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In Petroleum Argus
BP loans create 'buffer'
BP is borrowing $5bn backed by its crude production as it seeks further financial flexibility to meet uncertain liabilities from the Macondo oil spill in the Gulf of Mexico.
The loans are a new funding avenue, creating “a liquidity buffer in order to ensure that BP has the flexibility to meet all of its future financial obligations”, BP says. The production-backed financing method “creates further flexibility, in addition to more conventional debt financings such as corporate lending or project finance structures”.
BP launched the syndication of two five-year term loans backed by future crude production on 16 August. It mandated European banks Societe Generale and Royal Bank of Scotland as lead arrangers for a $2bn five-year amortising term loan facility for BP Caspian, backed by crude produced from the company's 34pc operated stake in the Azeri-Chirag-Guneshli (ACG) deepwater field offshore Azerbaijan. BP produced 94,000 b/d of crude from ACG in 2009, and on 16 August closed a $2bn deal to acquire a 3.3pc stake in the project from US independent Devon Energy, adding another 10,000 b/d of production (WPA, 15 March, p3).
European banks BNP Paribas and Standard Chartered are arranging a $3bn five-year loan for BP, maturing on 30 June 2015, based on sales of Angolan crude. BP produced 211,000 b/d of crude from Angola in 2009. Commitments for both loans are due on 13 September, and they are scheduled to be signed before the end of next month, the banks say.
Reporting second-quarter results on 27 July, BP said it had $7bn in cash and $17bn in undrawn bank facilities, up from $5bn at the end of the first quarter. BP chief financial officer Byron Grote said BP was “comfortable that it may be able to draw on these lines in the future, although we have no intention to draw on them at the moment”.
BP's second-quarter cash flow was $8.9bn, up by 31pc from a year earlier as a result of higher crude prices and greater operating efficiencies, and BP says it retains a strong financial position. But the additional $5bn in funding indicates that BP remains highly uncertain of its potential liabilities from Macondo. BP says the loans are part of its “prudent approach” to managing its balance sheet and financial liquidity. BP is selling $25bn-30bn of assets — equivalent to 8-12pc of its production — over the next 18 months, “removing any worry about our financial position”, chairman Carl-Henric Svanberg says (WPA, 2 August, p2). Svanberg says the accelerated divestments are “not a reflection of any sort of speculation that potential costs could go higher”.
But BP is yet to clarify whether it will be adjudged to have been grossly negligent under the Clean Water Act. If gross negligence is proved, initial calculations of fines of $5.4bn could rise to $21bn (WPA, 9 August, p5). BP is already pledging revenue from its producing US oil and gas assets as collateral for payments to the $20bn escrow fund created to meet claims from the spill, into which it will pay $5bn this year. It faces nearly 300 civil lawsuits along with a federal lawsuit from the state of Alabama, seeking damages for economic losses, response and remediation costs and punitive damages.
Time for prudence
As liabilities mount, BP aims to reduce its net debt to $10bn-15bn from $23bn in the next 18 months. Of its gross debt of $31bn, $8.3bn is due for repayment within the next 12 months, and will be repaid through cash flow or replaced by new debt issuances. “With some uncertainty about what the liabilities are going forward, we believe that it is now prudent to run with a lower level of debt,” Grote says.
BP says it is well placed to meet financial obligations and is not shifting its strategy to match short-term views on liabilities. But it acknowledges that it must reduce debt to ensure that its balance sheet remains resilient. Cutting debt “does not reflect a view that the risks have suddenly changed”, Grote says. “It is reflecting the fact that we have uncertainty as to the liabilities that we are going to have to face over the course of the next few years in the US.”
In Argus Global Markets
Azeri long-haul shipments slump
Long-haul shipments of Caspian light sweet BTC Blend crude have been falling this year because of higher freight rates and rising demand from European refiners.
Asia-Pacific and North American buyers took less than 160,000 b/d of July-loading BTC Blend, 240,000 b/d lower than a year earlier. Total long-haul shipments were just 250,000 b/d in the first half of 2010, compared with over 400,000 b/d a year earlier (see graph).
