO Bill Klesse said his company enjoys an advantage due to its access to cheap shale crudes at its refineries along the Gulf Coast. Valero Energy Corp. is then able to upgrade these cheap crudes into middle distillates that can be exported to countries in Europe and Latin America, boosting company profitability. Mr. Klesse noted that "Distillates are where we want to be," commenting that demand for middle distillates will grow twice as fast as gasoline demand. Furthermore, the low cost of natural gas in the US allows operating costs at its refineries to be lowered, meaning it can export refined products for a cost that is about $2/bbl less than its competitors, allowing it to capitalize on export opportunities. (Feb 6)

Delta refinery outlook raises industry eyebrows. The US airline purchased Phillips 66's Trainer, PA (US) refinery last May at a cost of $150MM, with plans to maximize jet fuel production at the facility and supply its own fuel for an estimated savings of $300MM/y. However, industry conditions may prove an insurmountable obstacle to the company's optimistic projections, according to some analysts. Delta Air Lines posted a $63MM loss on the facility in 4Q 2012, with a further $100MM in losses expected through 1Q 2013. Although the company has attributed these blows to Superstorm Sandy, crude pricing conditions are also likely contributing factors—the Trainer facility's traditional light crude feedstock, imported from Nigeria, is currently priced approximately $4/bbl above the Brent benchmark. Although the company will



experiment with running Bakken crude-by-rail, the $22/bbl extra costs associated with such a venture could actually worsen the economics. Delta has announced an anticipated $280MM in 2013 savings, and expects to supply 80% of its domestic fleet's jet fuel need, while a settled airline industry has inspired confidence from Wall Street, driving Delta's stock up 25% over the course of the past year. But weak industry improvement combined with flat crude prices could easily swing Delta's Trainer refinery into an untenable economic situation. (Feb 3, 8)

LyondellBasell's profits shored up by O&P Americas. The American division of the petrochemical major's Olefins and Polyolefins (O&P) business saw strong profits in 4Q 2012, shooting to $693MM from $328MM year-on-year. Cheap LNG and abundant ethylene contributed to the increase. LyondellBasell's O&P business in the rest of the world, however, suffered a $94MM operating loss. Tough times in Europe were the main driver for the losses; ethylene, propylene and butadiene production fell in Western Europe during the period, ethylene by 5.15% year-on-year to 4.5MM mt, propylene by 4.9% to 3.4MM mt, and butadiene by 2.3% to 500K mt. According to Dow Chemical Co., Europe is regarded as a "continually challenged" region. (Feb 5)

BP earnings take 20% hit, less than expected. The oil major's net income for 4Q 2012 was reported at $3.98B, down from $4.98B in 4Q 2011. The figure, which came as a surprise to investors who had expected lower earnings due to a higher tax rate, did not include one-time transactions and inventory effects, but did include $4.13B in charges for the Deepwater Horizon fiasco in 2010. Since the accident, BP has divested itself of assets totaling $37.8B in order to cover its liabilities and could see "more billions" go to liabilities related to the accident as a result of civil penalties trial set to commence on Feb. 25. The company added that it expects to feel the impact of the divestures from the Deepwater Horizon spill on its reported results throughout the year but that this impact should be less beginning in 2014. Furthermore, the divestitures related to Deepwater Horizon have resulted in BP losing its title as largest producer in the Gulf of Mexico to Royal Dutch Shell. Divestments valued at $5.6B have reduced rates by 46K b/d in 2012, and further reductions were caused by seabed maintenance at the Atlantis field, losing the company another 86K b/d in 2Q. The company's replacement cost profit for the year was $17.6B, down from $21.7B in 2011.

BP's downstream operations, on the other hand, posted replacement cost profits at $1.32B for 4Q 2012, up from $564MM for the same quarter in 2011. The difference was made up by higher margins; the company actually processed less crude than a year ago, 2.35MM b/d down from 2.45MM b/d. BP expects less refinery downtime in 2013, but also a higher tax rate, around 36-38%, up from 30% in 2012.

