Energy Finance Week Issue 06

Week 06• 14 March • 2016

ENERGY FINANCE WEEK This week’s top stories

v Vicious investment cycle

reinforced as global banks cut debt exposure p2

v CNR slashes cap-ex by C$2.2 billion p4

v Unipetrol targets acquisitions as CEE refining sector recalibrates

p5

v Moody’s downgrades Inpex, JAPEX p12

w w w. N E W S B A S E . c o m NewsBase Ltd. • 108 Dundas Street, Edinburgh EH3 • Tel: +44(0)131-478-7000 • Email: research@newsbase.com

ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Vicious investment cycle reinforced as global banks cut debt exposure MARKET SAUDI Arabia had planned to offset the record budget deficit incurred last year with the expansion of its international capital markets funding pool. The likelihood of Riyadh plugging the US$100-billion gap is now somewhat diminished, with Saudi’s investor ratings being undermined.

With no sign that the ongoing slump in the oil price will reverse any time soon, the prospect of tougher government stress tests and market-targeting of weak equity links in the tight oil investment universe means that global banks are looking more carefully than ever at their shale industry debt exposure.

This, in turn, will continue to push unconventional firms’ high-yield debt spreads higher, driving up financing costs, and thus increasing their lending banks’ debt exposure to the sector, at least until an equilibrium is reached, which it is yet to do.

Fears of energy-sector bankruptcies have long weighed on the US banking sector – to begin with, as it almost single-handedly financed expansion of the tight oil sector over the past decade, both through direct loans and through the structuring of high-yield bond issues, which, as underwriters, often ended up by being held by the banks themselves.

Indeed, around US$360 billion worth of high-yield bonds have been issued by US energy companies since 2003, most of it from shale oil and gas producers.

Although the redemption curve is not an urgent issue over the next three years, with only US$35.5 billion due prior to, and including 2019; after that date, the maturity profile worsens dramatically, soaring over US$30 billion per year in 2020 and 2021 and then to over US$40 billion in 2022.

“With a growing consensus that oil prices will remain lower for longer, and spreads higher, this means more companies will be at risk of defaulting during the next few years and, additionally, more companies in the same sector defaulting at roughly the same time may result in forced sales,” Gary Russell, high-yield portfolio manager at Deutsche Asset Management, told Energy Finance Week.

By way of highlighting the present challenging environment, the number of such bankruptcies in the second half of 2015 amounted to 28, compared to 13 in the first half. Among high-yield issuers in the US: “Riskier credits have an increasingly difficult time raising money in the bond market,” added Russell. “The decrease in liquidity combined with the low oil price has increased the

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expectations of defaults in the market,” he said.

An additional negative factor for the sector’s banks is the low recovery rate. According to Deutsche Bank research, the market may currently be pricing-in an implied five-year cumulative default rate of almost 50% for US high-yield bonds as a whole, assuming a 40% recovery rate.

Bubble ready to pop?

The reason that this is much worse news now than, for example, the banks’ holdings of mortgage-backed securities before they blew up and prompted the global financial crisis in 2007/08, is that precisely because of previous laxity by the US regulators, oversight has now been markedly tightened and this year’s ‘Comprehensive Capital Analysis and Review’ (CCAR) and ‘Dodd-Frank Act’ stress test exercises (that monitor capital adequacy) will be a lot tougher than before.

The 33 bank holding companies (with US$50 billion or more in total consolidated assets) will face testing scenarios in which the price of oil will weigh much more heavily than ever before, with oil prices now already around 55% below the level when the Fed set last year’s stress test scenarios in October 2014, according to Michael Alix, financial services consulting risk leader for PwC. “It would test those [banks] for both the direct effects [of oil price falls] on their oil or commodity trading business [as they did last year] but importantly the indirect effects of lending to energy companies, lending in areas of the country that are more dependent on energy companies and energy-related revenues [which they have never done before],” he said.

That test included looking at how banks’ trading books would fare if there was a one-off 68% fall in oil prices sometime before the end of 2017. Banks’ loan books were not tested against falls in oil prices.

Of these top 33 banks, Wells Fargo & Co., the world’s largest bank by market value, said last month that bad energy loans climbed 49% in the last three months of 2015, whilst JP Morgan Chase said that its reserves for impaired energy loans would increase by around US$500 million in the first quarter and it would have to provide an additional US$1.5 billion for losses if oil prices held at around US$25 per barrel for around 18 months.

Even more specific to the energy firms were comments made last month by the head of JP Morgan’s commercial

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

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Week 6• 14 March • 2016

bank, Doug Petno, that such companies could see a further 15-20% cut in their credit lines, adding that, although banks had previously been flexible enough to be more lenient with their energy clients, all this is now changing.

Drastic measures According to Petno, JP Morgan for one is not waiting for April – when banks traditionally reassess the value of oil reserves underpinning energy loans (the ‘redetermination process’) to reassess its exposure. “The most distressed clients know when they are going to be pinched and are taking the steps to deal with it, with most of these clients working with their banks way in advance of redeterminations, so it is compelling mergers and acquisitions, it is compelling asset sales, it is compelling discussions with private equity,” said Petno. “However, there will be a meaningful number of these players who have no options, and I think we have only begun to see the range of bankruptcies in oil and gas,” he added.

For some of the smaller regional banks in the US, the situation is more advanced, with major global credit ratings agency, Moody’s, having placed four of them – BOK Financial Corp., Cullen/Frost Bankers, Hancock Holding Co. and Texas Capital Bancshares – on review for a downgrade of their long-term ratings and standalone baseline credit assessments (BCA) in February.

Moody’s explained that these banks hold significantly higher direct energy-related loan concentrations than the median for US regional banks, 40%-110% of tangible common equity, compared to 10%-15% median for roughly 60 rated US regional banks.

“We believe it is reasonable to assume increased problem loans in the energy sector as a result of weakening liquidity as energy borrowers experience reduced cash flow, pressure from bank-loan covenants and a withdrawal of bank and capital market liquidity,” said Moody’s New York-based banking analyst, Megan Snyder.

Widening reach The same regulatory concerns have been brought into focus by the markets on the European banking system in recent weeks, as traders await the results’ breakdown from the 2016 European Banking Authority’s banking sector stress test for institutions in the Eurozone.

“Traders always look for weak links and push those until they break, which is precisely what we have seen in those European banking stocks that are regarded as having considerable exposure – across their global network – either to the tight oil industry segment or to the oil and gas segment in general,” Sam Barden, CEO of energy trading and consultancy firm, SBI Markets, told Energy Finance Week.

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Such trading dynamics reached their latest zenith last month when the Stoxx Europe 600 Banks index was pushed to a 25% loss over the first eight weeks of the year, with Credit Suisse sold down by 40% over the period and Deutsche Bank by just over 30%.

Although some banking analysts – albeit, at European banks – have recently said that only around 20% of the European banking sector’s loans to energy companies are high-yield and project losses of around 6 billion euros (US$6.7 billion) out of combined 400 billion euros (US$448 billino) in outstanding energy company debt held by Eurozone banks, the fact remains that – in Europe – it is anybody’s guess, owing to the opacity of the reporting, said Barden.

“European banks don’t publish deep-down data on the extent of their exposure to the energy sector, so in reality nobody has a a clue who holds what exposure, so the market view is [to] go after the big names – like Credit Suisse, like Deutsche – and you are bound to hit a weak target sooner or later,” he added. Indeed, figures released recently by US bank, Bank of America Merrill Lynch, stated that European banks could book US$27 billion in loan losses from energy firms, or 6% of the industry’s entire pre-tax profits over three years.

The increased link being made by traders between European banks and the oil price in general is highlighted by the huge spike in the correlation between the aggregate price of European bank shares and the price of oil. On a scale of 0 to 10 (where 0 is no correlation and 10 is total correlation), the correlation is now nearly 0.5, according to UBS analysis of industry data, compared to 0 just over a year ago. The extra bonus of shorting certain European banks, he added, is that because of their capital structures, their share price could collapse as and when they breach the new capital adequacy rules, which have been markedly tightened up under the new Basel III international regulatory framework for banks.

In this context, in order to bolster its Basel IIImandated Tier 1 capital, Deutsche Bank was ‘persuaded’ into raising nearly 20 billion euros (US$22 billion) in 2010 and 2014, most of it by selling shares, but also by issuing the equivalent of 4.6 billion (US$5.2 billion) in ‘contingent convertible (CoCo) bonds’, which convert automatically into the bank’s shares if its capital drops below certain thresholds, so – in theory – saving the Eurozone taxpayer the cost of having to bail it out.

“It’s like waving a red flag at a bull for traders to be honest; you get a 6% yield at least just for holding the bonds, and if you then sell the shares down to a level where the bonds-equity conversion takes place, you already have the yield from the bonds, plus the short profit from selling the shares, and then the free long at low levels from the new stock you’re been given, it’s a no lose trade,” concluded Barden.n

Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

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Week 6• 14 March • 2016

Historically bad investor climate in US NORTH AMERICA US oil and gas companies faced the worst-ever conditions for obtaining cash last month, Moody’s rating agency has said in a new report. Moody’s Oil & Gas Liquidity Stress Index (LSI) surged to a record high of 27.2% on the back of depressed oil prices, the agency said. That compares with a surge of 24.5% during the last recession.

February marked the “biggest month ever” for liquidity downgrades, with 17 exploration and production companies out of a total of 25 downgraded, the agency added. Moody’s downgraded a total of 19 energy companies during February. The liquidity ratings of ten E&P companies were cut to SGL-4, which is the agency’s lowest liquidity rating, along with one oilfield services company. “The prolonged weakness in energy sector credit conditions is driving the sustained increase in the LSI,” said Moody’s senior vice president John Puchalla.

“Energy liquidity downgrades came as part of our ongoing review of oil & gas companies globally in light of the weaker price environment,” he added.

The agency’s composite LSI surged to 8.9% last month, from 7.9% in mid-January, and is now at its

highest level since November 2009. “This progression signals that the default rate will continue to rise as the year progresses,” Puchalla said.

Crude prices have slid more than 70% since June 2014, putting pressure on oil and gas companies worldwide. Some analysts are now predicting that crude prices could drop as low as US$20 per barrel in the near future. Sliding oil prices have resulted in many companies tightening their belts by cutting back on investments, especially riskier ventures, in the last year. Companies have also cut back workforces and restructured debt, all in an effort to avoid insolvency. However, the number of bankruptcies is rising. Analysts have noted that for most independent explorers, cash flows have been severely dented by the decline in oil prices. It has affected those companies that do not have other assets like refineries or retail petrol stations the most. Ratings agency Standard & Poor’s also cut the credit ratings of some leading US oil and gas companies last month. Chevron, the second largest oil and gas firm in the US, and Apache were among the companies to see their ratings cut.n

CNR slashes cap-ex by C$2.2 billion NORTH AMERICA CANADIAN Natural Resources (CNR) has said it will cut its capital expenditure budget by up to around C$2.2 billion (US$1.7 billion) this year, as part of efforts to trim down costs in the current oil price environment. The company reduced its estimated 2016 capital spending to between around C$3.5 billion (US$2.64 billion) and C$3.9 billion (US$2.94 billion), from C$5.2 billion (US$3.92 billion) last year.

The Calgary-based company said it would also slash capital expenditure in 2017 and 2018, citing the impact of lower crude prices on its revenue. “Canadian Natural develops its capital budgets to be flexible and nimble, allowing the company to proactively adapt to changing market conditions,” the firm said in its earnings update last week. “In 2017, we’re looking to spend around C$2.5 to C$2.6 billion dollars [US$.1.88-1.96 billion].

Getting to 2018, we expect to spend about the same.

Those are the numbers that keep our production flat.

We’re assuming we have a low oil price throughout that time,” said CNR president Steve Laut in a conference call, according to a Reuters report. A number of North American firms have scaled back spending in the last few years, citing weaker oil prices. Oil prices have dropped by 70% since mid-2014. In 2015, CNR cut its capital

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budget by C$2.4 billion (US$1.81 billion) to C$5.22 billion (US$3.93 billion), which was 28% lower than its original forecast of C$8.6 billion (US$6.48 billion) for the year. Canada’s second biggest oil and gas producer operates in Western Canada, the UK’s North Sea and offshore West Africa. Last week, the firm reported an 89% fall in profit in the last quarter of 2015, but said it had managed to reduce capital expenditure as planned.

“2015 was a strong operational year for Canadian Natural despite the significant drop in commodity prices.

