Opportunities in US Refining

Introduction

The US shale boom has provided a boost for the countrys refiners, which have benefitted from soaring domestic crude production, a ban on exporting oil and insufficient infrastructure to transport the countrys crude to new markets. These factors have all contributed to creating an oversupply of oil, which has depressed prices of domestic crude and kept feedstock costs for refiners low.

Prices for West Texas Intermediate (WTI) crude have tumbled by around 60% since July 2014, which has given US refiners a competitive advantage over foreign competitors, allowing them to boost refinery utilization rates to record highs and invest in capacity expansion.

But US crude prices have now fallen so low that the staggering growth rates the country has experienced in upstream production over the past few years is beginning to slow, which would threaten availability of cheap feedstock for refiners.

The US governments decision last year to allow two companies to export conden-sate has also reopened the debate surrounding whether the 40-year old ban on crude exports should be lifted.

The upstream sector is lobbying hard to make this happen in the hope that their crude then would be able to reach export markets in Europe and Asia where they could achieve higher prices.

However, if the ban is lifted, the refining sector could lose its access to cheap crude feedstock, pushing its costs up and rendering recent investments in capacity expansion economically unviable.

This paper will outline the supply and policy concerns facing potential new investors in the US refining sector and explain the advantages and challenges that remain to ensure the continued profitability of the industry.

US Shale Supply

The use of hydraulic fracturing over the past decade has unlocked a wealth of US shale oil and gas resources - previously considered uneconomic to produce and has helped the US to transform itself into an energy producing powerhouse.

US crude output reached 9.19 million barrels per day (b/d) on 9 January 2015, a 1 million b/d rise from year-earlier figures and up from production lows of 3.8 million b/d in September 2008. The US Energy Information Administration (EIA) expects oil production to increase from an average of 8.7 million b/d in 2014 to 9.3 million b/d this year, then reaching 9.5 million b/d in 2016.

Table: EIA figures on US crude production Jan 1983-2015:

US Crude Oil and Liquids Fuels Production

This increase in domestic production has contributed to a significant decline in the US crude oil imports over the past decade. The share of total US liquid fuels consumption met by net imports fell from 60% in 2005 to just 27% in 2014. The EIA expects this to fall further, to 20% in 2016, which would be the lowest level since 1968.

Prices and Production

However, in the medium-term the EIA expects US crude production growth to slow mainly because of the recent crash in domestic crude prices.

The US benchmark crude has lost almost 60% of its value in the past seven months due to these rapid rises in US oil production, a lack of transportation infrastructure to take crude to markets and a 40-year-old government ban on exporting US crude.

The EIA estimates WTI crude oil prices will average $49/b in the first half of 2015, down from $100/b in July last year. This will lead to a slowdown in drilling activity because of unattractive economic returns in some areas of both emerging and mature oil production regions.

Fast depletion rates for shale wells mean high levels of capital investment are needed to finance new production. With crude prices falling and US interest rates rising, it will be increasingly tougher to finance this expansion.

Some companies have begun redirecting investment away from marginal explora-tion and research drilling to focus instead on proven, core areas in already-pro-ducing, major tight oil plays.

However, WTI prices are expected to remain high enough to support some development drilling activity in 2015 in the Bakken, Eagle Ford, Niobrara, and Permian Basin, albeit at lower levels than previously forecast.

Companies which have lower drilling and debt costs and have acreage in the sweet spots of these regions will continue to drill highly productive wells in 2015, the EIA said.

Bill Fairhurst, Vice President Exploration at Eagle Oil & Gas, said drilling has already begun to slow down because of the oil price drop.

Weve already seen a 200-250 rig count drop which is a more direct indicator of what will happen with production in the least economic plays in the US, Fairhurst said. Drilling will continue because some operators are in a better financial place than others and have more economically viable acreage.

Eagle Oil and Gas has operations in some of the US most prolific shale plays such as the Eagle Ford, Haynesville and the Marcellus.

He added that high decline rates in shale wells meant that any slowdown in drilling new wells will result in quickly slowing overall production growth. Fairhurst said that there has already been a slowing in the rate of production increases in the Permian, Eagle Ford and Bakken plays.

The negative side is the way these wells perform. They have extremely high decline rates over the first two years. You have to keep drilling wells to replace the rapidly declining production. As soon as you stop that treadmill (of drilling) youll start to see production cut quickly.

Fairhurst said at the end of the first quarter of 2015 that we would start to see the effects of crude price falls on production.

He added that the rates at which shale operators can drill economically varies.

People who are not the best performers could produce in the best areas at $50-60/b but would differ depending on many variables. But at $50/b more than half of wells drilled are not economic.

Charles Ebinger, a senior fellow in the Energy Security and Climate Initiative at the Brookings Institution, said he believes WTI prices would have to fall to around $30/b and stay there for 6-12 months before we start to see significant produc-tion cuts.

Ebinger said he believes WTI prices will fall to around $30/b in the next few months before rising to around $60/b next year.

Its going to hurt [the upstream industry] a lot before it gets better, Ebinger said. But Id be very surprised if a year from now were not seeing prices around $60/b.

Ebinger said breakeven prices for drilling shale wells vary from well to well and from play to play. Some existing Bakken wells, which are already producing, could continue to do so if WTI prices fall as low as $28/b. However less productive wells could be rendered unviable if WTI falls below $42/b.

The EIA expects US crude production to reach 9.4 million b/d in the second quarter of 2015 and then decline by 190,000 b/d in the third quarter because of the drop in crude prices.

If WTI prices start to rise in the second half of 2015, drilling activity could increase again as companies take advantage of lower costs for both leasing acreage and drilling services, causing production to rise at a relatively low WTI price.

However the EIA adds that whether this forecast proves to be true will depend on actual prices available at the wellhead and drilling economics that vary across regions and operators.

The Impact of the Export Ban

The US government introduced a ban on exporting crude oil in 1975 to protect US consumers from volatility and price spikes.

But four decades later US crude output is expected to surpass Russias and Saudi Arabias. The debate over whether the export should be lifted has come to the forefront of the countrys political agenda.

Industry experts generally agree there is increasing momentum behind the individuals opposing the ban and the economic benefits to the US economy would be huge. However, most agree it is unlikely to happen under the current administration.

Eventually the ban will be lifted whether its done this year, under this administra-tion, or not. Thats because its outdated and doesnt reflect the energy reality we have today, said Robert Dillon, spokesperson for Republican Senator Lisa Murkowski a proponent of lifting the export ban.

He added: For the upstream (lifting the ban) would be good as the market is saturated. Refiners might not have such a big discount (if the ban in lifted) but they will still have access to lots of US crude. The more supply there is on the

global market the better for everybody.

There are estimates that suggest that lifting the 1970s-era restrictions on US crude oil exports could cause production to increase to 11.2 million b/d and add industry-wide investment of nearly $750 billion. It would also support almost a million jobs.

The upstream industry is lobbying hard to get the crude export ban lifted.

What we [upstream producers] are asking for is the ability to compete at world market prices. I think it will happen this year which will help US crude reach world markets, Fairhurst said.

However for the refining sector, allowing the US to export crude could push their feedstock costs up, rendering planned or recently completed refinery capacity additions or upgrades uneconomic.

Another issue is the Jones Act which states that all US crude or oil products shipped between US ports has to be done on a ship which has been built, owned and crewed by US citizens.

Due to a shortage of these ships, transport costs between US ports are high. So if the US crude export ban was lifted, it would become cheaper to ship US crude and products to Europe on a foreign ship than it would be to transport the products to the US East Coast. This could potentially render it uneconomic to ship US west coast crude and oil products to east coast refineries, forcing the sector offline.

Fairhurst said the majority of US refiners wont suffer financially if the ban is lifted because many domestic refineries are configured to process heavier crudes rather than the light, sweet crude produced from US shale plays. There is no shortage of these heavier crudes which many refineries process, coming from Canada and Venezuela.

For the refineries set up to process light, sweet crude they already have more than they can process, Fairhurst said.

Compared to the huge advantage the American consumer and the exploration and production industry will have in lifting the ban, the inconvenience to the refining industry will be minor.

However Ebinger is less optimistic about the impact that lifting the export ban would have on refiners.

Most refinery margins now are the best they have been in years. Overall lifting the ban will probably hurt them more than help them because most will lose access to highly discounted crude oil to sell, Ebinger said. .

Refining Industry Overview

The rise in US crude production over the past decade has given refiners access to cheap feedstock and enabled them to invest in capacity increases to boost output.

