Insight Gea2013 Lowres

December 2013www.platts.com

GLOBAL ENERGY OUTLOOK 2014

YEAR OF THE RFSPost-RINsanity, where next?

THE REAL REVOLUTIONIts not all about shale

OPEC ANGSTSeismic shifts for the key producer group

THE PRICE DEBATEAfter the 2008 spike, questions linger

PLUS: EUROPES REFINING MOMENTBRAZILS SUBSALT PINCHSHIFTING SHALE IN THE US BIOFUELS BACKLASH, AND MORE

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DECEMBER 2013 insight iii

CONTENTSinsight

1

4 YEAR OF THE RFS (AND THE LCFS)A rollercoaster year for the RINs market leaves questions about whether the assumptions US renewable fuels legislation is based on have changed so much that it needs an overhaul. Meanwhile, Californias experiment in fuel regulation is dividing opinion too.

10 THE REAL REVOLUTIONThe massive expansion of shale oil and gas liquids in the US has doused peak oil fever and apparently given a new lease of life to the hydrocarbon economy. But it hasnt brought the price of oil down. Nor has the regulatory onslaught against high emission hydrocarbons diminished. Substitution not shale is the real revolution.

16 THE PRICE DEBATEConcerns over transparency in oil markets have been stoked by high prices, even though oil is the most tracked commodity in the world. Efforts to manage markets can only interfere with the necessary signals that prices transmit to both producers and consumers.

22 EUROPES REFINING MOMENTAfter enjoying strong margins in the early part of the century, Europes refining sector has wilted in the face of alternate fuels, collapsing demand, engine efficiencies, overseas competition, health and safety costs and, more recently, emissions legislation. Will a review by Brussels offer any respite?

28 SUBSALT PINCHBrazil faces tough questions over the pace of its subsalt oil boom: has it got the regulatory regime right; is state oil company Petrobras up to the massive task at hand; what wider impact might OGXs spectacular fall from grace have?

33 ABBOTTS CARBON GAMBITInternationally there is a clear momentum behind emissions trading systems but Australia is going against the grain following the election of Prime Minister Tony Abbott. If his new government successfully repeals the Carbon Pricing Mechanism, the country will become a test bed for alternatives to cap-and-trade systems in other regions.

38 OPEC ANGSTWhen Insight last looked at OPEC in late 2010, there wasnt even a hint of the wave of protests that would shortly begin its sweep across the Arab world, unseating regimes that had been in power for decades. Nor was the extent to which shale would revolutionize oil production in the United States remotely apparent.

44 SHIFTING SHALEThe vast amount of oil and gas suddenly generated by the North American shale revolution has driven a rapid change in the market, not least in the way crude is transported around the continent.

49 MARGINAL SUCCESSCapacity markets in the US, designed to spur investment in the peakload capacity needed to keep the lights on, have so far achieved their aim but that doesnt mean there arent plenty of people keen to change them.

54 ... TILL THE WELL RUNS DRYRising energy demand is bringing with it an increase in water usage at the same time as resources are dwindling in some areas is water scarcity a threat to the energy sector?

58 BIOFUELS BACKLASHIn the face of dwindling support from many former advocates, the global biofuels sector has been shifting focus to second generation biofuels that do not compete with food for their feedstocks. But the outlook for first generation biofuels is not as bleak as it might appear.

64 GRAYING AT THE EDGESThe upstream oil and gas industrys technical innovations and pioneering spirit have been pushing back the boundaries that once seemed to place an upper limit on production, but it faces a potential constraint of a very different kind a shortage of the necessary skills to keep the boom going.

84 PLATTS GLOBAL ENERGY AWARDSShale Takes Top Prize: a special section on this years winners of Platts Global Energy Awards.

insight

insight DECEMBER 2013

December 2013

2

EDITORS NOTEIts something of a tradition, by which I probably mean clich,

to start these editors notes with a quote about change, then muse about how fast things are changing all around us. So this year, I said to myself, lets not have a quote, and lets not talk about change.

But some things never change, so heres a quote. Death and taxes are the only certain things, Benjamin Franklin said.

To that can be added, in the modern world, regulations. Th e word crops up often in this issue, typically not too far away from phrases like struggling under, burden of, and crippling. Everyone is wont to complain about regulations placed upon them by government.

Its generally accepted these days that markets provide effi cient solutions as far as they go, but they dont deliver on costs that are external to market factors, for example climate change objectives, security of supply or even local air pollution without regulation.

Th e challenge is to fi nd a regulatory path that achieves these objectives without too many bad and unexpected economic impacts. Its a diffi cult balance to strike and sometimes it can go wrong, as has been noted by many people, not least Karl Marx, who wrote that crack-brained meddling by the authorities in its regulation may aggravate an existing crisis.

So what of the other certainty, death? Th e energy industry lost a true hero this year, and it would feel wrong not to acknowledge him in this forum. Th at man is, of course, George Mitchell, the pioneer of shale drilling, who passed away at the age of 93. Th e revolution he started is still ripping up the old rulebook. In fact, it may not be going too far to say that his pioneering work is partly responsible for what could be era-defi ning shifts in the geostrategic map of the world unfolding at the moment.

Im referring to Americas shift of direction in the Middle East, the logic of which is underpinned by its rapid swing towards energy self-suffi ciency. Its too early to say exactly where this will all lead, but the cards the US is holding in its hand now look very diff erent to just a couple of years ago.

Finally, it seems fi tting to give the last word to Mr. Mitchell, who had an interesting, perhaps somewhat surprising attitude towards regulation of the shale drilling industry in the US. Th e administration is trying to tighten up controls. I think its a good idea. Th ey should have very strict controls. Why? Because if they dont do it right there could be trouble. Government also has to get it right though, or there will be trouble ahead.

Alisdair Bowles, Editor

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US FUELS

When government regulations take hold, measuring their success can take time. But two key environmental measures that are being introduced on a sloping scale are providing indications on their impact, in one case on a daily basis.

Th e one with daily feedback is the Renewable Fuel Standard, and as we look back on the US fuels market in 2013, we might want to declare it the year of the RFS. A conversation about the state of gasoline or diesel trade couldnt go on for even 30 seconds without the terms RFS, blendwall or RINs popping up. For awhile back in the spring and summer of 2013, the price of those RINs was an indicator that was signaling a major fail in the RFS.

Th e second is the California Low Carbon Fuel Standard, limited for now to that one state, and still fl ying mostly under the radar.

Both initiatives rely on a market for credits to smooth out the rough spots. In the case of the RFS, the credits are the previously mentioned Renewable Identifi cation Numbers, RINs, the

possession of which can be used by an obligated party to meet the mandates of the RFS. Similarly, LCFS credits can be used by a refi ner or importer to buy down the carbon intensity of the fuels they are putting into the states market.

Th e RINs market has generally been more active and transparent than the LCFS credit market, though the latter is showing signs of increased activity. For example, data released by the California Air Resources board which administers the LCFS showed 41 transactions of LCFS credits in the second quarter of this year. For the third quarter, the total was 66. And those numbers are well above prior years.

But it was the RINs market that soared and plunged in 2013, raising signifi cant questions about whether the assumptions behind the RFS legislation passed in 2005 and then expanded in 2007 by the US Congress and then-President George W. Bush have been so fundamentally altered that the basic legislation, or at least the implementation of it, needs to be overhauled.

YEAR OF THE RFS(AND THE LCFS)

A rollercoaster year for the RINs market leaves questions about

whether the assumptions US renewable fuels legislation is based

on have changed so much that it needs an overhaul. Meanwhile,

Californias experiment in fuel regulation is dividing opinion too.

JOHN KINGSTONGlobal Director of News

5DECEMBER 2013 insight

US FUELS

When that RFS was passed, the assumption was that US gasoline consumption would rise if not ad infi nitum maybe thered be some breakthrough in hydrogen or battery storage that would slow its growth then every year for a long time. So if the government mandated a certain number of gallons as part of the ever-rising total, the mandate would slide easily into that growth.

But that didnt happen: EIA data showed US fi nished gasoline consumption peaking in July 2007 at 9.64 million b/d, dropping to 8.8 million b/d in the corresponding month of 2012, and rising only slightly to 9 million b/d in July 2013. (Th e recent low point was 8.19 million b/d in January 2012, down almost 700,000 b/d from the January 2007 fi gure.)