In 2015, we were able to reduce original budgeted capital spending by C$3.4 billion {US$2.56 billion], but still delivered 8% production growth,” said Laut in a company press release. Despite the price downturn, the company intends to go ahead with its Horizon oil sands mining project, which should generate an additional 125,000 bpd of crude production capacity by the end of 2017.

CNR said that capital investment in the expansion of the Horizon project would drop to approximately C$1 billion (US$754.4 million) in 2017. The following year, Horizon expansion capital will drop to zero, it added.

CNR said it anticipated producing between 809,000 and 868,000 barrels of oil equivalent per day this year, which is around 2% lower than last year.n

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

NewsBase Ltd. 108 Dundas Street, Edinburgh EH3 Tel: +44(0)131-478-7000 Email: research@newsbase.com Web: www.newsbase.com

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Week 6• 14 March • 2016

Unipetrol targets acquisitions as CEE refining sector recalibrates

Low oil prices and high margins have presented an opportunity to refiners like Unipetrol to expand. But benign market conditions are not guaranteed to last, as the regional downstream sector goes through a period of transformation EUROPE US shale producers are hunkering down to survive the storm as the oil price environment takes its toll on the industry after an initial period of resilience. The price of US benchmark West Texas Intermediate (WTI) has fallen by over 60% from above US$100 per barrel in July 2014 to less than US$34 per barrel earlier this week, near a 12-year low.

Czech oil refiner Unipetrol, part of Poland’s PKN Orlen group, had a highly eventful 2015. The company recorded a substantially improved financial performance and chalked up several new acquisitions, though a fire at its Litvinov refinery was a low point.

NewsBase spoke to Andrzej Kozlowski, executive director and head of strategy at PKN Orlen and a board member at Unipetrol, to gain insight into the group’s acquisition strategy and how it sees global oil and refining markets evolving in 2016.

“In 2015, Unipetrol earned a high operating profit of almost 11 billion Czech crowns [US$441 million],” said Kozlowski. “We prospered from the favourable ‘macro’ environment, especially very good refining and petrochemical margins. We also managed to increase sales of refining products after the stake acquisition in Ceska Rafinerska. But results were affected by limited production capacity at the Litvinov refinery owing to the steam cracker accident in August. Our results would have been even better if there had been no accident.”

Acquisitions Turning to the company’s acquisition policy, Kozlowski said: “Our main goal is to build the value of the Orlen Group and strengthen the company’s position on the European markets. That’s why Unipetrol purchased the shares of Eni and Shell in Ceska Rafinerska, and more recently finalised the acquisition of filling stations from OMV. This increases our share of the Benzina network of the retail market in the Czech Republic.”

He went on to say that the group was looking for new downstream opportunities in Central and Eastern Europe (CEE). “We are now monitoring the market in the region for other interesting opportunities. Orlen Group … strives for further expansion in this segment, organically and through acquisitions. This mainly applies to foreign

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markets in which we operate. From this point, we are ready to examine any offer of acquisition which can help increase our share of the retail market, provided that the asset price is reasonable and will bring added value to our shareholders.”

Kozlowski did not provide details of any specific targets for investment. But it should be noted that fellow oil refiner Slovnaft, in neighbouring Slovakia, also performed well in 2015 and could provide attractive synergies, given its strong downstream and retail assets.

Further afield, investment in refining assets such as Petrotel in Romania could be a possibility should Russian backer LUKoil decide to reduce its stake.

Long-term view Any investment must be based on credible long-term prospects of continuity and good performance, though.

Looking ahead, Kozlowski offered his assessment of oil market trends and how they might affect the performance of European oil refiners.

“According to our own oil and fuel market outlook,” he said, “after excess oil supply has been absorbed by the market and relevant adjustments have been made on the supply side (we expect this by around the end of 2016), oil prices will enter a lasting uptrend, which will begin the next oil ‘super-cycle’. So in the next four quarters, we are likely to witness oil prices rising and falling in search of a balance and fuel demand adjusting to lower prices”.

He went on to say that the “cyclical oil price decline, which we have observed since June 2014, creates losers and winners. Among the beneficiaries of lower oil prices are refineries. The main reason to rejoice for refiners, because of lower oil prices, is wide refinery margins. The lower prices of fuels due to lower crude oil prices also have a positive effect in terms of higher fuels consumption.” He remained cautious of being overly optimistic, however. “One must remember that the high refinery margins are not to stay for long, and are likely to contract to some extent,” he said.

Future of refining Kozlowski anticipates that volatile price dynamics will alter the state of the global refining market. “It is becoming a

Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

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Week 6• 14 March • 2016

global game. New refineries will be built mainly in the Middle East and Asia to capture refinery margins and extend the value chain in oil-producing countries. These refineries are designed to supply global markets and will successfully compete with European refineries, which are old, relatively small, and exposed to higher oil prices and regulatory costs,” he said.

The broader outlook for refining in the CEE region is that there will be further structural changes that influence demand for oil products, which could hasten the consolidation process.

Jan Jujeczka, a spokesperson for regional energy group Central Europe Energy Partners (CEEP), told NewsBase: “Consumption of fuels depends heavily on the number of motor vehicles per capita, which in Central Europe is still not at the level of the EU-15 [Western European] countries. But in a few years’ time, these levels should become equal, and we should then expect a very small increase in fuels consumption in the CEE region until 2020.”

Looking further ahead, Jujeczka added: “In the EU15, we expect a decrease [in consumption] of around 30% by 2030. As Central Europe will follow the EU-15 trend, we expect a 20% decrease in consumption by 2030 compared to the current level. The reasons for the decrease will be the higher efficiency of engines, as

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well as the rising popularity of hybrid, electric, gas- and hydrogen-powered vehicles.”

The outcomes from these quite dramatic changes will be twofold, the CEEP has forecast. “First, we will see the closure of refineries, which is already happening in the EU-15,” Jujeczka said. “This process should start in Central Europe around 2018-20. It will be even more intensive if the refineries will not receive a 100% allocation of European Union Allowances (EUAs) free of charge, under the ‘carbon leakage’ programme.”

He continued: “The second scenario will see further mergers and acquisitions. This process is less probable before 2020, yet after that date it will be necessary due to the decrease in the fuels business and capacities.”

The CEE region’s downstream oil market is transforming rapidly. Unipetrol’s expansion is being driven by its recent successful financial performance.

The company has acknowledged that the benign market conditions it is benefiting from will not last, hence the need for quick deals. Other energy groups are also taking note of the window of opportunity and mobilising resources to buy attractive assets in the region. Whilst some oil majors want to quit refining, others that lack a significant presence in the region, like Norway’s Statoil or Russia’s Rosneft, could step in to buy assets that complement their diversification strategies.n

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

NewsBase Ltd. 108 Dundas Street, Edinburgh EH3 Tel: +44(0)131-478-7000 Email: research@newsbase.com Web: www.newsbase.com

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Week 6• 14 March • 2016

More details on Shell’s divestment push EUROPE ROYAL Dutch Shell’s three-year divestment plan is likely to focus on offloading assets in the US, Trinidad and India.

The European super-major intends to raise US$30 billion through asset sales after wrapping up a US$52 billion deal to buy BG Group last month.

The acquisition, widely expected to trigger a wave of mergers, is so far the only major merger and acquisition (M&A) story to emerge from the current market downturn.

Shell could dispose of interests in Trinidad and Tobago, two people with knowledge of the matter told Bloomberg.

The company bought into Trinidad’s four-train Atlantic LNG terminal in 2014 as part of a deal with Spain’s Repsol. By acquiring BG, Shell has raised its stake in the facility while gaining control of its source fields and connecting pipeline system.

Shell’s upstream portfolio in India could also be placed on the block. Through BG, Shell now owns a 30% stake in the Panna/Mukta and Tapti (PMT) cluster of fields off India’s west coast. Output from the fields is declining and Tapti, the site’s major gas producer, is due to cease

operations altogether this year. Shell could also shed its interests in a network of crude and oil product pipelines in the US. The assets are partly owned via the company’s subsidiary, Shell Midstream Partners. Last month, CEO Ben van Beurden said the business unit could account for up to 15% of Shell’s total divestments.

Shell has already offloaded US$20 billion in assets over the last two years, including major developments like the Carmon Creek oil sands project in Canada and exploration licences in the Arctic.

But the BG takeover has put further pressure on Shell to trim its portfolio and raise cash. The company saw profits slide 80% in 2015 to a 13-year low of US$3.8 billion. Fitch Ratings also recently downgraded Shell’s credit rating on account of its high debt-to-earnings ratio.

Van Beurden said the first US$10-15 billion of Shell’s divestment drive would come from the sale of downstream and midstream assets. The company wants to delay the bulk of these sales until 2017 and 2018, in the hope that assets will fetch higher prices.n

DNO buys Noreco Norwegian portfolio EUROPE DET norske oljeselskap (DNO) has signed a deal to buy Noreco’s Norwegian licences. The latter’s portfolio comprises seven licences on the Norwegian Continental Shelf (NCS), including a 20% stake in the Barents Sea’s Gohta find, otherwise known as Production Licence (PL) 492. Noreco’s 4.36% interest in the Enoch field is not included.

The deal, which has been negotiated to become effective from January 1, 2016, also sees Det norske acquire Noreco’s US$5.2 million cash balance.

Det norske’s CEO Karl Johnny Hersvik said the agreement underlined the company’s “belief in, and commitment to, the NCS.” For Noreco, however, the deal marks a complete departure from petroleum activities in Norway. The company has already secured acceptance for the deal from its major bondholders that hold the bulk of its outstanding bonds.

The deal remains conditional upon approvals from Norway’s petroleum and finance ministries.

Det norske has in recent months been building up its

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portfolio in Norway, looking to acquire assets while the depressed oil environment keeps them cheap.

In October 2015, it agreed to buy Svenska Petroleum Exploration for US$75 million.

That deal gave it holdings in 13 licences in Norway, including a 40% stake in Frigg Gamma Delta, 25% each of Krafla/Askja and Fulla/Lille-Frigg, and a 20% stake in Garantiana. Det norske also inherited Svenska’s four exploration licences in the Norwegian Sea. December 2015 then saw Det norske complete its acquisition of Premier Oil’s Norwegian assets in a transaction valued at around US$120 million.

Det norske’s majority shareholder Aker predicted late last month that the company’s output would rise to 160,000 barrels of oil equivalent per day from 2020, and that mergers and acquisitions would drive growth.

“There is an increased activity level in the market, with companies in need for capital that are going through big restructuring processes,” Aker’s CEO Oeyvind Eriksen said at the time. Expect more deals from Det norske as the year progresses.n

Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

NewsBase Ltd. 108 Dundas Street, Edinburgh EH3 Tel: +44(0)131-478-7000 Email: research@newsbase.com Web: www.newsbase.com

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Petroceltic shares suspended EUROPE TIME appears to be running out for Petroceltic after dissident 29.6% stakeholder Worldview asked the Irish High Court to appoint an examiner for the company.

Worldview subsidiary Sunny Hill on February 26 mounted an opportunistic GBP6.4 million (US$9.08 million) hostile bid for the London-listed company, which is equivalent to GBP0.03 (US$0.04) per share.

In order to proceed, the offer needs approval from 90% of Petroceltic’s share capital not owned by Worldview. The bid is significantly less than the GBP0.44 (US$0.63) target price set by BMO Markets, based on the value of Petroceltic’s Ain Tsila gas project in Algeria, which is scheduled to launch in 2018. The company’s second largest shareholder, Skye Investments, which controls a 19.2% stake and is owned by Petroceltic non-executive chairman Robert Adair, confirmed its intention to reject the bid last week. Petroceltic currently owes around US$230 million under its bank facility, but only holds US$7 million in readily convertible cash balances. The company failed to push through a US$175 million bond issue in August 2015, after opposition from Worldview.

Cenkos analyst Ashley Kelty told NewsBase he

thought Petroceltic would agree waivers with its lenders, but that the Worldview bid was “ludicrous” given that “Ais Tsila is certainly worth more than 3p a share on an NPV basis.” He added: “I can certainly understand why they’re not interested in entertaining Worldview’s offer. It’s just how long they can hold on for before Worldview [increases its offer], or forces them into administration.” Worldview has now lodged a petition requesting court protection for Petroceltic, which will be heard by the Irish High Court in Dublin on April 4. Petroceltic said it was unable to finalise an extension to its waivers on March 4 as a result of the petition, and was seeking legal advice because Worldview had moved without prior consultation.