The drop in long-haul shipments of BTC Blend — which is around 90pc Azeri Light crude combined with Azeri Shakh Deniz condensate — largely reflects lower purchases by Asian refiners. The grade's main Asia-Pacific customers include India's IOC and Bharat Petroleum, and Thailand's PTT — which buys the crude for Indonesia's state-owned Pertamina. Pertamina runs the crude at its 260,000 b/d Balikpapan refinery.  The Azeri blend must generally trade below Malaysian Tapis for shipments to Asia-Pacific destinations to be economic.
Rising freight rates have also deterred some Asian buyers. The cost of shipping a 1mn bl crude cargo to Singapore from the Mediterranean basin was $3.5mn in the first half of 2010, up by around 25pc on a year earlier.
Demand from North American refiners — key transatlantic buyers include Sunoco and Valero — has also been lower this year, although this was mostly when production was limited in the first quarter. The Tengizchevroil consortium halted exports of up to 50,000 b/d of Tengiz crude along the Baku-Tbilisi-Ceyhan pipeline route in January because of a dispute over transit costs. There were also Azeri Light production disruptions.
Production increases have since offset most of the previous declines. And the introduction of 40,000 b/d of Turkmen crude to BTC Blend in July-August means that exports are likely to be higher in the second half of the year. BTC Blend loadings from the Turkish port of Ceyhan will rise to 815,000 b/d in September, 50,000 b/d higher than scheduled August shipments.
Firm demand from Mediterranean refiners continues to support the grade, despite rising supplies. BTC Blend has been trading at $2.30/bl above benchmark North Sea Dated on average so far this month, more than 70¢/bl higher than the market a year earlier.
In Argus LPG World
Japan has new supply giant
A giant LPG joint venture linking Japanese companies JX Energy, Mitsui and Marubeni is the latest in the wave of consolidation in Japan.
Japanese oil firm JX Energy and trading houses Mitsui and Marubeni are combining their LPG operations just two years after Mitsui and Marubeni joined forces in the sector.
The joint venture is expected to sell 3.63mn t/yr of LPG domestically in its first year of operation. This will make it the largest supplier in Japan, exceeding top supplier Astomos Energy's sales of 3.5mn t/yr. Astomos Energy is a joint venture company comprising refiner Idemitsu and trading house Mitsubishi. JX imports 1.57mn t/yr of LPG, while Mitsui Marubeni Liquefied Gas (MLG) imports 1.59mn t/yr.
The new joint venture LPG firm will begin combined operations by the end of March next year, consolidating the three firms' import, wholesale and retail businesses. JX will take a 50pc share of the new and as yet unnamed company, Mitsui will hold a 30pc share and Marubeni a 20pc share.
On trend
The merger continues the long-term trend of rationalisation in Japan's domestic LPG sector in the face of poor margins and tough competition. The number of Japanese firms importing LPG has shrunk in the past decade to around nine from more than 20 in the late 1990s. And Japanese importers still struggle to cut costs and secure viable margins in the shrinking market.
The JX-Mitsui-Marubeni merger will help rationalise the LPG supply and logistics chain from bulk import to domestic retailing, the three firms say. This should improve the profitability of their combined LPG business. And the new firm aims to invest in developing new energy technology such as LPG-powered fuel cells.
Tricky merger
This latest consolidation has not proved as straightforward as the merger of other Japanese LPG operations, given the complex networks of joint ventures already in place.
JX Energy only started up in July under its parent company, JX Energy Holdings. And the latter was created just three months earlier, when Japanese refiner Nippon Oil and oil company Japan Energy's parent firm, Nippon Mining, merged.
Japan Energy in turn created the LPG joint venture Japan Gas Energy last year with four other partners - town gas firm Osaka Gas and its LPG subsidiary Nissho Petroleum Gas, trading house Itochu and oil wholesaler Itochu Enex. Japan Energy holds a controlling 51pc stake in Japan Gas Energy.
JX has not decided if it will fold Japan Gas Energy into the latest joint venture with MLG or leave it operating on its own. "We just can say that we will continue discussions about the issue," a company spokesman says.
In the latest issue of Argus LatAm Energy
PdV and Sonatrach agree gas and LNG tie-up
Venezuela's state-owned PdV and its Algerian counterpart Sonatrach have signed an initial agreement covering joint-venture opportunities in offshore natural gas production and LNG exports from east Venezuela, official news agency AVN reported on 9 August.
Sonatrach may take a 10pc stake in a joint venture integrating offshore gas production from PdV's Mariscal Sucre project with the second of three LNG trains that PdV plans to develop as separate joint ventures under its Delta Caribe LNG export initiative.