As of January 1, 2014 there are 133 operating refineries in the US with atmospher-ic crude oil distillation units (ACDU) totaling capacity of 18.9 million b/d.

Production Capacity of Operable Petroleum Refineries: Source: IEA

More than 50% of the country's refinery capacity and most of the country's heavy crude processing capacity is located in the Gulf Coast. The region's 51 operating refineries with ACDUs have capacity totaling 9.7 million b/d.

In 2013 Gulf Coast gross inputs to refineries in the region averaged around 8.2 million b/d, according to EIA figures. Thats up from around 7.2 million b/d in 2003 and soaring above the average 5.5 million b/d processed in the region in 1985.

Genealogy of Major U.S. Refiners Source: EIA

Most crude supply to East Coast refineries has traditionally been imported light sweet crude. The region lacks crude oil pipeline connections from domestic production regions and has very limited production within the area.

However since 2010 increasing light tight crude oil production in the Bakken formation in North Dakota, combined with the expansion of crude-by-rail infrastructure, has reduced the regions import dependence.

The availability of cheap crude for feedstock has boosted US refinery utilization capacity rates as they are able to maximize output.

Refinery utilization rates averaged around 90% last year, according to EIA figures, up from an average of around 86% in 2010.

Percentage of US Refinery Utilization

The Midwest is the second-largest refining region in the country with 27 operable facilities. The 26 refineries currently operating have 4.1 million b/d of ACDU capacity, 70% of which has facilities with coking capacity. The coking unit is needed to process heavy crude oil into higher-valued lighter products, such as distillates and gasoline.

Since 2010, several Midwest refiners have upgraded their facilities to process more heavy crude, adding a total of 157,000 b/d of coking capacity. Over the same time, ACDU capacity has increased by 148,000 b/d and gross inputs have risen by 205,000 b/d.

Valero

Valero is the world's largest independent refiner, with 15 facilities stretching between California, Canada and the UK. This cross-continental network of refineries gives Valero a combined throughput capacity of around 2.9 million b/d.

Valero says the key to its success has been its ability to upgrade and expand refining operations to produce high-value, clean fuels from a wide variety of crude feedstocks, two-thirds of which come from discounted feedstocks.

As an independent refiner rather than an upstream producer Valero adjusts its feedstock mix based on market conditions. It buys crude oil from producing leases, domestic oil trading centers and ships cargoes of foreign and domestic oil.

Heavy sour and residual oil, medium sour oil, and light sweet and other oil grades each represent about one-third of the companys feedstocks.

Valero has invested heavily in expanding and upgrading its refinery capacity to be able to process the large amounts of US light, tight crude being produced.

In 2013 Valero completed work on a new hydrocracker unit at its St. Charles refinery in Louisiana with a throughput rate of 60,000 b/d. Valero started up a similar hydrocracker at its Port Arthur refinery in December 2012.

The hydrocrackers were designed to take advantage of high crude oil and low natural gas prices at the time and to enable the company to process heavy-sulfur crude.

They were designed mainly to produce diesel to meet growing demand in both domestic and export markets. Each of the units cost about $1.6 billion to build, Valero said.

The company is also pursuing projects to expand throughput capacity to 75,000 b/d at each of the new hydrocrackers. With successful permitting, the expansion projects are expected to be complete this year.

The first round of expansion was about meeting demand for products around the world. The second round was about handling supply of light, sweet crude in the US, said Bill Day, Vice President Community and Media Relations at Valero.

Companies like Valero are experimenting. We want more cheap crude so we support (the) Keystone XL (pipeline). Were well positioned to take advantage of abundant crude supplies in the US and natural gas too, Day said.

We havent seen any decline in upstream production so far. Were buying lots of discounted crude, which gives us an advantage. Our heavy presence on the Gulf Coast is well positioned for product export markets. The cost [of new refinery capacity and upgrades] is the biggest challenge.

Day declined to comment on whether Valero was concerned about the possibility of the US crude export ban being lifted, potentially increasing the companys feedstock costs.

We support the current system going forward, he said.

Day added that overcoming environmental regulations and a dearth of skilled labour were also challenges the company has to face.

Were often competing with the upstream sector for labour. Weve had to search a bit harder for skilled workers and thats pushed the price up, Day said.

He added that Valero hasnt taken any additional investment decisions to boost refinery capacity or upgrade facilities because of the cost of undergoing such work.

Were cautious spending money. We want to make sure there will be a long-term return for our shareholders.

What they are considering is investing in new petrochemical capacity, he said.

ExxonMobils share of the market

ExxonMobil is the largest refiner in the world and processes more than 1.9 million barrels of crude oil per day through its 7 facilities in the US.

Last year the company announced it was investing $1 billion in upgrading its refinery in Antwerp, Belgium. ExxonMobil is building a new delayed coker unit at the facility to convert heavy, higher sulfur residual oil into products such as diesel. This is despite conditions for Europe-based refiners being far more challenging than in the US due to stagnant demand growth, years of high Brent crude prices and competition from capacity additions in other regions.

The refining industry makes long-term investment decisions looking forward over 30 years. ExxonMobil makes long-term investment decisions with a view that they must be able to perform across a range of pricing that accommodates the types of price swings we have seen in recent months, ExxonMobil said.

It added: Our recent investments in Europe at Antwerp and Slagen provide excellent examples of ExxonMobils long-term view.

Condensate Investments

While exports of US crude and other products remain banned, there has been a loosening of laws around exports of condensate an ultra-light oil that can be exported after mild distillation.

Condensate is produced from shale plays alongside crude when underground it is gassier in structure but it then condenses into a liquid when pumped to the surface.

US Crude And Condensate Production 1960-2014

Similarly to crude, exports of condensate have long been banned. However, in 2014 the US Commerce Department granted permission to two Texas-based companies, Pioneer Natural Resources and Enterprise Products Partners, to export condensate abroad.

Pioneer Natural Resources now sells condensate from its Eagle Ford shale site to Enterprise, which markets the oil to foreign buyers. The first cargo was exported in July 2014. The company said it has received higher prices than it could command for condensate sales domestically and that international interest in its condensate is growing, particularly from Asian petrochemical companies.

Allowing exports of condensate to burgeoning Asian markets has opened up new opportunities for refiners as well as upstream and midstream companies. However, the US government has yet to approve other applications to export condensate.

On December 30 2014 the Federal Government, through the Bureau of Industry and Security (BIS) at the Commerce Department, issued guidelines to the industry regarding the export of processed crude oil and condensate.

The guidelines state that lease condensate, produced from tar sands, gilsonite, and oil shale that has been processed through a crude oil distillation tower is not classified as crude oil but as a petroleum product. This means that it is not subject to the same export restrictions as crude oil is. Those unsure whether their lease condensate has been processed sufficiently to be considered an oil product eligible for export may request a formal Commodity Classification from the BIS.

Jacob Dweck is a partner at Sutherland law firm. He has represented Enterprise in obtaining its successful determination to export processed condensate, and he is counseling many other companies in their government approval process or in engaging in condensate exports on their own.Dweck explains that the technical factors published by the government in the FAQs for determining when processed condensate can be exported are qualita-tive, not quantitative, and that they are not categorical or exhaustive. But he adds that any company able to meet the criteria of the Enterprise classification should be able to export its condensate.Dweck said he does not believe the US crude export ban will be lifted under the current Administration.

The condensate export guidelines (the FAQs) are as far as the Administration is willing to go at this time to ease export restrictions. The Republican Congress also is very unlikely to legislate the ban away Dweck said. Most US refiners believe in free trade and support lifting the ban, and nearly all refiners have no quarrel with condensate exports. However, certain East Coast refiners, representing some 7% of US refining capacity, have banded together to oppose lifting the ban as this will increase their feedstock cost disproportionately. They are particularly concerned about the Jones Act, which requires all shipments of crude from the Gulf to the East Coast to to be on more costly US vessels." He added:If the ban is lifted, the majority of US refiners will do just fine. The US has the world best and most advanced refining fleet. Removing the ban would be economically beneficial all around, rationalizing the allocation of oil and gas

resources in a market-oriented manner and with the greatest benefit to the US as well as our trade relationship with our countries around the world.

Conclusion

There is still plenty of scope for investing in the US refining sector, which will benefit from abundant supplies of crude from the US and Canada even if the export ban is lifted.

Experts say the current low crude oil prices will have a slight impact on US production in the short term but the abundance of light sweet crude available, high storage levels and the fact the many US refineries process heavier crudes means there will be no shortage of available feedstock supply for the industry.

