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Oil prices could be stabilizing. Benchmark Brent crude seems to have hit bottom, and has crept above $60 per barrel in recent weeks. But there is still little consensus on whether the market is now set for a relatively swift rebalancing, or whether supply disruptions or other unexpected events could cause another price whiplash. Some observers — and to judge by net length in futures markets, many speculators too — see the market tightening rapidly as US output growth starts falling off, compounding ongoing supply problems in Libya and recent weather-related disruptions in Iraq and Kuwait. Others see greater risks to the downside, from still-plentiful supply and from the shrinking volume of storage left available to soak up the surplus (PIW Feb.2’15). Those who think market rebal-ancing is well under way seemed to have the upper hand in early February, but plenty of market watchers believe further price falls are looming — Citibank thinks Brent will fall back to the $40/bbl range or even lower, while Denver-based consultancy Bentek believes US benchmark West Texas Intermediate could drop below $40/bbl. Several other banks — Bank of America, UBS and Commerzbank — all see Brent dropping below $50/bbl again, while US analysts caution that although the country’s rig count has sunk to a five-year low, production may not necessarily follow suit, as rigs drill faster, producers get better at locating sweet spots and new wells deliver progressively better initial volumes.

The bulls can also point to other factors — the cuts in spending announced by companies world-wide, and most notably by the small, highly leveraged producers that dominate the US’ tight oil

• Are High Costs, Complexity Shrinking Industry Ambitions?, p2

• Libyan Output Remains Stuck On Roller Coaster, p3

• Russian Majors Keep Calm And Carry On, p4

• Petrobras Cleanup Lent Credibility by Bendine, p5

• Can Europe Absorb Global Gasoil Surge?, p6

• Marketview: Limited Upside, p8

Low Oil Prices Create New

Safety Challenges

Risks Aplenty To New Oil

Price ‘Stability’

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Vol. LIV, No. 8 February 23, 2015

Five years on from the Macondo disaster in the Gulf of Mexico, the oil industry is facing a new test of its safety credentials. High oil prices gave rise to one set of safety challenges, as the industry pushed the boundaries of its technical capabilities to develop new plays and resources made economically viable by $100 oil. But the recent fall in oil prices creates new risks, as companies try to square main-taining safety standards with cutting spending and staff levels. The danger is that the lessons learned from Macondo will be forgotten, and for some, alarm bells are already ringing (PIW Jun.14’10). Unsurprisingly, it is oil workers’ unions that have been most vocal — their members clearly stand to lose jobs in the current round of cost-cutting, but it is also blue-collar staff on rigs and in refineries who are most

at risk from any lapses in safety. The UK’s Unite union has claimed that cuts to North Sea staffing by companies such as BP, Chevron and Royal Dutch Shell are compromising safety standards, while the USW union has also pointed to a range

of safety concerns — unsafe staffing levels, frequent fires, leaks and emissions — as a principal reason for strikes this month at US refineries.

The message from oil companies is that huge advances have been made in safety management since Macondo, and that this progress will not be compromised by lower oil prices. New systems, new technology and better regulation are now in place, allowing companies and regulators to talk with cautious confidence about the industry’s preparedness. But that confidence should not mask two very important considerations. Firstly, lower oil prices and constrained budgets clearly will cre-ate risks vis-à-vis safety, much as they will in other areas of corporate performance, by encouraging a

(Please turn to p.4)

Macondo5 YEARS ON

Macondo5 YEARS ON

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PIW® February 23, 2015 www.energyintel.com Page 2

plays; strong demand from refiners, who are running their units hard to take advantage of good margins; and the International Energy Agency (IEA), which expects the market to rebalance in the second half of 2015. In its latest monthly report, the agency revised its projection for non-Opec sup-ply growth this year to 800,000 barrels per day, down from 950,000 b/d in its January market report and 1.3 million b/d in the December edition, reflecting the impact of lower oil prices. The US Energy Information Administration (EIA), on the other hand, still sees US crude supply climbing by 670,000 b/d this year, with a further 250,000 b/d increase in the country’s natural gas liquids output. The IEA’s figure for US crude growth this year is some 290,000 b/d lower than the EIA’s.

A key question remains how much storage space is available to absorb the crude surplus. US marker West Texas Intermediate (WTI) already looks to be heading for another fall as and when tanks at the Cushing, Oklahoma, storage and trading hub are full, which could happen in the next few months. That may not have much direct impact on Brent, for which the more pertinent question relates to storage outside the US — but that too is apparently filling up fast (PIW Feb.16’15). With tanks filling up in Cushing, also the pricing and delivery point for the Nymex crude futures contract, WTI’s discount to Brent is set to blow out to $10/bbl or more. As long as Brent-priced oil can find storage tanks, Brent’s contango — the spot discount versus later deliveries — will create the financial incentive to buy oil for storage. But if Brent-priced cargoes can no longer find a place to go, they will start pulling down the Brent price. Full tanks in the US will create havoc there, but while this might accelerate the shutting-in of some US production, it might not have immediate implications for Brent, which will really take its cue from the storage situation in Europe and Asia. Source say there is tankage available with refiners and producers in both these regions, but that free storage is getting tight.