On March 7, Petroceltic suspended trading on the London and Dublin stock exchanges with immediate effect, maintaining Petroceltic’s nominal value of GBP0.07 (US$0.09) per share. “It just seems to go from bad to worse,” Kelty said. “They managed to fend off various attempts to oust the board over the last couple of years, although the bond issue they wanted … was scuppered

by Worldview, and that has contributed to the parlous financial state they are in.”n

France to fund marine projects EUROPE

FRANCE’S national research agency ANR, in partnership with France Energies Marine, the country’s wave and tidal power association, has announced funding for marine energy research projects. The two groups plan to allocate 3 million euros (US$3.35 million) to projects that help to build capacity in the French marine energy sector. Bids must be submitted by April 22, 2016, with the winning projects announced in July. Successful companies will receive up to half of the funding they require, with between 50,000 euros (US$55 million) and 2 million euros (US$2.2 million) available for individual projects in upstream and industrial research that builds knowledge across the sector at the pre-competitive stage. Projects are expected to be in the form of public-private partnerships, although FEM may manage some schemes internally.

The call for bids follows an earlier tender in 2015 to help build the energy sector of the future and hopes to further its aims, in line with priorities of the European Strategic Energy Technology Plan (SET-Plan) of the European Commission and the France Energies Marines roadmap. Specifically, ANR and FEM are looking for projects which can: improve the competitiveness of the value chain; help the development of marine energy supply chains; optimise logistics; develop standards and integrate systems. Bids that address non-technological

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issues such as financing, the environment and social engagement will also be considered. All projects should have a maximum duration of 36 months.

Small business bidders that are not FEM members are expected to present joint bids with research labs.

While the UK is generally considered to be leading the way in the marine energy sector, France is also a strong player, though so far much of it has been via foreign companies. Shipbuilder DCNS has played an important role, given its majority stake in Irish tidal power company OpenHydro. The group recently deployed a 2-MW device off the coast of Brittany and is planning to deploy a second machine in the same location by the summer, as well as two 2-MW turbines in the Bay of Fundy, Nova Scotia, when weather conditions permit in the spring. It also has plans for further installations in Northern Ireland, Scotland and the Channel Islands. A further 14 MW of capacity will be installed off the coast of Normandy in partnership with EdF. While highly encouraging for the sector, it may not be enough to accomplish the country’s goals. France’s renewable energy targets include a requirement to produce at least 6 GW of marine renewable energy by 2020 – an incredibly ambitious feat. Even as the perceived world leader, the UK currently only has a handful of operating projects, most of which are pilot installations.n

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

BP takes Angola charges AFRICA BP has taken significant charges on its assets in Angola, the company disclosed in its annual report, published last week, including in the pre-salt. Pandora-1, the first presalt well drilled by BP in Block 19 of the Kwanza Basin, found hydrocarbons, the super-major said, but would require developments to take place nearby in order to be declared commercial.

As a result, BP took a charge – for the well and the Block 19 licence – of US$336 million in 2015. The company also took a US$432 million write-off in Libya, based on “significant uncertainty” about when drilling may be possible.

The company took impairment charges of US$1.2 billion on its Angolan portfolio in December, as a result of falling oil prices. A “significant portion” of this, it said, was related to the Angola LNG plant.

Chevron, in its annual report published in late February, confirmed work had been completed on plant modifications and reliability enhancement at Angola LNG in early 2016. As such, a first cargo is expected in the second quarter of 2016, with an expected economic life to be more than 20 years. The Angola LNG project, in Soyo, is the world’s first to be supplied by gas from associated gas production. It will produce 670 million cubic feet (18.97 million cubic metres) per day for sale and up to 63,000 barrels per day of NGLs. Chevron also said that its Congo River Canyon Crossing pipeline will be able to carry up to 250 mmcf (7.1 mcm) per day of gas from Block 0 and Block 14 to the liquefaction plant. Construction on the 140 km pipeline was completed in mid-2015 and start-up is planned for this year.

The US super-major also said its Mafumeira Sul project, in Block 0, was expected to start up in the second half of this year and reach full production by the end of 2018. Design capacity is 150,000 bpd and 350 mmcf (9.91 mcm) per day of gas.

One potential bright spot for Angola’s pre-salt, though, was the Katambi-1, which was drilled in Block 24, of the Benguela Basin. This was the first well drilled by BP in this basin, with the company saying that technical and

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commercial work was ongoing.

BP was involved in three projects that came on line in Angola last year. These are Block 15’s Kizomba Satellites Phase 2, Block 18’s Greater Plutonio Phase 3 and Block 17’s Dalia Phase 1A. On the list of the company’s expected start ups in 2017-20 was Platina, in Angola’s Block 18.

The company’s production from Angola reached 221,000 bpd of oil in 2015, down from 181,000 bpd in 2014. Angola provided the majority of BP’s total African oil production, which was 270,000 bpd in 2015, from 222,000 bpd in 2014.

Ratings warning While companies are struggling to make headway, given the present tough conditions, so too are governments that are reliant on commodity exports. Moody’s Investors Service, on March 4, said it had put Angola’s Ba2 bond on review for downgrade.

The ratings agency said it would assess the extent to which the sharp fall in prices, which it expected to remain low for several years, would hamper Luanda’s plans. Oil and gas account for 97% of Angola’s exports, providing around 67% of government revenues and 45% of its GDP. Moody’s has reduced its price expectations for Brent to US$33 per barrel in 2016, US$38 per barrel in 2017 and US$48 per barrel by 2019. Lower prices have reversed Angola’s economic trend, from surplus to deficit.

The currency depreciation to the US dollar, of around 50% from January 2015 to February 2016, has reduced some of the impact on government revenues, but inflation is up sharply. Exacerbating this has been the removal of fuel subsidies, with inflation reaching 17.6% in January.

In addition, the government’s cash reserves have been run down, to around US$24.7 billion at the end of 2015, from US$32 billion at the end of 2013. This reduces Luanda’s ability to respond to shocks. The Angolan government has taken steps to protect its standing – including cutting spending and tax reforms. Moody’s intends to examine the extent to which these plans will have an impact on Angola’s future credit standing.n

Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Nigeria plans to break up NNPC AFRICA NIGERIA has set out plans to break up the Nigerian National Petroleum Corp. (NNPC) into 30 companies, in addition to speeding up the contracting cycle for upstream projects.

“For the first time, we are unbundling the subset of the NNPC to 30 independent companies with their own managing directors. Titles like group executive directors are going to disappear and in their place you are going to have [CEOs] and they are going to take responsibilities for their titles. At the end of the day, the CEO of an upstream company must deliver an upstream result,” NNPC’s managing director, Ibe Kachikwu, said, announcing the plan, on March 3. Kachikwu is also Nigeria’s junior oil minister, while Nigerian President Muhammadu Buhari holds the senior position.

A report in This Day newspaper quoted Kachikwu as saying the corporation would be divided up into five operational zones, in “the upstream, downstream, midstream, refining and … the venture group”.

The NNPC statement said the unbundling would take place in the weeks ahead. Kachikwu made his comments at an energy forum in Abuja. Changes at NNPC already

appear to be providing some progress, with the official saying it had moved from making a loss of 160 billion nairas (US$803 million) to only 3 billion nairas (US$15 million) by January 2016. By the end of this year, Kachikwu projected NNPC would be making a profit.

Buhari’s government is eager to develop Nigeria’s gas resources, as part of its work to drive diversification, the statement continued, while at the same time reducing the amount of time for contracting in the upstream, from two years to six months. Efforts to review existing productionsharing contracts (PSCs) are in “top gear”, the statement continued, which it described as long overdue.

Nigeria has struggled as a result of the oil price fall but, despite being a member of OPEC, has been unable to persuade the organisation’s Middle Eastern members to cut output. The statement said the group would hold talks with the Russian government on March 20, in Moscow, in order to “fine tune collaborative strategies”.

Abuja may be hoping to shore up talk of a production freeze – or even cut. While such a move would provide much-needed respite for the West African state, this seems unlikely as yet.n

IFC slashes Vaalco credit facility AFRICA VAALCO Energy’s revolving credit facility has been reduced to US$20.1 million, effective as of the end of 2015, the company said on March 2. The facility was reduced from US$65 million.

The company has drawn down only US$15 million of this facility, unchanged from that at the end of December.

The previous redetermination was announced at the end of July, when it was US$65 million. The redetermination came as a result of a semi-annual review carried out by the International Finance Corp. (IFC). The covenants on the facility are unchanged. The borrowing base is supported by Vaalco’s Etame Marin asset, in Gabon. The next redetermination is due on June 30 of this year.

“The significant downturn in oil prices was the primary reason that the IFC decided to lower our borrowing base. We are actively exploring a variety of options to supplement Vaalco’s potential liquidity needs in conjunction with our strategic alternatives review process announced January 26, 2016,” said the company’s CEO, Steve Guidry.

Vaalco warned that, should it seek to drawdown cash before the next redetermination, the IFC could carry out an interim reassessment that may lead to its borrowing base

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being reduced under US$20.1 million. Such a reduction would come about as a result of commodity prices having fallen this year. Vaalco, in its third-quarter results from November, said capital expenditure in 2015 was expected to be US$83-86 million. In January, the company said it expected to spend US$4-6 million in 2016.

The Gabon-focused explorer has struggled with poor exploration results in Angola, in addition to the broader headwinds being faced by the industry. In late 2015 an activist investor group raised a number of issues for Vaalco and a resolution was reached in December. In late January, the company said it was exploring “strategic alternatives”, signalling an openness to a sale. US companies working on domestic projects have announced major cuts to capex amid pressure on their balance sheets. Although Vaalco is working beyond its home shores, the pressures are similar.

“Bank lines with borrowing base re-determinations are expected to be cut 15-20% this spring while we suspect some cuts will be much greater,” Stifel’s Michael Scialla, in a note on March 4, said. The Vaalco example demonstrates the broader industry trend of redeterminations.n

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Vaalco operations map

Marubeni, Elsewedy sign 4,000MW power deal in Egypt AFRICA A consortium of Japan-based Marubeni and Elsewedy Electric has signed a memorandum of understanding (MoU) with Egypt’s Egyptian Electricity Holding Co. (EEHC) to build a 4,000- MW, coal-fired thermal power plant (TPP) in northern Egypt.

“The coal-fired power plant will be built in two phases, each with capacity of approximately 2,000 MW,” said Elsdwedy Electric after signing the MoU in Tokyo last week.

The project involves building a 4,000 MW highefficiency ultra-supercritical coal-fired power plant on the Mediterranean coast in west Mersa Matrouh Province with an estimated investment of US$3.5 billion.

It includes development, a desalination plant, port and land works related to the import, handling and storage of coal shipments for the project. The proposed desalination plant will remove minerals from around 360,000 cubic metres of seawater daily.

The design and capacity of the plant, however, will be decided after a detailed feasibility study.

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Marubeni will provide engineering and procurement of critical equipment such as boilers and steam turbines, while Elsewedy will engage in site preparation, civil construction and site utilities for the project.

The power plant is to source the required coal from the southern African states, such as Mozambique and South Africa, under a longtern supply agreement.

The Japanese government has agreed to provide loans for the development of the proposed power project through Japan Bank of International Co-operation (JBIC) and Japan International Co-operation Agency (JICA).

EEHC has taken up this project as part of a plan to build 8,000 MW of coal-fired capacity by 2022.

The company wants to lower its dependence on expensive oil and natural gas in power generation, which currently account for around 60%.

The Egypt government has also given conditional approval for China’s Dongfang Electric and Shanghai Electric to build two coal-fired TPPs, with total capacity of 3,300 MW, in Hamrawein in the Red Sea governorate.n

Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Moody’s downgrades Inpex, JAPEX Japan’s top two oil and gas producers have seen their ratings downgraded by Moody’s owing to the prospect of reduced profitability.

ASIA JAPAN’S top two oil and gas exploration and production companies took it on the chin last week with news of a Moody’s downgrade for both.

Using almost exactly the same wording to justify downgrades for Inpex and Japan Petroleum Exploration (JAPEX), the credit ratings agency predicted that profitability at both firms “will deteriorate significantly as a result of sustained low oil prices”.

But while the downgrades certainly highlight some of the issues both companies have been wrangling with, the situation is still far from dire.