As this decline was occurring, a few voices started predicting an ethanol train wreck. Th e drop in outright consumption, they predicted, would collide with two things: the annual mandated rise in renewable fuel usage, particularly ethanol, and the fact that there was a widely-held consensus that ethanol blends above 10% in most cars would create engine problems. (In fact, everybody agreed with that, except one key interest group. More on that later.) And, it was noted, when that collision started to bite, youd see it in the price of RINs, which for most of their history lingered near 1-2 cents per RIN, possibly the dullest, most predictable market in the world of petroleum.

It didnt stay that way. As the refi ning industry began 2013 and started looking out to the future, it saw that the amount of ethanol being used in US gasoline consumption was getting close to the 10% level, begging the question: how

were they going to meet a rising outright numerical mandate in a market of declining volume while looking at a hard stop percentage?

RINs is the answer to that question, and as the accompanying chart shows, ethanol RINs known as D6 RINs soared from a few cents at the start of the year to

Courtesy: Getty Images

An immature market.


US FUELS

hit $1.02 per ethanol RIN in early March. Th en the market calmed to about 70 cents, roared back to peak at about $1.44 in early July, sunk back to another stabilization near 70 cents and then began a long slide which will probably mean that while 2013 was the year of RFS and RINs, 2014 defi nitely will not be.

Two things happened. First, in early August, the Environmental Protection Agency, long

after it would normally be expected to do so, fi nalized the 2013 mandates at a previously announced preliminary level. It also said it expected ethanol consumption to be about 9.75% of gasoline consumption, getting close to that 10% blendwall.

Th e EPA then said that blendwall would probably be breached in 2014, given the combination of mandates and consumption, and that it would use fl exibilities in the RFS statute to reduce both the advanced biofuel and total

renewable volumes in setting the 14 mandates.

Soon after that, a leaked document said the EPA would set a mandate of 15.21 billion gallons of biofuels to be blended in the US in 2014, down from 16.55 billion gallons in the 2013 mandate. Th ere would be changes in non-ethanol biofuels as well, but most of the pressure would be eased on ethanol.

Two-bit RINsTh e leaked document was a big push in sending RINs prices by late October down to a level that Americans used to describe as two bits: 25 cents. Th at would mark a decline of more than 80% from its July high, the sort of decline that doesnt seem all that odd when you consider the various elements in this market: a government mandate that hasnt evolved with the market; an inability to easily generate new supply (you cant just make ethanol to create a RIN it has to be consumed to generate one); an immature market. Th ats a formula for huge volatility.

Finally, the 2013 RINS bubble, if it was that, came to a crashing end. In mid-November, the EPA fi nalized its 15.21 billion gallons rule, and what was interesting is that the RINs market dropped further; the prospect of easier rules was not baked into the price already.

Th e fi rst trading on RINs after the announcement took levels down near 16 cents; they rebounded to about 20 cents and for the 2013 ethanol RINs, stood at about 22 cents on November 22.

In the background of all of this was a debate, led by the Renewable Fuels Association, the ethanol producers trade Source: Platts

2013 RINS PRICES

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A government mandate that hasnt evolved with the market; an inability to easily generate new supply; an immature market. Th ats a formula for huge volatility.


US FUELS

group. It rejected the basic idea that theres a blendwall, noting that the EPA had approved E15 use in cars of model year 2001 and beyond. It also noted that fl ex-fuel vehicles had the capability of using E85, which is 85% ethanol.

Th e group also noted these things with a full heap of conspiracy theories, charging that the only reason that the limited use of these fuels which would help make the blendwall obsolete was that evil/greedy oil companies didnt like ethanol and were working against its consumption by not putting enough E85 and E15 pumps in stores they didnt own anyway. In essence, they were being told to meet their responsibilities to help the mandate be reached through these 10-plus ethanol blends, ignoring the fact that such cooperation was never seen as a required part of the original plan for growing ethanol consumption; a rising level of total fuel use would take care of that.

California teethinTh e conspiracy theories have yet to hit the California LCFS, probably because its too early in the game. Th e goal there is a 10% reduction in the carbon intensity (CI) of the states fuel mix by 2020, with incremental increases in the standard each year as 2020 approaches.

Th e LCFS is diff erent from previous fuels regulations in two key ways. First of all, it is not requiring any bad things to be taken out of the fuel, like lead or sulfur. Th ose can be removed; carbon cant be.

Second, the LCFS does not have tight mandates, e.g., you must use X amount of a certain type of fuel. In fact, the standard of reducing carbon intensity by 10% applies to the entire state and is not on a

refi nery-by-refi nery basis. Th at raises the free-rider possibility that some importer or refi ner might just choose to skate by, and allow its brethren to cut their carbon emissions. But when asked about this anomaly, CARB offi cials repeatedly have said that they have specifi c information on those parties, and can fi nd ways to try to modify those carbon hogs behavior.

In the same way that the RINs price is a barometer of the industrys present ability to meet standards, there are some LCFS numbers that send signals also, though not as frequently as the daily occurrence of RINs assessments. Several months after each quarter, CARB releases a document that has several key numbers. One is the number of LCFS credits generated during the quarter, as well as the defi cits.

Th at number, through the second quarter of this year (the most recent data available at this publications deadline), had been running solidly in favor of credit generation. Th ats what is supposed to happen; one report, by ICF International, said credit generation would exceed defi cit generation into 2016-2017, and then the surplus could be drawn down to help make the target.

So at the end of the second quarter, CARB reported that there was a

LCFS CREDITS

Credits generated De cits generated

Q2 2013 802 617Q1 2013 560 550Q4 2012 430 250Q3 2012 390 250Q2 2012 310 240Q1 2012 340 230

Source: Platts


US FUELS

net surplus of 1.64 million metric tons of credits. In the fi rst quarter, credit/defi cit generation was virtually fl at; thats a lot sooner than the 2016-2017 timeline laid out by ICF. CARB offi cials queried about it said dont worry. Th e rules were tighter at the start of 2013, and it took some time to adjust.

And in the second quarter, the data made them look prescient. Th ere was signifi cant credit generation in excess of defi cit creation, which basically meant that the crude inputs into refi neries, combined with the use of various low-carbon fuels like less carbon-intensive ethanol was feeding a larger portion of California petroleum demand than that from higher carbon intensity sources.

It can show up in diff erent ways. Some of it was obvious: a company called Clean Energy announced a plan that would put low-carbon natural gas from landfi lls into vehicles, an action it conceded was driven in part by a substantial number of LCFS credits generated by that activity.

Others are less obvious. For example, when a major refi ner in the state was said to be backing out Alaskan North Slope crude in favor of Brazilian crude which carries a lower CI rating than the Alaskan oil was that LCFS-driven? Brazilian oil is not a rare commodity in California, according to

EIA data, but the clear substitution of one for another could be one of the small steps that the state hopes it will incentivize not just through its regulatory power, but by LCFS credit prices that companies want to be able to get their hands on.

Th is may all sound benign, but it isnt to the states oil industry. Catherine Reheis-Boyd, president of the Western States Petroleum Association, which represents both upstream and downstream players in California, wrote a blog piece in which she likened the LCFS to the fi nal scene of Th elma and Louise, with the Geena Davis and Susan Sarandon characters driving their car off a cliff .

But the plans of the states two biggest refi ners show a sharp diff erence in the outlook for the future. Valero, in October 2012, was reported to be shopping its refi neries in California: Benecia, near San Francisco, and Wilmington, near Los Angeles. Th e states regulatory structure presumably including the LCFS, but not exclusively was said to be a key reason for looking to exit the state, though Valero has not confi rmed any sale attempts. (But its CEO, William Klesse, has described California as a tough place to do business.)

Meanwhile, Tesoro in June closed on the purchase of BPs Carson refi nery, also near Los Angeles, with the refi nery (net of working capital and inventory) valued at a little more than $1 billion. If the people at Tesoro, which has been operating in California a long time, agree with the characterization of the LCFS as driving off a cliff , buying a refi nery for a billion dollars is a strange way of showing it.

In the same way that the RINs price is a barometer of the industrys present ability to meet standards, there are some LCFS numbers that send signals also.

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HYDROCARBON ECONOMY

Tesla, the US electric car maker, announced over the summer that it had achieved record sales of 5,150 Model S vehicles in North America in the second quarter and that it was on track to achieve a gross margin of 25% in the fourth, excluding zero emission vehicle credits. Th e company reported almost $750 million in cash and, notably, no government debt. It also opened this summer its new European assembly plant at Tilberg in the Netherlands, having rolled out a substantial supercharging network in Norway.