The knives are out for bloated corporate budgets, with cuts all around as oil companies adjust to lower prices. As capital expenditure is slashed, firms are adopting a mix of measures to cut costs and simplify those projects that have hitherto needed an oil price closer to $100 per barrel than recent levels of around $50/bbl to make commercial sense. Oil companies see the oil-field services sector as a big part of the cost problem, and are cutting exploration and delaying final investment decisions (FIDs) until the cost structure adjusts. The early casualties range from LNG in Australia to deepwater oil developments in West Africa and the US Gulf of Mexico. Cuts to capex continue, but those announced so far by 29 of the world’s biggest oil companies already exceed $60 billion for 2015, preliminary analysis by Energy Intelligence Research shows — and if oil prices remain around $50-$60/bbl, deeper cuts are promised. Among the big ticket victims are floating LNG ventures in Australia, with Bonaparte, Browse and Cash Maple all on ice. In Africa, Royal Dutch Shell’s deepwater Bonga South West development in Nigeria is being delayed due to prohibitively high bids from contrac-tors, PIW learns (PIW Feb.16’15). Having already simplified the design, BP has pushed back FID for Mad Dog II in the deepwater US Gulf, waiting to see if contractor costs fall further. Total blames bids that came in 30% over budget for the delay to its Zinia-2 development in Angola. “On some new proj-ects, costs are just too high and we are not going to award contracts,” says Total’s upstream chief Arnaud Breuillac. “We are not going to FID. Let’s see if the service sector gets the message.”

For some, this is the standard Big Oil response to an oil price downturn. But the insistence on lower costs and reduced complexity could constrain oil exploration and project economics for far longer than the current price slump. Some of the shrinkage could be permanent. On the cost side, companies are targeting project break-even at a much lower level, and hard-wiring it into their long term strategy, while explorers are now avoiding riskier frontiers, whether presalt, ultra-deep-water or the Arctic, and getting back to basics — sticking closer to existing production, reconsid-ering shallow-water potential or returning to the onshore. So steep have costs become that Total plans to make two-thirds of its 30% reduction in exploration spending this year into a permanent cut — the idea being to impose greater discipline on the future selection of drillable prospects (PIW Oct.6’14). On top of the cost issue, the cooling of interest in plays like Africa’s Atlantic Margin is partly a recogni-tion that recent drilling results have been poor, featuring mostly small subcommercial finds (PIW

PIW® February 23, 2015 www.energyintel.com Page 2

Are High Costs, Complexity Shrinking

Industry Ambitions?

Jul.7’14). Instead of the ultra-deep and deepwater presalt off Angola or Congo (Brazzaville), the focus for Eni and Total has switched back to cheaper shallow water, drilling on the continental shelf edge, and poten-tial tie-ins of marginal fields to existing infrastructure. But even these can be problematic at recent project cost levels.

The longer-term cost for companies — in missed output targets and lower growth due to aban-doned exploration plans and postponed projects — has yet to be counted, with investors encouraged for now by the displays of greater financial discipline. But by spending and doing less and insisting that more of their business breaks even at a much lower oil price, companies are increasing the risk that the already low level of new oil discoveries declines even further, new project approvals drop off dramatically and today’s excess oil supply becomes tomorrow’s shortage. Projects now being pushed back on cost grounds, such as Shell’s Carmon Creek oil sands expansion in Canada or Chevron’s Tengiz expansion in Kazakhstan, will be needed if existing oil production, half of which is expected to disappear by 2030, is to be replaced. Total has slashed capex by 10% and says its aim is to “do more with less.” But it also reckons that 50 million barrels per day of new supply will be required by 2030 — of which some 20% will need a $90/bbl oil price if it is to be developed.

The roller coaster that has been Libya’s crude output over the past few years shows no sign of stop-ping as the North African producer marks the fourth anniversary of the fall of the Qaddafi regime. From a stable pre-revolutionary level of 1.79 million barrels per day at the start of 2011, output sank to zero in August of that year, before a rebound to 1.6 million b/d in September 2012 gave a mislead-ing impression of the country’s short-term production prospects. Volumes have ebbed and flowed since then as the country’s civil strife has worsened — Libya is currently producing a mere 220,000 b/d, and with UN-sponsored peace talks continuing, industry observers are asking what level of out-put could be sustainable if a political solution can be found (PIW Nov.24’14). Libya is currently export-ing only from the Bouri and Al-Jurf offshore terminals and the 110,000 b/d onshore terminal at Marsa el-Hariga, although liftings from the latter are coming solely from storage, with another 10 days needed to repair a pipeline to the terminal from the eastern Sarir field, officials with state Arabian Gulf Oil Co. (Agoco) tell PIW. The onshore ports of Melitah and Marsa el-Brega are also available for crude liftings, but are handling little oil due to field shutdowns. The key eastern ports of Es Sider and Ras Lanuf, with com-bined capacity of 600,000 b/d, have been under force majeure since December. Rival governments in Tripoli under former General National Congress leader Omar al-Hassi and the eastern town of Bayda under Prime Minister Abdullah al-Thinni continue to fight for control of Es Sider. Some 800,000 bbl of crude stor-age capacity at the port was destroyed in December, although 3 million bbl remains, and no further destruc-tion has been reported so far this year, oil and maritime sources say.

