Energy finance Week Issue 03 by NewsBase Ltd.

Week 03• 22 February • 2016

ENERGY FINANCE WEEK This week’s top stories

vWitless output freeze tactic destabilises long-term credibility p2

vLower credit ratings, reduced

debt availability exacerbate Canadian industry’s challenges p4

vTullow grinds onward p9

vPetsec buys Oxy out of Yemen block p21

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Week 3• 22 February • 2016

Witless output freeze tactic destabilises long-term credibility MARKET THE fact that oil prices bounced back initially on the Saudi-led tactic to freeze oil output was a product of two factors, according to a range of senior oil and gas analysts spoken to by Energy Finance Week last week. The first, was simply that the initial rumours doing the rounds in the market omitted to mention that output would be frozen at January’s levels (already near record highs) and that it did not include all OPEC members, most notably Iran. The second was that it is an old market adage that traders ‘buy the rumour, sell the fact’ – and so it was proven as the near 6% rise in the price of Brent on the day of the rumours was immediately eradicated as specific news regarding this event became better known. The subsequent price movement back up was also of a similar ilk, said analysts, as it is now predicated upon the notion that this move to freeze output is the precursor to an agreement to actually cut output by some OPEC members, which may or may not turn out to be true. Freeze! What is true, though, is the damage done to Saudi Arabia’s market credibility and the fact that Riyadh’s call for a freeze marks the death knell of its strategy of the past couple of years to price out the threat of the nascent shale energy industry to benefit its own share in the global oil market, as a rise in price above US$36 per barrel for WTI is the point at which many US shale players are more than happy to continue to operate (see last week’s edition). “The output freeze is both meaningless to the oil supply/demand balance, and therefore to oil prices, as they are frozen at levels that still mean we are running an oil surplus of around 1.5 million barrels per day, and it signals that Saudi’s big words about doing whatever it took to price out shale mean nothing either,” Sam Barden, CEO of energy trading and consultancy, SBI Markets, told Energy Finance Week. Indeed, as it stands, the agreement is only between Saudi Arabia and Russia (both of which produced oil at near record levels in January), with Iraq, Qatar, Kuwait, and Venezuela saying that they would also freeze output at January levels provided a deal could be agreed with other OPEC and non-OPEC countries. “The fact that this agreement does not yet include Iran as well makes it all the more meaningless in practical terms, and even if Iran does go for it – which looks

extremely unlikely – then we are still talking about an oil glut persisting for as long as anyone can reasonably predict and Saudi has shown itself to be weak to the markets,” added Barden. Suspect timing On the Iran factor, there appears to be little chance of the Islamic republic agreeing to any such output freeze only a month or so after the Joint Comprehensive Plan of Action (JCPOA) on 16 January removed most sanctions on the country. Iran is “extremely suspicious that the Saudis’ have decided all of a sudden – precisely at the time when sanctions have been removed on us – to embark on an output freeze, as it’s well known that we’re doing everything we can to get production back up to presanctions levels as fast as possible, and build out our economy from that,” Mahmood Khaghani, former director general of the National Iranian Oil Co. (NIOC) and director for Caspian Sea Oil and Gas Affairs in the Ministry of Petroleum, told Energy Finance Week. “The Saudis benefitted from higher oil prices all those years that we were frozen out of the markets under sanctions and now, when we are back, they decide that they want us to pay the price for a strategy that they put into action; it’s absurd,” he added. Indeed, at the last OPEC meeting in December, Iran’s Petroleum Minister, Bijan Zanganeh rejected outright any plan to curtail Iran’s production before it rises to presanction levels. Nonetheless, said Barden, it may be the case that Iran becomes persuaded temporarily to hold to some sort of output deal in the short-term, as a sign of good faith to other OPEC countries, if only for broader geopolitical considerations. “It may be that Iran might agree to hold off some future production increases until the oil price has rebounded to a certain level, as it wants to win friends and influence in OPEC away from Saudi, but in practical terms this will be done in such a way as to not affect its actual output increases or export earnings at all,” he added. In this context, for instance, Iran might agree to limit oil increases for a certain period to the 300,000 bpd extra that it has been producing – rather than the planned 500,000 bpd increase scheduled over the next few weeks, but in fact it is unlikely that before the target date – March 20 – Iran will have gone above 500,000 bpd extra anyway.

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 3• 22 February • 2016

Even if it does agree to limit production, it is notable that, for a long time prior to the removal of sanctions Iran was exporting oil, to China, India and others, and to customers elsewhere via ports in the UAE, in the amounts it saw fit. As it stands, the line from Tehran is that it supports the output freeze, but it will not freeze its own output. “Why not support it? They want to freeze, fine, we’re not freezing, but we’re very happy if it leads to higher oil prices,” Khaghani said. The natural question of this sudden announcement is ‘why now’? “There’s no doubt that part of this is linked to Iran being back on the scene, obviously, but even more than this, the Saudi finances are really starting to buckle to a point where the princes are becoming very critical, with questions being raised about the impact of removal of subsidies on the populace at a jittery political time in the region, the negative effect on key companies’ revenues, the almost heretical idea of selling off parts of Aramco that was mooted, and pressure growing on the [USD] currency peg,” Christopher Cook, director of energy consultancy Wimpole International, told Energy Finance Week. In this latter regard, Jeremy Stretch, chief markets strategist for CIBC, told Energy Finance Week there has been consistent pressure over recent weeks on forward

Saudi Riyal prices all the way out to one year duration on the curve, indicating speculation over whether the Riyal’s 3.75 effective currency peg to the US dollar, which has existed since 1986 and is a cornerstone of the country’s economic stability, will survive intact. Interestingly, with the Saudi Arabian Monetary Authority (SAMA) having been active in attempting to shore up the value of the Riyal across all dates, short and long, since the beginning of this year, according to FX dealers spoken to by Energy Finance Week last week, hedge funds in particular have been looking to effectively short the Riyal – and by implication bet against the survival of the peg at 3.75 – by buying interest rate swaps (IRS). Only a couple of weeks ago, in fact, Saudi IRS hit multi-year highs, with the idea being that – as the SAMA eventually runs too low on USD reserves to prop up the Riyal (selling the USD to buy the Saudi currency) then it will have to embark on interest rate hikes to bolster the currency instead. In this vein, two-year Saudi IRS have climbed by around 100 basis points (bps) since the end of September 2015, to over 2% last month – their highest level since January 2009 – a massive number, given that the Saudi central bank has raised official interest rates by only 25 bps over the same period.n

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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

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Week 3• 22 February • 2016

Lower credit ratings, reduced debt availability exacerbate Canadian industry’s challenges

A number of Canadian producers have had their credit ratings downgraded, with more anticipated to follow, amid fears over reduced debt availability NORTH AMERICA OVER the past 18 months, as oil and gas prices have fallen, Canadian producers could rely on a safety net in the form of widely available debt, anchored by strong credit. But as prices languish for a second consecutive year, more Canadian energy companies are in danger of having that net pulled out from under them, and the implications could be widespread. Recent moves by Moody’s credit rating agency to lower large energy companies’ credit ratings will likely force many – especially publicly traded firms – to re-think their production, acquisition and disposition strategies in the coming months. Moody’s recently downgraded oil sands producer Suncor Energy’s rating one notch to a triple B rating while downgrading the firm Suncor is acquiring, Canadian Oil Sands, into a double B rating, or junk status. Moody’s also lowered the credit ratings on five other Canadian oil and gas producers, including MEG Energy and Baytex Energy. Suncor’s outlook is still considered stable thanks to a strong refining business, but low oil prices have still taken their toll on the company’s rating. “The downgrade of Suncor’s senior unsecured rating to Baa1 reflects the impact of low oil prices on Suncor’s cash flow and leverage metrics,” said Moody’s senior vice president, Terry Marshall, in a news release. “However, Suncor’s significant downstream refining assets provide an offset to the diminished upstream cash flow and support the Baa1 rating.” Suncor’s acquisition of Canadian Oil Sands also factored into the reduced credit rating which, according to the Moody’s statement, affects C$11.1 billion (US$8.1 billion) in debt. “Suncor’s rating is negatively impacted by its weak cash flow-based leverage metrics that will decline in 2016 (retained cash flow to debt to 18%; EBITDA/ interest to 6x), significant remaining capex to be incurred in developing the large Fort Hills mining project and the challenges inherent in its 49% ownership of the operationally challenged Syncrude mine and upgrader,” Moody’s said.

The acquisition of Canadian Oil Sands boosted Suncor’s ownership in Syncrude to the majority 49% level. Meanwhile, Moody’s reduced MEG’S rating three notches to C-level status – or eight notches below investment grade – while lowering Baytex by four. Northern Blizzard Resources, Bellatrix Exploration and Paramount Resources also had their ratings lowered. The moves on Suncor, Canadian Oil Sands and the five other firms came after Moody’s began a sweeping review of 19 oil and gas companies on January 21 after the ratings agency reduced its forecast for oil prices for the second time in a month. Tougher times Moody’s is not the only organisation taking a more negative stance on Canadian energy companies. Major banks and other lenders, which are suffering from lower profits and revenues, are also tightening up on energy companies’ outstanding loans and debt availability as low oil prices begin to have a greater impact on other Canadian industry sectors and the country’s economy as a whole. The situation is compounded by the fact that Canadian oil traditionally trades at a discount to US and global benchmark prices and, over the next year, many of Canada’s producers will see their higher price hedges end. With oil and gas prices remaining low in the short term, producers will not be able to hedge – essentially pre-sell – future production at higher prices as they have done in recent years. What next? Questions are now being asked about what these changes and the ongoing Moody’s review mean for Canadian producers and other energy companies. First of all, the lower Canadian Oil Sands rating could be moot and may no longer apply after Suncor completes the takeover. Suncor’s new rating status is slated to last at least two years, and it should be able to withstand the challenge given its relative strengths.