Inpex On the credit rating agency’s decision to downgrade Inpex’s issuer rating to A2 from A1, Kailash Chhaya, a vice president for Moody’s and its lead analyst for Inpex, projected that the company’s weakened profitability, combined with rising adjusted debt related to Ichthys – the huge LNG export project that Inpex will operate in Australia – will weaken its key credit metrics over at least the next 18-24 months and probably beyond this point.

Ichthys has indeed proved a thorn in Inpex’s side. The company warned in September 2015 that first production would be as much as nine months late and that costs were already 10% ahead of the project’s original US$34 billion budget – hence the rising debt that Moody’s referred to.

Moody’s noted in its downgrade announcement that execution risks for Ichthys remain and that Inpex’s rating could be cut again in the event of significant further cost overruns or delayed production targets that result in financial deterioration for the company.

Any misstep on Ichthys “would be likely to delay recovery” for Inpex and lead to ratings pressure, the agency wrote. Other scenarios that could put Inpex under further downward rating pressure include a failure to maintain the adjusted retained cash flow/debt ratio of 20% to 30% that Moody’s expects.

On the other hand, if Inpex successfully completes Ichthys and achieves “expected improvements in retained cash flow,” the company’s rating outlook will stabilise, Moody’s said.

It was a similar story for JAPEX, with Moody’s downgrading the company’s issuer rating to Baa1 from A2, although here Chhaya referred to rising debt related to the company’s “large-scale investments”, without singling

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out a specific project.

JAPEX “The negative outlook reflects the current difficult operating environment” for JAPEX, as well as the “high level of execution risk still remaining on the company’s key overseas projects.”

JAPEX’s ratings outlook could stabilise if it is able to limit any profit falls by cost cutting and other measures aimed at improving its retained cash flow, Moody’s said. A senior official at JAPEX referred to efforts in this direction just last week, before the Moody’s announcement.

The company “should put every effort to reduce cost” and is working to do so across logistics, transportation and in its liquefaction project, the vice president of JAPEX’s Americas and Russia project division, Hajime Ito, said on the sidelines of a conference.

Ito also stressed the importance to JAPEX of its projects in Canada, saying that economic stability was a major determinant of where JAPEX invests. This commitment to Canada makes it unlikely that any efforts by JAPEX to boost its credit rating could include divestments in North America.

Its North America assets include a 100% stake in the 3.75 section of Block Hangingstone and a 75% stake in the block’s undeveloped parts, both via wholly owned subsidiary Japan Canada Oil Sands. JAPEX is also a stakeholder in British Columbia’s Pacific Northwest LNG project.

Ito at the same time flagged up mounting instability in the Middle East as a driver behind its diversification efforts. Increased output at Iraq’s Gharraf oilfield was, however, partly credited for a surge in JAPEX’s energy output in its latest fiscal year, making it also unlikely that it would seek to offload this stake.

Implications One area where the Moody’s downgrade will have repercussions on both JAPEX and Inpex is their ability to raise fresh debt.

There are no indications, however, that either firm is currently planning major issuances and – barring further cost overruns at Ichthys for Inpex – this should not present a major challenge.

It is also important to note that Inpex and JAPEX are far from alone in their treatment by Moody’s, and this is

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

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Week 6• 14 March • 2016

reflected by the fact their shares dipped only 0.6% and 1.9% respectively on March 7, following big gains in the week before the ratings announcement.

Moody’s said it had downgraded the two as part of a wider “recalibration” of its energy ratings on energy companies globally, to factor in its view that there is a “substantial risk” that oil prices could take several years to rise from current levels and might even fall further.

And “even under a scenario of a modest recovery from current price levels, E&P companies globally can expect a deteriorated financial profile with much weaker cash flows,” the ratings agency wrote.

A rush by both Inpex and JAPEX in recent years to expand overseas to secure Japan’s energy security at a

time when a cash-rich China has been cherry-picking international assets has left the two relatively indebted as well as painfully exposed to low oil prices, as highlighted

by Moody’s.

But both companies, to a large extent, dance to Tokyo’s tune and Japan’s government remains committed to increasing the amount of oil and gas production that Japanese firms have an equity share in. Major overseas asset divestments, therefore, look unlikely.

The Moody’s downgrade spells disaster for neither firm but could help focus minds within management and accelerate efforts to reduce costs. If the wake-up call results in real cost savings, Moody’s downgrade could benefit both companies in thelong term.n

Santos wraps up Kipper stake sale ASIA SANTOS has completed the A$520 million (US$386.8 million) sale of its stake at Kipper gas field in the Gippsland Basin offshore Victoria to Japan’s Mitsui & Co. Mitsui said on March 3 that its subsidiary Mitsui Exploration & Production Australia had taken the 35% interest as previously agreed on November 6, 2015. Other shareholders at Kipper include operators ExxonMobil and partners BHP Billiton, each with 35% stakes.

Kipper lies around 45 km from the coast of Victoria in water depths of about 100 metres. The field is part of ExxonMobil’s Kipper-Tuna-Turrum complex, which includes developments at the Tuna and Turrum oil and gas fields, launched in June and October 2013 respectively.

Kipper will commence later this year, according to ExxonMobil, and will produce from subsea wells, coolers and a manifold via a seabed pipeline to the platform at West Tuna. Gas from Kipper will then be sent to ExxonMobil’s processing plant in Longford near Sale in southeastern Victoria.

The field holds an estimated 620 billion cubic feet (17.5 billion cubic metres) in recoverable gas reserves, and an estimated 30 million barrels of condensate and LPG reserves.

While Santos will hope last week’s transaction helps soothe the anxiety of its investors, Mitsui believes its

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purchase is well placed to meet burgeoning gas demand on Australia’s east coast.

Three LNG plants, including Santos’ Gladstone GLNG (GLNG) plant, have launched on the east coast within the last 15 months.

Research from AME Group suggests output from upstream gas assets in the region will reach 180 million cubic metres per day by 2020. But reaching dwindling resources in shallow basins such as the Gippsland could present technical challenges.

AME’s report noted that newly discovered fields often held fewer associated liquids, with more impurities that may require processing.

Kipper has already suffered cost overruns owing to mercury encountered at the field, and Mitsui has said projects in the region would require continuous investment to keep up with demand.

Mitsui hopes domestic Australian gas assets such as Kipper will protect its asset portfolio against volatility in the global oil price.

The firm’s Australasian unit owns a 25% stake at Santos’ Casino, Henry and Netherby fields in Victoria, and a 49% stake in Westside’s Meridian Seam coal-bed methane (CBM) field in Queensland. All these projects supply gas to local networks.n

Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Shell sees Philippines FSRU FID in 2017 ASIA SHELL Philippines is finalising the technical aspects of its front-end engineering and design (FEED) study on the construction of a planned LNG terminal in the country. A final investment decision (FID) may be taken in 2017.

Shell Philippines Exploration’ managing director, Sebastian Quinones, said Batangas Bay, on the main island of Luzon, near Manila, could be the site of a floating storage regasification unit (FSRU). The official said the company needed to iron out details of the FEED before reaching an FID. Quinones said investors and company shareholders would only approve the project if there was a “good and viable plus-minus 10 percent estimate” on the total project cost. “Probably, this would be hundreds and hundreds of millions again,” he said. “I don’t think [the final decision] will be this year. It could be next year.”

The Philippine Star said supply from the Malampaya deepwater gas-to-power project was projected to run out by 2024, building an LNG import terminal would help

overcome any shortfall. Quinones said that once the FID was issued, it would take less than three years to install the FSRU terminal.

The Malampaya field supplies three gas-fired power plants on Luzon, the country’s most populous island, providing 40-50% of the island’s power generation needs.

“Energy projects like this take a long time. Remember, Malampaya took a decade ... that’s why we are already preparing for LNG as a fuel source to replace Malampaya,” Quinones said. “Hopefully, we can find something in between but now it’s too late to be able to develop something that can replace Malampaya. So, to bridge the gap would require LNG imports,” he added.

The Philippines’ first LNG regasification facility – the US$800 million Energy World terminal – is being completed in Quezon Province, on Luzon. It is scheduled to come on stream later this year or next year, which is at least two years behind schedule.n

Sino Australia O&G to be liquidated after misconduct ASIA THE Australian Securities and Investments Commission (ASIC) said on February 7 that it had appointed a liquidator to close down drilling services company Sino Australia Oil and Gas. The action was taken after a judge found substantial and serious misconduct and mismanagement at the company, ASIC said. The markets watchdog added that it would continue proceedings against the company and its former chairman.

Sino Australia Oil and Gas is a Chinese drilling services company, which is listed on the Australian Securities Exchange (ASX). An official liquidator has been appointed in order to wind up the company “on just and equitable grounds”, Sino Australia said in a press statement.

The chairman of the Chinese company had tried to transfer A$7.5 million (US$5.6 million) to a bank account without disclosing the reasons, ASIC said.

“This is my message to overseas companies wanting to list here: in Australia investors value market integrity over everything else and that means we expect every decision to be taken with the investors absolutely front of mind,” said ASIC Commissioner John Price, according to a

14

report in The Australian Financial Review.

“Our job is to make sure companies that come in through listing rules reflect the quality and depth of the broader market and have a coherent investment story,” added ASX listing and issuer services general manager Max Cunningham.

There are mounting concerns that the ASX is hosting Chinese companies that have complex ownership structures and assets that cannot be verified by independent auditors, the report said.

One of the biggest concerns is that investors in small Chinese companies that are listed on the ASX may have very little access to information about the holding company in China, it added.

Some of these companies are reportedly held through a series of complicated contractual arrangements, rather than by a direct equity stake, making it more difficult to get background information on the firm.

In addition, although Australian directors nominally run some of these firms, the company in China often makes the biggest business decisions, the report added.

Sino Australia is based in Daqing in northeastern China, the country’s largest oil-producing area.n

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Petrolimex posts strong 2015 results ASIA PETROLIMEX has continued its turnaround with an impressive set of financial results unveiled for 2015.

The company generated an after-tax profit of more than 3.1 trillion Vietnamese dong (US$137.8 million) last year, compared with a 9.1 billion dong (US$408,000) loss posted in 2014.

Petrolimex’s 3.8 trillion dong (US$170 million) pre-tax result was reportedly more than 10 times higher than in 2014, reflecting the huge inventory losses booked by Petrolimex’s Singapore unit that year.

Petrolimex’s deputy general director, Tran Ngoc Nam, attributed the gains to buoyant Vietnamese growth of around 6.68%. The state-owned company saw a particularly strong performance at its petrochemical, jet fuel, insurance and transportation segments.

Nam noted domestic fuel sales by volume had grown by 8% year on year in 2015, while inventory losses eased as month-on-month declines in oil prices narrowed compared to 2014. This allowed Petrolimex to reduce provisional funding for oil price fluctuations in 2015, Nam said. Petrolimex has experienced significant growth

in profit margins over the last year, with the company reporting a 49% increase in profits from products and services in the first half of 2015. The higher margins reportedly came despite Vietnamese gasoline prices falling by 20% in the second quarter.

Petrolimex’s full-year results came after JX Nippon’s reported the acquisition of a 10% stake in the company in February. According to Nikkei Business Review, JX will pay 20 billion yen (US$117 million) in a deal expected to inject foreign investment into Petrolimex’s 200,000 barrel per day refinery project in the Van Phong Economic Zone.

Since 2011, Petrolimex has been looking to cut the state’s share of the company from around 95% to 65%.

With Vietnam’s sole refinery, Dung Quat, satisfying roughly 30-40% of domestic demand, Japanese investors are looking to tap Vietnamese capacity developments in response to falling demand in their home market.

JX’s rival Idemitsu is thought to have promised US$9 billion in investment for PetroVietnam’s 200,000 bpd Nghi Son refinery in Thanh Hoa Province, in which the Japanese company holds 35.1%.n

Origin faces restructuring to cut debt ASIA DEBT-BURDENED Australian generator and retailer Origin Energy is considering de-merging its power assets from its developing gas business as the company continues to come under investor pressure.

Origin, which produces 13% of Australia’s electricity and supplies 4.3 million customers – about 20% of the population – has accumulated debts of around US$9.2 billion through its 37.5% stake in the Australian Pacific LNG project (APLNG) in Queensland.

Although Origin’s APLNG project has just moved into first phase production and export, a gas glut in the region is undermining plans to secure long-term supply contracts, especially with China, said the Australian Financial Review. Origin managing director Grant King told local media last week that a demerger and potential mergers were on the table as part of efforts to restore shareholder value. The company had not ruled out anything, he said.