Teslas share price has rocketed as a result, hitting a peak of $193 in late September, nearly fi ve times its level in April, when it announced impressive fi rst-quarter results. Despite its small production run, the company momentarily achieved an eye watering $20 billion market capitalization. To put that in context, GM Motors, whose dealers delivered more than 275,000 units in August alone in the US, had an early September market cap of about $50 billion.

Forecasts for the penetration of plug-in electric vehicles have so far proven over-optimistic, and Tesla released disappointing earnings results for the third quarter. Its market cap had dropped to just below $15 billion in mid-November, hit also by the potential ramifi cations of a National Highway Traffi c Administration investigation into the safety of its cars. Nevertheless, the companys latest earnings report did show revenues up eight-fold, even if costs proved higher than expected.

Teslas performance suggests that in fi ts and starts the electric car sector may be moving beyond the initial phase of the hype cycle that dogs new technologies, in

THE REAL REVOLUTION

The massive expansion of shale oil and gas liquids in the US has

doused peak oil fever and apparently given a new lease of life to the

hydrocarbon economy. But it hasnt brought the price of oil down.

Nor has the regulatory onslaught against high emission hydrocarbons diminished. Substitution not shale is

the real revolution.

ROSS MCCRACKENEditor,Platts Energy Economist

Courtesy: Getty Images


HYDROCARBON ECONOMY

which expectations run far ahead of the capacity to meet them. Instead, the sector is slowly gaining a base in manufacturing, servicing and recharging infrastructure, which is suffi cient to attract new capital, allowing movement down the cost curve. Th e scene is being set for future, possibly exponential, growth.

Shale shadowSuch enthusiasm for the maker of expensive luxury electric cars may seem strange in a country where cleantech investment has been overshadowed to some extent by the lack of federal climate change legislation and a revolution in domestic oil and gas output. More widely, huge reserves growth in unconventional resources would appear to have put paid to concerns over peak oil and US import dependencies.

Th e USs hydrocarbon economy now appears sustainable at least beyond the time horizons of the current generation. Importantly, exposure to global oil and gas supply chains is supposedly no longer part of the price of Americas petroleum addiction.

However, the unconventional oil and gas boom has not diminished the threat of climate change, nor the regulatory impetus for demand reduction and emissions control measures. If anything, by dispelling the idea that the hydrocarbon economy is heading imminently towards the edge of a supply precipice, it has raised environmental concerns that hydrocarbons will in fact be much harder to shake off , or worse may gain a new lease on life. From a climate change perspective, greater availability of unconventional oil and gas is a reason for greater activism.

Th ere has indeed been a sea-change. World proved oil reserves have seen large

jumps in size in recent years rather than incremental growth, driven not by statistically suspect leaps in Middle Eastern reserves, but by the inclusion of unconventional resources elsewhere that now appear economically recoverable.

In the US, this has delivered a welcome discount to domestically-produced crude as seen by the enduring diff erential between US marker West Texas Intermediate and international benchmark Dated Brent. Th is has proved a huge bonus to those US refi ners positioned to take advantage and helped rejuvenate the US petrochemicals industry.

However, critically, the North American shale boom has not delivered for the end-consumers of oil. International oil prices remain historically high, supported, as ever, by instability in the Middle East. Th e price of gasoline in the US has continued to climb, reaching for all grades in the densely populated East Coast an average of $3.695/gallon in 2012, its highest ever level on an annual basis.

Relative valuesTh e cross-commodity impact of unconventional oil and gas has been much greater than its impact on the oil market alone, and it is this impact that may have the most far-reaching consequences. Th e real sea-change has not been the end of peak oil, nor the change in US security interests

Th e real sea-change has not been the end of peak oil, nor the change in US security interests abroad, but in the relative value of the diff erent hydrocarbons.


HYDROCARBON ECONOMY

abroad, but in the relative value of the diff erent hydrocarbons.

In the US market, the unconventional oil and gas boom has delivered both low coal and gas prices. Th e ratio of gas ($/MMBtu) to oil prices ($/b) was 9.47 in 2006 and rose steadily to a huge 33.26 in 2012. Th e small recovery in US gas prices in 2013 and a halt in oils rise had reduced this ratio to about 27 as of mid-October, but oils comparative price in relation to gas is still much higher now than in the past, in the US market at least.

Prices in the coal market have also moderated, while oil has remained high. In the US, low gas prices depressed the demand for coal from the power sector leading to the lowest level of coal consumption in 17 years in 2012. With demand growth for electricity low, new capacity being added in the renewables sector and a drop in feedstock prices for thermal power generation, electricity prices have been depressed. In fuel cost terms, both electric cars and Natural Gas Vehicles look like a good deal compared with gasoline or diesel.

Price outlookTh is change in relative values is likely to be sustained. Th e global coal market, like oil, has seen a huge rise in investment over the past decade, taking its part in the commodity super cycle, but it now appears to have over-reached itself, with supply catching up with demand.

It does not suff er the same political risk profi le as oil in terms of the stability of its major producers, nor the presence of a cartel powerful enough to infl uence global prices, nor, indeed, is it as large in terms of the amount of internationally-traded coal volumes compared with the amount of coal that is produced and consumed domestically.

Th ere are concerns about future coal quality and a rise in extraction costs, but these are more localized than global. Coals challenge is its emissions, both in terms of local and global pollution, not its market structure or supply. As a result, coal burn is likely to continue to provide relatively low-cost electricity to those countries that use it.

But it is clear that being cheap and reliable is no longer enough. China is the worlds largest producer and consumer of coal, but even there the regulatory tide has turned against coal. Dangerous levels of air pollution have led to a change in energy strategy as outlined in the Chinese State Councils Airborne Pollution Prevention and Control Action Plan 2013-2017, published in September. New coal plant construction has been banned in three key urban regions and the government now wants to reduce the proportion of coal in its energy mix to less than 65% by 2017.

In the United States, the worlds second largest market for coal, new proposed

*Year-to-date

Source: Platts

US NATURAL GAS TO OIL RATIO ($/b DIVIDED BY $MMBtu)

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US EAST COAST RETAIL GASOLINE PRICES, ALL GRADES, ALL FORMULATIONS (ANNUAL AVERAGES)

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HYDROCARBON ECONOMY

emissions and air quality regulations appear so stringent that they would make the construction of new coal plant uneconomic. In addition, under any economic scenario, the sizeable, aged tail end of the US coal fl eet is unprofi table and slated for retirement. Both in Europe and the US, coal for power generation is caught in a process of long-term structural decline, which is being accelerated by emissions regulation.

Th e situation for gas is diff erent and more complex because the global market for gas represented by spot LNG trade remains small. Gas pricing remains regional rather than global. Th is highlights the fact that the benefi ts of the North American shale boom have largely been contained within the continent. Th e advent of US LNG exports can be expected to have some impact, but most likely a modest one in the short term.

Moreover, the extension of shale gas technology beyond North America has been slow to produce results. Despite early optimism, nowhere appears likely in the short term to replicate the rise in US oil and gas output to such an extent that it might seriously challenge existing import dependencies. But even if unconventional gas does not result in US style changes in domestic production, it will act to moderate growth in imports. At the same time, substantial increases in global LNG production for export should provide security for importing countries looking to raise natural gas share of the domestic energy mix.

Th e oil market, by contrast, looks much more problematic. Th e specter of peak oil may have lost its menace, but that does not reduce the challenges faced by an industry with mature assets that has to

meet continued rises in demand. Even if the extraction costs in some countries, such as Iraq, and for some unconventional liquids are low, compared with current prices, they do not make up a signifi cant enough share of the market to impact the marginal price.

Other key segments of future output growth Canadian oil sands and carbonate plays, Brazilian and West African pre-salt, deep and ultra deepwater, Venezuelan heavy oil, the Arctic and Russian shale oil are all at the high end of the cost spectrum. All are expected to be needed to meet future demand and replace declines from maturing fi elds.

Unlike coal or gas, the unique, international structure of the oil market leaves it vulnerable to supply shocks, the price eff ects of which are felt worldwide. High oil prices mobilize capital in support of new production, but they also sustain the investment conditions for substitution.

Linked processesTh ere are two major processes in train. A shift in the current and future availability of oil and gas, and the substitution of hydrocarbons for low carbon sources of energy. Both are supportive of oil substitution because there is considerable doubt that the increased availability of economically recoverable oil

Source: Nasdaq

TESLA SHARE PRICE, WEEKLY

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Source: BP Statistical Review of World Energy, 2013

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Natural gas Oil

GLOBAL PROVED OIL AND GAS RESERVES


HYDROCARBON ECONOMY

reserves will deliver signifi cantly lower oil prices in the future. As a result, alternative transport modes and fuels are growing, as is distributed and renewable electricity generation, even if the impact in terms of oil demand for the moment remains small.