The company also added it expects to startup four new major upstream projects in 2013 which include Angola LNG, Chirag oil project in Azerbaijan, Na Kika 3 in the Gulf of Mexico, and North Rankin 2 in Australia. Furthermore, another six upstream projects should come online in 2014. The company also plans to invest $4B a year for the next ten years in increasing production in the Gulf of Mexico. According to Fadel Gheit, an analyst with Oppenheimer & Co., BP is likely to retake the top spot in terms of crude production in the Gulf of Mexico in the coming years. (Feb 5, 6)

Loss from renewable fuels business dents Neste 4Q profit. The Finnish energy firm state that an unexpected loss of $2.71MM from its renewable fuels business that converts palm oil and waste animal fat into biodiesel coupled with one-off costs of $91MM related to its technology systems resulted in a 4Q group comparable operating profit of $120.6MM, well below analysts estimates of $160MM. Neste Oil also noted that its 4Q profit was hurt by a loss at its j.v. with PDVSA Nynas. Neste expects to post positive results in 2013 and anticipates its yearly comparable operating profit to rise from the $477MM seen in 2012. The company did warn that its renewable fuels sales will be down in 1Q due to a three-week maintenance shutdown at its Singapore biodiesel refinery. Furthermore, the company announced that its diesel production line 4 at its Porvoo, Finland refinery will be down for eight weeks of maintenance during the 2Q which will hurt earnings from its refining arm during that quarter. (Feb 5)



JX tops 1MM b/d on domestic market. According to parent company JX Holdings, JX Nippon Oil & Energy sold 1.01 b/d of oil and oil products domestically in April-Dec. 2012, with its domestic oil market share rising from 35.3% a year before to 36.2% on Dec. 31. At the same time, Japan's oil demand grew to 3.3MM b/d, up 2.7% year-on-year. JX's product exports shot up 12.8% to 172K b/d during the period as well. Not all of the company's sales were high-profit products, however; JX sold 86K b/d of crude over the period, to be burned as fuel for power generation. Since the March 2011 earthquake and tsunami, Japan has been burning additional fossil fuels to fill the gap left by the shuttering of its nuclear reactors. (Feb 5)

Strong currency, lower margins pressure South Korean refiners' earnings. The sharp appreciation of South Korea's currency coupled with lower refining margins resulted in South Korean refiners reporting lower 4Q earnings. According to an analyst at Seoul-based KTB Securities, "(South Korean) refiners suffered poor refining margins in the fourth quarter. European refiners hiked operating rates in the fourth quarter to meet winter heating demand, which led to increased supplies." South Korean refiners are dependent on refined product exports to help boost profitability and the additional European supplies negatively impacted their ability to sell product on the international market. The same KTB analyst added that South Korean refiners saw $92-184MM in inventory and foreign exchange losses on the quarter due to lower global crude prices. Overall, domestic oil demand was up 1.2% from 4Q 2011 levels to 212.99MM bbl.

SK Innovation reported that its refining segment operating profit was down 55% from 4Q 2011 levels to $72.2MM; GS Caltex noted that its refining arm swung from an operating profit of $133.0MM in 4Q 2011 to an operating loss of $131.6MM in 4Q 2012; likewise, S-Oil Corp. saw its refining arm decline from an operating profit of $64.5MM in 4Q 2011 to a loss of $190.5MM. Commenting on its earnings, SK released a statement saying, "Operating profit decreased owing to weak refining margin and inventory related losses. In particular, the fourth-quarter fuel oil crack hit a record low for the year," as the fuel oil crack widened to -$11.30/bbl in 4Q 2012 from -$2.80/bbl in 4Q 2011. An economist at Eugene Investments & Securities added that the average operating profit of South Korea's three main refiners was 57% below market forecasts blaming the won's 7.6% gain against the dollar during 2012, with most of that coming in the 4Q. "Dollar-based refining margin was $6.80/bbl in the 4Q, down 37.5% from $10.90/bbl in the 3Q, but in won terms, the margin was down 40% due to the currency's appreciation against the dollar."