The industry doesnt expect the crude export ban to be lifted under this adminis-tration but momentum is building from both the upstream industry and the political sphere so the longer-term outlook is less certain. Allowing condensate exports has opened the floodgates to new debate on the issue, which proponents say would have enormous benefits for the US economy as a whole, as well as US consumers, while the refining sector will still have access to reasonably prices feedstock.

Expert Insight From: Bill FairhurstVice President ExplorationEagle Oil & Gas

Charles EbingerSenior Fellow, Energy Security Initiative, Foreign PolicyThe Brookings Institution

Robert DillonSpokesperson

Republican Senator Lisa Murkowski

Bill DayVice PresidentMedia RelationsValero

Jacob DweckPartnerSutherland

Opportunities in US Refining

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Introduction

The US shale boom has provided a boost for the countrys refiners, which have benefitted from soaring domestic crude production, a ban on exporting oil and insufficient infrastructure to transport the countrys crude to new markets. These factors have all contributed to creating an oversupply of oil, which has depressed prices of domestic crude and kept feedstock costs for refiners low.

Prices for West Texas Intermediate (WTI) crude have tumbled by around 60% since July 2014, which has given US refiners a competitive advantage over foreign competitors, allowing them to boost refinery utilization rates to record highs and invest in capacity expansion.

But US crude prices have now fallen so low that the staggering growth rates the country has experienced in upstream production over the past few years is beginning to slow, which would threaten availability of cheap feedstock for refiners.

The US governments decision last year to allow two companies to export conden-sate has also reopened the debate surrounding whether the 40-year old ban on crude exports should be lifted.

The upstream sector is lobbying hard to make this happen in the hope that their crude then would be able to reach export markets in Europe and Asia where they could achieve higher prices.

However, if the ban is lifted, the refining sector could lose its access to cheap crude feedstock, pushing its costs up and rendering recent investments in capacity expansion economically unviable.

This paper will outline the supply and policy concerns facing potential new investors in the US refining sector and explain the advantages and challenges that remain to ensure the continued profitability of the industry.

US Shale Supply

The use of hydraulic fracturing over the past decade has unlocked a wealth of US shale oil and gas resources - previously considered uneconomic to produce and has helped the US to transform itself into an energy producing powerhouse.

US crude output reached 9.19 million barrels per day (b/d) on 9 January 2015, a 1 million b/d rise from year-earlier figures and up from production lows of 3.8 million b/d in September 2008. The US Energy Information Administration (EIA) expects oil production to increase from an average of 8.7 million b/d in 2014 to 9.3 million b/d this year, then reaching 9.5 million b/d in 2016.

Table: EIA figures on US crude production Jan 1983-2015:

US Crude Oil and Liquids Fuels Production

This increase in domestic production has contributed to a significant decline in the US crude oil imports over the past decade. The share of total US liquid fuels consumption met by net imports fell from 60% in 2005 to just 27% in 2014. The EIA expects this to fall further, to 20% in 2016, which would be the lowest level since 1968.

Prices and Production

However, in the medium-term the EIA expects US crude production growth to slow mainly because of the recent crash in domestic crude prices.

The US benchmark crude has lost almost 60% of its value in the past seven months due to these rapid rises in US oil production, a lack of transportation infrastructure to take crude to markets and a 40-year-old government ban on exporting US crude.

The EIA estimates WTI crude oil prices will average $49/b in the first half of 2015, down from $100/b in July last year. This will lead to a slowdown in drilling activity because of unattractive economic returns in some areas of both emerging and mature oil production regions.

Fast depletion rates for shale wells mean high levels of capital investment are needed to finance new production. With crude prices falling and US interest rates rising, it will be increasingly tougher to finance this expansion.

Some companies have begun redirecting investment away from marginal explora-tion and research drilling to focus instead on proven, core areas in already-pro-ducing, major tight oil plays.

However, WTI prices are expected to remain high enough to support some development drilling activity in 2015 in the Bakken, Eagle Ford, Niobrara, and Permian Basin, albeit at lower levels than previously forecast.

Companies which have lower drilling and debt costs and have acreage in the sweet spots of these regions will continue to drill highly productive wells in 2015, the EIA said.

Bill Fairhurst, Vice President Exploration at Eagle Oil & Gas, said drilling has already begun to slow down because of the oil price drop.

Weve already seen a 200-250 rig count drop which is a more direct indicator of what will happen with production in the least economic plays in the US, Fairhurst said. Drilling will continue because some operators are in a better financial place than others and have more economically viable acreage.

Eagle Oil and Gas has operations in some of the US most prolific shale plays such as the Eagle Ford, Haynesville and the Marcellus.

He added that high decline rates in shale wells meant that any slowdown in drilling new wells will result in quickly slowing overall production growth. Fairhurst said that there has already been a slowing in the rate of production increases in the Permian, Eagle Ford and Bakken plays.

The negative side is the way these wells perform. They have extremely high decline rates over the first two years. You have to keep drilling wells to replace the rapidly declining production. As soon as you stop that treadmill (of drilling) youll start to see production cut quickly.

Fairhurst said at the end of the first quarter of 2015 that we would start to see the effects of crude price falls on production.

He added that the rates at which shale operators can drill economically varies.

People who are not the best performers could produce in the best areas at $50-60/b but would differ depending on many variables. But at $50/b more than half of wells drilled are not economic.

Charles Ebinger, a senior fellow in the Energy Security and Climate Initiative at the Brookings Institution, said he believes WTI prices would have to fall to around $30/b and stay there for 6-12 months before we start to see significant produc-tion cuts.

Ebinger said he believes WTI prices will fall to around $30/b in the next few months before rising to around $60/b next year.

Its going to hurt [the upstream industry] a lot before it gets better, Ebinger said. But Id be very surprised if a year from now were not seeing prices around $60/b.

Ebinger said breakeven prices for drilling shale wells vary from well to well and from play to play. Some existing Bakken wells, which are already producing, could continue to do so if WTI prices fall as low as $28/b. However less productive wells could be rendered unviable if WTI falls below $42/b.

The EIA expects US crude production to reach 9.4 million b/d in the second quarter of 2015 and then decline by 190,000 b/d in the third quarter because of the drop in crude prices.

If WTI prices start to rise in the second half of 2015, drilling activity could increase again as companies take advantage of lower costs for both leasing acreage and drilling services, causing production to rise at a relatively low WTI price.

However the EIA adds that whether this forecast proves to be true will depend on actual prices available at the wellhead and drilling economics that vary across regions and operators.

The Impact of the Export Ban

The US government introduced a ban on exporting crude oil in 1975 to protect US consumers from volatility and price spikes.

But four decades later US crude output is expected to surpass Russias and Saudi Arabias. The debate over whether the export should be lifted has come to the forefront of the countrys political agenda.

Industry experts generally agree there is increasing momentum behind the individuals opposing the ban and the economic benefits to the US economy would be huge. However, most agree it is unlikely to happen under the current administration.

Eventually the ban will be lifted whether its done this year, under this administra-tion, or not. Thats because its outdated and doesnt reflect the energy reality we have today, said Robert Dillon, spokesperson for Republican Senator Lisa Murkowski a proponent of lifting the export ban.

He added: For the upstream (lifting the ban) would be good as the market is saturated. Refiners might not have such a big discount (if the ban in lifted) but they will still have access to lots of US crude. The more supply there is on the

global market the better for everybody.

There are estimates that suggest that lifting the 1970s-era restrictions on US crude oil exports could cause production to increase to 11.2 million b/d and add industry-wide investment of nearly $750 billion. It would also support almost a million jobs.

The upstream industry is lobbying hard to get the crude export ban lifted.

What we [upstream producers] are asking for is the ability to compete at world market prices. I think it will happen this year which will help US crude reach world markets, Fairhurst said.

However for the refining sector, allowing the US to export crude could push their feedstock costs up, rendering planned or recently completed refinery capacity additions or upgrades uneconomic.

Another issue is the Jones Act which states that all US crude or oil products shipped between US ports has to be done on a ship which has been built, owned and crewed by US citizens.

Due to a shortage of these ships, transport costs between US ports are high. So if the US crude export ban was lifted, it would become cheaper to ship US crude and products to Europe on a foreign ship than it would be to transport the products to the US East Coast. This could potentially render it uneconomic to ship US west coast crude and oil products to east coast refineries, forcing the sector offline.

Fairhurst said the majority of US refiners wont suffer financially if the ban is lifted because many domestic refineries are configured to process heavier crudes rather than the light, sweet crude produced from US shale plays. There is no shortage of these heavier crudes which many refineries process, coming from Canada and Venezuela.