Brazils use of ethanol in transport is long-standing and although it has not been replicated elsewhere, biofuels now make up about 3-4% of global oil demand. Other countries have adopted Compressed Natural Gas as an alternative fuel source.

Unusually for a developing economy, Pakistans oil consumption was lower in 2012 than in 2009, despite averaging GDP growth of about 3% a year during the period. Part of the reason is the huge growth in CNG use for transport, which saw over 3,000 CNG fi lling stations built between 1993-2013, with most growth coming between 2005-2010.

Th e number of Natural Gas Vehicles jumped from 500,000 to over 2 million between 2004-2008 and is now around 3 million. Although the sector is in the grip of a crisis, driven by gas shortages and the governments prioritization of natural gas for power generation, Pakistans experience

remains an important model for developing economies seeking alternatives to oil.

Encroachment on oils dominance of the transport sector can also been seen in the growing use of LNG in ships. Driven by emissions control regulation, the number of LNG-powered ships is rising as the infrastructure for refueling spreads slowly along the worlds major sea lanes. Classifi cation society DNV estimates that under the right conditions by 2018-2020 some 35% of newbuild ships could be powered by LNG.

Change in transport technologies and major shifts in power generation mixes

are generally measured in decades rather than years. Disruptive technologies tend to follow an S-curve, in which rates of adoption are low in the early years as delivery infrastructure is built out and manufacturing costs reduced, allowing a later, steeper acceleration in uptake. Th e example used by the US Natural Gas Vehicle industry is the displacement of gasoline by diesel from the heavy duty class 8 truck market in the US, a process which took 40 years.

However, the potential for exponential growth of new technologies has been demonstrated in Germany, which now has some 30 GW of solar PV installed. If electric vehicles also expand, it would represent a major shift in the delivery and consumption of energy towards electrifi cation. Looking even further forward, Germany has a number of pilot projects based on power-to-gas, which eff ectively uses existing gas infrastructure as a storage and delivery mechanism for excess electricity output, intelligently combining the trends towards electrifi cation and the increased use of gas.

CNG users in Pakistan, Tesla Model S drivers in the United States, German householders with PV panels and Norwegian ship owners building LNG-powered vessels may seem like a disparate bunch, but they all have one thing in common; they are early adopters. At some point, and again the measurement is likely to be decadal, the oil industry may have to confront the possibility that even if it has the capacity to cope with the supply-side issues that dominate pricing in the international market, it is the slow-burn demand-side revolution that proves their real undoing.

Source: NGV Global

0

4

8

12

16

201120092007200520032001

MILLIONS

NGV VEHICLES WORLDWIDE

High oil prices mobilize capital in support of new production, but they also sustain the investment conditions for low-carbon substitution.


OPINION

Th e 2008 oil price spike, which was accompanied by similarly sharp price rises for coal, iron ore, food and many other commodities, sparked a debate which still resonates fi ve years later. Countless articles, commentaries, analyses, conferences and all sorts of learned discourse have chewed over whether the market was working well and providing the right price signals or just plainly dysfunctional or, worse yet, willfully distorted.

Th at debate can essentially be summed up in three key questions: Was the price rise really real? What, or who, was behind the spike? What can, or should, be done about it?

In some cases, solutions increased regulation and oversight were being devised even though the nature of the problem, such as it may be, was not fully understood.

Th e issuePrices for Dated Brent, the global bellwether for crude oils, reached a peak of over $145/barrel in June 2008, then tumbled all the way down to nearly

$35/b in the same year as markets corrected in the aftermath of the Lehman Brothers collapse in mid-September that year and a confl uence of negative macroeconomic events, to which sky-high commodity prices were a major contributory factor.

Th e surge to an all-time high crude price and the ensuing volatility shocked consumers, producers and governments. But the spike, the correction and the recent tenuous price stability at around the $100/b mark are all signs not of a dysfunctional market, but of market forces at work delivering messages some of which aff ected parties may not want to hear.

Price is a function of supply and demand and provides the signals to invest in production, or not, as the case may be. Above all, price modifi es behavior. However, some of the signals can be very painful to both consumers and producers. It is therefore understandable that people should look for ways to dampen volatility, trying to fi nd a price that is simultaneously comfortable for buyers and sellers. But

THE PRICE DEBATE$

Concerns over transparency in oil markets have been stoked by high prices, even though oil is the most

tracked commodity in the world. Efforts to manage markets can

only interfere with the necessary signals that prices transmit to both

producers and consumers.

JORGE MONTEPEQUEGlobal Director of Markets

THE PRICE DEBATE


OIL PRICES

when measures are put in place that distort the free-market price signal, incongruence occurs and the necessary investment or adaptation by consumers and producers will not occur.

Experiments to manage price are as old as history, with examples of price controls from Roman times. In the current era, there are plenty of cases of countries trying to shield their fi nal consumers from market prices and suff ering runaway budgets and/or retail shortages as a result, like the US in the 1970s when it tried to control the price of gasoline and other products, or India in recent years.

Th e precipitous rise to close to $150/b caught everyone unawares; the likelihood of prices rising above $100/b had seemed remote before it actually happened. But in retrospect, we can clearly see that demand for oil was growing at a faster pace than supply.

China and other emerging economies were enjoying rapid growth fueled by a low interest rate policy, underpinned globally by the US Federal Reserve. And economic growth needs energy, loads of energy. Chinese oil demand jumped nearly 50% from 4.8 million b/d in 2000 to 7.5 million b/d by 2007, according to the US Energy Information Administration, accounting for close to a third of the rise in global oil demand from 76.8 million b/d to just under 86 million b/d over the period.

Dated Brent prices in 2000 were at nearly $30/b but by 2007 had jumped to nearly $75/b, refl ecting those demand pressures. At fi rst glance it may seem counterintuitive that prices would double if demand had not risen by a

similar amount. However, in any market with low spare capacity, a relatively small change in demand can trigger a disproportionate change in price to ensure that production plus changes in inventories equal demand. Caution: the opposite is also true.

While the reason for the price rise sharp increases in demand appears obvious in retrospect, the debate continues. In a panel discussion at the World Energy Congress conference in South Korea this year, one pricing expert opined that markets had been dysfunctional in 2008 and that the $147/b price did not refl ect the true market.

But it is worth noting that similar if not higher prices were observed the world over, in the US, Canada, Africa, Europe, the Middle East and Asia. Th e high price was global and detected by price reporting agencies and exchanges. And similar price developments were also evident in other commodity markets from grains to metal ores as China and other emerging

Source: FT

WHEAT FRONT MONTH FUTURES

400

200

600

800

1000

1200

2012 2013201120102009200820072005 20052004


OIL PRICES

economies consumed ever greater amounts.

Prices needed to rise almost across the board to send the signals that would ensure supply met demand without shortages or surpluses. A dispassionate assessment, which has thankfully become more common, leads to the conclusion that markets were working, and the result of the higher prices was a thinning of the herd of buyers.

Th e contractionTh e price reversal in late 2008 turned into a stampede, with a thinner herd galloping the other way. Prior to this period, energy was considered to have a low price elasticity, that is to say that consumers buying patterns would not be modifi ed greatly by increases in prices. But the behavior of consumers in the US, where changes in the wholesale price of gasoline were transmitted almost instantaneously and fully to the end consumer due to relatively low gasoline taxation around this time, explodes that theory. Demand started to contract as high prices bit.

US gasoline demand peaked in the summer of 2007 at 9.6 million b/d having historically followed a near ruler straight line of year-on-year increases. But then consumers began voting with their feet, fi guratively speaking, and a process began where medium to small size vehicles started to see their market share grow. And again, a relatively small change in demand had a disproportionately large impact on prices.

Th e retreat was fast and furious starting in early July 2008, with prices descending to $35/b by the end of the year. A rapid output cut by OPEC, monetary easing and sociopolitical upheavals such as the Arab Spring and other instability in the Middle East subsequently moved prices back up to the $100 mark, with occasional jumps towards $120/b. But the main point had been demonstrated: prices can move violently both ways, not just up but also down, as producers and consumers respond to market forces.