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Week 3• 22 February • 2016

But the other companies that have already had their ratings lowered, and firms which could still be affected by the Moody’s review, might not be as fortunate. Ultimately, good credit ratings and debt will not be as widely available as they have in the past. With banks and lenders taking tougher stances, some lesser known companies have already failed to meet their debt facility requirements and are curbing – or even ceasing – production while also attempting to shed assets and scrambling to keep financiers content. In the coming months, other companies with more production and higher profiles will also come under increasing pressure to do the same – or suffer consequences that could include reduced investment and profits, outright company sales or bankruptcy proceedings. Canadian companies will also have to pay more attention to the domestic supply glut, which stems largely from reduced US demand for Canadian oil and gas and Canada’s inability to send its output to overseas markets. More broadly, OPEC’s refusal thus far to reduce its annual output has led to a global supply glut that would make it more difficult for Canada to sell its oil even if it had established export routes. However, OPEC showed signs this week that it may be more willing than before to reduce production as Saudi Arabia, the cartel’s de facto leader, and Russia, which is not part of the group, agreed on February 16 to freeze their output levels. Other OPEC member states have indicated they would sign on to the deal subject to other countries joining. But Canada’s domestic glut could

nonetheless still prove to be problematic. In the past, the domestic glut did not pose as much of a deterrent to Canadian companies, which continued to produce as the strong credit ratings and widely available debt were propped up by high oil prices. Now, though, the domestic glut, lower credit ratings and reduced debt availability will force Canadian producers to become more disciplined with their operations. Output cuts will likely affect small producers that partner with larger companies and large and small services companies alike. Political and public relations battles are also likely to increase as energy companies struggle to have proposed pipelines, LNG facilities and other major projects approved. The Canadian Association of Oilwell Drilling Contractors (CAODC) has already served notice of its intention to fight harder, announcing on February 17, launching a campaign to restore respect to the country’s energy sector. “Our industry is being hit hard. [Around 100,000] oilfield sector workers are unemployed,” the association said in a statement. “Thousands of businesses are in trouble. CAODC’s Oil Respect campaign will defend the industry within the context of its national and international image, economic benefits and global environmental impact. We will encourage Canada’s leaders to fight for the Canadian energy industry.” In other words, the industry wants to bolster its public and political ratings even as credit ratings come under renewed pressure.n

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Week 3• 22 February • 2016

Cenovus considers selling up to US$5 billion in securities NORTH AMERICA CANADA’S Cenovus Energy has said it may sell up to US$5 billion of stock, debt or other securities. This news came a day after the oil sands producer announced a dividend cut of 69% to help shore up its balance sheet. Low oil prices have hit Canadian producers particularly hard because of their higher costs and the fact that Canadian oil generally trades at a discount to the US and global benchmarks. Calgary-based Cenovus filed with the US Securities and Exchange Commission (SEC) to sell securities in one or more separate offerings. Its stock is traded in both Toronto and New York. The company has also said it would cut its 2016 budget by C$400-500 million (US$291-364 million) – reducing its capital expenditure for the year to C$1.21.3 billion (US$875-948 million) – as well as cutting more jobs. In 2015, the company reduced its number of employees by 24%. Last year, Cenovus also agreed to sell its Heritage Royalty Limited Partnership subsidiary to the Ontario Teachers’ Pension Plan for the equivalent of US$2.7

billion in one of the largest upstream deals in North America in 2015. In the US, other producers have recently launched stock offerings, including Dallas-based driller Pioneer Natural Resources, which announced in January that it planned to offer 12 million new shares. It raised US$1.4 billion, more than expected, suggesting that capital markets were still willing to invest in shale production. Also in January, Oasis Petroleum said it would offer 34 million shares to raise US$160 million. It had previously said it would cut its capex estimate for 2016 by about 30%. Cenovus’ planned capex reduction for 2016 includes lower spending at its Foster Creek and Christina Lake oil sands projects, as well as at its emerging oil sands assets and its conventional operations. The planned capex cut is expected to have minimal impact on its oil sands production for 2016, said Cenovus. The company has forecast its oil sands production to be 144,000-157,000 barrels per day net.n

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Week 3• 22 February • 2016

Paragon seeks bankruptcy protection NORTH AMERICA PARAGON Offshore, a rig owner that was spun off from Noble and that has significant debt, has sought bankruptcy protection. This move came after the company recently announced several deals to reorganise its debt and cut it by US$1.1 billion. The company announced on February 15 that it had filed for Chapter 11 bankruptcy in the US Bankruptcy Court in Delaware. Low oil prices have squeezed oil and gas companies, and rig owners have been hit hard as drilling has been scaled back. Three days before filing for bankruptcy, Paragon had entered into a plan support – or restructuring – agreement. The agreement, which requires court approval, was quickly signed by an ad hoc committee representing about 77% of the aggregate of holders of the company’s senior unsecured notes and a group comprising 96% of the amounts outstanding under Paragon’s revolving credit agreement. The company will use the bankruptcy to execute the restructuring agreement. “We look forward to moving as quickly as possible through this process while maintaining our focus on

delivering safe, reliable, and efficient operations as the industry’s high-quality, low-cost drilling contractor,” Paragon’s president and CEO, Randall Stilley. “We are confident that Paragon will emerge as an even stronger company, better positioned for long-term growth and success.” Paragon’s operated fleet includes 34 jack-ups, including two high specification heavy duty and harsh environment jack-ups, and six floaters comprised of four drillships and two semi-submersibles. In its bankruptcy filing, the company cited the impact of oil and gas prices, the debt it incurred in its spin-off from Noble, and the termination of long-term contracts with two customers, Mexico’s Pemex and Brazil’s Petrobras, Bloomberg reported. Paragon said in its filing that it was disputing the termination of some contracts with Petrobras. The restructuring agreement includes a settlement that releases Noble from all claims linked to the 2014 spin-off. According to the bankruptcy filing, the average age of the rigs Paragon received in the spin-off was 35 years.n

Pioneer scales back drilling, budget NORTH AMERICA PIONEER Natural Resources has said it will scale back its unconventional activity in 2016 in order to preserve capital, including pulling out of drilling in the Eagle Ford shale and southern Wolfcamp play altogether. The announcement came as the company reported a net loss attributable to common stockholders of US$623 million, or US$4.17 per diluted share, for the fourth quarter of 2015. Because of weak oil prices, Pioneer said it will cut its horizontal drilling activity by 50% from 24 rigs at the end of 2015 to 12 rigs by mid-2016. The company still anticipates its production to grow by at least 10% this year, though. Pioneer produced 215,000 barrels of oil equivalent per day in the fourth quarter, of which 53% was oil, it said in its recent earnings report. The company’s Eagle Ford rig count is being reduced from six at the end of 2015 to zero during the first quarter. Two rigs were released in January. The rig count in Pioneer’s southern Wolfcamp joint venture area is being reduced from four to none by the middle of the year. Meanwhile the rig count in the northern SpraberryWolfcamp is being reduced slightly from 14 rigs at the

end of 2015 to 12 rigs during the first quarter, with one rig already released. Pioneer is hoping that ongoing efficiency gains at its Spraberry-Wolfcamp operations will allow it to continue generating. The company’s two Eagle Ford pressure pumping fleets will be relocated to the Spraberry-Wolfcamp. “The performance from our Spraberry-Wolfcamp horizontal drilling programme continues to be outstanding,” said Pioneer’s chairman and CEO, Scott Sheffield. “We have the financial flexibility to prudently manage through the current commodity price downturn or quickly ramp up drilling activity when prices improve.” The company is now estimating its capital expenditure in 2016 to be US$2 billion as a result of the reduction in drilling activity, down from its preliminary forecast of US$2.4-2.6 billion and US$2.2 billion in 2015. It was previously one of the few shale drillers planning to increase capex this year. Pioneer is now earmarking US$1.85 billion for drilling and completions and US$150 million for vertical integration, systems upgrades and field facilities.n

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Week 3• 22 February • 2016

Alaska debates oil and gas tax credit system NORTH AMERICA THE Alaska House Resources Committee is opposing a proposal by Governor Bill Walker that would reform the state’s oil and gas tax credit system and raise additional production tax revenue. The proposal, HB 247, represents a US$500 million portion of a fiscal plan that would reduce the 2017 fiscal year gap to US$440 million from about US$3.8 billion, Alaska Commons reported on February 14. The bill addresses several of the recommendations from the Alaska Senate Oil and Gas Tax Credit Working Group, including recommendations to increase the minimum production tax, at the same time as raising the North Slope tax floor from 4% to 5%. Walker’s administration estimates that these two measures together would generate revenue of US$100 million per year. Other oil and gas tax credit reforms are also included in the bill. Walker’s proposal comes as state revenue is falling amid low oil and gas prices and as oil production in Alaska continues to drop. The state produces just over 500,000 barrels per day, down from a high of 2 million bpd in 1988. Alaska depends on petroleum production for around 90% of its state revenue. The oil and tax incentive programme was started years ago as a way to stimulate new exploration and production. Tax credits are taken in two ways – as credit against an oil company’s production tax liability if there is output, or in the form of a cash payment from the state if a company is exploring but has no production. However, the programme has been controversial because some producers, often small independent companies, have been able to reduce their state production tax liability to zero and still receive cash payments under the incentives. Often these companies receive reimbursement of up to 75% of expenses related to exploration and development of new projects. The incentives account for about US$500 million

of Alaska’s budget deficit this year. They would have originally amounted to US$700 million, but Walker vetoed US$200 million of this. Opponents claim that Walker’s bill represents a much more significant change to oil and gas tax law than he has suggested. They also claim that if the bill is made into law it would raise taxes on companies that are currently losing money in Alaska. Oil companies are also opposed to Walker’s bill. Two weeks ago, BlueCrest Energy’s president and CEO, Benjamin Johnson, urged the public to contact the state legislature and ask it not to make any changes to the oil and gas tax credit programme until 2017. The Alaska Journal said BlueCrest was less than three months away from its first oil production at the Cosmopolitan field off the coast of Anchor Point. Johnson said production would not be economic without the tax credits or some type of incentive. “We know that we have large amounts of resources. These resources need to be developed. The tax credits are really critical to make sure that that’s done,” he said. Indeed, the state has a uniquely high cost of doing business, and the credits have therefore helped spur development in the past. However, with oil prices hovering around US$30 per barrel and likely to remain depressed for the remainder of the year – or possibly longer – Walker has little choice but to reduce state expenditures and avoid budget deficits. Walker has also offered a substitute plan – though one that is also controversial – to producers, by replacing development tax credits with a loan programme administered by the Alaska Industrial Development and Export Authority. This part of Walker’s proposal is also being debated in Juneau. The Alaska legislation session ends on April 17.n