“The comments come as some investors suggest a demerger between Origin’s core energy markets business and its growing oil and gas business is a natural next step for Origin once the APLNG project is fully on stream and

15

reaches technical completion in about 12 months,” the Sydney Morning Herald said.

Origin’s partners in the APLNG project are ConocoPhillips and Sinopec. Origin has already initiated action such as a cash-raising share issue, capital expenditure cuts totalling US$1 billion and the planned sale of some renewable projects, including a geothermal plant in Indonesia.

In Australia, its power portfolio is fuelled by coal, gas, wind and solar. It operates the country’s biggest power plant, the 2,880-MW coalfired Eraring thermal power plant (TPP) in New South Wales.

Last August, Origin sold its controlling 53% stake in Contact Energy, New Zealand’s second biggest generator with 22% of the market, for US$1.6 billion. That sale was intended to reduce debt and try to improve its credit rating but, as analysts noted, it also diminished a reliable revenue stream.

Despite its share in the APLNG project Origin still only sources 20% of its gas needs from its own resources, even though its operates six gas-fired TPPs.n

Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Vitol quietly exits Russia FSU OIL trading giant Vitol has reportedly sold its last remaining Russian assets as the firm looks to wind up its Russian portfolio to refocus on its core trading business.

Citing sources close to the deal, the Russian edition of Forbes said on March 1 that Vitol had offloaded the North Irael oilfield in the northern region of Komi. The company also sold the nearby Sotchemyu oilfield and the East Turyshevskoye field in Komi, which were operated by Recher-Komi and Kosyuneft respectively. These entities were reputedly controlled by the oil trader’s subsidiary, Vitol Arawak Energy Russia, and RF Energy Investments.

The deal was reportedly closed in late 2015 for between US$50 million and US$100 million, according to the sources.

A Vitol spokesperson was not available for comment when contacted by NewsBase.

The assets were said to have been bought by Swedish explorer and producer Petrogrand, which acquired another three other licences in the Komi region in December 2015. But on March 2 Petrogrand denied reports that it had bought the acreage from Vitol, saying in a press release that its purchases late last year “were not in any

way related” to the Vitol sale.

The three oilfields annually produce up to 500,000 tonnes (1,370 barrels per day) of Urals crude, which is pumped into the Transneft pipeline system and mainly sold to domestic refineries or exported abroad.

Analysts argue that Vitol is looking to shed costly upstream assets to focus on its core trading business. “[Vitol] is now optimising its asset portfolio, getting rid of less efficient and less relevant ones,” Alexander Kornilov, senior energy analyst at Russian investment firm Aton, told NewsBase. “The purchase of Vitol’s assets by the Swedish company only stresses that the assets look attractive in the current oil price environment, given that Russia is one of a few large oil-producing nations that still sits mostly on conventional reserves,” he added.

Reuters quoted industry sources on March 3 as saying that Vitol was seeking to sell a stake in its wholly owned oil storage subsidiary VTTI as it looks to mitigate risk surrounding oil futures and fluctuating demand. VTTI is one of the group’s prize assets, as demand for oil and oil product storage space is at a premium amid the global supply glut and soft demand.n

Gazprom secures Chinese loan FSU THE Bank of China will lend Gazprom 2 billion euros (US$2.17 billion) in what is the Russian firm’s first funding deal with a Chinese bank.

Gazprom announced it had signed the five-year facility on March 3, following a ceremony attended by Andrey Kruglov and Wang Huabin, the deputy managers at Gazprom and Bank of China respectively.

With Western sanctions effectively barring Russian companies from US and EU capital markets, last week’s deal marks another foray by Chinese lenders into Russian energy financing. Most notably, Novatek is still awaiting a financing package for its Yamal LNG project, which aims to raise US$12 billion from Chinese funds. In 2013, Rosneft took out a long-term US$2 billion loan with China Development Bank that was secured by a crude supply contract. The firm signed a 25-year supply deal worth US$270 billion with CNPC in the same year.

China has often offered funding in return for key stakes in Russian energy projects, thereby supporting Beijing’s broader goal of strengthening energy security. In 2013, China’s CNPC bought a 20% stake in the Yamal project, later clinching a 15-year agreement to purchase

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the terminal’s fuel. Novatek secured US$792 million in financing for Yamal from China’s Silk Road Fund in December. In exchange, the fund received a 9.9% stake in the project. Chinese financing has featured as part of Moscow’s so-called Asian pivot in pursuit of alternative markets for Russian oil and gas. It is uncertain whether the Bank of China loan is linked to Power of Siberia, a plan to build a 38 bcm per year pipeline linking Russia’s Far East to China’s eastern seaboard. Capital spending on the project is pegged at 168 billion rubles (US$2.34 billion) for this year alone. The overall cost of the project is estimated at US$55 billion.

Progress on the pipeline plan has slowed with China’s weakening economy and the launch of alternative supplies from LNG plants in Australia. Beijing is expected to press the Russian giant for a better price for gas supplies and last week’s loan agreement could strengthen its bargaining position. China is essentially wielding its financial muscle to secure more favourable supply deals at a time when Russian companies have limited options. It is also able to grab Russian energy assets at a time when their value is depressed by low oil prices.n

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Tethys clinches financing deal with Kazakhstan’s Olisol FSU TETHYS Petroleum said last week it had reached a final agreement with Kazakhstan-based Olisol, concluding months of negotiations and uncertainty over the former’s ability to meet its financial obligations.

Tethys, which is listed on the Toronto Stock Exchange (TSX), has operations in Kazakhstan, Tajikistan and Georgia.

Under the amended agreement of March 2, the company will receive US$1 million out of a previously agreed debt facility of US$15 million. The remaining facility, plus US$6.25 million of accrued interest, will be converted into shares in Tethys, giving Olisol 15.6% of the company’s net worth.

Tethys will sell an additional 181 million shares to the Kazakh investor, although the price has not yet been decided on. This will replace a previous plan under which Olisol would buy 150 million shares and support a further offering of 50 million shares (both at a price of C$0.17 (US$0.13) per share).

Once this process is wrapped up, Olisol’s stake in Tethys will ramp up to 42%.

Additionally, Olisol has agreed to raise US$10 million in funding from a Kazakh bank for one of Tethys’ subsidiaries within 60 days. “Principals at one potential Kazakh Bank have already provisionally approved offering the Kazakh loan, subject to satisfactory due diligence refreshment,” Tethys said in a statement.

The company, registered in the Cayman Islands, has

stressed the importance of the deal. “Tethys now has a strong in-country strategic partner which has committed to becoming a minority shareholder and who will help the company in its objective to supply the growing energy demand in China,” John Bell, Tethys’ executive chairman, said in a statement.

Once the deal is closed, Bell and three other board members will step down. “We leave the board having steered Tethys into a company focused on capital efficiency and cost discipline, well placed to become a strong platform for future growth,” Bell said.

Last month, Tethys’ shares surged to C$0.05 (US$0.037) on the TSX, from a historic low of C$0.03 (US$0.024), as the amended deal with Olisol began to take shape.

The agreement should end Tethys’ long search for a partner to ease its financial woes. After the company scrapped plans to sell its Kazakh operations last year, it entered into takeover talks with London-listed Nostrum Oil & Gas. But the latter pulled out when one of its biggest shareholders rejected the price of the offer. Tethys then began negotiations with Olisol, a little known energy investment vehicle in Kazakhstan.

Sustained low oil prices, legal skirmishes with the Tajik government and stagnating production figures have taken their toll on Tethys’ performance. It posted a loss of US$31.1 million in the first nine months of 2015, up from a US$11.1 million loss a year earlier.n

Tethys Petroleum assets

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Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

NewsBase Ltd. 108 Dundas Street, Edinburgh EH3 Tel: +44(0)131-478-7000 Email: research@newsbase.com Web: www.newsbase.com

ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Gazprom Neft sees profits slide on forex losses FSU GAZPROM’S oil division last week unveiled a 109.66 billion ruble (US$1.53 billion) net profit for 2015, 10.2% lower than in the previous year as a result of heavy foreign exchange losses.

Gazprom Neft’s result included a 21.22 billion ruble (US$296.9 million) net loss for the fourth quarter, which was 22% higher than the 17.4 billion ruble (US$243.63 million) loss recorded a year earlier. Full-year revenues decreased 2.1% year on year to 1.66 trillion rubles (US$ 23.15 billion).

Russia’s fourth largest crude producer saw a 261.6% quarter-on-quarter rise in other expenses, which included writes-downs worth 11.6 billion rubles (US$162.42 million) and 4 billion rubles (US$56 million) for its upstream operations in Iraq and Russia respectively.

Earnings saw growth for the full year but slipped quarter on quarter. Adjusted EBITDA for 2015 was 18.2% higher at 404.8 billion rubles (US$5.6 billion), while quarterly EBITDA decreased 17.7% quarter on quarter to 92.6 billion rubles (US$1.29 billion).

Gazprom attributed the quarterly performance to repairs and upgrades at the Moscow and Omsk refineries from September to December 2015 as well as seasonal factors. The company suffered exchange rate losses of 26.9 billion rubles (US$375 million) in the quarter, much of which was owing to the re-evaluation of

Gazprom Neft’s loan portfolio held in rubles. Gazprom Neft’s unit breakdown of earnings illustrated the extent of depreciation and how it had affected margins. EBITDA per barrel of oil equivalent fell 1.8% in 2015 when denominated in rubles, but was 38.6% lower in US dollar terms. Crude and condensate production for the year rose 8.3% to 1.14 million barrels per day, while processing fell 0.9% to 995,479 bpd.

The company saw higher output at the SeverEnergia, Prirazlomnoye and Novoport projects. Gazprom Neft’s takeover of an operating stake in the NorthGas joint venture from Novatek also helped raise production, the firm said.

Regarding its downstream segment, director Vladimir Konstantinov told investors the company’s refining margin for the fourth quarter ranged from US$5-10 per barrel, outperforming full-year averages of between US$4-6 per barrel. Gazprom Neft is now mulling whether to cut its dividend for the second half of 2015. VTB Capital analysts quoted by Vedomosti even warned the payout could be scrapped altogether. The company paid shareholders 5.92 rubles (US$0.083) per share for the first half of last year, equivalent to 25% of net profits. Gazprom Neft has set capital spending at 362 billion rubles (US$5.13 billion) for 2016, slightly up on last year’s estimated spend of 343 billion rubles (US$4.74 billion).n

Gazprom Neft asset map

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Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

NewsBase Ltd. 108 Dundas Street, Edinburgh EH3 Tel: +44(0)131-478-7000 Email: research@newsbase.com Web: www.newsbase.com

ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Sete Brasil on brink of bankruptcy

Failure to agree new rig leasing terms with Petrobras could see Sete Brasil go bust.

LATIN AMERICA SETE Brasil looks no closer to resolving its myriad financial problems. The rig leasing firm, which was set up

by Petrobras along with a syndicate of investors in 2011, is now in a stand-off with its parent company over plans to cut the number of rigs on order.

Sete has been sliding towards bankruptcy for over a year now. Emergency cash infusions have not masked the fact that its operations generate zero cash flow.

The problems at Petrobras have halted payments from the state-run oil company, while the cost of servicing its dollar debts have increased with the collapse of the Brazilian real. It was reportedly set to file for bankruptcy protection last month if Petrobras presented it a proposed revised rig leasing agreement that management considered non-viable. Though Petrobras’ subsequent proposal was deemed unfit for purpose, the majority of shareholders pulled back from the bankruptcy option.

Instead Sete’s management is drawing up a counterproposal it hopes will be good enough to tempt cashstrapped Petrobras into signing an agreement that will prove financially feasible.

Petrobras had proposed cutting the number of rigs it leases from Sete from 29 to just 10 for five years with an option for another five years at a cost of US$300,000 per day. The original proposal was for the company to take out 15 year leases at a rate of US$390,000 per day.

The problem is that investors in Sete have already sunk around US$2 billion into the venture and piled up another US$4.5 billion in debt.

The Petrobras proposal would imply that instead of Sete generating US$60 billion over 15 years it would only make US$5.5 billion in five years. The reduced order book from Petrobras would not even allow it to service its debts, the firm has calculated.

The stand-off is freighted with conflicts of interest.

Creditor banks and Petrobras, who with a 5% holding is also Sete’s only client to date, are also shareholders and oppose bankruptcy protection. This needs 85% approval

from shareholders with Petrobras unable to vote.

Any bankruptcy would likely spread further chaos through Brazil’s crippled rig-building industry, which has borne the brunt of the financial crisis afflicting Petrobras.