The view among Libya’s long-term crude customers is that production could climb to 1.2 mil-lion-1.4 million b/d if the UN talks lead to a peace deal between the country’s rival governments. Output did reach 900,000 b/d last year shortly after the lifting of the 11-month militia-led oil block-ade, but questions remain over what is really achievable given concerns over the integrity of reser-voirs at key oil fields and the state of pipeline infrastructure and port facilities, which continue to be targeted by both sides in the civil war (PIW Jun.23’14). Since the blockade was lifted, state National Oil Corp. (NOC) has had no time, amid the various output restarts and stoppages, to carry out a full assessment of damage to surface facilities. In addition to the Sarir to Marsa el-Hariga pipeline and Es Sider storage

tanks, other infrastructure subject to recent attack includes the 120,000 b/d Zawiyah refinery that supplies fuel to Tripoli and a pipeline linking the refinery to Repsol’s 340,000-350,000 b/d El-Sharara field. As for the subsurface, reservoir engineers have concerns that the reservoir of Eni’s 130,000 b/d Elephant field could be fractured, although the field is still producing despite repeated shutdowns last year. Agoco’s fields in the eastern Sirte Basin — home to 80% of Libya’s production — also appear unharmed for now, but engineers are monitoring reservoirs closely.

In the long term, Libya’s biggest challenge will be the lack of investment currently going into the country’s upstream. With a civil war raging, oil policy remains in limbo, and decisions on a new bid round, changes to fiscal terms and oil law reform are being delayed. Any national unity government will need to entice international oil companies against a backdrop of weak oil prices. One positive is that major foreign investors such as Eni and Repsol show no sign of wanting to leave, but many development projects requiring improved or enhanced oil recovery (EOR) techniques are not moving beyond the design

Page 3 www.energyintel.com PIW® February 23, 2015

Libyan Output Remains Stuck on

Roller Coaster

Libyan Oil Output 2011-152,000

1,750

1,500

1,250

1,000

750

500

250

0Jan ‘11 Jul ‘11 Jan ‘12 Jul ‘12 Jan ‘13 Jul ‘13 Jan ‘14 Jul ‘14 Jan ‘15

(‘000 b/d)

Source: PIW estimates

stage. State-owned Waha Oil Co.’s plan to boost output from its Sirte Basin fields by 600,000 b/d has been delayed until the end of 2018, although design work continues. A big problem for NOC had been persuading contracting companies to return to Libya in 2012 after the revolution, and it can expect little foreign technical assistance unless a peace deal is signed (PIW Nov.19’12). Other more entrenched issues concern the state of fiscal terms where in some cases — such as Eni’s Mellitah joint venture with NOC — disagreements over development projects had arisen in 2013 as a result of the lack of specific EOR terms written into old Epsa-IV contracts. Former NOC officials have denied such tensions, however.

Oil and gas companies worldwide are laboring under lower oil prices, but in Russia, where firms are also contending with Western sanctions and a weak ruble, producers are staying calm. None have announced any staff cuts — only Lukoil has said it is not hiring at present — and the talk is mainly of reducing costs by improving efficiency, and fulfilling investment plans even at oil prices of $40-$50 per barrel. But while there is a determination to press on with existing projects, there will inevitably be delays, notably to greenfield developments, LNG schemes and refinery upgrades. All of Russia’s major oil firms say they are planning to maintain dividend payouts, at least in ruble terms, and in their favor, oil production costs are relatively low (PIW Feb.9’15). But companies have also been asking the natural resources ministry to show leniency and give them more time to meet the terms of their exploration and development licenses.

Some companies have been eyeing the government’s rainy-day National Wealth Fund as a potential source of cash, but so far only well-connected independent gas producer Novatek has been promised a handout, securing $2.4 billion toward its Yamal LNG venture. State oil giant Rosneft has applied for government aid for 28 projects, but has so far received nothing. Sanctions-hit Novatek

PIW® February 23, 2015 www.energyintel.com Page 4

Russian Majors Keep Calm and

Carry On

focus on short-term decision-making at the expense of longer-term factors. Just as cuts in explora-tion spending will boost short-term cash flow but harm the longer-term health of a company by not add-ing the new resources and development opportunities that support long-term cash flow, short-term cuts in safety and maintenance budgets can lead to bigger problems further out — cuts to maintenance might mean problems are not spotted and rectified at an early stage and become much more expensive and hazardous to address at a later date.

Secondly, the oil industry has in fact dealt rather poorly with the major safety issue that has emerged since Macondo — crude-by-rail transportation. This has expanded exponentially in North America over the past few years as a flexible means of getting growing onshore oil output to market. But it has also led to one of the biggest oil sector accidents of the post-Macondo years, the Lac-Megantic derailment in Canada in 2013, which left 47 people dead and which highlighted the industry’s reluctance to take responsibility for crude-by-rail safety (PIW Jul.15’13). This was but the worst of a series of crude-by-rail derailments, spills and explosions, but the initial response from oil lobby groups was to blame the railways and resist calls for mandatory retrofitting of aging rail-tank cars ill-suited for carrying highly flammable petroleum through major population centers (PIW Jan.20’14). Stricter rules for rail-tank cars are now in place, but accidents are still happening, with two derailments and fires in the past week in West Virginia and Ontario.