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Week 3• 22 February • 2016

Tullow grinds onward

Sector-wide challenges have combined with specific issues for Tullow. EUROPE TULLOW Oil set out its 2015 results last week, demonstrating a dogged tenacity to its course – even while the company waits for a number of events to occur and watches the oil price carnage continue. In positive news, Tullow said its TEN project, off Ghana, remained on track for start-up in July or August this year, and the company continues to work on reducing its costs. Capital expenditure will be US$1.1 billion, with work under way to cut this, and the chance of reducing this number to US$300 million in 2017. A number of issues remain unresolved, though. The sale of East African assets would do much to rally investor interest in the company, as would a resolution on the maritime border dispute between Cote d’Ivoire and Ghana, which may have an impact on TEN’s future. Unfortunately, neither of these issues looks likely to be resolved in 2016, leaving the company at the mercy of a widespread bearish sentiment in the oil sector. Tullow’s CEO, Aidan Heavey, in the February 10 statement, said the company had “adjusted well” to the fall in oil prices in 2015. “In the year ahead, we have three key priorities: ensuring continued low cost production from West Africa – including the start-up of production from TEN between July and August 2016; driving further reductions in operating costs and capital expenditure; and focusing on deleveraging the balance sheet through free cash flow generation and strategic portfolio management.” Noting the company’s holdings in “one of the world’s newest, low cost, oil provinces [of] East Africa” he also said that production would reach 100,000 barrels of oil per day in 2017. Tudor Pickering Holt said balance sheet concerns persisted in the medium term, with the current course likely to reduce debt by only US$300-600 million in 2016-18, based on a US$40-60 per barrel price. This year, based on a US$30 per barrel price, the company’s net debt is estimated to increase by around US$700 million. Bernstein Research called for patience over the next six months, saying that the market had failed to price-in the 1.3 billion barrels of low-cost conventional resources. Jefferies picked up on the low capex guidance for 2017, of US$300 million, below the US$500 million it was expecting. Financials Revenues fell 27% in 2015, from 2014 levels, with an

after-tax loss of US$1 billion. At the end of the year, net debt was US$4 billion with free cash of US$1.9 billion. Financing facilities were increased in March 2015, by US$450 million, and talks on the next redetermination, due in March of this year, have begun. Hedging has performed strongly for Tullow, contributing US$365 million in 2015, with its book assessed as being worth US$668 million at the end of January. Tullow’s reserve-based loan will begin to amortise in October this year and the company expects to refinance this facility ahead of further payments in 2017. It also hopes to extend its three-year revolving corporate facility before April 2017. The company took an exploration pre-tax write off of US$749 million, a pre-tax impairment of US$406 million and an onerous service charge of US$186 million. A simplification programme was completed in 2015 and should provide cost savings of US$500 million over three years. Production in West Africa, from Jubilee and its nonoperated portfolio, is low cost, with operating expenditure of US$10 and US$15 per barrel respectively. In 2018, the cost savings from Jubilee and TEN in Ghana should reduce this further to US$8 per barrel. Spending in 2015 was US$1.7 billion, with a target of this year of US$1.1 billion – and the company aims to cut this to US$900 million. Should low oil prices continue, it will reduce capex to US$300 million from 2017 onwards, which will be assisted by end of major spending on TEN. Capex this year includes US$600 million on TEN, of which 75% will come in the first half. Another US$400 million will be incurred on production and development, while exploration has been reduced to US$100 million. Tullow said that while exploration was a long-term strategy, the focus this year would be on seismic, processing and working on developing prospects – sad news for drillers hoping for frontier work. There are, though, plans for infill work at Tullow’s non-operated West African projects. Ghana The TEN project – made up of Tweneboa, Enyenra and Ntomme fields – is over 85% complete, the company said. The addition of volumes from this development should help increase Tullow’s output to 73,000-80,000 bpd in 2016, from a working interest of 66,600 bpd in

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Week 3• 22 February • 2016

2015. The floating production, storage and offloading (FPSO) for TEN left Singapore on January 23, and should arrive in March. The 11 pre-drilled wells are being completed, with the sixth completion under way. Final commissioning and testing will take place in the second quarter and production should ramp up, reaching a plateau in the second half of the year. Average gross production from TEN this year is projected to be 23,000 bpd. Gross spending on the development is around US$5 billion, with capex to first oil of US$4 billion. The remaining US$1 billion will come from the drilling and completion of another 13 wells. First gas is due to come online a year after first oil. However, the International Tribunal of the Law of the Sea (ITLOS) in April last year ordered that no new drilling could take place in the disputed area between Ghana and its neighbour, Cote d’Ivoire. A decision on ownership is expected in late 2017 – so development drilling will be unable to restart until this has been resolved, Tullow said. Jubilee averaged 102,600 bpd in 2015, with gas production averaging 90 million cubic feet (2.55 million cubic metres) per day in the fourth quarter. The forecast for this year from Jubilee is 101,000 bpd, with two weeks of planned maintenance in March, and reduced water injection in the first half. Drilling is continuing at the non-operated parts of its portfolio, with a stated focus of limiting decline rates at mature fields. Spending on these assets will fall to US$100 million this year, from US$200 million in 2015. Six wells are planned for Cote d’Ivoire’s Espoir field, three wells are planned for the Mboundi field in the Republic of Congo (Brazzaville) in the second half, while drilling may resume in Gabon in late 2016 or early 2017. Infill drilling will start at Elon and Oveng in Equatorial

Guinea, at Hess’ Okume complex, in 2017. East Africa A field development plan was submitted to the Kenyan government in December 2015. Talks are continuing on a final investment decision (FID) on the Kenyan and Ugandan upstream projects, Tullow said. During 2015, nine appraisal wells were drilled and successfully completed at the Ngamia and Amosing fields, in the South Lokichar Basin, as were five extended well tests. During the well tests, around 68,000 barrels of oil were produced into storage. Furthermore, 3-D seismic found “significant” exploration prospectivity in the area around Etom, which Tullow said supported the thesis of 1 billion barrels of oil in the Kenyan basin. The company said it would evaluate plans for exploration drilling to follow this up in the first half. Beyond the South Lokichar Basin, though, disappointments continued in 2015. Three wells were drilled in new basins – Epir-1 in North Kerio, Engomo-1 in North Turkana and Emesek-1 in North Lokichar – but none were successful. Drilling on the Cheptuket-1 exploration well should be completed in late February, after which the rig,, the PR Marriott-46, would be demobilised. Tullow also noted the signing, by the Ugandan and Kenyan presidents, in August last year of an agreement choosing the northern Kenya route for oil exports. Approval of this link, though, includes ensuring this is the lowest cost route. Uganda subsequently signed an agreement with Tanzania, which Total has supported, thereby throwing some uncertainty on these export plans. A resolution of the ITLOS case, an East African sale and an increase in oil prices would do much to shore up Tullow’s case. In the meantime, the company seems determined to keep grinding forward along its line of reduced exploration and development spending.n

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ENERGY FINANCE WEEK

Week 3• 22 February • 2016

NNPC charts cash call shortfall AFRICA

THE Nigerian National Petroleum Corporation (NNPC) has recorded a US$3.3 billion shortfall in cash call obligations to joint ventures during 2015. The corporation recorded crude export sales revenue of US$4.74 billion, of which it paid US$4.13 billion to its joint venture partners – part of the US$7.39 billion owed for the development of these assets. Just US$610 million was remitted into the federation account, meaning over 75% of Nigeria’s revenue from crude oil export did not make it to the federation account. The structure of Nigeria’s oil and gas production is split between joint ventures onshore and in shallow water with foreign and domestic companies and production sharing contracts in deepwater offshore. NNPC owns a 60% stake in most of its joint ventures, except those with Royal Dutch Shell, where it owns 55%. Production from joint ventures has dropped over the last few years, in part owing to funding constraints driven by NNPC’s inability to meet its share of the costs. During 2005-15, a 53% decline in cash call payments contributed to a 62% drop in joint venture production. Unpaid cash calls has been a longstanding issue for NNPC, with the gap between what the corporation owes

and what it has paid growing larger and larger. According to a report by the Natural Resources Governance Institute (NRGI), NNPC’s debt to its joint venture partners grew to US$19.7 billion between 2006 and 2012.The corporation’s inability to pay this sum has also caused it to enter into questionable alternative financing arrangements. Despite its asset base and equity holdings in the petroleum industry, speculation has been mounting that NNPC is broke. The corporation posted a 267 billion naira (US$1.34 billion) loss in 2015 stemming from its marketing operations, in addition to its cash call debts. Billions of dollars are also believed to be owed to fuel importers. Although the subsidy commitment is less expensive now, the debts continue over time and have been accumulating over some years. Attempts to offset these debts with swap arrangements with commodity trading companies has put the NNPC in deeper financial trouble, with the terms of the previous deals favouring the companies by as much as US$16 per barrel in excess profit, according to some sources. Nigeria has cancelled the swap programme and moved to a direct sales, direct purchase system instead, which will be implemented in March.n