There are already concerns that a raft of lawsuits would be filed by shipyards should the company seek protection.

Several rig builders have already made impairment charges on their Sete contracts.

Furthermore, one investor in Sete – Washington registered EIG Partners– has initiated legal action against Petrobras. It is seeking US$221 million in the US for losses it says it has incurred by investing in the rig leaser.

The risk of further such actions might help keep in check those within Petrobras who, in light of the company’s financial problems and the wider retraction under way in the sector, have argued for letting Sete going bust. But with many of the rigs contracted by Sete from yards well on the way to completion, Petrobras might figure it could pick them up at far lower rates direct from their manufacturers should the leaser go bust.

With Petrobras fighting for its life and controlled by a government that is itself broke and desperate to avoid having to bail it out, this latter option might yet be the most attractive. It might also explain Petrobras’ revised rig-leasing proposal to Sete that, given its position on both sides of the negotiating table, the company must have known would be dismissed as a non-starter.

Looking ahead to what might happen next, “right now anything is possible,” former Petrobras manager, Adriano Pires, who is now president of the Brazilian Infrastructure Center, told NewsBase.

“Sete’s situation is very complicated. Its customer Petrobras is broke. The market is offering rigs cheaper than it is. I think it is already condemned company. It doesn’t build rigs but orders them from manufacturers. If it fails, these shipyards will be able to negotiate directly with Petrobras which can negotiate the eight or ten rigs it needs, not the 29 that Sete was created to supply.”n

Brazilian shipyards

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Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

NewsBase Ltd. 108 Dundas Street, Edinburgh EH3 Tel: +44(0)131-478-7000 Email: research@newsbase.com Web: www.newsbase.com

ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Talara Oil & Gas creates new venture targeting Peru LATIN AMERICA US independent Talara Oil & Gas has formed a new venture aimed at acquiring oil and gas properties first in Peru, and later in other parts of North and South America.

Manuel Pablo Zuniga-Pflucker will be appointed president and CEO of the newly formed company, Talara Oil & Gas said in a press statement. Zuniga-Pflucker was previously CEO at Houston-based BPZ Energy, which had assets in Peru and Ecuador. The company filed for Chapter 11 bankruptcy in March 2015.

The company has closed its initial round of funding having secured seed capital to “allow the management team to focus on multiple opportunities,” said Zuniga-Pflucker.

“We are excited to launch this venture at a time when oil and gas companies are looking for ways to divest properties in an effort to preserve their cash,” he said. “We will focus initially on Peru, where we believe there are opportunities to build a portfolio of onshore assets that, with proper management and the application of appropriate technologies, are sustainable at today’s commodity prices,” he added.

Zuniga-Pflucker said that in the longer-term the company plans to look at assets in other parts of the

Americas that would provide strategic growth.

The new CEO will be joined at the helm by Greg Smith and Chuck Fetzner. Smith will lead the finance, treasury and capital markets strategy. He previously worked at Houston-based Energy XXI and BPZ Energy.

Meanwhile Fetzner will lead the new company’s asset acquisitions and development. Fetzner previously worked at Apache Corporation, Sun Exploration and Production and Oryx Energy.

BPZ had licence contracts covering 1.9 million net acres (7,689 square km) in four blocks in the northwest of Peru. It had a 51% working interest in Block Z-1 with its joint venture partner, Toronto-based Pacific Ecploration & Production (Pacific E&P).

A number of international oil companies (IOCs) have retreated from Peru in recent years, citing difficulties with indigenous communities and the slow pace of projects.

In 2014, Norway’s Interoil transferred all its local operations to Peru’s United Oilfields, following a dispute with state-run Petroperu over the operatorship of blocks III and IV. Canada’s Talisman Energy and Brazil’s stateowned Petrobras have also wrapped up operations in Peru in the last few years.n

Petrobras finds potential buyer for Argentine assets LATIN AMERICA

BRAZIL’S state-run oil company Petrobras said on March 2 it had started talks to sell its Argentine assets to Pampa Energia.

The negotiations will be “exclusive for 30 days, and could be extended for the same amount of time,” Petrobras said in a filing with the Buenos Aires Stock Exchange.

On the block is a 67.2% stake in Petrobras Argentina, a leading energy player in the country. Petrobras has been trying to sell the stake since last year, part of a wider divestment plan in response to a global plunge in oil prices since the middle of 2014. The company said it wanted to raise US$15.1 billion from the divestment scheme by the end of 2016.

The need to offload assets has increased since then, as the Rio de Janeiro-based company is struggling through a corruption scandal in Brazil that has worsened

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its financial outlook. Last year, Petrobras invited four companies to bid for the Argentine assets, which it valued at more than US$1 billion.

Argentine companies Pluspetrol, Tecpetrol and Pan American Energy, that latter of which is controlled by BP, did not make bids, and the fourth invitee, Argentina’s state-run energy company YPF, offered US$920 million.

Petrobras said YPF’s offer was too low, opting instead to suspend the sale and then reopen it in January.

Pampa Energia would benefit from the acquisition by widening its interests not only in power, where it is a leader in Argentina, but also in oil and petrochemicals.

The company, founded in 2005, has acquired large power interests, and expanded into the downstream sector through Petrolera Pampa. The latter is now producing tight gas in the southwest in a partnership with YPF. Petrobras Argentina produces around 14,000 barrels

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

NewsBase Ltd. 108 Dundas Street, Edinburgh EH3 Tel: +44(0)131-478-7000 Email: research@newsbase.com Web: www.newsbase.com

ENERGY FINANCE WEEK

Week 6• 14 March • 2016

per day of oil, or 2.6% of the 532,000 bpd national total, and 7 million cubic metres per day of gas, or 5.8% of the 120 mcm per day national total, according to data from the Argentine Oil and Gas Institute, an industry group.

It also has interests in the midstream and downstream sectors, plus electricity and petrochemical assets. The assets include a 30,500 bpd oil refinery and petrol station network.n

Pemex ponders sell-off strategy LATIN AMERICA THE new head of Pemex, Jose Antonio Gonzalez Anaya, has been hard at work since taking over last month. His first task was to work out which projects are profitable at an oil price of US$25 per barrel – anything more expensive is officially out. Now he is looking at what to sell.

In a meeting with deputies last week, Gonzalez Anaya stressed that Pemex was facing a liquidity crunch and would focus on profitable ventures, deferring others worth 64.9 billion pesos (US$3.6 billion) until market conditions improve. He said he would use all the instruments at Pemex’s disposal as a result of Mexico’s energy reform.

It is a line that the new director general has trotted repeatedly since taking the helm, though he has yet to spell out his plans in detail. Mexico’s energy reform relieves Pemex of the burden of shouldering all investment alone in both the upstream and downstream sectors, paving the way for farm-outs and joint-ventures that have been on the table without progress for months.

Gonzalez Anaya is tasked with implementing cuts of more than US$5 billion after Pemex reported a US$30 billion net loss in 2015, nearly double the previous year. He has earmarked 27.5 billion pesos (US$1.5 billion) in upstream projects to be deferred, as well as 35.4 billion pesos (US$1.9 billion) in the downstream, principally refinery activities. What this means, in large part – although he has not spelled it out publicly – is a speeding up of joint-venture deals in Pemex’s six lossmaking refineries. He hopes that partnerships will also mitigate the need for Pemex to lay off too many staff since they could be redeployed in the new alliances. Pemex announced at the end of last year that it was in talks on stake sales for three of its refineries. It is pinning its hopes on strong interest from US operators, though it has not yet said which companies might be interested. One thing Gonzalez Anaya has made clear, however, is that

21

peripheral activities will be chopped. Asked last week whether such units as Pemex’s loss-making fertiliser business could be sold, he said: “It is possible.”

Pemex’s investment in fertiliser production has not been a success. The business racked up losses of 271 million pesos (US$15 million) at the end of 2015.

Gonzalez Anaya said that talks on pension benefits were being reopened with the company’s powerful union, though he stressed his aim to protect jobs as far as possible. He has not yet given a job reduction target.

But monetisation of Pemex assets, including potential sales, is separate to the US$5 billion already earmarked to be saved. “They are on the table and we’re going to continue making progress,” he said last week.

The Pemex chief was due to be quizzed on his costcutting plans by the plenary of Congress on March 8.

Deepwater Among the upstream activities for which Pemex is now urgently seeking partners is 10 billion pesos (US$560 million) in investment in deepwater exploration and production activities that the company had been undertaking. It hopes to bring in a partner to take over that financial burden – though it does not mean Pemex is writing off its deepwater participation entirely.

Mexico’s showcase deepwater auction is due to be held on December 5, and it would be a political embarrassment if Pemex were absent. The company has always expected to team up with others for the deepwater tender round, as the projects are so costly the expense must be shared.

This remains the plan and Pemex claims potential bidders are keen to partner with it because of its local knowledge. Gonzalez Anaya is clear-sighted about the challenges ahead and he has a reputation as an unflinching restructurer. Expect announcements soon.n

Andrew Kemp, Editor, Asia Pacific and China Oil & Gas • Email: andrew.kemp@newsbase.com Anna Kachkova, Editor, North America Oil & Gas and Unconventionals • Email: annak@newsbase.com Joe Murphy, Editor, FSU Oil & Gas • Email: joem@newsbaase.com Andrew Dykes, Editor, Renewables • Email: andrewd@newsbase.com

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ENERGY FINANCE WEEK

Week 6• 14 March • 2016

Genel shocks with Taq Taq reserves downgrade MIDDLE EAST ANGLO-TURKISH Genel Energy shocked markets in late February by halving the reserves estimate for its most prized asset – the Taq Taq field in the Kurdistan Region of northern Iraq. The firm quantified the financial impact in annual results delivered three days later, recording a trebling of 12-month losses on the back of a massive impairment charge.

Executives attempted to remain upbeat as the company’s share price plunged, pointing to low production costs across the company’s Kurdish assets – ensuring profitability even at low prices – and to the potential profits to be reaped as delayed gas development plans for the area approach implementation. The beginning and anticipated continuation of crude export payments from Erbil were also prominently highlighted, strengthening the current and future balance sheet while enabling essential investment to proceed.

Nevertheless, production, revenue and capital expenditure guidance were all set substantially below either planned or actual figures for 2015 – with Taq Taq’s output projected to decline steadily over the coming three years.

A trading and operations update in January had noted that a new Competent Person’s Report (CPR) for Taq Taq had been commissioned as part of a review of the field’s reservoir model and future investment profile.

However, the announcement on February 29 that the CPR by Calgary-based McDaniel & Associates had concluded that total proven and probable (2P) reserves stood at 356 million barrels at the end of 2015, only 172 million barrels of which remained to be produced – compared with the 683 million barrels estimated at the end of 2011 – came as such a blow to the company that chairman and founder Tony Hayward felt obliged to reassure analysts that “whilst this is a major setback, it is by no means the end of Genel”.

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The downgrade was attributed to lower fracture porosity at the field’s shallowest reservoir. Fewer remaining barrels to be sold at a lower price than previously projected prompted a US$1.038 billion impairment charge, in turn widening the firm’s 2015 losses to US$1.16 billion from US$312.8 million the previous year.

Net production across Genel’s operations – which at 84,900 barrels per day last year narrowly missed guidance of 85,000-90,000 bpd despite a 22% increase on 2014 – is anticipated to fall in 2016 to 60,000-70,000 bpd as Taq Taq’s declining output offsets production gains from the firm’s stake in the 675 million barrel Tawke field, operated by Norway’s DNO: gross production from Taq Taq is projected to fall from 116,000 bpd in 2015 to 80,000 bpd this year and then to 65,000-75,000 bpd and 50,000-70,000 bpd in 2017 and 2018 respectively as the firm pursues “a discretionary investment programme aiming to maximise the value of the remaining reserves” while targeting prospective resources in a deeper Cretaceous reservoir.

Company-wide capital expenditure is to be reduced, however – although not as dramatically as last year’s 77% cut to US$157 million – to US$80-120 million, with actual spending said to be dependent largely on continued regular payments from the Kurdistan Regional Government (KRG) as enshrined in the new formalised mechanism initiated last month.

“We will aim to progress our oil development in a way that is broadly cash flow neutral to Genel in the near term,” Hayward explained.

Revenues – which dropped by 34% to US$344 million in 2015, falling short of the US$350-375 million guidance – are anticipated to slump even lower in 2016 to US$200-275 million.