Perhaps it is worth noting that China also had a downward demand correction

Source: EIA

4-WEEK AVERAGE US GASOLINE DEMAND

6.0

6.5

7.0

7.5

8.0

8.5

9.0

9.5

10.0

Mar-91 Mar-93 Mar-95 Mar-98 Mar-99 Mar-01 Mar-03 Mar-05 Mar-07 Mar-09 Mar-11 Mar-13

MILLION BARRELS/DAY

Source: Platts

DATED BRENT

30

50

70

90

110

130

150

Nov-07Jan-07 Sep-08 Jul-09 May-10 Mar-11 Jan-12 Nov-12 Sep-13


OIL PRICES

in 2008, but the trend of oil demand in the worlds second largest economy has continued to move up with China now being the largest importer of waterborne oil in the world.

So far, we can conclude that the price was, and continues to be real, with rather prosaic forces behind the sharp moves such as rising consumption in key developing economies.

A disconnect emerges, though, between the data showing what drove the price up in the new millennium and various measures debated to address the price issue. Countless hours have been spent trying to fi nd more interesting reasons than just mere supply-and-demand forces being at play.

Concerns over transparency in oil markets have grown even though oil is the most tracked commodity in the world, with numerous service providers compiling and publishing information covering production, inventories, ship tracking, arbitrages, but most importantly trade data on who bought and who sold and at what price.

Nonetheless, the lack of hard data demonstrating malfunction in the market has not stopped well intentioned proposals and measures being put forward. Meanwhile, the market continues to work.

High prices are not only supposed to modify buyers behavior. Prices also infl uence sellers behavior, their investments and exploration and production plans. Coincidental with high prices, a new round of investments fi nanced by high prices took over in the US with the advent of technology that enabled the exploitation of shale reserves.

US crude production has increased by more than 50% since 2008 to nearly 8 million b/d, the highest in over 25 years, while oil imports have hit an 18-year low. It is easy to conclude that the sharp increase in production is a direct function of recent high prices. Th e American experience is remarkable: output in 2013 has been running at 17% year-on-year, and in terms of total liquids production the country is vying to become the largest producer globally. It is churning out roughly 7.8 million b/d of crude plus

Source: Platts

CHINAS APPARENT CRUDE OIL DEMAND

MILLION BARRELS/DAY

5.9

6.4

6.9

7.4

7.9

8.4

8.9

9.4

9.9

10.4

Jan-05 Nov-05 Sep-06 Jul-07 May-08 Mar-09 Jan-10 Nov-10 Sep-11 Jul-12 May-13

Source: EIA

US CRUDE OIL PRODUCTION

MILLION BARRELS/DAY

4

3

5

6

7

8

Jul-05 Jul-06 Jul-07 Jul-08 Jul-09 Jul-10 Jul-11 Jul-12 Jul-13


OIL PRICES

nearly 2.5 million b/d in natural gas liquids and over 800,000 b/d of biofuels.

Other geographical areas have not benefi ted as much as the US from the afterglow of the price boom for various reasons. Either they do not have the resources or the infrastructure to exploit them, or they have high taxation regimes

that discourage investment or policies halting shale development outright.

Th e solutionsWhile classical economists would look to address prices through measures that infl uence demand or supply, eff orts on the soft side of pricing continue. Th ere are various initiatives to improve transparency and/or implement new procedural or data recording processes. Th ese proposed changes or principles, though, do not add or subtract one single barrel of oil supply or demand.

One area of concern in the wider industry is the potential for unintended consequences for the integrity of pricing processes from these initiatives, all the more so because the energy industry is undergoing major fundamental changes.

We are seeing many infl ection points sharp changes in direction in the oil industry currently. Not least among these is the US no longer being the largest waterborne importer of crude oil, ceding the top spot to China.

Th ere is also the ongoing decline in production from the North Sea, which

has been depleting at the rate of about 7% per annum, while at the same time the major construction of refi neries in Asia and Middle East points to more refi nery closures in Europe over the coming years if current economic conditions do not perk up. Europes importance in the global oil market could diminish due to a combination of

falling crude oil output and demand and a trading environment being increasingly burdened with regulatory exposure.

Th ese changes point to a shift to greater Middle East-Asian crude pricing prominence at the expense of the traditional Western benchmarks, with a likely growing reliance on the still young Dubai benchmark although some expect Europe to become more business-friendly if the slowdown or production decline is too steep. As an emerging sign, the UK is undergoing a deep review of investment in the country and looking at what needs to be changed to arrest the production decline.

Nevertheless, Middle East and Asian participants understandably question their reliance on Western systems as the structural weight of demand moves east. Th ere are signs of this emerging already, with some evidence of balkanization in Western markets as non-US domiciled entities seek to trade only with similarly incorporated entities to avoid Dodd-Frank or any other transnational issues.

But the core market concern is liquidity. Th ere are fears that growing requirements from the trade will naturally raise costs and cause players to exit the market or shift their business to areas less burdened by regulation. Th e declining liquidity in the natural gas futures market is held up by some as evidence of a retreat. Liquidity is also declining in derivative markets, with some noting a loss of market depth that is leaving participants with fewer counterparties to trade with.

Platts tracking of derivatives versus physical markets trading reveals some signifi cant recent changes in the composition of the market, with the share of derivatives instruments shrinking on a year to year basis. Th e share of derivatives declined from 55% to 51% on a year-to-year basis in the fi rst 10 months of 2013.

Whether one believes that energy markets are providing completely unbiased price signals, few would disagree that a free-market price provides the correct triggers to infl uence demand and supply. And this price message should not be managed or guided, even if the message is not welcomed.

After all, if there is a concern over high prices, one should not forget the maxim Th ere is nothing like high price to cure high prices, as seen in the downward correction in US natural gas prices and the emerging behavior in the US crude oil market. High prices brought about innovation and supply in those countries open to energy development and if prices were to fall by natural causes, such decline will spur the seeds for more consumption, bringing about another upward cycle.

Th ese changes point to a shift to greater Middle East-Asian crude pricing prominence at the expense of the traditional Western benchmarks.

The views expressed in this article are those of the author.

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21insightDECEMBER 2013


REFINING SECTOR

Th e startup in September of the 400,000 b/d capacity Jubail refi nery in Saudi Arabia was good news for the Middle Eastern oil giant and its ambition to become a major exporter of high value oil products.

But it represents yet another signifi cant setback for Europes fl ailing refi ning sector, already reeling from the eff ects of falling demand since the global economic crisis in 2008 and continued overcapacity.

Jubail and other planned refi neries in the Middle East set to come online this decade could start sending a lot of diesel Europes way, eroding the already slim refi ning margins in the region. Europe also faces competition from refi ners in the US looking for export markets to cash in on the surplus of cheap crude in the country and Russia, which is midway through a major refi nery modernization program designed to boost volumes of high-end products.

European refi neries are closing all the time the latest being the 55,000 b/d Mantova refi nery in Italy with more expected to shut as margins stay low. Th e warnings for Europe continue to come

thick and fast from refi ners, governments and traders alike: they all agree that it is diffi cult to see how European refi ning can compete in a global industry when demand is tight, newer plants are far more complex and EU environmental laws continue to threaten European refi neries profi tability.

Totals CFO Patrick de la Chevardiere in late October said there was still a refi ning overcapacity of 1.5 million b/d in Europe. Th e European Commission recognizes there is a problem. It is carrying out what it almost fondly called a fi tness check of the industry ostensibly a study to fi nd out what Brussels can do to fi x the sector that looks increasingly broken. It plans to report back in September next year.

Th is could be too late though. According to the International Energy Agency, 15 refi neries have shut between 2008 and 2013, and the EUs combined refi ning capacity has dropped by 8%. And that could just be the start. Refi ners in Italy are struggling, the UKs industry has been decimated, and the French sector remains under heavy pressure.

EUROPESREFINING MOMENT

After enjoying strong margins in the early part of the century, Europes

refining sector has wilted in the face of alternate fuels, collapsing

demand, engine efficiencies, overseas competition, health and safety costs and, more recently,

emissions legislation. Will a review by Brussels offer any respite?

STUART ELLIOTTSenior Managing Editor,Europe & Africa Oil News


REFINING SECTOR

Keep an eye on Total. A partner at Jubail, the French giant has often said European refi neries will have to fi ght to survive. It vowed in 2010 not to shut any more plants in France for fi ve years following the closure of its Dunkirk plant. But come 2015, its free to get started again. De la Chevardiere in September assured that Total would honor its pledge, but said nothing about what it might do after that.