What both Macondo and Lac-Megantic highlighted is that the industry’s talent for money-spinning innovation — whether in the exploitation of existing infrastructure or the development of new technology — often runs ahead of its grasp of the safety and risk implications. Even in the face of the short-term pressures created by low oil prices, the oil and gas industry needs to maintain its long-term focus and integrate safety into technological progress. It cannot afford not to — oil and gas companies are facing “social license” pressures on a number of fronts and cannot risk another set of negative headlines over a new safety failure (PIW Nov.25’13). Social license pressures are sure to intensify this year in the run-up to December’s UN climate talks in Paris, which will provide a focal point for anti-fossil fuel lobbyists. Oil companies’ grasp of these issues is improving, as the engagement of com-panies like Royal Dutch Shell and Statoil on the question of Arctic drilling has shown, but there is still much to do. Despite occasional successes such as last year’s campaign in Colorado, the industry has strug-gled to win the public argument over the environmental dangers of hydraulic fracturing, with the result that the shale drilling technique is now banned in a number of jurisdictions (PIW Jun.16’14).

This is the first in a series of articles that PIW will be running in connection with the five-year anni-versary of Macondo, looking at the accident’s lasting impact on the oil and gas industry.

(Continued from p.1)

Low Oil Prices Create New

Safety Challenges

remains confident of bringing Yamal on stream in 2017. Some $8 billion has already been invested in the $27 billion project, and this year’s budget envisages another $8 billion. The main source of outside funding will probably be Chinese banks, which will be encouraged by Moscow’s financial support (PIW Jan.19’15).

Even without government help, Rosneft says it will be able to fulfill its 2015 invest-ment program even with oil prices at $50/bbl. But the company has asked for exten-sions of up to two years on 12 of its 48 offshore licenses, saying some of the work can-not be done in time because of the sanctions-related departure of foreign partners. Rosneft is also pursuing self-help, looking to trim 10% from annual operating costs by bringing drilling services in-house. Rosneft boss Igor Sechin says investment outlays this year will be down by some 30% in dollar terms versus 2014 but around the same as the 730 billion rubles budgeted for last year — this would have been equivalent to $19 billion when the plan was announced last June, but only $11 billion now due to the sharp fall in the ruble. Analysts say actual spending last year was not more than 600 billion rubles.

State gas giant Gazprom is likely to see delays beyond 2020 for its various LNG schemes, including the expansion of the Sakhalkin-2 plant and the new Vladivostok LNG and Baltic LNG ventures. This year, at least, it’s business as usual — Gazprom says it can deliver this year’s 840 billion ruble ($13.5 billion) investment plan even with oil at $40/bbl, meaning major projects such as the Power of Siberia gas pipeline to China will go ahead (PIW May26’14).

The Russian producer best placed to weather the current storm is, ironically, that old Soviet relic Surgutneftegas. The company has never borrowed from the West and operates mainly conventional onshore fields, meaning it is less susceptible than its peers to both lower oil prices and constraints on access to Western capital and technology. A massive cash pile most recently estimated at $35 billion also gives it great financial flexibility. Private-sector producer Lukoil has insisted it will not need state aid and will proceed with its 2015 investment plan unchanged — although those spending plans were trimmed back in August last year, before oil prices began plunging. Gazprom Neft has also announced no changes to its 2015 investment plan.

The Carnaval celebrations that raged through Brazil last week traditionally give way to a period of moderation, penitence and soul-searching, and that should fit nicely with the mood at Petrobras, where the appointment of new Chief Executive Aldemir Bendine has been deemed an intervention of sorts to fix a deepening financial scandal that threatens to undo not just the state-controlled oil giant, but the government of President Dilma Rousseff. By choosing Bendine, a career banker with virtu-ally no oil and gas experience, to head one of the world’s largest oil companies, Rousseff has made clear that the top priority is to get Petrobras’ financial house in order, while leaving core upstream operations in the more capable hands of veteran Petrobras technocrats. Bendine’s appointment has provoked contrasting responses, reflected in the fact that all three of the company’s nongovernment-appointed board members voted against his selection. Although an industry outsider, Bendine holds close ties to Rousseff from his previous tenure as head of state banking giant Banco do Brasil, and therefore does not represent the clean break with the past that Petrobras needs. But with no direct ties to the company itself — or to the oil sector, for that matter — he is in a better position to clean up Petrobras’ accounts and start producing timely financial statements again (PIW Feb.9’15).

Bendine’s first job will be to produce by the end of April full-year financial statements that include transparent and credible write-downs for those allegedly inflated assets at the center of the scandal. This is needed to avoid an acceleration of certain debt repayments, and a massive one-off write-down would in theory be best for all parties. Investors appear more willing to stomach a large lump-sum loss than more prolonged uncertainty, while a sweeping purge of the company’s finances will lend credibil-ity to Bendine’s housecleaning efforts. Petrobras has previously suggested that impairment charges could be as high as 61 billion reals ($21.5 billion), but has not officially endorsed those figures, saying they were subject to other variables. Indeed, the inability of former CEO Maria das Gracas Foster’s team to quantify the company’s corruption exposure in recent third-quarter statements contributed to their loss of credibility and ultimate demise. Many expect Bendine to work in closer consultation with auditors, the US Securities & Exchange Commission and its Brazilian counterpart, the CVM, to arrive at more concrete figures.