For the refineries set up to process light, sweet crude they already have more than they can process, Fairhurst said.

Compared to the huge advantage the American consumer and the exploration and production industry will have in lifting the ban, the inconvenience to the refining industry will be minor.

However Ebinger is less optimistic about the impact that lifting the export ban would have on refiners.

Most refinery margins now are the best they have been in years. Overall lifting the ban will probably hurt them more than help them because most will lose access to highly discounted crude oil to sell, Ebinger said. .

Refining Industry Overview

The rise in US crude production over the past decade has given refiners access to cheap feedstock and enabled them to invest in capacity increases to boost output.

As of January 1, 2014 there are 133 operating refineries in the US with atmospher-ic crude oil distillation units (ACDU) totaling capacity of 18.9 million b/d.

Production Capacity of Operable Petroleum Refineries: Source: IEA

More than 50% of the country's refinery capacity and most of the country's heavy crude processing capacity is located in the Gulf Coast. The region's 51 operating refineries with ACDUs have capacity totaling 9.7 million b/d.

In 2013 Gulf Coast gross inputs to refineries in the region averaged around 8.2 million b/d, according to EIA figures. Thats up from around 7.2 million b/d in 2003 and soaring above the average 5.5 million b/d processed in the region in 1985.

Genealogy of Major U.S. Refiners Source: EIA

Most crude supply to East Coast refineries has traditionally been imported light sweet crude. The region lacks crude oil pipeline connections from domestic production regions and has very limited production within the area.

However since 2010 increasing light tight crude oil production in the Bakken formation in North Dakota, combined with the expansion of crude-by-rail infrastructure, has reduced the regions import dependence.

The availability of cheap crude for feedstock has boosted US refinery utilization capacity rates as they are able to maximize output.

Refinery utilization rates averaged around 90% last year, according to EIA figures, up from an average of around 86% in 2010.

Percentage of US Refinery Utilization

The Midwest is the second-largest refining region in the country with 27 operable facilities. The 26 refineries currently operating have 4.1 million b/d of ACDU capacity, 70% of which has facilities with coking capacity. The coking unit is needed to process heavy crude oil into higher-valued lighter products, such as distillates and gasoline.

Since 2010, several Midwest refiners have upgraded their facilities to process more heavy crude, adding a total of 157,000 b/d of coking capacity. Over the same time, ACDU capacity has increased by 148,000 b/d and gross inputs have risen by 205,000 b/d.

Valero

Valero is the world's largest independent refiner, with 15 facilities stretching between California, Canada and the UK. This cross-continental network of refineries gives Valero a combined throughput capacity of around 2.9 million b/d.

Valero says the key to its success has been its ability to upgrade and expand refining operations to produce high-value, clean fuels from a wide variety of crude feedstocks, two-thirds of which come from discounted feedstocks.

As an independent refiner rather than an upstream producer Valero adjusts its feedstock mix based on market conditions. It buys crude oil from producing leases, domestic oil trading centers and ships cargoes of foreign and domestic oil.

Heavy sour and residual oil, medium sour oil, and light sweet and other oil grades each represent about one-third of the companys feedstocks.

Valero has invested heavily in expanding and upgrading its refinery capacity to be able to process the large amounts of US light, tight crude being produced.

In 2013 Valero completed work on a new hydrocracker unit at its St. Charles refinery in Louisiana with a throughput rate of 60,000 b/d. Valero started up a similar hydrocracker at its Port Arthur refinery in December 2012.

The hydrocrackers were designed to take advantage of high crude oil and low natural gas prices at the time and to enable the company to process heavy-sulfur crude.

They were designed mainly to produce diesel to meet growing demand in both domestic and export markets. Each of the units cost about $1.6 billion to build, Valero said.

The company is also pursuing projects to expand throughput capacity to 75,000 b/d at each of the new hydrocrackers. With successful permitting, the expansion projects are expected to be complete this year.

The first round of expansion was about meeting demand for products around the world. The second round was about handling supply of light, sweet crude in the US, said Bill Day, Vice President Community and Media Relations at Valero.

Companies like Valero are experimenting. We want more cheap crude so we support (the) Keystone XL (pipeline). Were well positioned to take advantage of abundant crude supplies in the US and natural gas too, Day said.

We havent seen any decline in upstream production so far. Were buying lots of discounted crude, which gives us an advantage. Our heavy presence on the Gulf Coast is well positioned for product export markets. The cost [of new refinery capacity and upgrades] is the biggest challenge.

Day declined to comment on whether Valero was concerned about the possibility of the US crude export ban being lifted, potentially increasing the companys feedstock costs.

We support the current system going forward, he said.

Day added that overcoming environmental regulations and a dearth of skilled labour were also challenges the company has to face.

Were often competing with the upstream sector for labour. Weve had to search a bit harder for skilled workers and thats pushed the price up, Day said.

He added that Valero hasnt taken any additional investment decisions to boost refinery capacity or upgrade facilities because of the cost of undergoing such work.

Were cautious spending money. We want to make sure there will be a long-term return for our shareholders.

What they are considering is investing in new petrochemical capacity, he said.

ExxonMobils share of the market

ExxonMobil is the largest refiner in the world and processes more than 1.9 million barrels of crude oil per day through its 7 facilities in the US.

Last year the company announced it was investing $1 billion in upgrading its refinery in Antwerp, Belgium. ExxonMobil is building a new delayed coker unit at the facility to convert heavy, higher sulfur residual oil into products such as diesel. This is despite conditions for Europe-based refiners being far more challenging than in the US due to stagnant demand growth, years of high Brent crude prices and competition from capacity additions in other regions.

The refining industry makes long-term investment decisions looking forward over 30 years. ExxonMobil makes long-term investment decisions with a view that they must be able to perform across a range of pricing that accommodates the types of price swings we have seen in recent months, ExxonMobil said.

It added: Our recent investments in Europe at Antwerp and Slagen provide excellent examples of ExxonMobils long-term view.

Condensate Investments

While exports of US crude and other products remain banned, there has been a loosening of laws around exports of condensate an ultra-light oil that can be exported after mild distillation.

Condensate is produced from shale plays alongside crude when underground it is gassier in structure but it then condenses into a liquid when pumped to the surface.

US Crude And Condensate Production 1960-2014

Similarly to crude, exports of condensate have long been banned. However, in 2014 the US Commerce Department granted permission to two Texas-based companies, Pioneer Natural Resources and Enterprise Products Partners, to export condensate abroad.

Pioneer Natural Resources now sells condensate from its Eagle Ford shale site to Enterprise, which markets the oil to foreign buyers. The first cargo was exported in July 2014. The company said it has received higher prices than it could command for condensate sales domestically and that international interest in its condensate is growing, particularly from Asian petrochemical companies.

Allowing exports of condensate to burgeoning Asian markets has opened up new opportunities for refiners as well as upstream and midstream companies. However, the US government has yet to approve other applications to export condensate.

On December 30 2014 the Federal Government, through the Bureau of Industry and Security (BIS) at the Commerce Department, issued guidelines to the industry regarding the export of processed crude oil and condensate.

The guidelines state that lease condensate, produced from tar sands, gilsonite, and oil shale that has been processed through a crude oil distillation tower is not classified as crude oil but as a petroleum product. This means that it is not subject to the same export restrictions as crude oil is. Those unsure whether their lease condensate has been processed sufficiently to be considered an oil product eligible for export may request a formal Commodity Classification from the BIS.

Jacob Dweck is a partner at Sutherland law firm. He has represented Enterprise in obtaining its successful determination to export processed condensate, and he is counseling many other companies in their government approval process or in engaging in condensate exports on their own.Dweck explains that the technical factors published by the government in the FAQs for determining when processed condensate can be exported are qualita-tive, not quantitative, and that they are not categorical or exhaustive. But he adds that any company able to meet the criteria of the Enterprise classification should be able to export its condensate.Dweck said he does not believe the US crude export ban will be lifted under the current Administration.

The condensate export guidelines (the FAQs) are as far as the Administration is willing to go at this time to ease export restrictions. The Republican Congress also is very unlikely to legislate the ban away Dweck said. Most US refiners believe in free trade and support lifting the ban, and nearly all refiners have no quarrel with condensate exports. However, certain East Coast refiners, representing some 7% of US refining capacity, have banded together to oppose lifting the ban as this will increase their feedstock cost disproportionately. They are particularly concerned about the Jones Act, which requires all shipments of crude from the Gulf to the East Coast to to be on more costly US vessels." He added:If the ban is lifted, the majority of US refiners will do just fine. The US has the world best and most advanced refining fleet. Removing the ban would be economically beneficial all around, rationalizing the allocation of oil and gas

resources in a market-oriented manner and with the greatest benefit to the US as well as our trade relationship with our countries around the world.