While the 4Q was challenging for South Korean refiners, analysts expect margins to improve during 1Q 2013. According to the same economist from Eugene Investments & Securities, "Refining margins are at $10.30/bbl currently from $6.30/bbl in early Jan." The economist pointed to higher Chinese consumption and rising gasoline demand in the US and Southeast Asia as the main drivers behind stronger 1Q margins. SK added, "Refining margin is anticipated to display a recovery trend owing to solid demand in the Asia-Pacific region and planned refinery maintenance in Europe and Asia." (Feb 7)


INDUSTRY TRENDS & FORECASTS

"The era of cheap crude is over": refiners to see challenges in coming years. The world is changing, International Energy Agency (IEA) Executive Director Maria van der Hoeven remarks, commenting on the IEA's recent reports on long-term market prospects for global energy. 2012 was a good year for the refining industry, where high margins across the board were a welcome change from 2011's dismal numbers. 2012, however, was a glitch, according to van der Hoeven. High margins were caused by localized supply problems and reduced spare capacity, conditions that will change in coming years. The underlying long-term trend will be one of shrinking profit margins, especially in member countries of the Organization for Economic Co-operation and Development (OECD), where refining capacity continues to be lost to the developing world. Since the financial crisis of 2008, OECD countries have seen 4MM b/d of capacity go offline, of which 1.2MM b/d was lost in 2012 and 800K b/d in 2011. Refiners in developing countries, despite numerous advantages, will see margins shrink as well, as planned additions to global capacity will exceed demand growth through 2017. Any way forward will require considerable business savvy to get the most out of a plant, beginning with investment in advanced technologies to squeeze more high-quality products from increasingly heavy feedstocks.

Van der Hoeven is not alone in her analysis. Axens' Eric Benazzi points to forecasts indicating that global economic recovery has slowed, with gross domestic products expected to grow in most regions for 2013, but at reduced rates. Global oil product demand will grow by only about 800K b/d to 90.5MM b/d, and with the end of the "era of cheap crude," refiners will need to focus more and more on advanced methods of hydrocracking, catalysis, and other technologies to make the most out of every barrel. It will be increasingly necessary for refiners to deploy every edge they can get, integrating with petrochemical producers, taking advantage of cheap hydrogen where available to crack the heaviest oils, and optimizing products slates for local markets, just to turn a profit. Ujjal Mukherjee of Chevron Lummus Global agrees, pointing out that while crude prices may be high, technology and equipment are cheap, compared to six or seven years ago. Many of the largest companies, Aramco, Rosneft, SK Energy, and others are taking advantage of this to equip their plants to survive in the 21st century. US Gulf Coast refineries are likewise upgrading, as facilities that aren't able to process the heaviest oils will face an uphill battle in coming years, although this will be at least partially offset in some regions by the availability of tight oil from the Bakken and similar formations.

While crude quality is mostly on the decline, it has become increasingly clear that markets will not accept corresponding decreases in fuel quality. With high-sulfur, high-emissions fuels on the way out, it is increasingly important for refiners to consider alternatives as well as improving their refining processes. UOP President and CEO Rajeev Gautam points out that refiners will need to invest in natural gas purification technology, as well as "drop-in" units for the production of biodiesel. Concurring with Benazzi, he suggests that integration with petrochemical complexes can provide support for the bottom line, providing some of the efficiencies that will be required across the board. It is becoming clear that competitive refineries will have to be optimized in all areas, ranging from energy and process efficiency to product slate choices and crude selections in order to meet the demands of coming years. (PTQ 1Q/p 5-10)


TECHNOLOGY DEVELOPMENTS & COMMERCIALIZATION

Honeywell's UniSim™ technology utilized around the globe. The US-based firm recently signed several deals to license its UniSim simulation suite to a variety of industrial firms, including two refiners, one based in North America and another in Europe. Other recent licensees include a US petrochemicals company, which is designing a biomass-to-ammonia facility, as well as a Middle Eastern PC producer and refinery operator, and a South Korean NG supplier. (HE/Jan/p 5)

KBC to provide optimization work in Asia and Latin America. Chinese Fujian Refining and Petrochemical contracted UK-based KBC Advanced Technologies for an optimization and efficiency program at the j.v.'s complex in Fujian Province, China. The multi-million-dollar contract includes a five-year license for ProStream™ and Petro-SIM™ software, personnel training, an integrated flowsheet model for refining and PC operations, and an online utility optimizer. Fujian Refining and Petrochemical is a j.v. among Sinopec, ExxonMobil, and Saudi Aramco.