Bendine takes charge early on in a year in which upstream operations should be on virtual cruise control, with only one new production unit slated to come on line. This should allow him to devote significant time and resources to financial and accounting issues, but as this month’s fatal blast on a Petrobras floating production, storage and offloading (FPSO) vessel in the Espirito Santo Basin shows, events have a way of interfering with such plans (PIW Jan.19’15). Six people are confirmed dead

Page 5 www.energyintel.com PIW® February 23, 2015

Petrobras Cleanup Lent Credibility

By Bendine

Russia’s Top Oil Producers

2014 Crude Production*Company (‘000 b/d) 2014 Investments†

Rosneft 4,120 730 billion rublesLukoil 1,952 $16 billionSurgutneftegas 1,234 NAGazprom Neft 1,060 334 billion rublesTatneft 533 74 billion rublesBashneft 360 50 billion rubles

*Including outside Russia and by joint ventures. †Planned investments. Source: Company reports

and three more are missing following the Feb. 11 explosion on the Cidade de São Mateus FPSO, creat-ing an immediate crisis for Bendine to deal with just days after taking on his new role.

Bendine may turn out to be something of a caretaker boss for Petrobras — someone brought in to do a specific job, and then replaced once it is done by a successor more suited to managing the operational and strategic challenges that lie ahead. While the main focus this year will be on ramping up output from existing platforms, 2016 marks the start, at least based on current plans, of a drive to bring some 30 new projects on stream before the end of the decade. That plan will inevitably be altered, however, because of Petrobras’ current restricted access to debt markets, scandal-related penalties and lower revenues from oil sales.

New refining capacity additions are expected to add around 300,000 barrels per day to the gasoil supply available from Asia and the Middle East this year, volumes which only one market — Europe — seems even remotely capable of absorbing. It’s far from a perfect fit, however. Projections for growth in European gasoil consumption this year are largely based on a widely expected but far from certain increase in demand from shippers obliged to switch from bunker fuel to marine gasoil under the region’s new Emission Control Area (ECA) regulations. But this will create demand for relatively low-spec product, rather than the ultra-low-sulfur gasoil that new export refineries in the Mideast will be manufacturing. The ramp-up of Saudi Arabia’s new 400,000 b/d Yasref refinery and Abu Dhabi’s 417,000 b/d Ruwais refinery expansion will add a combined 380,000 b/d to the Mideast’s gasoil output, and will increase the region’s gasoil surplus by 200,000 b/d this year, consultancy FGE calculates (PIW May19’14). The ramp-up of the 300,000 b/d Paradip refinery is also expected to indirectly boost Indian gasoil exports by up to 40,000 b/d this year, while net exports from China could increase by 20,000-70,000 b/d this year, analysts estimate, thanks to sluggish domestic demand and additions to refining capacity (PIW Sep.1’14).

There is little chance of an already oversupplied Asia-Pacific market soaking up these addi-tional volumes (PIW Aug.18’14). Major buyer Indonesia’s imports are likely to be broadly flat this year, while the 30,000 b/d increase in Australian gasoil import needs following this year’s closure of BP’s 102,000 b/d Bulwer Island refinery could be easily met by rising volumes from India. Taiwan’s gasoil exports could be trimmed by up to 40,000 b/d this year following the shuttering of Chinese Petroleum Corp.’s Kaohsiung refinery, FGE suggests, but Taiwanese sources believe volumes will hold steady as the firm increases runs at its two remaining refineries.

That leaves Europe as the most obvious outlet, despite the mismatch between the 0.1% sul-fur gasoil stipulated under new ECA rules, and the higher-spec 10 parts per million (ppm) sul-fur content material that the Mideast’s sophisticated new export refineries are geared to pro-duce. The other unknown is the extent to which shippers actually make the switch to marine gasoil, given often lax enforcement of ECA regulations. This could substantially reduce pro-jected demand growth, acknowledges consultancy Wood Mackenzie, which sees ECA-related increases accounting for 150,000 b/d out of a projected 220,000 b/d jump in European gasoil demand this year. FGE sees ECA-related demand playing an even more important role, contributing 150,000-200,000 b/d to the overall increase. Beyond the ECA effect, little organic gasoil demand growth is likely due to Europe’s sluggish economy. This non-ECA demand growth of perhaps 50,000 b/d or so is likely to be for 10 ppm gasoil, but the Mideast can expect competition for these buyers from Russia, where recent refinery upgrades are likely to add around 50,000 b/d to gasoil output this year. Russian gasoil exports should be further boosted by weak domestic demand and the expansion of the pipeline to the Baltic Sea port of Primorsk.