Real vulnerabilityOne of the major issues facing the sector is current and proposed European legislation. Brussels over the summer held its fi rst refi ning forum to look at how it would aff ect the sector and another in late November.

BPs regional vice president for Europe, Peter Mather, said in April that the Commission needed to review its policies to help the sector survive its current competitiveness crisis. Th e EU refi ning sector has a real vulnerability, caught in a global market between the US with its low fuel costs and Asia with its low labor costs, Mather said.

At the same time EU refi ners are having to invest to meet increasingly stringent EU controls, for example on industrial emissions, which is eroding already narrow margins, he added.

EU refi ning trade body Europia estimates that there is around $30 billion of investment already announced for EU refi nery projects to 2020, but that another $21 billion would be required to meet the changes in demand and new specifi cations. Th at $51 billion total equates very roughly to $1/b on the refi ning margin in Europe, which makes it massively signifi cant as the normal margin ranges from $0 to $5/b, Mather said. A lot of this

investment is just to stay in business theres no obvious return, he added.

Industry group CONCAWE has warned that refi ners across Northwest Europe could face a bill of up to Eur25 billion ($33 billion) just to meet requirements of European Union legislation in the coming years. Th e newly elected president of CONCAWE, Michel Benezit, estimates that costs could amount to anywhere between Eur15 billion and Eur25 billion, just to comply with legislation, without any competitive improvement in our operations.

Speaking to Platts in September, Benezit said that refi ners in the EU will have to make choices, because it is such a huge amount of money, it is going to be diffi cult. He noted that refi ners in Europe are under very heavy pressure because of decreasing demand as a result of more energy effi cient engines, but he also identifi ed the diesel versus gasoline imbalance, the burden of EU

Courtesy: Shell

Shells Pernis re nery, the biggest in Europe.


REFINING SECTOR

legislation and global competition as other factors providing a substantial challenge.

Th e uncertainty surrounding the precise requirements of EU emissions and sustainability legislation has had a chilling eff ect, he said, with the lack of clear direction making it diffi cult to raise cash. Th e current investment framework does not always off er long-term perspective given that this industry has long investment cycles, he said.

A coherent EU legislative framework with clear and demonstrated benefi ts for sustainability and competitiveness is needed to create a clear investment environment over time, Benezit said. It is impossible to mobilize the capital which is required without the clear framework.

Some say that petroleum products are available [to import] and that no [refi ning] in Europe is better than [coping] with the diffi culties of our industry, which is said to be a burden, he said. We do believe that security of supply is important and that to have in-house refi ning capacity helps Western Europe to be safe and have a healthier economy in the long term.

After enjoying strong refi ning margins in the early part of the 21st century, Europes refi ning sector has been beset by a combination of challenges including alternate fuels; collapsing demand; rising engine effi ciencies; fi erce overseas competition; sluggish investment; the extensive burden of health and safety worker conditions; and, more recently, emissions legislation.

If EU refi ners want to remain key players in the international market, they have to become more competitive. Th is can be achieved by improving our effi ciency in our operations through investment but, again, the impact of EU legislation is critical in this perspective, Benezit said.

Killer regulationTh e Commissions fi tness check for the sector will look at the quantitative and qualitative impacts of relevant EU legislation on costs and productivity. But whether it can actually achieve anything is open to question. Its hard to see what Brussels can do that wouldnt undermine

EUROPEAN REFINERY CLOSURES SINCE 2008

Re nery Owner Capacity (000 b/d) Status Period

Italy

Mantova MOL 55 To close permanently January 2014 Gela Eni 105 10 month closure June 12-April 13 Rome TotalErg 86 Permanent closure September 2012 Falconara API 83 6 month closure January-June 2013Cremona Tamoil 90 Permanent closure October 2011 Porto Marghera Eni 80 Permanent closure Q3 2013

France

Petit Couronne Petroplus 162 Permanent closure December 2012 Reichstett Petroplus 85 Permanent closure November 2010 Berre lEtang LyondellBasell 105 Mothballed January 2012 Dunkirk Total 140 Permanent closure September 2009

Germany

Harburg Shell 110 Permanent closure April 2013 Wilhelmshaven Hestya Energy 260 Permanent closure October 2009

UK

Coryton Petroplus 220 Permanent closure July 2012 Teesside Petroplus 117 Permanent closure May 2009

Romania

Arpechim Petrom 70 Permanent closure January 2012

Czech Republic

Paramo Unipetrol 20 Permanent closure May 2012

Ukraine

Lisichansk Rosneft 160 Inde nite closure March 2012

Source: Platts


REFINING SECTOR

other goals related to climate change and environmental pollution.

Th e EU legislation includes the industrial emissions directive, which requires refi neries to meet best available technology benchmarks, and the fuel quality directive, which sets targets for cutting greenhouse gas emissions from fuels. BPs Mather said meeting the EUs draft best available technology benchmarks alone could require $300 million invested in each EU refi nery.

Th e refi ning sector is also impacted by EU legislation on renewables, emissions trading, strategic oil stocks, marine fuels, energy effi ciency, energy taxation and chemicals.

We believe the European Commission must look hard at what measures can be revised or suspended, said Mather. Th is is such a hard time for industry that we need to press pause on some things as we carry out the fi tness check, he added. Mather said he would like to see this pause particularly on the industrial emissions and fuel quality directives.

Chris Hunt from the UK Petroleum Industry Association told the Brussels refi ning forum in April that if there is no change in the timing of the key bits of killer regulation in the industrial emissions and fuel quality directives, then the fi tness check will be fi nished too late to be of use. Inevitably, then, more refi neries will be forced to close.

Buyers waryTh ere is, of course, one alternative to shutting refi ning capacity in Europe, and that is selling it. But buyers have not been exactly climbing over one another for European assets when theyve come up for sale.

A good example is the bankruptcy of independent refi ner Petroplus in 2012 when suddenly fi ve European refi neries appeared on the market. Interest was not high for the plants, and those who did show interest were not traditional refi ners. Only three were bought, all of them by global trading houses.

Trader Vitol took the 105,000 b/d Antwerp plant in Belgium and the small 68,000 b/d Cressier plant in Switzerland, while rival Gunvor bought the 100,000 b/d Ingolstadt refi nery in Germany. Th e others the 162,000 b/d Petit Couronne in France and the 220,000 b/d Coryton plant in the UK were shut. Petroplus had already closed the 117,000 b/d plant in Teesside, UK, and the 85,000 b/d plant at Reichstett in France.

Its unlikely traders want refi neries to make money as a stand-alone operation. Gunvor, on its website, says: Refi neries complement Gunvors trading function, which can create greater operational effi ciency across the supply chain. Gunvor is leveraging its expertise and excellent relationships with crude suppliers to gain access to the types of crude oils processed at its refi neries.

Vitol emphasizes its global access to crude and feedstock which can provide attractive crude input options. Th e products produced can be made available to our product trading teams. Vitol continues to look for opportunities to work with crude oil producers to access our owned refi nery system and with other refi ners to optimize their investment by accessing the best possible crude oil and feedstock alternatives.

IMPORT DEPENDENCY IN THE UKThere were 18 re neries in the UK in the late 1970s now there are only seven, the most recent closure being the 220,000 b/d Coryton re nery near London in early 2013.

At least two other plants have been up for sale. The US Murphy Oil has been trying to of oad the 135,000 b/d Milford Haven re nery for years, and Total only recently gave up on nding a buyer for the 220,000 b/d Lindsey re nery. The future of Scotlands 210,000 b/d Grangemouth re nery was also up in the air until operator Ineos unveiled a survival plan in October that involved some serious cost-cutting.

Others are trying different strategies. Indias Essar, which bought the Stanlow plant in 2011 from Shell, has switched to using opportunity crudes oil from West Africa, the Mediterranean and Canada, as well as some Russian M-100 straight-run fuel oil instead of traditional North Sea crude. It claims to have reaped a $1/barrel lift to its re ning margins in 2012, but its not exactly a stellar performance.

Like the EU, the UK is carrying out a review of the sector, due by the end of 2013. Junior energy minister Michael Fallon said the review would look at the balance between importing product and re ning product [ourselves], in terms of the obligations of stocking, the difference in duty treatment, not the duty itself, but the way the duty is applied, but also the central question of how much re nery capacity we need.

The future looks decidedly bleak, however. A recent study by IHS Purvin & Gertz suggested that the UK faces further re nery closures in the coming years as the industry is forced to deal with immense costs. From 2013 to 2030, UK re neries face an additional GBP11.4 billion ($17.5 billion) in capital and operating costs. The required capex over the period is estimated at GBP5.5 billion most of which would not generate any return on investment to pay for new emissions abatement equipment, processing capacity, and storage improvements, the report said.

continued over page...