Conclusion

There is still plenty of scope for investing in the US refining sector, which will benefit from abundant supplies of crude from the US and Canada even if the export ban is lifted.

Experts say the current low crude oil prices will have a slight impact on US production in the short term but the abundance of light sweet crude available, high storage levels and the fact the many US refineries process heavier crudes means there will be no shortage of available feedstock supply for the industry.

The industry doesnt expect the crude export ban to be lifted under this adminis-tration but momentum is building from both the upstream industry and the political sphere so the longer-term outlook is less certain. Allowing condensate exports has opened the floodgates to new debate on the issue, which proponents say would have enormous benefits for the US economy as a whole, as well as US consumers, while the refining sector will still have access to reasonably prices feedstock.

Opportunities in US Refining

North American Refining Conference

June 9-10 // DoubleTree by Hilton Hotel Houston - Greenway Plaza Book Early for Big Discounts

www.refiningupdate.com

Introduction

The US shale boom has provided a boost for the countrys refiners, which have benefitted from soaring domestic crude production, a ban on exporting oil and insufficient infrastructure to transport the countrys crude to new markets. These factors have all contributed to creating an oversupply of oil, which has depressed prices of domestic crude and kept feedstock costs for refiners low.

Prices for West Texas Intermediate (WTI) crude have tumbled by around 60% since July 2014, which has given US refiners a competitive advantage over foreign competitors, allowing them to boost refinery utilization rates to record highs and invest in capacity expansion.

But US crude prices have now fallen so low that the staggering growth rates the country has experienced in upstream production over the past few years is beginning to slow, which would threaten availability of cheap feedstock for refiners.

The US governments decision last year to allow two companies to export conden-sate has also reopened the debate surrounding whether the 40-year old ban on crude exports should be lifted.

The upstream sector is lobbying hard to make this happen in the hope that their crude then would be able to reach export markets in Europe and Asia where they could achieve higher prices.

However, if the ban is lifted, the refining sector could lose its access to cheap crude feedstock, pushing its costs up and rendering recent investments in capacity expansion economically unviable.

This paper will outline the supply and policy concerns facing potential new investors in the US refining sector and explain the advantages and challenges that remain to ensure the continued profitability of the industry.

US Shale Supply

The use of hydraulic fracturing over the past decade has unlocked a wealth of US shale oil and gas resources - previously considered uneconomic to produce and has helped the US to transform itself into an energy producing powerhouse.

US crude output reached 9.19 million barrels per day (b/d) on 9 January 2015, a 1 million b/d rise from year-earlier figures and up from production lows of 3.8 million b/d in September 2008. The US Energy Information Administration (EIA) expects oil production to increase from an average of 8.7 million b/d in 2014 to 9.3 million b/d this year, then reaching 9.5 million b/d in 2016.

Table: EIA figures on US crude production Jan 1983-2015:

US Crude Oil and Liquids Fuels Production

This increase in domestic production has contributed to a significant decline in the US crude oil imports over the past decade. The share of total US liquid fuels consumption met by net imports fell from 60% in 2005 to just 27% in 2014. The EIA expects this to fall further, to 20% in 2016, which would be the lowest level since 1968.

Prices and Production

However, in the medium-term the EIA expects US crude production growth to slow mainly because of the recent crash in domestic crude prices.

The US benchmark crude has lost almost 60% of its value in the past seven months due to these rapid rises in US oil production, a lack of transportation infrastructure to take crude to markets and a 40-year-old government ban on exporting US crude.

The EIA estimates WTI crude oil prices will average $49/b in the first half of 2015, down from $100/b in July last year. This will lead to a slowdown in drilling activity because of unattractive economic returns in some areas of both emerging and mature oil production regions.

Fast depletion rates for shale wells mean high levels of capital investment are needed to finance new production. With crude prices falling and US interest rates rising, it will be increasingly tougher to finance this expansion.

Some companies have begun redirecting investment away from marginal explora-tion and research drilling to focus instead on proven, core areas in already-pro-ducing, major tight oil plays.

However, WTI prices are expected to remain high enough to support some development drilling activity in 2015 in the Bakken, Eagle Ford, Niobrara, and Permian Basin, albeit at lower levels than previously forecast.

Companies which have lower drilling and debt costs and have acreage in the sweet spots of these regions will continue to drill highly productive wells in 2015, the EIA said.

Bill Fairhurst, Vice President Exploration at Eagle Oil & Gas, said drilling has already begun to slow down because of the oil price drop.

Weve already seen a 200-250 rig count drop which is a more direct indicator of what will happen with production in the least economic plays in the US, Fairhurst said. Drilling will continue because some operators are in a better financial place than others and have more economically viable acreage.

Eagle Oil and Gas has operations in some of the US most prolific shale plays such as the Eagle Ford, Haynesville and the Marcellus.

He added that high decline rates in shale wells meant that any slowdown in drilling new wells will result in quickly slowing overall production growth. Fairhurst said that there has already been a slowing in the rate of production increases in the Permian, Eagle Ford and Bakken plays.

The negative side is the way these wells perform. They have extremely high decline rates over the first two years. You have to keep drilling wells to replace the rapidly declining production. As soon as you stop that treadmill (of drilling) youll start to see production cut quickly.

Fairhurst said at the end of the first quarter of 2015 that we would start to see the effects of crude price falls on production.

He added that the rates at which shale operators can drill economically varies.

People who are not the best performers could produce in the best areas at $50-60/b but would differ depending on many variables. But at $50/b more than half of wells drilled are not economic.

Charles Ebinger, a senior fellow in the Energy Security and Climate Initiative at the Brookings Institution, said he believes WTI prices would have to fall to around $30/b and stay there for 6-12 months before we start to see significant produc-tion cuts.

Ebinger said he believes WTI prices will fall to around $30/b in the next few months before rising to around $60/b next year.

Its going to hurt [the upstream industry] a lot before it gets better, Ebinger said. But Id be very surprised if a year from now were not seeing prices around $60/b.

Ebinger said breakeven prices for drilling shale wells vary from well to well and from play to play. Some existing Bakken wells, which are already producing, could continue to do so if WTI prices fall as low as $28/b. However less productive wells could be rendered unviable if WTI falls below $42/b.

The EIA expects US crude production to reach 9.4 million b/d in the second quarter of 2015 and then decline by 190,000 b/d in the third quarter because of the drop in crude prices.

If WTI prices start to rise in the second half of 2015, drilling activity could increase again as companies take advantage of lower costs for both leasing acreage and drilling services, causing production to rise at a relatively low WTI price.

However the EIA adds that whether this forecast proves to be true will depend on actual prices available at the wellhead and drilling economics that vary across regions and operators.

The Impact of the Export Ban

The US government introduced a ban on exporting crude oil in 1975 to protect US consumers from volatility and price spikes.

But four decades later US crude output is expected to surpass Russias and Saudi Arabias. The debate over whether the export should be lifted has come to the forefront of the countrys political agenda.

Industry experts generally agree there is increasing momentum behind the individuals opposing the ban and the economic benefits to the US economy would be huge. However, most agree it is unlikely to happen under the current administration.

Eventually the ban will be lifted whether its done this year, under this administra-tion, or not. Thats because its outdated and doesnt reflect the energy reality we have today, said Robert Dillon, spokesperson for Republican Senator Lisa Murkowski a proponent of lifting the export ban.

He added: For the upstream (lifting the ban) would be good as the market is saturated. Refiners might not have such a big discount (if the ban in lifted) but they will still have access to lots of US crude. The more supply there is on the

global market the better for everybody.

There are estimates that suggest that lifting the 1970s-era restrictions on US crude oil exports could cause production to increase to 11.2 million b/d and add industry-wide investment of nearly $750 billion. It would also support almost a million jobs.

The upstream industry is lobbying hard to get the crude export ban lifted.

What we [upstream producers] are asking for is the ability to compete at world market prices. I think it will happen this year which will help US crude reach world markets, Fairhurst said.

However for the refining sector, allowing the US to export crude could push their feedstock costs up, rendering planned or recently completed refinery capacity additions or upgrades uneconomic.

Another issue is the Jones Act which states that all US crude or oil products shipped between US ports has to be done on a ship which has been built, owned and crewed by US citizens.