The only other major market that could soak up some of the incremental volumes from Asia and the Mideast is Africa, where analysts are expecting gasoil demand to rise by at least 60,000 b/d in 2015. US gasoil exports are expected to fall this year, due to new North American ECA rules, but this will be offset by higher volumes from Brazil. FGE sees African gasoil demand growing by 4% or 60,000 b/d this year, split evenly between the northern and sub-Saharan regions, but African oil consultancy Citac is more bullish, forecasting 8% demand growth in sub-Saharan Africa. Power genera-tion problems and the country’s old, inefficient refineries could boost South Africa’s import needs, with FGE expecting a 10,000-20,000 b/d increase this year. The East African market mostly switched to 50 ppm gasoil last year, a move that makes the region a more obvious outlet for the Mideast’s low-sulfur output. Analysts see the US’ gasoil surplus being trimmed by 100,000-140,000 b/d this year thanks to increased local demand linked to new ECA rules, but in Latin America — a key market for US gasoil exports — Petrobras’ new 230,000 b/d Abreu e Lima refinery will add 100,000 b/d to supply.

PIW® February 23, 2015 www.energyintel.com Page 6

Can Europe Absorb Global Gasoil Surge?

COUNTRIES

CHINA — The National Development and Reform Commission (NDRC) will allow inde-pendent refiners with at least one crude distilla-tion unit with capacity of over 40,000 b/d to apply for crude oil import quotas, somewhat liberalizing what is a state oil firm-dominated business. To be eligible, refiners must shut any sub-40,000 b/d units and will not be allowed to import more than their overall capacity, the NDRC said. The development is a boost for the country’s celebrated independent “teapot” refiner-ies, which now have real hope of gaining access to imported crude instead of their usual fuel oil feed-stock. Only well-connected teapot refiners have hitherto been able to secure crude import quotas, as Beijing remains keen to eliminate marginal refining capacity despite its key policy objective of opening up the economy to private capital (PIW Dec.23’13). Analysts said the NDRC’s timing was shrewd, since teapot refiners would pose little threat to state-run majors while the country’s prod-uct market remained oversupplied.

CHINA — Analysts have reacted with skepti-cism to reports that Beijing is considering a merger involving some of the country’s state oil giants, arguing that any such tie-up may in fact stifle competition and obstruct energy sector reform, rather than deliver the greater effi-ciency the government seeks. A report last week in the Wall Street Journal suggested that Beijing advisers were conducting a feasibility study involving a potential marriage of PetroChina, the listed arm of China National Petroleum Corp., with Sinopec, or a combination of China National Offshore Oil Corp. and Sinochem. This is not the first time the idea has been floated but previous proposals have been shelved due to strong opposi-tion from the companies themselves. Combining PetroChina and Sinopec, with a total workforce of 2.5 million, would inevitably result in job cuts and could lead to social instability, analysts noted, a sit-uation Beijing would be keen to avoid.

EAST TIMOR — Australia’s Woodside Petroleum has effectively put plans to develop the long-stalled Sunrise LNG scheme on the back burner and will cut capital spending this year in response to the oil price slump. The independent has been locked in a dispute with the East Timor and Australian governments over options for developing the project, which involves fields straddling the two countries’ mari-time boundary. While operator Woodside and its partners support a floating LNG scheme, East Timor favors an onshore development that would bring jobs and revenues (PIW Jun.10’13). It was difficult to justify spending money on Sunrise in the short term until there was more certainty on the development plan, maritime boundaries and the regulatory and fiscal framework for the scheme, Woodside CEO Peter Coleman said.

IRAN — Oil Minister Bijan Zanganeh has urged parliament to bolster his ministry’s abil-ity to fund the development of joint oil and gas fields Iran shares with its neighbors — a prior-ity goal for the government of President Hassan Rohani — and warned that investment in the forthcoming Iranian year may otherwise be nonexistent (PIW Sep.29’14). Zanganeh gave a frank assessment of oil revenues for the new Iranian year, which begins in March. Revenues have been hit by the dual pressures of lower oil prices and Western sanctions against Tehran, which have halved crude exports from 2.4 million b/d in 2011. At stake is whether lawmakers vote to approve a budget amendment that would allow the oil ministry to raise around $1.8 billion from public bonds and permit loans of up to $4.8 billion from the National Development Fund to help rein-vigorate the country’s beleaguered oil industry. Zanganeh said the country needs to invest more heavily in the oil industry and that the ministry’s share of oil receipts needed to be increased from 14.5% to 30% to help provide sufficient funds for priority developments.

NETHERLANDS — Royal Dutch Shell, Exxon Mobil and the government have been criticized in a new report into the causes of historic earth-quakes affecting homeowners in the vicinity of the giant Groningen gas field. NAM, the Shell/Exxon joint venture which operates the field, and the economy ministry “failed to act with due care for citizen safety in Groningen with regard to earth-quakes caused by gas extraction” prior to 2013, the Dutch Safety Board said in its report, which covers the period from 1959 to 2014. NAM announced at the start of 2014 that production from Groningen would be reduced for three years because of earth tremors and subsidence associated with the field’s operations (PIW Jan.27’14). The worst quake, in August 2012 in the village of Huizinge, registered at 3.6 on the Richter scale.