REFINING SECTOR

Who else might be interested in a European refi nery? Sovereign investment funds have certainly been sniffi ng around. Th e Libyan Investment Authority (LIA) was the French governments favored bidder for the Petit Couronne refi nery. Th is suggested that producers from outside of the region may look to take over refi neries as a way of gaining a foothold in Europe. But that never materialized, Tripoli saying it would not bid for Petit Couronne after all.

Russian companies have also been in the market for refi ning assets in recent years. Lukoil bought the 320,000 b/d ISAB refi nery in Sicily, and Rosneft bought a stake in the 300,000 b/d Sarroch refi nery in Sardinia.

But that may well be it. Didier Casimiro, Rosnefts vice president of commerce and logistics, said in September it would be sticking with its existing assets in Germany and Italy. We are not, at this moment, looking into further expansion in this part of the world, Casimiro said.

Casimiro also acknowledged that life for independent refi ners was likely to become tougher in the current refi ning climate because investment would be harder to attract in the face of increasingly integrated rivals. Standalone refi ning is likely to face even greater pressure, he warned.

Th is leaves some companies without a traditional background in refi ning such as Libyas little-known Murzuq Oil, which has made repeated bids for the Petit Couronne plant. Created in 2011 and describing itself as a marketer of refi ning products and provider of oil facility securities, Murzuq Oil says it

has signed crude oil and gasoline supply agreements with Libyan distributor Al Mahari Oil Services and that the Libyan government would take a 20% stake in the Petit Couronne assets, through the Commerce & Development Bank of Libya.

Th e French government would be off ered a 5% capital stake through its public investment bank BPI, as well as a seat on the board. Th e off er includes the construction of above-ground storage facilities for butane and propane, as the previously used underground storage facilities are insuffi cient for the companys needs. Murzuq Oil has also off ered to re-employ all the site workers who were made redundant, which amounts to almost 500 workers, reinstating their employment terms from before the plants closure.

Whats the catch then? Well, its not the fi rst time Murzuq Oil has tried to buy the plant each time previously, the French court tasked with deciding the refi nerys fate has rejected its off ers, saying the bids did not have the fi nancial and technical capacity to ensure the restart of the plant.

All in all, the future of European refi ning looks bleak. When its cheaper to import products from elsewhere in the world than it is to refi ne products on your own soil, there is clearly a major problem. But its not just about economics if more European refi neries close, there are bound to be supply security ramifi cations.

It remains to be seen what the EUs fi tness check will reveal. Th e chances are it will not make for especially comfortable reading for anyone involved in the industry.

Additional operating costs are seen at GBP5.9 billion, re ecting the cost of running the new equipment, plus a bill of around GBP 1 billion for carbon allowances. Further costs would also likely come from new processing capacity needed to address a growing surplus of gasoline and a de cit of middle distillates in the UK. Yet-to-be- nalized EU directives on the carbon intensity of fuels and energy ef ciency will add signi cant further costs.

It would be highly likely that when faced with such a large mandatory capital expenditure requirement that provides no return on investment, UK re ners could be forced to close more re neries, the report said.

On costs, Purvin & Gertz said that while UK re neries are globally competitive, enjoying average net cash margins of around $2.60/b, long-term investment in diesel production capacity is required. To simply keep pace with current demand trends, UK re neries would need to invest some GBP1.5 to GBP2.3 billion over the next 20 years, it said.

Based on an approach used by the International Energy Agency, the UK is already at a high risk level for supply of diesel and jet fuel, according to the Purvin & Gertz report. Overall, the UK is projected to have a total re ned product cover of 83%, a net de cit of 17%, which would put the UK in the low risk category. However, it has a jet fuel de cit of 55%, a diesel de cit of 47% and a kerosene de cit of 44%. The southeast of England is particularly at risk, with low supply cover for all fuels, and no spare capacity in import logistics to meet any future shortfall in the event of supply disruptions. The southern region is even short on gasoline, having an import dependency of 60% and a jet fuel import dependency of 91%.

...continued from page 25

Courtesy: MOL


BRAZILIAN UPSTREAM

A few years ago the swift transformation of Brazil into a New World oil powerhouse seemed all but assured. Th e subsalt bonanza in Latin Americas biggest economy heralded a new promised land, full of boundless riches set to propel the country and its lucky upstream players to new heights.

Brazil is still set to become the unrivalled leader in deepwater output over the coming years, with its subsalt developments accounting for almost 80% of the worlds overall 4.4 million b/d growth in deepwater oil supplies by

2035, according to the International Energy Agency.

But a spate of project delays has certainly taken the shine off initial hopes, with state-controlled Petrobras trimming its optimistic output targets, and more recent developments raise the question of whether those expectations were overblown from the outset.

Some investors caught up in the hype have already paid dearly as those who banked, and then lost, billions over Eike Batistas failed OGX can already attest (see box page 31). And in October, Brazil was faced with the uneasy question of why the biggest oil fi eld among its off shore giants didnt attract more interest in an auction.

Th e massive Libra fi eld, which holds 8-12 billion barrels of recoverable oil, attracted only one bid and deep-pocketed players such as ExxonMobil, BP and BG did not even bother to turn up. Only 11 foreign companies signed up to bid, far fewer than the 40 that Brazils oil agency had originally expected, and only four made up the

SUBSALT PINCHBrazil faces tough questions over the

pace of its subsalt oil boom: has it got the regulatory regime right; is state oil company Petrobras up to

the massive task at hand; what wider impact might OGXs spectacular fall

from grace have?

ROBERT PERKINSNews Correspondent

Courtesy: EBX


BRAZILIAN UPSTREAM

sole fi nal off er. With no competing bids, the government got the minimum 42% share of profi t oil allowed for the project.

Th e National Petroleum Agency (ANP) claimed BP, for one, held fi re due to legal and fi nancial uncertainties over its ongoing US spill settlement battle in the US courts. It seems likely though that BP like others may have been less keen to tie up capital in complex projects without greater control of the outcomes.

In the absence of generous terms, players such as BP and ExxonMobil prefer to create value on their own terms through the drill-bit rather than take minority stakes in pre-packaged assets. With state-backed Petrobras as the operator with strategic oversight for Libra, it is not surprising that oil companies had reservations about political control of the project.

Muted primary interest in Brazils fi rst subsalt round is triggering doubts that the countrys below-ground potential could be limited by associated above-ground risks, UK-based Business Monitor said in a recent report.

Libra, Brazils largest-ever discovery (although the ANP said recently the Franco fi eld may be as big or even bigger), was also the fi rst deal under a three-year-old legal framework which gives the government via Petrobras the central role in deciding how the $50 billion needed to develop the fi eld is spent. Under the regulatory framework, Petrobras must be the operator and have a minimum 30% stake in all projects in the subsalt blocks, a fl oor it

Brazil now has to vie for upstream investment with new players on the global energy scene.

LibraFranco

IaraLula (Tupi)

Sapinhoa (Guara)

Marlim

Golfinho

Espirito SantoBasin

CamposCamposBasinBasin

AtlanticOcean

Santos Basin

Sao Paulo Rio de Janeiro

Curitiha

Florianopolis

Vitoria

BRAZ I L

Ocean

Post-salt

Pre-salt

Salt

2km

5-7kmbelowsurface

2km

1km

Oil is stored in the poresof the reservoir rock layersin the pre-salt layer.

Exploration blocks

Oil elds

Pre-salt region

Source: Carrie Cockburn/The Globe and Mail, Petrobras, Wood Mackenzie, Graphics News

BRAZILIAN OIL FIELDS


BRAZILIAN UPSTREAM

surpassed at Libra after ending up with 40% of the project.

Now Petrobras 40% stake in the project only adds to the burden of its own fi nancial commitments in the coming years, to the tune of $3 billion upfront and a further $6 billion for its share of expected development costs. Th e winning consortium, made up of CNOOC, the China National Petroleum Corporation, Total and Shell, will need to operate up to 18 fl oating production vessels to develop Libra, whose output is expected to exceed 1 million b/d.

Creeping costs Certainly the creeping costs of developing large deepwater fi nds in recent years have put players off . Th e contract terms are also tough with the governments total take from the fi eld, including taxes, one of the highest in the world at about 80%.