Capex cuts hit Transocean off West Africa AFRICA

TRANSOCEAN has received notice of Vaalco Energy’s decision to terminate work early, adding to the drilling company’s difficulties. The GSF Constellation II was under contract to US-listed Vaalco for work in Gabon, Transocean said on February 11. “The drilling contract provides for a lump-sum payment for terminating for convenience,” Transocean said. The GSF Constellation II was working for Vaalco under a contract worth US$170,000 per day. Vaalco began demobilising the rig at the end of January, the operator said on Janaury 26. The company’s CEO, Steve Guidry, commented that Vaalco was pleased with the results from the rig’s work, which had reversed the decline in production. However, because of the “continued sharp decline in oil prices we have determined additional drilling to be uneconomic. As a result, we estimate our 2016 capital expenditures to now range from US$4 [million] to US$6 million. We are in discussions with Transocean regarding the remaining rig contract term which we believe carries a maximum exposure of

approximately US$7 million (net).” At the beginning of 2015, Vaalco had projected its capital expenditure for that year would be US$6575 million. By the time its third-quarter results were disclosed, this number had increased to US$83-86 million, partly as a result of higher than expected drilling costs. Transocean’s updated rig status report did flag up some short-term positives. The company won an extension for its Sedco 702 rig, offshore Nigeria, at a rate of US$275,000 per day. Furthermore, the Cajun Express won 80 days of work offshore Cote d’Ivoire, at an undisclosed dayrate. The Sedco 702 was previously working for Royal Dutch Shell in Nigeria at US$461,000 per day. The Cajun Express was priced at US$495,000 per day. A note from UBS on Transocean’s results expressed concern. The drilling company’s short-term contract wins came “at near break-even rates, but [they keep the] rigs working”, it said. Transocean’s results fell short of UBS’

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Week 3• 22 February • 2016

expectations, it continued, lowering its price expectation. “We continue to believe that the offshore rig count will continue to fall through 2016-17. Additionally, demand may not see a measureable improvement until 2018, at the earliest,” UBS continued. Ocean Rig, on February 15, also announced two rig cancellations, including in the Republic of Congo (Brazzaville). Total has terminated the contract for the Ocean Rig Apollo, the drilling company said, going on to say a termination fee would be payable. This amount varies from 50% to 95% of the day rate that would have been payable over the contract. The rig had been working for Total under a three-year drilling campaign. The contract was awarded in mid-2013 and the rig was delivered from a South Korean yard in the first quarter of 2015. Tough times are evident throughout the offshore drilling industry. Pacific Drilling, which has seven drillships, received notice from NYSE authorities at the beginning of the year that its share price was too low and that it faced compulsory removal from the exchange if this did not improve. Paragon Offshore, which has 34 jackups,

announced it was entering bankruptcy protection on February 15 amid reorganisation plans. There is a sense in the market that too many drilling rigs are chasing too little work. Maersk Drilling’s CEO, Claus Hemmingsen, was quoted by Reuters last week as saying that 25-33% of offshore drilling rigs could be idle in 2016, hit by reduced spending. “The current outlook for the oil companies bringing new projects to the market is very uncertain and not very optimistic … there will be oversupply in the foreseeable future,” he added. Much has been said about the lack of investment on new projects and the impact this will have on future production. However, it will also have an impact on maintaining output at mature fields, with reduced spending increasing decline rates. “Our analysis shows that decline rates increased significantly last year compared with 2013-14 levels,” said Bank of America Merrill Lynch, in its mediumterm outlook, published last week. The note suggested non-OPEC production decline would increase to 4.8% in 2015, from 4.2% in 2014, “a level consistent with decline rates observed in 2008 and 2009”.n

Egypt to miss arrears target AFRICA

EGYPT may miss its self-imposed target of paying off overdue debts to foreign operators producing oil and gas in the country, Egyptian Prime Minister Sherif Ismail talking in Dubai said last week. Egypt has managed to reduce the debt it owes to foreign operators to around US$3 billion, from US$6.3 billion two years ago, but the country is struggling with a host of economic and political problems. Initially, the new government of Egyptian President Abdul Fatah al-Sisi planned to repay the debt by mid2015. It was then forced to delay that to mid-2016 and now expects to reach that by the end of this year. Ismail said lower oil and gas prices would at least reduce the cost of the debt to a reasonable level. He said that no new deadline had been set and the government was continuing to stick to the current target date, although there exists the possibility that the debt might not be repaid by then. Egypt has cut government subsidies that it provides for domestic product sales in order to cut an annual subsidy bill that has been estimated at around US$15 billion. The repayments, combined with agreements with companies

to pay higher rates for domestically produced gas, new licensing rounds and new discoveries, have encouraged energy companies to start reinvesting in exploration and development. The government also plans to introduce a value added tax (VAT) that will further increase its revenues. Egypt owed BG Group US$1.1 billion at the end of the fourth quarter of 2015, of which US$900 million was overdue. Circle Oil, in a recent statement, said dollar payments from Egyptian General Petroleum Corp. (EGPC) were “limited”. Meanwhile, Daily News Egypt last week reported that Egypt expects around 80 cargoes of LNG to be delivered at its two floating storage and regasification units (FSRUs) at Ain Sukhna during 2016. The daily reported that officials at the Egyptian Natural Gas Holding (EGAS) said deliveries would cost US$2.5-3 billion and provide about 1 billion cubic feet (28.3 million cubic metres) per day to the industrial sector and power generation plants. Gas supply to power plants is averaging about 2.7 bcf (76.5 mcm) per day while the country’s total gas consumption is estimated at 4.65 bcf (131.7 mcm) per day. n

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Week 3• 22 February • 2016

JERA: Changing attitudes to supply ASIA

INCREASED production has hit LNG pricing over the last 24 months but competition is also having a broader impact. LNG supply has traditionally been governed by long-term supply contracts, often spanning 10 or 20 years. These have provided predictability and security of supply to both buyers and sellers. Attitudes to these deals are changing, though, as demonstrated by the JERA joint venture, formed in April 2015 as a vehicle for fuel procurement by Japanese power generators, Chubu Electric and Tokyo Electric Power Corp. (TEPCO). The venture’s new strategy document, released last week, maps out a radical new commodity procurement strategy for Chubu and TEPCO to 2030. Powered up Underlying JERA’s strategy is the expansion of conventional power generation, driven by construction and replacement plans from Chubu and TEPCO. The rate of newbuild and replacement activity of 650 MW of installed power at one site, scheduled for July 2016, will be ramped up to 12,000 MW at 10 sites by 2030. Chubu and TEPCO facilities will focus on “improved competitiveness and reducing the environmental burden by optimising existing infrastructure and promoting replacement with new technologies”. In parallel with this process, JERA is overhauling its LNG procurement strategy. The venture has proposed stable purchases of 30-40 million tonnes per year but shifting away from long-term agreements. These will fall from 35 million tonnes per year in 2016 to 15 million tonnes in 2030. This radical shift means that by 2030, 62.5% of LNG supplied to Chubu and TEPCO will be governed by spot or short-term supply deals. This is compared with 12.5% today. Second, expansion of fuel sales around the Chubu and TEPCO assets will be pursued with a view to the optimisation of the two generators’ coal and LNG market positions. Third, JERA intends to build up its own fleet of LNG carriers, marking an extensive move into the shipping and trading market. Setting terms The significance of JERA’s strategy lies in the message it is conveying to LNG sellers and buyers in Asia. The fact that JERA has disclosed its plans publicly means that LNG suppliers to Japanese power utilities must prepare for a market where short-term or spot supplies may dominate trading relationships. This has deep implications for new Australian and

US LNG suppliers which have been hoping to secure a raft of new Japanese contracts over the next few years – preferably under long-term contracts. Whether US or Australian, or from Papua New Guinea or Mozambique, LNG suppliers will have to decide quickly if they like JERA’s proposals, if they want to supply Chubu Electric or TEPCO. An unwillingness to endorse the move away from long-term deals may mean they leave any such negotiations empty-handed. JERA’s next steps will be monitored closely by other Japanese utilities, such as Kansai Electric and Kyushu Electric, in case they offer a good model for their own LNG procurement strategies. Not all LNG importers have the scale of Chubu or TEPCO in terms of imported LNG volumes and therefore may not be able to exert the same power over LNG suppliers. Smaller-scale importers, though, may be able to work with JERA to accomplish plans along these lines. The Electricity Generating Authority of Thailand (EGAT) has already signed an agreement with JERA to analyse options relating to its LNG import strategy. Thailand opened the small Map Ta Phut LNG terminal some years ago, but wants to increase capacity, partly to compensate for periodic interruptions to its overland supplies from Myanmar. Should long-term LNG supply contracts become the exception rather than the rule, suppliers will have to invest more in trading divisions. Legal practices will need to be modified to suit a market where fewer and fewer longterm supply contracts are under negotiation, while more standardised spot or short-term contracts are being signed. JERA’s terms and conditions may become a trading market standard in the Asian LNG market. While the logic for such a change appears compelling for now, there may be unintended consequences in the future. LNG supplies are, broadly, driven by expectations of future revenues from sales. Uncertainty on this aspect, as would stem from a shift from long-term to short-term sales, changes the methodology of evaluating an LNG export project. As such, final investment decisions (FIDs) will have to include more scrutiny of future gas and LNG markets. Should long-term supply contracts give way to spot trading more quickly than market observers may have expected, new projects will be exposed to more uncertainty on price, credit risks and new business development. That shift could well discourage supply, shifting the future market from glut to shortage, while prices become more volatile along the way.n