Both Hayward and CEO Murat Ozgul euphemistically

Ed Reed, Editor, Africa Oil & Gas and LNG • Email: edreed@newsbase.com Richard Lockhart, Editor, Africa, Asia and Central Europe Power • Email: richardl@newsbaase.com Ryan Stevenson, Editor, Europe and Latin America Oil & Gas • Email: ryans@newsbase.com Ian Simm, Editor, Middle East Oil & Gas and MEA Downstream • Email: ians@newsbase.com

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Week 6• 14 March • 2016

expressed “disappointment” at the Taq Taq downgrade in the results statement but stressed the general robustness of the business ensured by production costs at both Kurdish fields of less than US$2 per barrel and a breakeven Brent oil price of around US$20 per barrel.

Balance sheet strength was also trumpeted, with a combination of KRG payments totalling US$148 million and local sales more than covering costs and debt service to leave a positive cash position of US$455 million at year-end.

However, the magnitude of the Taq Taq miscalculation led analysts to recall the company’s past exploration failures – forgotten in the wake of the huge apparent successes in Kurdistan – and to note that the results also reported withdrawal from licences in Cote d’Ivoire, Ethiopia and Morocco, while the general sense of optimism surrounding Kurdistan’s underdeveloped

hydrocarbons potential was – at least temporarily – cooled. While insisting on the continued attractiveness of the company’s Kurdish oil activities, Genel officials were particularly bullish about the prospects for the development of gas reserves at the territory’s Bina Bawi and Miran fields taking off during the coming year, following the two licences’ consolidation in September.

A detailed timeline for the upstream and midstream components of the project – planned to supply gas to Turkey under an intergovernmental agreement struck in 2013 – was laid out.

Hayward summed up the firm’s future strategy as being “to maximise the potential of our KRI [Kurdistan Region of Iraq] oil assets and commercialise our KRI gas business, while seeking growth through the drill bit and the selective pursuit of value accretive M&A [mergers and acquisitions] opportunities”.n

Beijing strengthens Iraq ties with Missan refinery investment MIDDLE EAST THE long-delayed project to develop a major greenfield refinery in the southeastern Iraqi province of Missan was formally launched in late February by Oil Ministry officials and a consortium of Chinese and Swiss-based investors.

The news counters scepticism surrounding the deal provisionally struck more than two years ago.

Should the project proceed, it would become the first to succeed in securing private finance out of four such schemes planned by Baghdad to ease an acute domestic fuel shortage, induced by declining output from existing facilities and rapid consumption growth – forcing resort to costly imports and provoking popular protests.

The involvement of Chinese state banks – lending newfound credibility to the Missan project – forms part of a general deepening of Beijing’s involvement in Iraq’s upand downstream energy infrastructure, also encompassing investment in pipelines and oilfield operations.

The planned new refinery is a joint venture owned 15% by Swiss-based Satarem – the little-known firm which signed the original memorandum of understanding (MoU) with the government to develop the facility in late 2013 – and the remainder by a Chinese firm identified as Wahan and state-owned Missan Oil Co. (MOC).

Crucially, financing for the project, the cost of which was initially pegged at around US$6 billion, has apparently been agreed with China Development Bank and Export-Import Bank of China, with Deputy Oil Minister Dhia Jaffar emphasising during the groundbreaking ceremony on February 25 that the Iraqi

23

government would not be required to contribute funds.

The proposed refinery will have capacity of 150,000 barrels per day and is designed chiefly to provide highquality fuel to the local market. The original MoU, naming Saterem as the sole investor, attracted scepticism and strong criticism centring on the company’s inexperience in refining and purported lack of financial capacity to implement such a large project.

Parliamentary investigations were initiated into alleged corruption on the part of the then-government of former prime minister Nouri al-Maliki and deputy prime minister for energy Hussain al-Shahristani.

Also provoking doubts was Baghdad’s poor track record in attracting the private investment sought in all four planned refineries – at Karbala, Kirkuk, Missan and Nasiriyah.

A previous agreement to develop the Missan facility signed in 2011 with Egyptian private equity firm Citadel Capital was abandoned, while the US$6 billion contract to build the 140,000 bpd refinery at Karbala, 100 km southwest of Baghdad, was awarded on an engineering, procurement and construction (EPC) basis to South Korea’s Hyundai Engineering & Construction in early 2014 after efforts to attract private investors failed.

Oil Ministry spokesman Assim Jihad made reference during the Missan launch event to the largest of the proposed projects, for a 300,000 bpd facility at Nasiriyah in the southern Dhi Qar province. Attempts to include the refinery in an integrated venture also entailing

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development of the 4 billion barrel Nasiriyah oilfield stalled in mid-2014 in the wake of the Islamist militant invasion.

However, following the creation in January of the new state-owned Dhi Qar Oil Co. (DQOC) to assume management of the province’s assets previously handled

by South Oil Co. (SOC), officials said the intention was to revive discussions with the international oil companies (IOCs) that had previously expressed interest in the development – including Russia’s LUKoil and PetroChina.

In November, the latter had also been linked to development of the oilfield – in that instance in return for investment in the long-delayed, urgently required Common Seawater Supply Facility (CSSF) to provide treated water for injection across the southern oilfields – but the plan appears to have been superseded by a provisional agreement reported last month with the federal government for a consortium led by fellow

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Chinese parastatal China Petroleum Pipeline Bureau to invest in the CSSF. Beijing is also dominates upstream activity in Missan. PetroChina operates the province’s most productive oilfield, Halfaya, where output reached 200,000 bpd in 2014 and is being expanded to 400,000 bpd. Meanwhile, sister firm China National Offshore Oil Co. (CNOOC) leads a consortium holding the so-called Missan Oil Fields licence calling for production from the Abu Ghraib, Buzurgan and Faqqa fields to be raised to 450,000 bpd from around 100,000 bpd when the contract was signed in 2010. Following a visit to China

by Iraqi Prime Minister Haider al-Abadi and Oil Minister Adel Abd al-Mahdi in December, the two countries signed an MoU to establish a “long-term and comprehensive strategic partnership on energy co-operation” to include investment in production, transportation and refining, according to an oil ministry statement.n

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AFRICA

Two banking consortia offer US$325 million for Egypt’s Assiut refinery The state-run Egyptian General Petroleum Corporation (EGPC) has received two banking offers to secure around US$325 million, a senior source familiar with the matter said.

The financing will go for Assiut Oil Refining Company (ASORC)’s Hydrogen Cracking of Mazut Complex project, of which the investment cost ranges between US$1.3-1.6 billion. The project aims to convert low-valued mazut, the surplus of the south after natural gas delivery, into higher-valued products required by the market. It also seeks to maximise the benefit of the infrastructure and the available utilities of the company, thus achieving a high return.

The first offer was made by a consortium of several banks, notably Banque Misr and HSBC. The second offer is led by the National Bank of Egypt (NBE), which acts as a financial adviser, alongside some foreign banks, the source added. EGPC is expected to choose one of the two offers within the first half of 2016, so as to proceed with the financing process, the source stated. Moreover, the project is set to generate production of 1.4 million of diesel, 105,000 tonnes of butane, 389,000 tonnes of Naphtha, 346,000 tonnes of coal, and 75,000 of sulphur per year.

AMWAL ALGHAD (EGYPT), March 6, 2016

Egypt’s EGAS makes first LNG payments for year Egypt’s state-owned EGAS has made its first payments to LNG suppliers

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since payment terms for deliveries were extended, trade sources said.

Egypt imports around six to eight cargoes of LNG per month and traders said that until last week EGAS had not paid suppliers since December when it extended payment terms to 90 days from the usual 15 days, due to the country’s foreign currency crisis.

EGAS head Khaled Abdel Badie said his company has made all payments that were due on LNG shipments but did not specify whether these were the first payments this year. “We agreed with the companies to paying dues owed to them over a period of 90 days, and we are committed to this payment process,” he said.

Egypt became a major market for LNG shippers after the launch of two floating import terminals last year as the country looks to plug an energy shortage that has halted industrial production during summer months and caused rolling blackouts.

REUTERS, March 7, 2016

VRA owes Ghana Gas US$250 million for processed gas The Volta River Authority, main downstream off-taker of lean gas, owes Ghana National Gas Company (Ghana Gas) up to US$250 million for processed gas. This was disclosed when the new board of Ghana Gas visited the Atuabo Gas Processing Plant to familiarise themselves with the operations of the company. The board assured the management and staff of the company of measures to improve the financial options of the company. Board chairman of Ghana Gas John Armstrong Yao Klinogo said it would also put in place policies and programmes to make the company financially independent and to ensure settlement of indebtedness by offtakers of the company’s products.

The board has been challenged by the Energy and Petroleum Minister

Armah Kofi Buahto to end the country’s intermittent gas shortage challenges during its inauguration on February 4, 2016. Ghana Gas will soon commence the construction of a new gas plant, company CEO Dr George Sipa Yankey said.

In an interview with Accra based Citi FM, he said the construction of the new plant will commence once the new board approves the project.

PULSE (GHANA), March 4, 2016

Japan to fund Kigali power networks in Rwanda The governments of Rwanda and Japan have signed a financing agreement, worth US$18.4 million (about 14 billion Rwandan francs), aimed at boosting electricity distribution networks in the City of Kigali. The funds will specifically be injected in the construction of Ndera substation and the Murindi and Kabuga power-switching stations, both in Gasabo District, according to minister for finance and economic planning Claver Gatete. The fund will go toward procurement and installation of equipment at the two facilities, which will help stabilise energy distribution within the capital and surrounding areas.

“The support is part of the second phase aimed at rehabilitating and re-constructing the old substations as well as restore and expand the distribution networks in Jabana, Gikondo, Rwinkwavu, Huye and Musha,” Gatete said. He added that upgrading the distribution networks is crucial for faster economic growth and is well aligned to the country’s second Economic Development and Poverty Reduction Strategy (EDPRS II). According to EDPRS II blueprint, the government targets to increase power generation capacity to at least 563 MW by 2018, from the current 185 MW. Access to electricity is equally

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expected to have reached more than 70% of total population by 2018, according to the strategy. Although generation capacity has been increasing, with the rapid GDP growth of annual average rate of 8% in recent years, the demand for power is also growing at more than 10% each year.

Nomura expects Sinopec to cut capex by 15% this year, led by upstream exploration and a 20% cut in production. Sinopec’s depressed valuation reflects concerns about the slowdown in petrol and diesel sales in China, especially amid stiffer competition from domestic independent refiners known as teapots, says China oil and gas analyst at Nomura Gordon Kwan.

“However, sustained reforms should make Sinopec more competitive, while rebounding oil prices ahead should limit further upstream asset impairment risks,” he adds, noting Sinopec will likely announce lower domestic oil production target and further capex cuts for this year at end of the month.

year, a decline from a year ago of about 3.2 million tonnes, or 2.9%, general manager of the production and operation department of the state oil company Su Jun said. It has decided to cut capital spending this year by about 23%, Su said, without providing a total amount.

The state-run energy giant is facing “unprecedented” pressure from lower oil prices, according to Su. “We have to cut capital spending and output to sustain profit and maintain positive cash flow.” CNPC and listedunit PetroChina have struggled to survive low oil prices through cutting costs and selling assets including pipelines to strengthen the balance sheet. Brent crude, the global benchmark, has tumbled more than 60% since a peak in June 2014.

PetroChina warned in January that its 2015 profit may have fallen as much as 70% from a year earlier because of the energy slump.

CNPC is reviewing output at 16 oil and gas fields in China and may further cut targets, Su said. Output from its Daqing oilfield will fall by 1.5 million tonnes this year while the Liaohe oilfield, also in the nation’s northeast, will also have reduced output, he said. “The capex and output cut are prudent decisions by CNPC to survive this oil industry downturn,” head of Asia oil and gas research at Nomura Holdings Gordon Kwan said.

DOW JONES (US), March 7, 2016

BLOOMBERG, March 7, 2016

NEWSTIME.CO.RW (RWANDA), March 8, 2016

ASIA

Sinopec will cut capex by 15% this year

government official said.

It takes around US$1,500-1,700 to produce one tonne of aluminium with alumina and power accounting for 40% each of the cost, with raw materials and others contributing to the remaining 20%. The Navratna firm’s board has approved acquisition of 26% stake in Kakrapar Atomic Power Project for around 9 billion rupees through its joint venture (JV) with Nuclear Power Corporation of India Limited (NPCIL), NPCIL-NALCO Power Company, the official added.

Confirming the development, another official said: “Kakrapar is the first project of the JV and the plans are to increase this stake to 49% for which approval of the ministries of Finance, Mines among others has been sought.”