Th e IEA estimates that Brazil requires a massive $1.34 trillion in cumulative investment in the oil sector over the next two decades, or $57 billion per year on average. Including gas, the IEA sees the requirement for upstream spending in Brazil averaging $60 billion per year, on par with Russian and higher than the whole of the Middle East.

And now Brazil has to vie for upstream investment with new players on the global energy scene. Expensive deepwater developments have fast-growing competition from booming shale oil plays, and the new rift plays of West and East Africa may also have diverted attention from Brazils prolifi c off shore prize.

Indeed, it may be the global shale liquid potential that raises the biggest question marks over future returns from Brazils deepwater oil. If the US shale revolution story is replicated on a signifi cant scale around the world, sliding oil prices in the longer term could render heavily-taxed earnings from Libra and its like lackluster by comparison.

Local equipment and labor shortages have been part of the reason why Petrobras has been forced to scale back production targets and lower its earnings expectations. Since late 2010, Petrobras has seen its shares shed over 60% of their value while over the same period Source: Petrobras

0

20

40

60

80

100

120

Jun-13Dec-12Jun-12Dec-11Jun-11Dec-10

Net debt Adjusted cash and cash equivalents

PETROBRAS GROSS DEBT

BILLION $

Source: IEA's Medium Term Oil Market Outlook and World Energy Outlook 2013

BRAZILS OIL PRODUCTION GROWTH

2

3

4

5

6

203520302025202020152012

MILLION B/D


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ExxonMobil, for example, has risen by 20%. Th is year alone the company has lost 14% of its value while Exxon has gained 4%.

Saddled with debt and strapped for cash, concerns are that Libra could overburden the group fi nancially. Its current portfolio of off shore assets is already overstretching the company as it scrabbles to fund its $237 billion fi ve-year investment plan, mostly by selling assets abroad. Petrobras plans to shed some $9.9 billion worth of assets in 2013 alone.

At home, the companys enforced leadership in the subsalt is being diluted by the fi nancial, managerial and political demands of its vast asset base both upstream and downstream. While integrated oil companies might typically sell off less profi table assets in order to focus their resources on high-earning projects, Petrobras must allocate its capital across a wide range of projects new and old.

Th e strain on resources threatens eff orts to arrest declining production from mature fi elds in the Campos Basin, for example, a key requirement for it hitting a production target of 4.2 million b/d in 2020.

Petrobras last year posted its fi rst yearly output decline since 2004 and the fi rst quarterly loss in 13 years. More recently the company missed Q3 analyst earnings forecasts by almost 50% after growing fuel imports, the impact of heavy asset sales and higher exploration charges crimped its bottom line. Moodys Investors Service downgraded Petrobras debt on October 3 and the outlook is negative.

Still run largely as a government agency, government fuel subsidies are squeezing

its margins and have already cost it billions of dollars in lost revenues. Despite planned investment to boost Brazils refi nery capacity, the country is expected to remain dependent on fuel imports for years to come.

As a result, Petrobras is seen continuing to import fuels that it has to sell for a loss domestically, although this could begin to change with the government set to consider soon a new price increase mechanism which will allow the company to narrow its losses from fuel sales. Implementing a fuel pricing formula targeting international parity pricing would bring a welcome increase to Petrobras cashfl ow and likely reassure investors. Th e local gap to international fuel prices currently stands at around 3% for gasoline and 13% for diesel.

Subsalt challengesBrazils technically challenging, super-deepwater subsalt fi elds have cost a lot more than fi rst expected to produce and lifting costs have soared over the last few years.

With the cost of drilling a subsalt development often representing more than half of its total capex, timely access to reasonably-priced rigs has become a key problem. Th e UKs BG Group in particular has suff ered from costly slipped project milestones on the massive Guara/Lula development due to contractor holdups.

Th e bloated costs of doing business in Brazil, often referred to as the Custo Brasil, have been well documented with disgruntled investors pointing variously to poor infrastructure, red tape, high taxes and low productivity.

OGX BURNS UPSince Petrobras discovered the rst of Brazils giant subsalt oil elds in 2007, investors have pumped billions of dollars into domestic oil start-ups keen to tap into the market exuberance that followed. This year some of those bets began unraveling at a scale and pace that have taken many by surprise.

At the top of the pile is the spectacular decline of Brazils OGX; essentially a story of a debt-laden start-up which overpromised and under-delivered.

The agship of a business empire run by Rio-based tycoon Eike Batista, OGX banked $4.1 billion from a 2008 public offering less than a year after it was set up.

Then the biggest IPO in Brazilian history, OGX backed up its promises of future offshore oil wealth with estimates that its blocks in the Campos and Santos basins held 4.8 billion barrels of oil equivalent of reserves.

But Tubarao Azul, its rst development, failed to live up to companys ambitious output targets and the company also soon racked up debts of over $5 billion buying more exploration assets to fuel future growth.

Earlier this year, OGX hit the markets with news that most of the elds it has explored arent economically viable and its only producing oil wells were ops.

After wiping further millions from the companys market value, the bombshell also set in motion a chain of events culminating in OGX defaulting on its interest payments and then ling for bankruptcy protection at the end of October. At that point it was valued at $190 million; just three years earlier it had a stratospheric market capitalization of some $45 billion.

A thick cloud now hangs over the future of OGX. Documents on OGXs website indicate that the company will run out of cash in December and that it needs $250 million in new money to continue operations through April 2014.

Ultimately, OGXs survival hinges on whether it can generate cash from its most promising oil eld, Tubarao Martelo, and if can hold on to its remaining licenses.

continued over page...


BRAZILIAN UPSTREAM

Petrobras alone requires more than 50 FPSOs and other production units to meet its production targets, meaning the countrys timely resource development is likely to face more delays. At the same time, stringent local content requirements are overwhelming Brazilian shipyards, and delays at the swamped yards have already slowed the construction of its key production units. Hold-ups with construction of some planned shipyards themselves have also exacerbated the delays Petrobras faces.

Th e risk involved in a local content policy is that local suppliers develop in a way that is not internationally competitive, with a resulting increase in costs and delays, the IEA said in a recent report noting rising unit costs of manufacturing labor since 2009.

Some believe, however, that concerns over Brazils cost and infrastructure constraints may be overplayed. In a recent report, Citi analysts said they believe that production delays to the Guara/Lula oil developments may refl ect more teething problems for the countrys fast-expanding supply chains to the domestic oil industry rather than endemic limitations.

Brazils subsalt developments can still break even at $40-45/b, Citi estimates, putting it fi rmly among the worlds top 25% of fi eld developments in terms of breakeven cost.

We think the market fails to diff erentiate the value of investment across the industry, Citi said in a September study into BG, Repsol and Galps Brazilian projects. Our analysis of the supply chain gives us confi dence that

capital effi ciency is improving and that the fl exible, modular nature of the development can deliver on projected timetables.

Project cost defl ation will come through drilling effi ciency gains and more competitive pricing as local supply chain capacity builds within the country, according to Citi. Greater standardization in FPSOs and other subsea supplies as well as advancements in subsea technology will also play a role, it predicts.

Given the high levels of cash consumed by drilling subsalt fi elds, this cost area is one which off ers the greatest scope for reductions. Subsalt drilling costs have fallen about 40% over the past fi ve years, and Citi sees the potential for 5-10% cost defl ation in the Brazilian subsalt by 2018.

Increasingly it seems the fortunes of Brazils economic health are tied to Petrobras and the success of its oil and gas industry. Certainly, the pressure on Petrobras to fulfi ll its role as a national oil champion, develop a huge raft of upstream projects and fi ll government coff ers for public works is considerable.

Given the sheer scale of the challenge, it seems likely that Brazil may make things a little easier for foreign investors. Some now expect the contractual terms and bidding fees imposed by the country to be relaxed before the next subsalt round, expected in 2015.

By coincidence, that is also the year when Brazils subsalt oil revenues will by all accounts really take off as it gains entry to the global club of net oil exporters.

...continued from page 31

Eike Batista: the writings on the wall

Courtesy: Juliana Coutinho/Wikimedia

OGXs woes have already fuelled a growing crisis of con dence in Brazilian startups and other oil industry players have suffered. Brazilian independent HRT has seen its own market value decimated this year after dry wells in Namibia and the Amazon Solimoes Basin left it short on liquidity.

The company, which intentionally shunned Brazils offshore bonanza when it set out its own stall to investors, is scrabbling to sell assets to refocus on producing elds able to generate cash ow to stay in business. With little debt and reports of interested buyers for some of its assets, HRT looks well place

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