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Week 3• 22 February • 2016

Rosneft inching closer to purchase of Essar stake ASIA RUSSIA’S Rosneft is in the final stages of due diligence to buy a 49% stake in Essar Oil, the latter’s managing director, L K Gupta, said last week. Essar is India’s second biggest crude refiner and operates a chain of almost 2,000 retail fuel stations. “Rosneft is in advanced stage to conclude the due diligence process and it will still take some time before the deal is finally closed,” Gupta said in a conference call after announcing the firm’s quarterly earnings. The two firms signed a non-binding term sheet outlining plans for the stake sale in July 2015. In November 2015, sources familiar with the deal told the Times of India that the Russian producer had offered to pay around US$2.4-2.5 billion. Gupta stressed that talks with Rosneft were exclusive and refused to comment on “market rumours” that Essar was holding talks with other would-be investors. Bloomberg reported earlier this month that Essar was discussing a stake sale with National Iranian Oil Co. (NIOC) and Saudi Aramco. Interestingly, Rosneft CEO Igor Sechin said at a London forum last week that his firm was interested in Aramco’s potential privatisation. Essar Oil has launched a divestment programme to pay off its debt, estimated at more than US$14 billion, which it accumulated from heavy borrowing to fund expansion in India and overseas. But its overall performance has been buoyed by strong refining margins. Essar’s net profits rose to 3.64 billion rupees (US$53 million) in the quarter ending December 31, from 520 million rupees (US$7.6 million) a year earlier. This was in spite of a 37% decline in revenues to 139.5 billion rupees (US$2 billion). Its gross refining margin almost doubled to US$13.25 per barrel. The firm will fully delist its shares on the National Stock Exchange and Bombay Stock Exchange on February 17.

Vadinar oil refinery, a 400,000 bpd plant in Gujarat state. Sechin said the deal would help increase trade turnover between Russia and India by more than 50%. He also said his company would benefit from the opportunity to obtain a foothold in the Indian downstream market. There may be a downside for Essar, though. Russian Urals Blend crude is a relatively costly feedstock for the Vadinar refinery, which currently relies heavily on Iranian oil, because of its higher transport costs and different yields. Sechin said in July that his company would not rule out the possibility of using swaps to uphold its supply agreement with Essar but did not go into any further detail. But a Reuters source said in June that Rosneft might opt to send Venezuelan oil to the Vadinar plant. Alternatively, he said, the Russian firm could deliver Iranian crude to the refinery once sanctions on Tehran were lifted. Buying a stake in Essar will help Rosneft secure a foothold in the Indian oil market. But it is uncertain whether the timing of this purchase is apt, given Rosneft’s debt pile, which totalled US$24.5 billion at the end of September. Saudi Arabia and Iran could be eyeing a chunk of the Indian refiner for the same reason. Russia has found its market share increasingly under attack by Middle Eastern producers, especially in Europe. It emerged in October 2015 that ExxonMobil, Royal Dutch Shell, Total and Italy’s had all begun buying more Saudi oil, displacing supplies from Russia. Rosneft said at the time that Saudi oil had entered the Polish market, which traditionally relies on Russia for three quarters of its fuel imports.n

Supply ties Gupta said Essar had not yet decided whether to expand crude imports from its top supplier, Iran. “It depends on economic consideration … and whether the crude fits our basket,” he said. The company bought 96% more oil from Tehran in December 2015 than in the previous month, according to Reuters. But Essar has also raised crude supplies from Rosneft. In July, the two firms finalised a strategic agreement for the delivery of 200,000 barrels per day of oil to Essar’s

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Week 3• 22 February • 2016

Mandala Energy acquires two more Indonesian assets ASIA SINGAPORE-BASED Mandala Energy has strengthened its presence in the Indonesian upstream sector by acquiring two assets from Australia’s Cooper Energy. Under agreements signed on February 10, Southeast Asia-focused Mandala Energy will purchase Cooper Energy’s 100% stake in the Sumbagsel productionsharing contract (PSC) and the Merangin III PSC in the South Sumatra Basin for US$8.25 million. The deals are still subject to approval by the Indonesian government and are expected to be completed by the end of June, Cooper Energy said in a filing to the Australian Securities Exchange (ASX) on February 10. In the South Sumatra Basin, Cooper Energy also has a 55% stake in the Tangai-Sukananti joint operation agreement (Tangai-Sukananti KSO). Cooper Energy said in its filing that it would also continue the divestment process for its 55% stake in the Tangai-Sukananti KSO. The remaining 45% stake in the block is held by Mega Adhyaksa Pratama Sukananti, an affiliate of Indonesia’s Foster Oil & Energy. “Today’s transaction marks another important step in our strategy to concentrate Cooper Energy’s resources

and efforts on the eastern Australian energy market,” the Australian developer’s managing director, David Maxwell, said in the filing. In the same filing, Mandala Energy’s CEO, Barry O’Donnell, said: “From a portfolio perspective, [the acquisition] significantly increases our footprint in the prolific South Sumatra Basin and provides us with operatorship of two high-quality exploration assets. We look forward to executing an extensive seismic and drilling programme in order to quickly realise the potential of both blocks.” In October 2015, Mandala Energy also signed an agreement to acquire a 35% stake in the Lemang PSC, also located in the South Sumatra Basin, from Singaporelisted Ramba Energy. The transaction is now deemed to have been completed as it was approved by Indonesian upstream oil and gas regulator SKK Migas, Ramba Energy said on February 11. Ramba Energy retains a 31% stake in the Lemang PSC, while the remaining 34% stake is held by Eastwin Global Investments, which is incorporated in the British Virgin Islands..n

Pertamina seeks private investors NORTH AMERICA PERTAMINA will require private investment to proceed with the Bontang refinery development in East Kalimantan, the Indonesian government confirmed last week. The Jakarta Post reported on February 9 that the state-owned company had been appointed to take charge at Bontang, but that Jakarta would ask the major to seek out private investment. Jakarta will offer a range of incentives to attract investors, including cost-free land clearing and usage, as well as a 10-year tax holiday that can be extended to 15 years if needed. Indonesian Minister for Energy and Natural Resources Sudirman Said said land costs “will be zero”, and that the Ministry for Agriculture would ensure the project receives land certification. The minister added that five investors had already expressed an interest in the project, but did not provide further details. According to Indonesia Investments, Bontang could

cost Pertamina and its partners US$14.5 billion to build. Reports in January suggested Jakarta had already set aside 5 square km of land, and would consider a utility sharing plan that would partner Bontang with an LNG plant operated by Badak LNG. Bontang will have a 300,000 barrel per day capacity, and will be able to produce RON 92 gasoline and Euro IV/V type diesel. Most Indonesian plants currently produce RON 88 gasoline and Euro II diesel. The upgrade is part of Jakarta’s mission to expand Indonesia’s refining capabilities, which will see the effective capacity of Pertamina’s refining network boosted from 820,000 bpd to around 1.7 million bpd. The programme has already seen success at the Cilacap residue fluid catalytic cracking (RFCC) upgrade, which added 30,000 bpd of capacity, and at the relaunch of the TPPI refinery in Tuban, which will process around 61,000 bpd. But Pertamina has a mixed record with private

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Week 3• 22 February • 2016

investment, having cancelled its partnership with JX Nippon for upgrades at the Balikpapan refinery because of what the national oil company (NOC) claimed were differences between the two companies’ investment projections. On February 12, the Jakarta Post reported that Pertamina would need external funding to cover the hole in investment left by JX Nippon’s departure. Pertamina finance director Arief Budiman said the

firm would need US$2.6 billion over the next three to four years to fund the first stage of development at Balikpapan. Budiman conceded that finding external funding could be difficult in the current low price climate, “Looking for funding is harder now because lenders and investors want to ensure realistic financial assumptions and efficiency programmes to reduce expenditures,” he said.n

Sinoenergy behind bid for Canada’s Long Run ASIA CALGARY-BASED producer Long Run Exploration has named China’s Sinoenergy Pacific as the hopeful buyer of all of its oil and gas assets in northern Alberta. In December 2015, Long Run announced that a US$100 million offer had been made by an undisclosed Chinese firm, which was described at the time as a “Christmas miracle” by Dundee Capital Markets’ Chad Ellison owing to the fact that it will also assume the company’s figure of around C$679 million (US$494.5 million) in debt. Long Run has struggled for some time owing to the size of its liabilities, prompting it to look to sell a number of its assets. This is not Sinoenergy’s first foray into Canada, though. In 2015, the company completed its purchase of another Calgary firm, New Star Energy for C$215 million (US$157.2 million). Speaking to the Calgary Herald, Long Run chairman and CEO Bill Andrew said Sinoenergy’s desire to “run an active oil and gas exploration company” was behind the moves, and that further acquisitions could be on the cards.