NORWAY — Statoil is proceeding with plans to develop the giant Johan Sverdrup oil field despite current low oil prices and industry-wide cuts to capital spending that are making major oil companies rethink some megaproj-ects. Statoil has now formally delivered a devel-opment plan for the North Sea project to the oil and energy ministry in Oslo, envisaging full field development costs of $22 billion-$29 billion and recoverable resources at between 1.4 billion-2.4 billion boe. The field’s economics are “robust at current oil prices,” Statoil CEO Eldar Saetre said. Statoil said Phase 1 of the project will have output capacity of 315,000-380,000 boe/d, with first oil scheduled to come on stream by late 2019. Fully developed, the field could produce 550,000-650,000 boe/d, the company believes (PIW Nov.10’14). Consultancy Wood Mackenzie esti-mates the field will cost $31 billion to develop and produce 600,000 boe/d at peak, with a $41/bbl breakeven Brent price.

RUSSIA — In search of cash last week to pay some $7.15 billion owed for loans taken out to fund the acquisition of TNK-BP two years ago, state oil giant Rosneft had to offer addi-tional February crude volumes to trading house Trafigura on advanced payment terms. Rosneft must have received around $140 million from Trafigura for the additional crude, traders calculate, but the deal shows how difficult debt repayment has become for the state firm. Rosneft gave Trafigura the right to choose preferred load-ing dates, angering other regular offtakers. It remains to be seen if this affects how traders bid for volumes under Rosneft’s new six-monthly crude tender announced last week. Rosneft is offering up to 14.42 million tons to be lifted between April and September. The state firm has now repaid the entire $24.6 billion in two-year loans provided by international banks in 2013. The remaining $31 billion borrowed was taken out for five years (PIW Jan.13’14).

UGANDA — The government has chosen Russia’s RT-Global Resources as its partner for the construction and operation of a refin-ery linked to the stalled development of an estimated 1.7 billion bbl of recoverable reserves in the Lake Albert Basin. The Russian consortium beat out a rival offer from a group led by South Korea’s SK Engineering & Construction. Plans call for the 60,000 b/d refin-ery, a 205 km product pipeline and an oil terminal to be developed as a public-private partnership, with the private investor taking 60% of the equity and Kampala 40%, some of which it proposes to share with neighbors Kenya and Rwanda (PIW Jun.9’14). But financing the estimated $3 billion project with a Russian lead partner could be chal-lenging amid expanding Western sanctions over the crisis in Ukraine, industry sources say, although lower construction costs related to the fall in oil prices may help reduce the ultimate price tag for the refinery.

YEMEN — Canadian minnow TransGlobe Energy has become the third oil producer to relinquish producing assets so far this year, reiterating other companies’ concerns about rising costs and security risks and increasing the likelihood of further departures. TransGlobe is relinquishing its 13.81% interest in producing Block 32 and its 20% stake in exploration Block 72. Both assets are located in Hadramawt, one of the beleaguered country’s key oil-producing regions. Dubai-based Dove Energy and state China National Offshore Oil Corp.’s Nexen sub-sidiary have also recently announced that they would be relinquishing their nearby blocks in the same region (PIW Feb.16’15). The “contin-ued and deteriorating risk profile” forced TransGlobe to write down the value of its Yemeni assets to zero, resulting in a noncash impairment of $51.5 million against its fourth-quarter earnings.

What’s New Around the World

PIW® February 23, 2015 www.energyintel.com Page 7

($/barrel) Feb 16- Feb 9- Jan 19-Spot Crude Feb 18 Feb 13 Jan 23Opec Basket $56.65 $53.55 $43.38UK Brent (Dtd.) 61.01 56.56 46.48US WTI (Cushing) 52.80 51.09 46.42Lt. Louisiana Swt. 57.65 55.32 47.72Nigeria Bonny Lt. 62.28 57.66 46.93Dubai Fateh 58.57 55.36 44.48US Mars 53.62 51.18 43.47Russia Urals (NWE) 60.01 55.45 44.87Oman 58.77 56.71 46.74ESPO 60.70 58.39 47.30

Crude FuturesBrent 1st (ICE) 61.49 57.60 48.63Brent 2nd (ICE) 62.18 58.87 49.81B-wave (ICE) 61.47 57.70 48.97WTI 1st (Nymex) 52.84 51.14 46.52WTI 2nd (Nymex) 53.56 52.04 47.05Oman 1st (DME) 59.38 56.55 45.74Oman 2nd (DME) 59.47 57.26 46.77

Forward SpreadsBrent (1st-Dtd.) +$0.47 +$1.04 +$2.15Brent (2nd-1st) +0.70 +1.27 +1.18WTI (2nd-1st) +0.72 +0.90 +0.53WTI (3rd-2nd) +1.19 +1.24 +0.84Oman (2nd-1st) +0.09 +0.72 +1.04Oman (3rd-2nd) +0.80 +0.96 +1.16

Grade DifferentialsWTI-Brent (1st) -$8.65 -$6.46 -$2.12WTI-LLS -4.85 -4.23 -1.30WTI-Mars -0.83 -0.09 +2.95Brent(Dtd)-Dubai +2.45 +1.19 +2.00Brent(Dtd.)-Urals +1.00 +1.11 +1.61Brent(Dtd.)-Bonny Lt. -1.27 -1.10 -0.45

Term Crude FormulasArab Lt.-US (cif) $55.27 $52.83 $45.72Arab Lt.-Europe (Med) 57.37 53.60 46.97Arab Lt.-Far East (fob) 57.27 54.64 43.61Nigeria Bonny Lt. 61.34 56.89 47.13