Nuclear power is considered the future and with depleting fossil fuel resources as well as hardening of environmental concerns, this source of power is going to be one of preferred alternatives for aluminium production, he added. The equity infusion in Kakrapar will be made after the project is allotted to the JV firm by the government.

Besides, the public sector undertaking (PSU) is scouting for opportunities to set up a gasbased thermal power plant and an aluminium smelter in Iran, Qatar and Oman. Nalco faces a daunting challenge of keeping operational and raw material costs in check to stay competitive even as it tries to expand capacity to take advantage of a infrastructure boom in India.

CNPC to cut capex Nalco to invest in 23%, lower oil output India’s Kakrapar NPP on price crash Petronas Chemicals to spend US$4 billion on refinery, petrochem plant PTI (INDIA), March 6, 2016

China National Petroleum Corp (CNPC) said it will cut capital spending this year by more than 20% and sees domestic crude production slipping as the country’s biggest oil and gas company looks to shore up profit amid the energy downturn.

CNPC aims to produce 108 million tonnes of crude domestically this

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India’s state-run aluminium major Nalco will invest around 9 billion rupees (US$133.9 million) in the Kakrapar atomic power project to acquire 26% stake in the plant and plans to increase it to 49% later. The state-run firm has been exploring opportunities to enter the power sector in a bid to secure an uninterrupted power supply for its aluminium production facilities, a senior

Petronas Chemicals, a unit of Malaysia’s State energy company, will spend US$4 billion over the next five

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years to mostly invest in a refinery and petrochemicals complex spearheaded by its parent in Johor. The company predicts a “tougher” 2016 because of a plunge in crude and an oversupply that has pushed down product prices, CEO Datuk Sazali Hamzah said.

Petronas Chemicals typically benefits from higher oil which drives up petrochemical-product prices.

The industry’s outlook this year is clouded by volatility in the oil market and slower Chinese demand, he said.

“Many companies will tend to back off from capital investments, stopping or shelving some of their projects,” Sazali said. “With our strong cash position, we have the advantage to fund our existing projects and growth projects as well.” Petronas, the parent company, is proceeding with the US$27 billion integrated refinery and petrochemicals complex even as it defers some other projects. Petronas plans to lower capital and operating expenditure by as much as 20 billion ringgit in 2016. It joins global peers such as Shell in cutting spending as the industry contends with the worst crude downturn in a generation.

proceeds to enforce a deal with two US thermal power producers AES and ContourGlobal, under which the two will lower the price at which they sell their output to the public power provider NEK, a unit of BEH. After 12 banks initially expressed an interest in lending the money and organising the bond, BEH has received two offers, one from a consortium of Citigroup, HSBC, Unicredit, Societe Generale and ING, and another from Banka IMI. BEH has been trying to raise the debt since May last year but the process has hit a snag after the bidders demanded state guarantees.

Bulgaria’s finance ministry has declined to extend such guarantees before the huge deficits in the energy system are properly addressed. The delay in arranging the funding was one of the reasons for the dismissal of BEH’s chief executive last month.

In September, Fitch credit ratings agency downgraded BEH’s long term rating to BB- with a negative outlook, predicting weak credit ratios due to a widened tariff deficit at NEK. REUTERS, March 9, 2016

THE STAR (MALAYSIA), March 2, 2016

EUROPE

L AT I N A M E R I C A

will continue Bulgarian energy firm Ecopetrol BEH picks banks for to tighten its belt US$714 million loan Bulgaria’s state energy holding company BEH has picked a consortium of four banks led by Banka IMI, the investment arm of Intesa Saopaolo, to lend it up to 650 million euros (US$714 million) and place bonds in global markets up to a year later, BEH said.

The consortium led by Banka IMI - London Branch, Bank of China Lt, Luxembourg Branch and JPMorgan Securities, will receive an invitation to negotiate terms and sign a contract, BEH said. BEH needs the

27

Ecopetrol director Juan Carlos Echeverry said the company would continue to “tighten its belt” and maintain fiscal discipline. As well as ratifying an investment target of US$4.8 billion, a 26% slide compared with 2015, Echeverry said the aim is to maintain conservative debt levels because the company needs a solid investment foundation.

Vice-president of exploration for Ecopetrol Max Torres said that the company will combine onshore and offshore exploration and has expectations it will tap crude in the Colombian Caribbean and the Gulf of Mexico. “We will also review

the traditional fields, bringing new technology and new personnel to obtain results in 2017 and 2018,” he said. “Offshore exploration is not a promise, it’s a reality,” he said.

EL COLOMBIANO (COLOMBIA), March 8, 2016

Venezuela paying off debts with distressed bonds According to Reuters, Venezuela has settled its debts with three pharmaceutical companies using bonds that trade at a heavy discount.

Novartis, Bayer and Sanofi were all given dollar-denominated bonds by state oil company PDVSA, which they went on to resell for as little as a third of face value. The Reuters data showed that the deals contributed to US$500 million in foreign exchange losses for the three companies in Venezuela last year.

The system was used to shortcut Venezuela’s currency control mechanism, a system that is regarded as being one of the primary causes of Venezuela’s economic problems.

REUTERS, March 7, 2016 Venezuela and China consider ‘adjustments’ to financing accord Venezuela and China are considering “adjustments” to a multibillion-dollar financing agreement under which the South American nation borrows money and repays in shipments of oil and fuel, Venezuela’s Oil Minister said. The OPEC nation, which has received some US$50 billion in Chinese financing since 2007, is struggling with a contracting economy and runaway inflation following a collapse in oil prices that has raised concerns of a debt default this year.

Investors have hoped that China will provide financial relief, or at least ease the terms of the loan agreement to help Caracas meet heavy debt payments.

REUTERS, March 9, 2016

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MIDDLE EAST

Iran needs US$180 billion investment in oil industry Deputy Head of the National Iranian Oil Company for investment and financial resources, Ali Kardar said that US$100 billion is needed in the upstream sector and US$80 billion in the downstream sector in order for development of oil industry in the 6th Five-Year Economic Development Plan (2016-2021). Kardar told a group of the NIOC officials that in the past years, about US$70-75 billion dollars of investment were made in the oil sector. He said the target of US$100 billion investment in the energy sector seems logical and the development parameters is attainable with respect to 8% economic growth rate.

On the NIOC plan to provide US$100 billion of investment in the oil industry in the sixth plan, Kardar said US$14 billion out of the total will be met out of National Development Fund resources, US$10 billion out of the IPCF contracts, US$8 billion out of the capital market, US$12 billion through facilities, US$25 billion within framework of new oil contracts and the rest from the company’s resources.

ISLAMIC REPUBLIC NEWS AGENCY (IRAN), March 1, 2016

Iranian central banker visiting India over US$6 billion oil dues Iran is dispatching Central Bank Vice Governor Gholamali Kamyab to India this month after the Persian Gulf nation’s efforts to get nearly US$6 billion of past oil dues from refiners like Essar Oil hit roadblock over differences over the foreign exchange rate. With US lifting sanctions, Iran wants its past oil dues to be cleared.

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But differences have now cropped up over foreign exchange rate, sources privy to the development said. Iran sold oil to refiners like Essar Oil and Mangalore Refinery and Petrochemicals Limited (MRPL) in US dollars per barrel.

45% of the oil bill was paid in rupees in a UCO Bank account while the rest 55% was to be cleared whenever banking channels open.

Now with lifting of sanctions, Iran has presented its unpaid bill. But Essar Oil and other refiners want to pay Iran at the exchange rate prevalent at the time of buying crude oil in the last three years, sources said. Now with lifting of sanctions, Iran has presented its unpaid bill. But Essar Oil and other refiners want to pay Iran at the exchange rate prevalent at the time of buying crude oil in the last three years, sources said.

PTI (INDIA), March 6, 2016

NORTH AMERICA

Petronas threatens to abandon Canada LNG project Malaysia’s Petronas is frustrated that Prime Minister Justin Trudeau’s climate-change priorities are introducing new uncertainty for its proposed C$36 billion Pacific Northwest LNG project in northern British Columbia and has threatened to walk away if it does not get federal approval by March 31, according to a source close to the project. The project, to be located on federal lands on Lelu Island near Prince Rupert, received a largely favourable assessment from the Canadian Environmental Assessment Agency (CEAA) last month, was greenlighted by the British Columbian government in November, 2014, and received conditional corporate support, or a final investment decision, from Malaysia’s state-owned company and

its partners in June of last year.

But the new federal Liberal government is toughening up environmental reviews of major energy projects to regain “public trust” and as it strives to meet international commitments to reduce greenhouse gas emissions. It said in January they would be subject to additional assessment on “direct and upstream greenhouse gas emissions”.

A spokeswoman for CEAA said she would look into how the new requirements will impact Pacific Northwest LNG. After spending an estimated C$12 billion to get the project to this stage, and having suffered multiple delays and setbacks, including aboriginal and environmental movement opposition, Petronas has conveyed to federal cabinet ministers it will not accept additional hurdles.

“They have given Trudeau to March 31 to either approve it as it stands now or they are going to leave,” the source said. “They started off with the Conservatives, and the (environmental) standards are very high. They said OK we will meet those standards and they did in all the engineering and design of the project.

This last greenhouse gas thing that Trudeau came up with really threw them for a loop.”

THE FINANCIAL POST (CANADA), March 7, 2016

Sabine bankruptcy judge deals blow to midstream companies Bankrupt Sabine Oil & Gas can reject contracts with two companies that gather, treat and transport oil and natural gas, a federal judge said, driving down shares of other socalled midstream businesses. US Bankruptcy Judge Shelley Chapman in Manhattan said Sabine should be able to reject the contracts, with HPIP Gonzales Holdings and Nordheim Eagle Ford Gathering, an affiliate of

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Cheniere Energy. At the same time, she said she didn’t want to decide an underlying legal dispute “in a binding way.”

“It would have been preferable” to hear Sabine’s request to reject the contracts at the same time the court held a full trial on a more complex issue: whether the contracts gave the midstream companies the right to provide services on a specific tract of land, Chapman said. Pipeline operators including Williams Cos and Energy Transfer Equity LP slid on speculation that Chapman’s ruling may set a precedent for distressed energy explorers looking to break transportation commitments. Williams fell 9.4% in New York while Energy Transfer Equity dropped 11.4%.

Cheniere lost 8%. “It was a ruling against the existing rate structure,” said Bloomberg Intelligence analyst Michael Kay. “In all likelihood, it means that they’ll either renegotiate the rates or those contracts won’t be resigned.”

the event that Pacific Northwest LNG forges ahead, a new study shows.

The fate of the LNG project led by Malaysia’s state-owned Petronas is uncertain. But the Conference Board of Canada said if the C$11.4 billion terminal near Prince Rupert is built, the BC government is positioned to rake in C$85 million per year from an LNG tax and C$294 million in annual royalty revenue from natural gas drilling over a 30 year period.

The venture is considered the frontrunner among 20 BC LNG proposals. A glut of LNG supplies on world markets, however, has sent prices for the fuel tumbling. In 2012, Petronas acquired Progress Energy Canada, which drills for natural gas in northeast British Columbia.

The conference board said Progress provided funding for the new study, part of a broader report that was recently released.

GLOBE & MAIL (CANADA), March 8, 2016

ExxonMobil chief not Pacific Northwest inclined to buy ailing LNG could boost BC’s shale companies treasury BLOOMBERG, March 8, 2016

The British Columbian government’s tax coffers would receive a huge lift in

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its wallet, ExxonMobil, has all but laughed off the idea. The underlying value of the biggest US oil boom in four decades has been buried under a massive pile of debt and diluted by a de facto Wall Street bailout of shale companies, so buying a rival driller probably would not pay off for the Texas oil giant, even though the nation’s oil and gas plays are actually impressive, ExxonMobil chairman and CEO Tillerson said.

“There are a lot of quality resources out there. It’s just how they’ve been encumbered,” Tillerson said during an annual gathering of analysts and investors. “It’s like buying a home with a big mortgage, and there’s not a lot of equity.”

Tillerson’s assessment is likely to disappoint ailing companies wondering if ExxonMobil, the biggest US oil company and possibly the only one that could afford a major purchase, might be planning to write them a multibillion-dollar check anytime soon. That might have sparked more consolidation, and perhaps salvation, for struggling oil producers.

The collapse of crude oil has sent US shale drillers into such a severe financial tailspin that the one company that could rescue them with

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