Due to a shortage of these ships, transport costs between US ports are high. So if the US crude export ban was lifted, it would become cheaper to ship US crude and products to Europe on a foreign ship than it would be to transport the products to the US East Coast. This could potentially render it uneconomic to ship US west coast crude and oil products to east coast refineries, forcing the sector offline.

Fairhurst said the majority of US refiners wont suffer financially if the ban is lifted because many domestic refineries are configured to process heavier crudes rather than the light, sweet crude produced from US shale plays. There is no shortage of these heavier crudes which many refineries process, coming from Canada and Venezuela.

For the refineries set up to process light, sweet crude they already have more than they can process, Fairhurst said.

Compared to the huge advantage the American consumer and the exploration and production industry will have in lifting the ban, the inconvenience to the refining industry will be minor.

However Ebinger is less optimistic about the impact that lifting the export ban would have on refiners.

Most refinery margins now are the best they have been in years. Overall lifting the ban will probably hurt them more than help them because most will lose access to highly discounted crude oil to sell, Ebinger said. .

Refining Industry Overview

The rise in US crude production over the past decade has given refiners access to cheap feedstock and enabled them to invest in capacity increases to boost output.

As of January 1, 2014 there are 133 operating refineries in the US with atmospher-ic crude oil distillation units (ACDU) totaling capacity of 18.9 million b/d.

Production Capacity of Operable Petroleum Refineries: Source: IEA

More than 50% of the country's refinery capacity and most of the country's heavy crude processing capacity is located in the Gulf Coast. The region's 51 operating refineries with ACDUs have capacity totaling 9.7 million b/d.

In 2013 Gulf Coast gross inputs to refineries in the region averaged around 8.2 million b/d, according to EIA figures. Thats up from around 7.2 million b/d in 2003 and soaring above the average 5.5 million b/d processed in the region in 1985.

Genealogy of Major U.S. Refiners Source: EIA

Most crude supply to East Coast refineries has traditionally been imported light sweet crude. The region lacks crude oil pipeline connections from domestic production regions and has very limited production within the area.

However since 2010 increasing light tight crude oil production in the Bakken formation in North Dakota, combined with the expansion of crude-by-rail infrastructure, has reduced the regions import dependence.

The availability of cheap crude for feedstock has boosted US refinery utilization capacity rates as they are able to maximize output.

Refinery utilization rates averaged around 90% last year, according to EIA figures, up from an average of around 86% in 2010.

Percentage of US Refinery Utilization

The Midwest is the second-largest refining region in the country with 27 operable facilities. The 26 refineries currently operating have 4.1 million b/d of ACDU capacity, 70% of which has facilities with coking capacity. The coking unit is needed to process heavy crude oil into higher-valued lighter products, such as distillates and gasoline.

Since 2010, several Midwest refiners have upgraded their facilities to process more heavy crude, adding a total of 157,000 b/d of coking capacity. Over the same time, ACDU capacity has increased by 148,000 b/d and gross inputs have risen by 205,000 b/d.

Valero

Valero is the world's largest independent refiner, with 15 facilities stretching between California, Canada and the UK. This cross-continental network of refineries gives Valero a combined throughput capacity of around 2.9 million b/d.

Valero says the key to its success has been its ability to upgrade and expand refining operations to produce high-value, clean fuels from a wide variety of crude feedstocks, two-thirds of which come from discounted feedstocks.

As an independent refiner rather than an upstream producer Valero adjusts its feedstock mix based on market conditions. It buys crude oil from producing leases, domestic oil trading centers and ships cargoes of foreign and domestic oil.

Heavy sour and residual oil, medium sour oil, and light sweet and other oil grades each represent about one-third of the companys feedstocks.

Valero has invested heavily in expanding and upgrading its refinery capacity to be able to process the large amounts of US light, tight crude being produced.

In 2013 Valero completed work on a new hydrocracker unit at its St. Charles refinery in Louisiana with a throughput rate of 60,000 b/d. Valero started up a similar hydrocracker at its Port Arthur refinery in December 2012.

The hydrocrackers were designed to take advantage of high crude oil and low natural gas prices at the time and to enable the company to process heavy-sulfur crude.

They were designed mainly to produce diesel to meet growing demand in both domestic and export markets. Each of the units cost about $1.6 billion to build, Valero said.

The company is also pursuing projects to expand throughput capacity to 75,000 b/d at each of the new hydrocrackers. With successful permitting, the expansion projects are expected to be complete this year.

The first round of expansion was about meeting demand for products around the world. The second round was about handling supply of light, sweet crude in the US, said Bill Day, Vice President Community and Media Relations at Valero.

Companies like Valero are experimenting. We want more cheap crude so we support (the) Keystone XL (pipeline). Were well positioned to take advantage of abundant crude supplies in the US and natural gas too, Day said.

We havent seen any decline in upstream production so far. Were buying lots of discounted crude, which gives us an advantage. Our heavy presence on the Gulf Coast is well positioned for product export markets. The cost [of new refinery capacity and upgrades] is the biggest challenge.

Day declined to comment on whether Valero was concerned about the possibility of the US crude export ban being lifted, potentially increasing the companys feedstock costs.

We support the current system going forward, he said.

Day added that overcoming environmental regulations and a dearth of skilled labour were also challenges the company has to face.

Were often competing with the upstream sector for labour. Weve had to search a bit harder for skilled workers and thats pushed the price up, Day said.

He added that Valero hasnt taken any additional investment decisions to boost refinery capacity or upgrade facilities because of the cost of undergoing such work.

Were cautious spending money. We want to make sure there will be a long-term return for our shareholders.

What they are considering is investing in new petrochemical capacity, he said.

ExxonMobils share of the market

ExxonMobil is the largest refiner in the world and processes more than 1.9 million barrels of crude oil per day through its 7 facilities in the US.

Last year the company announced it was investing $1 billion in upgrading its refinery in Antwerp, Belgium. ExxonMobil is building a new delayed coker unit at the facility to convert heavy, higher sulfur residual oil into products such as diesel. This is despite conditions for Europe-based refiners being far more challenging than in the US due to stagnant demand growth, years of high Brent crude prices and competition from capacity additions in other regions.

The refining industry makes long-term investment decisions looking forward over 30 years. ExxonMobil makes long-term investment decisions with a view that they must be able to perform across a range of pricing that accommodates the types of price swings we have seen in recent months, ExxonMobil said.

It added: Our recent investments in Europe at Antwerp and Slagen provide excellent examples of ExxonMobils long-term view.

Condensate Investments

While exports of US crude and other products remain banned, there has been a loosening of laws around exports of condensate an ultra-light oil that can be exported after mild distillation.

Condensate is produced from shale plays alongside crude when underground it is gassier in structure but it then condenses into a liquid when pumped to the surface.

US Crude And Condensate Production 1960-2014

Similarly to crude, exports of condensate have long been banned. However, in 2014 the US Commerce Department granted permission to two Texas-based companies, Pioneer Natural Resources and Enterprise Products Partners, to export condensate abroad.

Pioneer Natural Resources now sells condensate from its Eagle Ford shale site to Enterprise, which markets the oil to foreign buyers. The first cargo was exported in July 2014. The company said it has received higher prices than it could command for condensate sales domestically and that international interest in its condensate is growing, particularly from Asian petrochemical companies.

Allowing exports of condensate to burgeoning Asian markets has opened up new opportunities for refiners as well as upstream and midstream companies. However, the US government has yet to approve other applications to export condensate.

On December 30 2014 the Federal Government, through the Bureau of Industry and Security (BIS) at the Commerce Department, issued guidelines to the industry regarding the export of processed crude oil and condensate.

The guidelines state that lease condensate, produced from tar sands, gilsonite, and oil shale that has been processed through a crude oil distillation tower is not classified as crude oil but as a petroleum product. This means that it is not subject to the same export restrictions as crude oil is. Those unsure whether their lease condensate has been processed sufficiently to be considered an oil product eligible for export may request a formal Commodity Classification from the BIS.

Jacob Dweck is a partner at Sutherland law firm. He has represented Enterprise in obtaining its successful determination to export processed condensate, and he is counseling many other companies in their government approval process or in engaging in condensate exports on their own.Dweck explains that the technical factors published by the government in the FAQs for determining when processed condensate can be exported are qualita-tive, not quantitative, and that they are not categorical or exhaustive. But he adds that any company able to meet the criteria of the Enterprise classification should be able to export its condensate.Dweck said he does not believe the US crude export ban will be lifted under the current Administration.