Arab Light Gross Product WorthRotterdam $63.03 $61.61 $50.73US Gulf Coast 62.63 62.19 50.29Singapore 64.61 61.87 51.40

Gross Product Worth & MarginsRotterdam UK Brent GPW $64.51 $63.44 $52.99 UK Brent Margin +2.70 +6.03 +5.19US Gulf Coast Mars GPW 60.64 60.15 48.41 Mars Margin +6.92 +8.88 +4.84Singapore Oman GPW 64.51 61.68 50.98 Oman Margin +4.50 +3.68 +2.79US Nymex WTI 3-2-1 Crack +$19.01 +$19.41 +$13.65

Refined ProductsRotterdam ($/ton) Eurobob Gasoline $557.00 $548.20 $450.20 Gasoil (0.1%) 570.25 555.80 468.15 Fuel Oil (1%) 299.67 286.00 244.20US Gulf Coast (¢/gal) RBOB Gasoline 157.18¢ 157.72¢ 126.29¢ ULS Diesel 186.37 182.26 152.07 Fuel Oil (0.7%, $/bbl) $61.58 $59.29 $46.69Singapore ($/bbl) Naphtha $59.01 $57.17 $46.08 Gasoil (0.05%) 74.23 71.55 61.25 Fuel Oil (3.5%, $/ton) 368.32 347.63 278.30

Latest week’s data are preliminary. For GPW and margin calculations, see Refining Profitability Methodologies on the Energy Intelligence website in Reference Tools Publication Methodologies. Spot prices from Thomson Reuters. Opec basket source, Opecna. 3-2-1 crack spread for 3 parts crude, 2 parts gasoline, and 1 part heating oil. PIW Numerical Datasource subscribers can download all indicators in Excel worksheets.

PIW Market Indicators

WASHINGTON — With so much attention on the fall in crude oil prices — after recently trading above $63 per barrel, Brent was back around $59/bbl as PIW went to press — there’s been much less scrutiny of products. US gasoline, however, could provide support for oil prices during the spring, although any upside is likely to be modest.

US gasoline consumption is expected to grow by a healthy 100,000 barrels per day this year, according to PIW esti-mates, amid strong economic growth and lower pump prices. Speculators are poised to con-tinue building length, but the upward trend in domestic inven-tories, not unlike the situation in the US crude market, should cap the upside (PIW Feb.16’15).

The front-month March Nymex RBOB futures contract, now around $1.51 per gallon, is trading some 40¢ under its counterpart diesel contract, which has been boosted by extended cold weather lifting heating oil demand in the key US Northeast market. RBOB’s discount is a sign of how fragile the gasoline market is, despite the optimistic demand outlook and investors’ buying ahead of the peak spring and summer driving season. Although the differential between the two products nar-rows after March, the forward curve shows diesel holding a premium to gasoline for the entire year, another sign of gas-oline’s weakness. Nymex RBOB’s crack spread to Brent is a modest $5.80/bbl, compared with around $22.60/bbl for Nymex diesel, further indicat-ing that most support from the product side is coming from the middle of the barrel.

US gasoline inventories, which are now

up 10 million bbl year-on-year and at their highest level since 1990, typically peak in February during refinery maintenance. But given that any stockdraw will be from such high levels, it is almost guaranteed that gaso-line will be well-supplied throughout the driv-ing season, particularly with refiner flexibility improved by holding high stocks of crude.

Speculators are none-theless getting excited about seasonal factors supporting RBOB futures, namely re-finery maintenance and the expected pickup in demand in the second and third quar-ters. But it’s unclear how high they can take prices given the fundamental situa-tion. Speculators in Nymex RBOB futures and options are net long by about 54,000 contracts, the high-est level since July and up by about 45% since mid-

January, when the front-month contract bot-tomed out at $1.2265/gallon. But they are still some 29,000 contracts below the net length

peak seen last May.Last year, from the end

of winter through the begin-ning of spring, US gasoline stocks fell by about 25 mil-lion bbl, or close to 10%. A similar pattern could play out this year, albeit from a higher starting point. Demand is now up by more than 300,000 b/d year-on-year, an encouraging sign for higher prices down the road, but the upside is nonetheless limited. Both production and imports are also above year-ago levels,

and with the US exporting more distillate fuel than gasoline, domestic supply will be plentiful. Speculators are likely to be liqui-dating their long positions before summer has even arrived.

Limited Upside

Marketview

Page 8 www.energyintel.com PIW® February 23, 2015

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Join us in congratulating Rex Tillerson, Chairman and CEO of Exxon Mobil, the 2015 Petroleum Executive of the Year, at a dinner in his honor on October 6.

2015 PETROLEUM EXECUTIVE OF THE YEAR

($/bbl)Prompt Crude Oil Prices

Jun Aug Oct Dec Feb

ICE BrentDME OmanNymex WTI

130

115

100

85

70

55

40

($/MMbtu)

Nymex Prompt HH Natural Gas vs. NYH ULSD

Jun Aug Oct Dec Feb

Natural GasNYH ULSA

5.0

4.5

4.0

3.5

3.0

2.5

(¢/gal)310

280

250

220

190

160