The global software and consulting company has been chosen for a multimillion dollar contract with Japanese TonenGeneral Sekiyu, under which it will provide a five-year PetroSim license along with SIM models, software implementation, and software services.

Additionally, KBC signed a deal with state oil company Petroecuador for services at the 110K-b/d Esmeraldas refinery in Ecuador. The $100MM contract aims at improving overall performance and margins at the facility, utilizing KBC's support systems, training expertise, and energy and modeling software tools, including the Petro-SIM suite. (Feb 1, HE/Jan/p 5)


BIOFUELS, ALTERNATIVE ENERGY & CARBON MANAGEMENT

Bioethanol, Biodiesel, & Drop-in Fuels

US biodiesel production to reach at least 97.8K b/d this year. According to the country's National Biodiesel Board, total US production of biodiesel should be 97.8K b/d or greater in 2013. If this figure is reached it would be more than enough to satisfy the EPA's 2013 biodiesel blend requirement of 83.5K b/d. The National Biodiesel Board CEO stated that the reimplementation of a $1/gal tax credit for biodiesel blending coupled with the correction to the fraudulent RINs issued in 2012 will spur biodiesel production growth. Biodiesel also receives 1.5 RINs for every gallon blended compared to just 1 RIN for alcohol-based fuels like ethanol derived from sugarcane, making it even more attractive for blenders looking to meet EPA requirements. (Feb 5)

US sees rise in ethanol production, zero imports. Over the week ending Feb. 1, domestic ethanol output in the US rose by 4K b/d from its lowest recorded level since the government began tracking ethanol production over two years ago to 774K b/d. High corn prices resulting from last summer's drought has caused a number of US ethanol producers to idle facilities, with Pinal Energy being the latest to shutter a plant after it put its Maricopa, AZ complex into "cold idle" mode.

Despite the uptick in production, demand in the market was still poor, prompting imports into the US to cease, through stockpiles dropped by 2.2% to 20.1MM bbl due to increased pulls from exiting inventories. According to an analyst from Linn Group, "We see demand improving in the weeks ahead, but a more aggressive expansion will likely not occur until the end of the month. I was a little surprised at how soft demand was in this particular week, but given the seasonal time frame, blender usage is often pretty soft." (Feb 6)

Petrobras to increase ethanol output. The Brazilian state-owned company's biofuels subsidiary, Petrobras Biocumbustivel (PBio), will process 18% more sugarcane throughout the 2013-2014 harvest season than through the 2012-2013 season, and further expects ethanol production to increase 29% from 822MM L (14.2K b/d) during the 2012-2013 harvest to 1.06B L (18.3K b/d) during the upcoming season. The company, which crushed 21.8MM mt of sugarcane in 2012-2013, will crush 25.6MM mt in the 2013-2014 season. Contributing to increases are plant quality improvements, major replanting efforts, and the addition of 60K hectares (148K acres) of grow-space. Brazilian regulatory changes will also contribute to projected ethanol market improvement in the year to come, with the country's ethanol blend level in gasoline set to rise from 20% to 25% in May, and a governmentally mandated gasoline price increase expected to contribute to strengthened ethanol margins. The company last year saw $126MM in biofuels losses. (Feb 5)