The Mariscal Sucre project covers the development of 1.2bn ft³/d (12.4bn m³/yr) of offshore non-associated gas production and 18,000 b/d of condensate from the Dragon, Patao, Mejillones and Rio Caribe fields located north of the Paria peninsula in eastern Venezuela ( ALE, 28 July, p6 ). The four gas fields hold over 7 trillion ft³ (200bn m³) of reserves. PdV's externally audited 2009 annual report costs the project at over $10.8bn.
PdV's Delta Caribe LNG train 2 would have a capacity of 4.7mn t/yr of LNG, and would be located at the proposed Gran Mariscal de Ayacucho industrial gas complex (Cigma) near the town of Guiria in Sucre state.
PdV signed separate agreements in 2008 with foreign oil companies to build three LNG trains at the complex with a processing capacity of 4.7mn t/yr each, or 14.1mn t/yr of LNG for export. PdV estimates the total capital expenditure for its three planned LNG trains at over $10bn.
LNG train 1 was to be developed by a joint venture comprising PdV (60pc), Portugal's Galp (15pc), Qatar's state-owned QP (10pc), Chevron (10pc) and Japanese tie-up Mitsubishi-Mitsui (5pc).
LNG train 2 would be developed by a joint venture comprising PdV (60pc), Galp (15pc), Argentina's state-run Enarsa (10pc), Japan's Itochu (10pc) and Mitsubishi-Mitsui (5pc).
A joint venture comprising PdV (60pc), Italy's Eni, Malaysia's state-owned Petronas, Portugal's EdP and Russia's state-controlled Gazprom would develop LNG train 3.
Gas would come from offshore fields that PdV is developing under its Mariscal Sucre and Deltana platform projects, and from the Blanquilla and Tortuga offshore blocks.
The energy ministry officially designated these foreign companies as strategic allies when the LNG agreements were signed in 2008. But three consecutive invitations by PdV for bids in November and December last year, and January 2010 failed to attract a single bid.
Diving for pearls
PdV opted to develop Mariscal Sucre's offshore gas project by itself with the Aban Pearl semi-submersible drilling rig leased from India's Aban Offshore. But the rig sank on 13 May and a substitute drilling rig has not yet arrived in Venezuela ( ALE, 19 May, p8 ).
PdV does not have the financial capacity or offshore operational experience to develop Mariscal Sucre on its own. A joint-venture agreement with Sonatrach would be an important step forward for PdV's plans. Once a firm joint-venture agreement is signed, other foreign companies will show more interest in joining an integrated project, senior PdV officials say.
But a potential deal breaker for Sonatrach could be the energy ministry's insistence that 100pc of Venezuela's local gas demand must be supplied before any offshore gas is exported as LNG. Mariscal Sucre's peak gas production capacity is estimated at 1.2bn ft³/d after 2016. But Venezuela's gas deficit is around 3bn ft³/d.
This month in Argus China Petroleum
Gas tipped to gain from new five-year plan
The Chinese government is expected to release the country's next five-year plan by October.
Proposals to increase dramatically the amount of energy derived from renewable sources will be a central feature of the 12th five-year plan, which will lay out development targets for the country's oil, petrochemical, power, coal and renewable energy sectors in 2011-15.
The government aims to reduce emissions and improve energy conservation. It wants non-fossil fuel energy to make up 15pc of the country's primary fuel mix by 2020 and clean energy to account for 30pc of the power generation mix. And Beijing wants to reduce coal's share of the power generation fuel mix to 63pc from more than 70pc last year.
This is likely to require encouraging utilities to switch from burning coal to gas. China's gas demand is about 110bn m³/yr. Beijing aims to double gas' share of the primary energy mix to 8pc by 2015 and 10pc by 2020 from 4pc through further gas price liberalisation. But there are few firm plans in place for effecting a switch to gas. Government policy - as recently as June, when gas prices were raised for the first time in five years - has tended to discourage power plants from burning gas.
Crude knock-on
The plan will firm up targets for the oil sector. The government wants oil firms to build large-scale, 400,000 b/d refineries in the Pearl and Yangtze river delta mouths and in the Bohai bay economic zone.