In the third quarter of 2015, the period for which data is available, Long Run produced 30,700 barrels of oil equivalent per day from its fields in the Alberta Deep Basin, Peace River Montney and Redwater Viking. Meanwhile, New Star produced about 3,500 boepd prior to its sale. “I think the ability to get into Canada, the ability to play not only on the oil side but the gas side, says a lot about why they did the New Star deal and why they’re looking to do this deal,” Andrew added. “And I don’t think … they’re finished.” He went on to say that Sinoenergy had discovered the company through its proposed asset sale. “We put the pieces of the company up for sale, so [that included] all the properties in Long Run, and our agent was Macquarie. The people from Sinoenergy reached out to Macquarie and wanted to look at the property and they did. Then the request came through Macquarie, ‘Could they look at the whole company?’ We said there’s nothing to prevent that.” Long Run’s board has unanimously recommended that shareholders vote for the deal.n

Long Run assets

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Week 3• 22 February • 2016

Rosneft secures four lines of credit from VTB FSU STATE-OWNED Rosneft, Russia’s largest oil company, has arranged to borrow more than 85 billion rubles (US$1.09 billion) from VTB Bank. Members of Rosneft’s central procurement committee reported at a meeting last week that governmentcontrolled VTB had agreed to provide it with four separate lines of credit. Under the first contract, they said, the company will be able to borrow up to 34 billion rubles (US$437 million). The other three lines of credit are worth up to 17 billion rubles (US$218 million) each, they noted. According to the minutes of the committee meeting, which were cited by the Prime news agency, all four contracts came into effect on February 9. Each credit has a term of five years. Rosneft has not revealed how it intends to use the loan funds from VTB. Committee members indicated at the meeting that the parties would seek to reach an agreement on this front later. This is not the company’s first deal with VTB in the

current year. Rosneft and the bank finalised contracts for three five-year lines of credit worth up to 85.4 billion rubles (US$1.1 billion) on January 27. To date, the company has not identified any specific purpose for the funds. The oil operator also intends to seek a 17 billion ruble (US$218 million) line of credit from Gazprombank this year, according to Vedomosti. At the time of going to press, no word was available on when this deal might be finalised. Rosneft is due to repay US$13.7 billion worth of credits this year. At September 30, 2015, the firm’s gross debts stood at US$47.5 billion and its net debts at US$24.5 million. In its interim report on the first nine months of 2015, Rosneft said it had succeeded in reducing its gross debt load by 21.5% year on year by paying off a number of short-term credits. It also stated that it had improved its credit profile “mainly by generating stable free cash flows and receiving funds under long-term crude oil supply agreements.”n

Pacific E&P takeover nears LATIN AMERICA IN the clearest sign yet that a takeover of struggling Pacific E&P may be imminent, the company said in a February 11 release that it was in active contact with interested parties as part of a restructuring process. Harbour subsidiary EIG has extended an offer to buy struggling Canadian developer Pacific’s debt until March 24 and reduced its price per share, saying the company’s financial situation has deteriorated further since it made its initial bid in mid-January. Harbour initially launched a takeover bid for Pacific in May 2015 but it fell through when a group of shareholders opposed it. Since then, Pacific has struggled with the imminent loss of its highest producing field and low oil prices. Investors began to express concern about the company’s future when Pacific waived its January credit payments and subsequently announced an extension to the waiver on February 4. The company’s latest press release says it is “working with lenders and noteholders” to “ensure the long-term

viability of the business”. EIG has given Pacific shareholders until March 24 to vote on its offer. EIG CEO R Blair Thomas told Reuters that “it seems apparent that Pacific is insolvent and that a bankruptcy filing is imminent”. The company theoretically has until February 26 to sort out its cash flow problems but, with ratings agencies lowering Pacific to default level and the company itself addressing rumours of a takeover bid, such a bid now seems inevitable. The O’Hara Group – a group of shareholders headed by Orlando Alvarado which torpedoed the last takeover bid for the company – has so far kept quiet about the EIG offer. It is not clear whether they may be one of the interested parties mentioned by Pacific or how the group would vote on the EIG offer. Pacific itself is not providing any insight, saying in the press release that it “will continue to interact with these [interested] parties directly and refrain from commenting on mischaracterisations made in the media”.n

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Week 3• 22 February • 2016

Iran pushes old theme of replacing dollar for but with new leverage MIDDLE EAST SINCE the lifting of sanctions on January16, Iran has been vocal about its plans to make the Euro the priority currency both for the payment of the vast sums still owed it by buyers of oil accrued over the sanctions era and for all new crude oil sales. This policy is in line with its previous efforts to undermine the US dollar as the principal pricing currency for oil transactions. The fact that it is only the US that has failed to roll back all sanctions fully (see MEOG Week 02) has only added to Tehran’s desire to effect lasting change in this direction. Resuming the push In 2007, Iran – backed by China and Russia – pushed for the replacement of the US dollar as the benchmark currency for the global hydrocarbons pricing complex, going so far as to lobby OPEC members over the course of that year to switch away from the US currency, which then-President, Mahmoud Ahmadinejad, called a “worthless piece of paper.” Although rejected by key OPEC members at the time, by 2009 central bankers and finance ministers from Iran, China, Russia, and Japan, were secretly touting a more developed plan, which involved the replacement of the US dollar with a pricing mechanism based on a basket of currencies, constituted of the Japanese yen, the Chinese renminbi, and the Euro. Again though, pressure from the US persuaded the key Middle Eastern producers of the day to reject it, despite the obvious advantages to the big oil importers China and Japan that this new pricing structure would afford them, and the obvious geopolitical victory that Russia would have gained. Now, though, with Iran set to regain its position as one of the top oil and gas exporters in the world, it can at least implement its US dollar replacement strategy on its own deals initially and, as soon as Iraq is able to do without the support of the US-influenced IMF, use its enormous influence in Baghdad to persuade its neighbour to do likewise. “It is not a question of Iran bearing a grudge against the US per se for its role in being the catalyst for the imposition of sanctions in the first place [in 1979, following the seizing of the US Embassy] or of it ramping up sanctions in the following years,” Mahmood Khaghani, former director general of the National Iranian Oil Co. (NIOC) and director for Caspian Sea Oil and Gas Affairs in the Ministry of Petroleum, told NewsBase.

Instead, “the fact that the US is still holding onto some sanctions even after Implementation Day – and that these could be tightened further after the upcoming Presidential Elections in November – has made them take a no-nonsense view on how to do business in the new sanctions-free environment.” Eurotrip From a practical perspective, with hydrocarbons deals signed since Implementation Day with France’s Total, Italy’s Eni (and before with Maire Technimont), Spain’s CEPSA and Greece’s Hellenic Petroleum (ELPE) – not to mention major non-hydrocarbons deals with Airbus, Peugeot and Danieli, and many more to come from EU firms (see DMEA Week 03) – there is little reason for Iran to take payment in US dollars. “The EU has been a particularly staunch supporter of Iran ever since Edward Snowden’s revelations about the US spying on major EU politicians, including [German Chancellor] Angela Merkel, regardless of US considerations on the matter, and its firms know that Iran, together with Iraq with which it holds enormous sway, is the single greatest opportunity in the global hydrocarbons sphere,” Christopher Cook, director of energy consultancy Wimpole International, told NewsBase. “In Iran’s case, [being] a huge potential trading partner across all other areas of industry,” he added. Underlining the point was the announcement from Rokneddin Javadi, managing director of NIOC that the weekend saw Iran begin the process of loading 4 million barrels of crude oil onto tankers destined to arrive in Europe in the coming days, including 2 million barrels bought by Total. As it stands, according to a statement last week from Iranian vice-president Eshaq Jahangiri, the country is exporting around 1.3 million barrels per day of crude oil, but will be exporting at least 1.5 million bpd by the start of the next Iranian year on March 20 (the pre-sanctions 2011 peak was around 3 million bpd). Moreover, last week Iran’s Petroleum Minister, Bijan Zanganeh announced that ELPE, Italy’s Saras and Royal Dutch Shell – which together owe around US$4 billion to Iran – will use the Euro as the repayment currency. Bills to settle Outside Europe as well, Zanganeh said that the Emirates National Oil Co. (ENOC), Japan and India are working on

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Week 3• 22 February • 2016

settling their debts to Iran’s central bank. NewsBase understands from senior oil and gas industry sources in Tehran that all of these will be paid in Euros, which can now be executed through the global SWIFT transaction network to which Iran has been relinked following Implementation Day. The same is true for the huge debts owed to Iran by China, Cook added. Through its various banking arms, Beijing was a major buyer of Euros (against the US dollar) at the end of December when the Euro was at rock-bottom prices against the US currency, a large contributor to the massive short-squeeze that reversed the long-running bearish sentiment on the EU currency at that time.

“The situation between China and Iran is more complicated than between Iran and India, as the two [Iran and China] have a much more multi-layered relationship, but there is no doubt that China will not pay its debt is US dollars,” he concluded. In fact, a source working closely with the Iranian finance ministry on rolling out a range of new capital markets-related structures told Energy Finance Week last week that it is entirely possible that either China will pay the tens of billions that it owes Iran either in Euros, or in a renminbi-based currency swap structure, now that the Chinese currency has been included in the global basket of reserve currencies that comprise the Special Drawing Rights unit.n

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Week 3• 22 February • 2016

IOCs pledge renewed Kurdish investment MIDDLE EAST THE Kurdistan Regional Government (KRG) last week released its January export report with a headline increase in total sales masking a slight decline in the average daily volumes during the days when the export pipeline to Ceyhan was actually operational. Since mid-2015, international oil company (IOC) producers have been cutting back on the investment required to maintain output levels in response to Erbil’s mounting arrears. However, with the first payments received in early February under the authorities’ new and more formalised remuneration system to replace the ad-hoc disbursals of the previous five months, immediate pledges by both Anglo-Turkish Genel Energy and Norway’s DNO International to resume spending on the territory’s two most-productive fields indicated that the KRG’s bid to win back IOC confidence and thus spur increased output appeared to be succeeding. Exports through pipelines (both the region’s own and the Baghdad-owned Kirkuk-Ceyhan conduit) to Turkey totalled 18.7 million barrels in January, the Ministry of Natural Resources reported – up from 18.1 million barrels in December. However, with the infrastructure suffering only one day of ‘downtime’ last month, compared with three during the month before, average volumes when the route was in operation fell slightly to 624,000 barrels per day from 644,000 bpd. Three months earlier, in October, the average was 661,000 bpd. Exports from the KRG-administered fields fell to 469,000 bpd in January from 480,000 bpd while the North Oil Company’s assets delivered 155,000 bpd during the pipeline’s working days, compared to 164,000 bpd in December. Genel noted in a trading update published in late January that drilling and completion activity had been suspended during the course of last year at the Taq Taq field it operates – which produced an average 116,100 bpd in 2015 – as a result of the KRG’s continued indebtedness: arrears stood at US$421 million at the end of December. The London-listed firm and DNO – operator of Tawke field, where 2015 output averaged 135,200 bpd – had been receiving gross payments of US$30 million per month since September as Erbil attempted to secure their continued commitment to the territory.