The condensate export guidelines (the FAQs) are as far as the Administration is willing to go at this time to ease export restrictions. The Republican Congress also is very unlikely to legislate the ban away Dweck said. Most US refiners believe in free trade and support lifting the ban, and nearly all refiners have no quarrel with condensate exports. However, certain East Coast refiners, representing some 7% of US refining capacity, have banded together to oppose lifting the ban as this will increase their feedstock cost disproportionately. They are particularly concerned about the Jones Act, which requires all shipments of crude from the Gulf to the East Coast to to be on more costly US vessels." He added:If the ban is lifted, the majority of US refiners will do just fine. The US has the world best and most advanced refining fleet. Removing the ban would be economically beneficial all around, rationalizing the allocation of oil and gas

resources in a market-oriented manner and with the greatest benefit to the US as well as our trade relationship with our countries around the world.

Conclusion

There is still plenty of scope for investing in the US refining sector, which will benefit from abundant supplies of crude from the US and Canada even if the export ban is lifted.

Experts say the current low crude oil prices will have a slight impact on US production in the short term but the abundance of light sweet crude available, high storage levels and the fact the many US refineries process heavier crudes means there will be no shortage of available feedstock supply for the industry.

The industry doesnt expect the crude export ban to be lifted under this adminis-tration but momentum is building from both the upstream industry and the political sphere so the longer-term outlook is less certain. Allowing condensate exports has opened the floodgates to new debate on the issue, which proponents say would have enormous benefits for the US economy as a whole, as well as US consumers, while the refining sector will still have access to reasonably prices feedstock.

Opportunities in US Refining

North American Refining Conference

June 9-10 // DoubleTree by Hilton Hotel Houston - Greenway Plaza Book Early for Big Discounts

www.refiningupdate.com

Introduction

The US shale boom has provided a boost for the countrys refiners, which have benefitted from soaring domestic crude production, a ban on exporting oil and insufficient infrastructure to transport the countrys crude to new markets. These factors have all contributed to creating an oversupply of oil, which has depressed prices of domestic crude and kept feedstock costs for refiners low.

Prices for West Texas Intermediate (WTI) crude have tumbled by around 60% since July 2014, which has given US refiners a competitive advantage over foreign competitors, allowing them to boost refinery utilization rates to record highs and invest in capacity expansion.

But US crude prices have now fallen so low that the staggering growth rates the country has experienced in upstream production over the past few years is beginning to slow, which would threaten availability of cheap feedstock for refiners.

The US governments decision last year to allow two companies to export conden-sate has also reopened the debate surrounding whether the 40-year old ban on crude exports should be lifted.

The upstream sector is lobbying hard to make this happen in the hope that their crude then would be able to reach export markets in Europe and Asia where they could achieve higher prices.

However, if the ban is lifted, the refining sector could lose its access to cheap crude feedstock, pushing its costs up and rendering recent investments in capacity expansion economically unviable.

This paper will outline the supply and policy concerns facing potential new investors in the US refining sector and explain the advantages and challenges that remain to ensure the continued profitability of the industry.

US Shale Supply

The use of hydraulic fracturing over the past decade has unlocked a wealth of US shale oil and gas resources - previously considered uneconomic to produce and has helped the US to transform itself into an energy producing powerhouse.

US crude output reached 9.19 million barrels per day (b/d) on 9 January 2015, a 1 million b/d rise from year-earlier figures and up from production lows of 3.8 million b/d in September 2008. The US Energy Information Administration (EIA) expects oil production to increase from an average of 8.7 million b/d in 2014 to 9.3 million b/d this year, then reaching 9.5 million b/d in 2016.

Table: EIA figures on US crude production Jan 1983-2015:

US Crude Oil and Liquids Fuels Production

This increase in domestic production has contributed to a significant decline in the US crude oil imports over the past decade. The share of total US liquid fuels consumption met by net imports fell from 60% in 2005 to just 27% in 2014. The EIA expects this to fall further, to 20% in 2016, which would be the lowest level since 1968.

Prices and Production

However, in the medium-term the EIA expects US crude production growth to slow mainly because of the recent crash in domestic crude prices.

The US benchmark crude has lost almost 60% of its value in the past seven months due to these rapid rises in US oil production, a lack of transportation infrastructure to take crude to markets and a 40-year-old government ban on exporting US crude.

The EIA estimates WTI crude oil prices will average $49/b in the first half of 2015, down from $100/b in July last year. This will lead to a slowdown in drilling activity because of unattractive economic returns in some areas of both emerging and mature oil production regions.

Fast depletion rates for shale wells mean high levels of capital investment are needed to finance new production. With crude prices falling and US interest rates rising, it will be increasingly tougher to finance this expansion.

Some companies have begun redirecting investment away from marginal explora-tion and research drilling to focus instead on proven, core areas in already-pro-ducing, major tight oil plays.

However, WTI prices are expected to remain high enough to support some development drilling activity in 2015 in the Bakken, Eagle Ford, Niobrara, and Permian Basin, albeit at lower levels than previously forecast.

Companies which have lower drilling and debt costs and have acreage in the sweet spots of these regions will continue to drill highly productive wells in 2015, the EIA said.

Bill Fairhurst, Vice President Exploration at Eagle Oil & Gas, said drilling has already begun to slow down because of the oil price drop.

Weve already seen a 200-250 rig count drop which is a more direct indicator of what will happen with production in the least economic plays in the US, Fairhurst said. Drilling will continue because some operators are in a better financial place than others and have more economically viable acreage.

Eagle Oil and Gas has operations in some of the US most prolific shale plays such as the Eagle Ford, Haynesville and the Marcellus.

He added that high decline rates in shale wells meant that any slowdown in drilling new wells will result in quickly slowing overall production growth. Fairhurst said that there has already been a slowing in the rate of production increases in the Permian, Eagle Ford and Bakken plays.

The negative side is the way these wells perform. They have extremely high decline rates over the first two years. You have to keep drilling wells to replace the rapidly declining production. As soon as you stop that treadmill (of drilling) youll start to see production cut quickly.

Fairhurst said at the end of the first quarter of 2015 that we would start to see the effects of crude price falls on production.

He added that the rates at which shale operators can drill economically varies.

People who are not the best performers could produce in the best areas at $50-60/b but would differ depending on many variables. But at $50/b more than half of wells drilled are not economic.

Charles Ebinger, a senior fellow in the Energy Security and Climate Initiative at the Brookings Institution, said he believes WTI prices would have to fall to around $30/b and stay there for 6-12 months before we start to see significant produc-tion cuts.

Ebinger said he believes WTI prices will fall to around $30/b in the next few months before rising to around $60/b next year.

Its going to hurt [the upstream industry] a lot before it gets better, Ebinger said. But Id be very surprised if a year from now were not seeing prices around $60/b.

Ebinger said breakeven prices for drilling shale wells vary from well to well and from play to play. Some existing Bakken wells, which are already producing, could continue to do so if WTI prices fall as low as $28/b. However less productive wells could be rendered unviable if WTI falls below $42/b.

The EIA expects US crude production to reach 9.4 million b/d in the second quarter of 2015 and then decline by 190,000 b/d in the third quarter because of the drop in crude prices.

If WTI prices start to rise in the second half of 2015, drilling activity could increase again as companies take advantage of lower costs for both leasing acreage and drilling services, causing production to rise at a relatively low WTI price.

However the EIA adds that whether this forecast proves to be true will depend on actual prices available at the wellhead and drilling economics that vary across regions and operators.

The Impact of the Export Ban

The US government introduced a ban on exporting crude oil in 1975 to protect US consumers from volatility and price spikes.

But four decades later US crude output is expected to surpass Russias and Saudi Arabias. The debate over whether the export should be lifted has come to the forefront of the countrys political agenda.

Industry experts generally agree there is increasing momentum behind the individuals opposing the ban and the economic benefits to the US economy would be huge. However, most agree it is unlikely to happen under the current administration.

Eventually the ban will be lifted whether its done this year, under this administra-tion, or not. Thats because its outdated and doesnt reflect the energy reality we have today, said Robert Dillon, spokesperson for Republican Senator Lisa Murkowski a proponent of lifting the export ban.

He added: For the upstream (lifting the ban) would be good as the market is saturated. Refiners might not have such a big discount (if the ban in lifted) but they will still have access to lots of US crude. The more supply there is on the

global market the better for everybody.

There are estimates that suggest that lifting the 1970s-era restrictions on US crude oil exports could cause production to increase to 11.2 million b/d and add industry-wide investment of nearly $750 billion. It would also support almost a million jobs.