Oil companies are lobbying to get their plans included in the document. They have proposed building new refineries with a combined capacity of 4.4mn b/d. But the government is unlikely to approve all of these, because it suspects refining capacity may be leaping ahead of demand. Refineries must have a capacity of more than 120,000 b/d to gain approval, as the government considers small plants inefficient. Most of the refineries proposed by state-owned firms will be larger than this, having on average 200,000 b/d of throughput capacity, but smaller than those favoured by the government.
Infrastructure push
The government is pressing oil firms to improve their networks of pipelines for transporting oil products. Efforts to improve supply chain logistics have become a feature of companies' recent strategies. PetroChina had laid 13,200km of crude pipelines by the end of last year, up by 19pc from 2008. But its oil product pipeline network grew by more than 200pc last year to 8,900km.
Beijing has been promoting national self-sufficiency in refining. The government wants about 80pc of the naphtha used for petrochemicals to be sourced domestically by 2015. But it remains highly concerned about the country's dependence on crude imports.
Official forecasts put China's crude import dependency at 55pc by 2015. But almost 54pc of China's crude this year has come from imports and dependency rose to almost 57pc in April. Some government analysts expect dependency to reach 60pc by 2015. The state council, China's cabinet, is expected to approve the 12th five-year plan by December.
This month in Argus FSU Energy
Transneft warns on Trebs and Titov
Russia's pipeline operator says development of the Trebs and Titov fields poses significant logistical challenges.
Whoever wins the licence for the Trebs and Titov fields will have to agree expansion of the 440,000 b/d Usa-Ukhta pipeline to send domestic crude shipments along this route, or fund a new line, Transneft says.
The 406km Usa-Ukhta line, the first leg of the Transneft system that heads southwest out of Timan-Pechora, is running at capacity and will not cope with rising output from the province, the pipeline operator says. Usa-Ukhta is the only existing line for shipments from oil-rich Timan-Pechora.
The 140mn t Trebs and Titov fields in the Nenets autonomous district will be put up for tender at an asking price of Rbs18.17bn ($605mn) on 2 December (FSUE, 13 August, p1). The licence terms require the developer to process at least 42pc of Trebs and Titov oil at its own Russian refineries and sell 15pc of resulting products through the St Petersburg exchange. As swap deals using oil from the fields will be prohibited, the developer must build a line linking Trebs and Titov with Usa-Ukhta for onward domestic shipments.
Bottleneck frustration
Transneft's warning suggests the developer will have to fund expansion of Usa-Ukhta too, or lay a new line for Trebs and Titov oil. The fields are expected to produce a joint peak of 200,000 b/d, so just under 100,000 b/d of extra pipeline capacity is required.
Usa-Ukhta has been the subject of disagreement between Transneft and oil firms, particularly Lukoil, over the past decade. Companies operating in Timan-Pechora, including Lukoil, Rosneft and a number of independents, have complained that bottlenecks on the line have restricted crude output growth. In 2004, Rosneft blamed a 12,000 b/d cut in its annual output on the line's limited capacity, while output from the Total-led Kharyaga production-sharing agreement is still hampered to some extent by the same problem.
Transneft agreed in 2005 to expand Usa-Ukhta to 440,000 b/d from 360,000 b/d after striking a deal with oil firms on an investment fee — essentially a rise in the tariff — to pay for the $137mn upgrade. The line had already been running above its nominal capacity of 324,000 b/d thanks to flow-enhancing additives. Transneft completed the upgrade in 2006. Boosting capacity to 600,000 b/d would cost $2bn, Transneft said in 2004, adding that producers would have to pay.
Lukoil's frustration with Timan-Pechora infrastructure was partly behind the construction of its 240,000 b/d Varandey terminal on the Barents Sea. This now provides the firm with a cost-effective export route for oil from its Yuzhno-Khylchuyu field.
Transneft does not say whether output from Trebs and Titov will prompt it to boost the 406,000 b/d capacity of the 1,132km Ukhta-Yaroslavl line. The prospect of funding pipeline upgrades, coupled with the economically unattractive domestic refining requirement, is likely to dampen potential bidders' enthusiasm for Trebs and Titov.
The participation of Lukoil, which had been widely regarded as the best-placed Russian oil company to bid for the licence, looks less likely. The firm has ruled out the possibility of processing Trebs and Titov crude at its nearby 75,000 b/d Ukhta refinery — the closest plant to the fields — because it already runs at capacity processing oil from Lukoil fields in the Komi republic.
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