While welcomed by all three IOC recipients – including London-based Gulf Keystone Petroleum, operator of the 40,000-bpd Shaikan field – the producers made clear that investment in further development would be contingent on a track record of ongoing regular payments and progress on settling arrears. To this end, the KRG on February 1 announced a new payment mechanism aligning payment with production according to the entitlement originally set out in the fields’ production-sharing contracts (PSCs) with an additional 5% of the field’s gross monthly netback revenue added towards outstanding debt. Four days later, Genel revealed the financial implications of the switch – reporting gross payment received for Taq Taq exports in January of US$16.3 million plus US$3.2 million towards outstanding debt. A day later, DNO acknowledged receipt of US$18 million for exports from Tawke last month and US$3.5 million towards receivables. While the producers were thus worse off in purely financial terms than under the ad-hoc arrangement, the switch to a more formal and predictable mechanism was strongly welcomed. Genel responded first – and exactly as the KRG hoped – by pledging to resume drilling, cessation of which had prompted production to decline. “Drilling work will restart imminently – in the next few weeks,” chief financial officer Ben Monaghan said on February 9. “It is a symbolic restart of our investment.” Last month’s trading update declared a large portion of the company’s US$80-120 million 2016 capital expenditure budget contingent on acceptable resolution of the payment issue. DNO, reporting 2015 results two days later, was even more emphatic – promising new investments at Tawke to reverse natural decline and raise output by 10% by mid-year and further in future months, despite market conditions that saw the firm record a net loss of US$174 million last year. It also intends to drill a second appraisal well at the Peshkabir field in the west of the licence area. “The export payment arrangement just put in place provides regularity, predictability and transparency, thereby laying the foundation for stepped up investments in Kurdistan,” enthused executive chairman Bijan Mossavar-Rahmani.n

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Week 3• 22 February • 2016

Petsec buys Oxy out of Yemen block MIDDLE EAST AUSTRALIA’S Petsec Energy continued to bet on a return to stability in Yemen in early February by acquiring its second concession in the conflict-ridden state. The move also allows former operator Occidental Petroleum (Oxy) of the US to fulfil part of a planned retreat from non-core markets across the region. The US-focussed Australian junior paid less than US$1 million for the producing block – reflecting the enormous risk in investing in an area where operations have been suspended for two years because of persistent security problems predating the current conflict between Houthi rebels and Saudi-backed forces supporting exiled president Abdu-Rabbu Mansour Hadi. However, the company expressed optimism about an imminent resumption of output that is not contingent on an end to the wider war. Petsec acquired 100% of the so-called Damis (block-S1) production licence from Oxy, which owned 75%, and partner Transglobe of Canada for a base case payment of US$700,000 plus trailing payments subject to the resumption of production and other unspecified conditions. The 1,156 square-km block lies in the south of the prolific Ma’arib-Shabwa basin and contains five oil and gas fields, one of which – An Nagyah – was producing at “a limited rate” of around 5,000 barrels per day when force-majeure was declared in February 2014. The acquisition announcement implied that the problem was not primarily with security at the block itself but rather wider political conditions preventing shipments from the terminus of the Ma’arib export pipeline at Ras Isa on the Red Sea coast. Damis’ surface facilities have the capacity to process up to 20,000 bpd of crude and are connected by an 80,000-bpd trunkline to the main 200,000-bpd export conduit – allowing for future increases in production from the block’s undeveloped fields, Petsec said. Calgarybased DeGolyer & MacNaughton Canada has been commissioned to carry out a reserves audit. Production from An Nagyah peaked at more than 12,000 bpd in 2006 and – in common with most of Yemen’s main producing fields – had been in decline as a result of age and underinvestment. Petsec’s stated aim is to resume production this year and to deploy the resulting cash flow to develop other reserves both in Damis and in nearby exploration block 7 (Al-Barqa) in the

Sab’atayn basin 80 km to the northeast – where the firm launched its investment in Yemen in March 2014 with the acquisition of a minority interest. Majority control and operatorship followed in 2015 through the purchase of additional shares from compatriot Oil Search. “It is Petsec’s intention to restart production [from An Nagyah] as early as is feasible, either by piping or trucking or a combination of both, even while conflict exists elsewhere in the country,” chairman Terry Fern explained – adding that the resumption would occur “soon after shipping and refinery acceptances recommence in Yemen, which we are hopeful will be this year”. Yemen’s sole refinery, a 150,000-bpd facility close to the southern city of Aden, resumed operations – processing oil held in storage – last September after pro-government forces recaptured the area but has since reportedly ceased production again through lack of crude feedstock and continues to be subject to security threats. Shipments from the Ras Isa oil terminal, located in an area under Houthi control, stopped last year. According to OPEC statistics, Yemen was producing around 120,000 bpd in 2013-14 before the start of the war – down from 205,000 bpd in 2011, as the instability that both led to and followed the downfall of former president Ali Abdullah al-Saleh in 2012 forced most international oil companies to shut-in operations and evacuate their staff. The Petsec deal completes Oxy’s exit from Yemen, where it had operated for 29 years. The firm’s other interest in the country was a minority share in block 10 (East Shabwa), which was relinquished in December by operator Total of France. While political and security conditions naturally provide sufficient motivation to exit, the American major’s withdrawal also forms part of a broader strategy restated in January of divesting non-core Middle Eastern assets – including those in Iraq and Libya – in order to focus on Abu Dhabi, Oman and Qatar. “In Iraq, we have a strategy as per a procedure defined in our contract with the government, which is just to exit – we’re in the process of doing that now,” incoming CEO Vicky Hollub explained in late January. “In Libya, we are trying to figure out how we exit there – the process is not well-defined.” Oxy owns a stake in the Zubair field in southern Iraq and in various concessions in Libya’s Sirte Basin.n

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Week 3• 22 February • 2016

AFRICA

Egypt cannot repay debts this year Egypt may miss its target of repaying the US$3 billion (11 billion Emirati dirham) it owes to foreign oil and gas companies by the end of 2016, the Egyptian Prime Minister said on February 9. Sharif Esmail told reporters in Dubai lower oil and gas revenues mean the debt will “at least [be reduced] to a very reasonable” level by the end of year. This would not be the first time the government has pushed backed the deadline. It previously said it would repay its arrears by mid-2015, then it said by mid-2016 before again pushing the target back to the end of the year. The prime minister declined to offer a new target date and instead said the government is sticking with its end of year deadline despite raising doubts over whether it remains reachable. “Our objective is to finalise this by the end of this year,” Esmail said at the World Government Summit. The Egyptian government has halved the amount owed to foreign oil and gas companies to around US$3 billion dollars from US$6.3 billion two years ago, Esmail said. Egypt delayed payments to oil and gas firms as its economy was battered after the popular uprising against long time President Hosni Mubarak in 2011. AL BAWABA (JORDAN), February 11, 2016

Japan plans US$800 million rehabilitation credit for Nigeria’s Jebba HPP The Nigerian government and the government of Japan have completed arrangement to sign all relevant agreements towards securing an US$800 million credit to add 578.4

MW of power generation capacity to Jebba Hydropower Plant. This is just as one of the plant’s turbines with a generation capacity of 96.4 MW, which was rehabilitated by Japan after a fire outbreak, was commissioned to increase its available generation capacity to 482 MW. Deputy head of mission at Japan’s embassy Masaya Otsuka, who made the disclosure in Jebba when Japan handed over to Nigeria, the overhauled unit of the six generating turbines it rehabilitated for the country at the plant, said the credit line would be used to rehabilitate and extend the lifespan of four extra units of the plant. VANGUARD (NIGERIA), February 17, 2016

ASIA

China sees boosting defence spending as South China Sea, reforms weigh China will likely announce another large rise in defence spending next month, as the ruling Communist Party seeks to assuage the military’s unhappiness at sweeping reforms and as worries over the South China Sea and Taiwan weigh on Beijing. China will likely announce another large rise in defence spending next month, as the ruling Communist Party seeks to assuage the military’s unhappiness at sweeping reforms and as worries over the South China Sea and Taiwan weigh on Beijing. Military spending last year was budgeted to jump by 10.1%, outpacing slowing, singledigit GDP growth, and another doubledigit rise looks set to be announced at the annual meeting of China’s largely rubber-stamp parliament in March. One source with ties to the military who meets regularly with senior officers said a 30% increase in spending this year had been

mooted in military circles, though the actual rise was unlikely to be that dramatic. “The party has got to show the troop cuts don’t mean the military is being ignored or shunted aside,” the source said, speaking on condition of anonymity for fear of the consequences of talking to a foreign reporter. President Xi Jinping, who has rattled nerves around the region with an increasingly muscular attitude to territorial disputes in the East and South China Seas, is now seeking to drag the People’s Liberation Army into the modern age, cutting 300,000 jobs and revamping the Cold War-era command structure. But the reforms have run into opposition from soldiers and officers worried about job security. “Xi has to keep them on side as there’s so much unhappiness and uncertainty in the ranks,” the source said. CHANNEL NEWS ASIA (SINGAPORE), February 16, 2016