The upstream industry is lobbying hard to get the crude export ban lifted.

What we [upstream producers] are asking for is the ability to compete at world market prices. I think it will happen this year which will help US crude reach world markets, Fairhurst said.

However for the refining sector, allowing the US to export crude could push their feedstock costs up, rendering planned or recently completed refinery capacity additions or upgrades uneconomic.

Another issue is the Jones Act which states that all US crude or oil products shipped between US ports has to be done on a ship which has been built, owned and crewed by US citizens.

Due to a shortage of these ships, transport costs between US ports are high. So if the US crude export ban was lifted, it would become cheaper to ship US crude and products to Europe on a foreign ship than it would be to transport the products to the US East Coast. This could potentially render it uneconomic to ship US west coast crude and oil products to east coast refineries, forcing the sector offline.

Fairhurst said the majority of US refiners wont suffer financially if the ban is lifted because many domestic refineries are configured to process heavier crudes rather than the light, sweet crude produced from US shale plays. There is no shortage of these heavier crudes which many refineries process, coming from Canada and Venezuela.

For the refineries set up to process light, sweet crude they already have more than they can process, Fairhurst said.

Compared to the huge advantage the American consumer and the exploration and production industry will have in lifting the ban, the inconvenience to the refining industry will be minor.

However Ebinger is less optimistic about the impact that lifting the export ban would have on refiners.

Most refinery margins now are the best they have been in years. Overall lifting the ban will probably hurt them more than help them because most will lose access to highly discounted crude oil to sell, Ebinger said. .

Refining Industry Overview

The rise in US crude production over the past decade has given refiners access to cheap feedstock and enabled them to invest in capacity increases to boost output.

As of January 1, 2014 there are 133 operating refineries in the US with atmospher-ic crude oil distillation units (ACDU) totaling capacity of 18.9 million b/d.

Production Capacity of Operable Petroleum Refineries: Source: IEA

More than 50% of the country's refinery capacity and most of the country's heavy crude processing capacity is located in the Gulf Coast. The region's 51 operating refineries with ACDUs have capacity totaling 9.7 million b/d.

In 2013 Gulf Coast gross inputs to refineries in the region averaged around 8.2 million b/d, according to EIA figures. Thats up from around 7.2 million b/d in 2003 and soaring above the average 5.5 million b/d processed in the region in 1985.

Genealogy of Major U.S. Refiners Source: EIA

Most crude supply to East Coast refineries has traditionally been imported light sweet crude. The region lacks crude oil pipeline connections from domestic production regions and has very limited production within the area.

However since 2010 increasing light tight crude oil production in the Bakken formation in North Dakota, combined with the expansion of crude-by-rail infrastructure, has reduced the regions import dependence.

The availability of cheap crude for feedstock has boosted US refinery utilization capacity rates as they are able to maximize output.

Refinery utilization rates averaged around 90% last year, according to EIA figures, up from an average of around 86% in 2010.

Percentage of US Refinery Utilization

The Midwest is the second-largest refining region in the country with 27 operable facilities. The 26 refineries currently operating have 4.1 million b/d of ACDU capacity, 70% of which has facilities with coking capacity. The coking unit is needed to process heavy crude oil into higher-valued lighter products, such as distillates and gasoline.

Since 2010, several Midwest refiners have upgraded their facilities to process more heavy crude, adding a total of 157,000 b/d of coking capacity. Over the same time, ACDU capacity has increased by 148,000 b/d and gross inputs have risen by 205,000 b/d.

Valero

Valero is the world's largest independent refiner, with 15 facilities stretching between California, Canada and the UK. This cross-continental network of refineries gives Valero a combined throughput capacity of around 2.9 million b/d.

Valero says the key to its success has been its ability to upgrade and expand refining operations to produce high-value, clean fuels from a wide variety of crude feedstocks, two-thirds of which come from discounted feedstocks.

As an independent refiner rather than an upstream producer Valero adjusts its feedstock mix based on market conditions. It buys crude oil from producing leases, domestic oil trading centers and ships cargoes of foreign and domestic oil.

Heavy sour and residual oil, medium sour oil, and light sweet and other oil grades each represent about one-third of the companys feedstocks.

Valero has invested heavily in expanding and upgrading its refinery capacity to be able to process the large amounts of US light, tight crude being produced.

In 2013 Valero completed work on a new hydrocracker unit at its St. Charles refinery in Louisiana with a throughput rate of 60,000 b/d. Valero started up a similar hydrocracker at its Port Arthur refinery in December 2012.

The hydrocrackers were designed to take advantage of high crude oil and low natural gas prices at the time and to enable the company to process heavy-sulfur crude.

They were designed mainly to produce diesel to meet growing demand in both domestic and export markets. Each of the units cost about $1.6 billion to build, Valero said.

The company is also pursuing projects to expand throughput capacity to 75,000 b/d at each of the new hydrocrackers. With successful permitting, the expansion projects are expected to be complete this year.

The first round of expansion was about meeting demand for products around the world. The second round was about handling supply of light, sweet crude in the US, said Bill Day, Vice President Community and Media Relations at Valero.

Companies like Valero are experimenting. We want more cheap crude so we support (the) Keystone XL (pipeline). Were well positioned to take advantage of abundant crude supplies in the US and natural gas too, Day said.

We havent seen any decline in upstream production so far. Were buying lots of discounted crude, which gives us an advantage. Our heavy presence on the Gulf Coast is well positioned for product export markets. The cost [of new refinery capacity and upgrades] is the biggest challenge.

Day declined to comment on whether Valero was concerned about the possibility of the US crude export ban being lifted, potentially increasing the companys feedstock costs.

We support the current system going forward, he said.

Day added that overcoming environmental regulations and a dearth of skilled labour were also challenges the company has to face.

Were often competing with the upstream sector for labour. Weve had to search a bit harder for skilled workers and thats pushed the price up, Day said.

He added that Valero hasnt taken any additional investment decisions to boost refinery capacity or upgrade facilities because of the cost of undergoing such work.

Were cautious spending money. We want to make sure there will be a long-term return for our shareholders.

What they are considering is investing in new petrochemical capacity, he said.

ExxonMobils share of the market

ExxonMobil is the largest refiner in the world and processes more than 1.9 million barrels of crude oil per day through its 7 facilities in the US.

Last year the company announced it was investing $1 billion in upgrading its refinery in Antwerp, Belgium. ExxonMobil is building a new delayed coker unit at the facility to convert heavy, higher sulfur residual oil into products such as diesel. This is despite conditions for Europe-based refiners being far more challenging than in the US due to stagnant demand growth, years of high Brent crude prices and competition from capacity additions in other regions.

The refining industry makes long-term investment decisions looking forward over 30 years. ExxonMobil makes long-term investment decisions with a view that they must be able to perform across a range of pricing that accommodates the types of price swings we have seen in recent months, ExxonMobil said.

It added: Our recent investments in Europe at Antwerp and Slagen provide excellent examples of ExxonMobils long-term view.

Condensate Investments

While exports of US crude and other products remain banned, there has been a loosening of laws around exports of condensate an ultra-light oil that can be exported after mild distillation.

Condensate is produced from shale plays alongside crude when underground it is gassier in structure but it then condenses into a liquid when pumped to the surface.

US Crude And Condensate Production 1960-2014

Similarly to crude, exports of condensate have long been banned. However, in 2014 the US Commerce Department granted permission to two Texas-based companies, Pioneer Natural Resources and Enterprise Products Partners, to export condensate abroad.

Pioneer Natural Resources now sells condensate from its Eagle Ford shale site to Enterprise, which markets the oil to foreign buyers. The first cargo was exported in July 2014. The company said it has received higher prices than it could command for condensate sales domestically and that international interest in its condensate is growing, particularly from Asian petrochemical companies.

Allowing exports of condensate to burgeoning Asian markets has opened up new opportunities for refiners as well as upstream and midstream companies. However, the US government has yet to approve other applications to export condensate.

On December 30 2014 the Federal Government, through the Bureau of Industry and Security (BIS) at the Commerce Department, issued guidelines to the industry regarding the export of processed crude oil and condensate.

The guidelines state that lease condensate, produced from tar sands, gilsonite, and oil shale that has been processed through a crude oil distillation tower is not classified as crude oil but as a petroleum product. This means that it is not subject to the same export restrictions as crude oil is. Those unsure whether their lease condensate has been processed sufficiently to be considered an oil product eligible for export may request a formal Commodity Classification from the BIS.

Jacob Dweck is a partner at Sutherland law firm. He has represented Enterprise in obtaining i