REFERENCE SOURCES AND ABBREVIATIONS

Sources Most of the Digest's information is sourced from newswires (including but not limited to Business Wire, Knight Ridder, OPECNA, PR News Wire, Thomson Reuters, and UPI) or various web sites (including but not limited to the EIA and OPEC). All source dates refer to newswires or information gathered from the Internet unless they are accompanied by one of the following abbreviations.BMG ........... Bloomberg C&EN ........ Chemical & Engineering News CB ................ ICIS Chemical Business CE ............... Chemical Engineering CW .............. Chemical Week DN .............. DieselNet DJ ................ Dow Jones FT ................ Financial Times HA ............... Hydrocarbon Asia

HE ............... Hydrocarbon Engineering HP ................ Hydrocarbon Processing IEA .............. Int'l Energy Agency's Oil Market Report OGJ ............. Oil & Gas Journal PTS .............. Platts PTQ ............. Petroleum Technology Quarterly SGE ............. Sino Global Energy ECON ......... The Economist WSJ .............. Wall Street Journal

Abbreviations 1Q, 2Q, 3Q, 4Q ........ (the) first, second, third, and fourth quarters,

respectively AAA ........................... American Automobile Association (US) ANS ............................ Alaskan North Slope crude API ............................. American Petroleum Institute (US) ARA ............................ Antwerp, Rotterdam, Amsterdam ASTM ......................... American Society for Testing & Materials b or bbl ...................... barrel(s) B .................................. billion boe .............................. barrel(s) of oil equivalent CA ............................... California CAA ............................ Clean Air Act (US) CARB ......................... California Air Resources Board cf ................................. cubic foot, cubic feet cfr ................................ cost and freight cif ................................ cost, insurance, and freight Concawe .................... Conservation of Clean Air and Water

Europe CIS .............................. Commonwealth of Independent States CNG ........................... compressed natural gas cst ................................ centistoke d .................................. day DOE ........................... Department of Energy EEC ............................ European Economic Community EIA ................................ US Energy Information Administration EPA ............................ US Environmental Protection Agency EPC(M) ...................... engineering, procurement, and construction

(management) EU15 .......................... 15 original EU members EU25 .......................... EU15 and the 10 new members admitted in

May 2004 EUROPIA ................. European Petroleum Industry Association

(Brussels) FCV ............................ fuel cell vehicle fd ................................. free delivered FEED ......................... front-end engineering design fob .............................. free on board gal ................................ gallon GHG .......................... greenhouse gas(es) GTL ............................ gas to liquid(s) h .................................. hour H1 or H2 ................... first or second half of the year ICE ............................. Int'l Commodity Exchange (UK) IEA ............................. Int'l Energy Agency (Paris-based)

IPO ............................. initial public offering j.v................................. joint venture LPG ............................ liquefied petroleum gas K ................................. thousand kL ................................ kiloliter lb ................................. pound(s) METI .......................... Ministry of Economy, Trade and Industry

(Japan) MM ............................. million MOU .......................... memorandum of understanding mpg ............................. miles per gallon mt ................................ metric ton MW ............................. megawatt N.A. ............................ not applicable or not available NAAQS ..................... national ambient air quality standards NESCAUM ............... Northeast States for Coordinated Air Use

Management NG .............................. natural gas NGL ........................... natural gas liquid NPRA ......................... National Petrochemical & Refiners

Association (US) NWE .......................... Northwest Europe NYMEX .................... New York Mercantile Exchange (US) OECD ........................ Organization for Economic Cooperation &

Development OPEC ......................... Organization of the Petroleum Exporting

Countries OSHA ........................ Occupational, Safety and Health Admin. (US) PC ............................... petrochemical(s) PM .............................. particulate matter RBOB ......................... RFG before oxygenate blending RFG ............................ reformulated gasoline RMT ............................... refining, marketing, and transportation RVP ............................ Reid vapor pressure SCAQMD .................. South Coast Air Quality Management

District (California) VLCC ......................... very large crude carrier WTI ............................ West Texas Intermediate y ................................... year ¢ ................................... US cent(s) € ................................... EU euro(s) £ .................................. UK pound(s) $ ................................... US dollar(s) ¥ .................................. Japanese yen

Please note that other international currencies are abbreviated using International Standards Organization codes, which can be found at www.xe.com

worldwide refining business digest weekly.e

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