40 billion ringgits in oil revenue loss in 2016 for Malaysia The Malaysian government expects a revenue shortfall of 40 billion ringgits (US$9.52 billion) this year given the sharp drop in oil and gas income, said Prime Minister Datuk Seri Najib Razak. “If you look at the oil price today and what it was one year ago, it means we would lose 40 billion ringgits,” he told Malaysians working and studying in southern California. In stressing the necessity of the Goods and Services Tax (GST), he spoke about how international bodies, such as the International Monetary Fund, had praised Malaysia’s prudent fiscal and monetary policies, and how GST revenue had largely offset the impact of the low oil price. “Can you imagine, without GST, what kind of adverse impact it would have on not only the economy, but also the people’s welfare?” Najib, who is also finance minister, had, on January 28,

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unveiled proactive measures in the re-calibrated 2016 Budget to deal with the global slowdown, including optimising government expenditure and raising revenue from other sources to plug revenue shortfalls. Malaysian officials and analysts said the 40 billion ringgits referred to the reduction in government revenue from oil and gas compared with 2014, when the average price of oil was US$100 (415 ringgits) per barrel. The original assumption for the 2016 Budget was that the price of oil would be US$48 per barrel, or a 30-billionringgit reduction in government revenue.

solar irradiation have also been made in several parts of the country, he added. Amjad said that the AEDB has issued over 25 letters of interest (LoI) to various solar projects having 663 MW accumulative capacity so far, adding that all these projects would attain commercial operations date (COD) by 2018. DAILY TIMES (PAKISTAN), February 11, 2016

AUSTRALASIA

Australian nuclear waste dump could be Pakistan’s renewable highly lucrative sector attracts US$3 billion in one year NEW STRAITS TIMES (MALAYSIA), February 15, 2016

The Renewable Energy sector has attracted foreign investment of over US$3 billion during the last one year. “Due to the potential, robust policy framework, lucrative tariff structures and bankable security documents, Pakistan has become a choicer investment destination for private investors,” said Alternative Energy Development Board (AEDB) CEO Amjad Ali Awan. He said the government was taking pragmatic steps to harness the available renewable energy potential, diversify its energy mix and ensure energy security and sustainable development in the country. He observed that owing to the promotion and development of RE technology in the country, a record investment has been witnessed in just one year, revealing the interest of investors in this sector. The CEO said that detailed resource assessment of wind, solar and biomass was carried out in the country through ESMAP’s (World Bank) assistance. Ground installations for measuring of

An Australian facility to store and dispose of spent nuclear fuel rods and other waste from around the world could bring in A$5 billion in revenue every year for at least 30 years, a Royal Commission into the nuclear industry has found, BusinessDay reported. The review found that such a facility would be “highly profitable under a range of cost and revenue assumptions”. Total revenue from the project would reach A$257 billion, with costs conservatively modelled at A$145 billion over a 120-year project life. An integrated storage and nuclear waste disposal facility could be operational by the late 2020s and could meet a global need, with 390,000 tonnes currently in temporary storage in other countries, much of it in the Asia-Pacific region. The Royal Commission into the Nuclear Fuel Cycle, headed by former South Australian Governor Kevin Scarce, has taken evidence from 128 witnesses over the past 12 months. The Royal Commissioner found that setting up a nuclear power plant now in the state wouldn’t be commercially viable under the national electricity market amid projections of “flat future demand” in South Australia as more people used solar and exited the

national grid. BUSINESSDAY (AUSTRALIA), February 15, 2016

China’s global nuclear power ambitions depend on safety China has embarked on a programme to triple nuclear power generation by 2020. With 27 reactors, the reduction in pollution is impressive and with a further 25 under construction, that will increasingly be so. But the rush to end a reliance on power from polluting coal cannot come with excessive haste; the nation’s first white paper on nuclear energy makes clear that above all else must come safety and security. Proving the point, construction of two latest generation reactors in Guangdong has been halted over safety concerns. Accidents at Fukushima in Japan in 2011, Chernobyl in Ukraine in 1986, and at Three Mile Island in the US in 1979 highlight why safety has to always come first, as poor oversight, management and safety standards were behind the disasters. The paper details policies and measures to boost emergency preparedness and strengthen security. SCMP (CHINA), February 12, 2016

EUROPE

Growing market for decommissioning in Norway evident from Oil & Gas UK forecast Norway’s decommissioning market has the potential to be the second largest in the North Sea after the UK Continental Shelf, according to Oil & Gas UK’s first Norwegian Continental Shelf Decommissioning Insight report, which provides a forecast for

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the region over the next decade. The publication was launched February 16 at the Norwegian Petroleum Society’s North Sea Decommissioning conference in Oslo. Oil & Gas UK’s operations director Oonagh Werngren said: “While the Norwegian oil and gas industry is less mature than the UK sector and decommissioning activity is in its infancy, the report shows there are 12 concrete facilities, 19 floating steel facilities, 88 steel facilities and nearly 350 subsea systems in place, most of which will eventually require decommissioning. An estimated 3,000 wells will also need to be plugged and abandoned. “Oil & Gas UK has worked together with the five key operators on the Norwegian Continental Shelf to analyse data that reveals there will be twenty three decommissioning projects, ranging from small subsea tie-backs to full-scale integrated platform removals, between 2015 and 2024. With the Norwegian Petroleum Directorate estimating that decommissioning expenditure during this period could reach 160 billion Norwegian krone (GBP 12.5 billion), the activity represents a significant emerging business in the sector.” Werngren added: “While decommissioning activities are steadily growing, the industry’s efforts are focused on maintaining offshore production in the North Sea for as long as it’s safe and economically possible to do. To sustain the health of the sector, we must help an efficient decommissioning market emerge as part of, and alongside, the industry’s continued and sustained programme of capital investment in new developments.” OIL & GAS UK (UK), February 16, 2016

Polish Tauron flags US$1.3 billion 2015 impairment hit Poland’s No 2 energy producer, state-run Tauron, expects to take a

4.931-billion zloty (US$1.3 billion) hit from asset impairments on its 2015 net profit, the group said. The impairments are related to Tauron’s power generation and heating assets and will impact its last-year standalone results, which the company plans to publish on March 9. Tauron’s larger local rival PGE run similar impairment tests last year, which resulted in a record 8.8-billionzloty writedown. REUTERS, February 15, 2016

Gazprom taking comprehensive cost optimisation measures The Gazprom board of directors took notice of the information about the cost optimisation trends across Gazprom Group in 2016. It was highlighted that Gazprom pursued the consistent policy of improving the cost management practices, reducing operating costs and maximising the value for money ratio. In an unstable economic environment this work is highly relevant, therefore Gazprom is using all possible means and exploring new opportunities for further cost optimisation. The cost optimisation strategy is focused around several key areas: generation of the Investment Programme and the Budget, development and execution of the cost reduction program, implementation of cost optimisation plans by types of activity and procurement of goods, works, and services. At the budgeting stage, Gazprom optimises a number of expenditure items by using a standard setting approach, determining specific cost parameters and finding the best deals on the market. The costs are ranked according to the level of significance for performing the current activities and unconditionally fulfilling all the obligations. In respect of the Investment Programme preparation, the projects are divided by the degree

of priority for achieving the company’s strategic goals and meeting peak demand during the autumn-winter period. INTERFAX (RUSSIA), February 16, 2016

L AT I N A M E R I C A

Iran, Brazil in talks on investment in Brazil refineries Iran and Brazil are in talks about possible Iranian investment in troubled refinery projects controlled by Brazilian state-led oil company Petroleo Brasileiro SA (Petrobras), a Brazilian government source said. Iran, which is boosting oil output after the end of sanctions over its nuclear programme, is interested in exporting oil to Brazil, processing that crude at refineries in Brazil’s northeastern region and then selling it in the Brazilian market, the source said, adding that talks are at an early stage. Talks though are far from any result, the source added. “For this subject to be considered embryonic it will still need to evolve a lot,” said the source, who asked for anonymity because the inter-government talks are private. Iran has shown interest in investing in the construction of the Premium I and Premium II refineries in Brazil’s north-eastern states of Maranhao and Ceara, the source said. The refineries are designed to produce low-sulphur fuels. While plans for those projects were developed by Petrobras, as the state-owned oil company is known, they have been dropped from its investment plan. The source was not clear if any Iranian investment would include Petrobras. Battered by financial problems, a corruption scandal and falling oil prices, Petrobras suspended work on both projects. Each is expected to cost more than US$15 billion. To help reduce its debt of about

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US$130 billion, Petrobras plans to sell US$15.1 billion of assets by the end of this year and it has long said it has been seeking partners for its refinery assets. Earlier, Brazilian Mines and Energy Minister Eduardo Braga said Brazil “is in talks with the Iranians about the question of refineries in Brazil” but he declined to give details. REUTERS, February 12, 2016

MIDDLE EAST

Iraq PM offers cashstrapped Kurds salaries for oil Iraq’s federal government will pay the salaries of the cash-strapped Kurdish region’s employees if it halts its independent oil exports, Prime Minister Haider al-Abadi said. Iraq’s autonomous Kurdistan region, facing a financial crisis due to low oil prices, has announced its employees will be paid partial salaries until further notice and that months of unpaid wages will be considered loans to the government. “Give us the oil and I will give every employee in Kurdistan (their) salary,” Abadi said. Iraqi Kurdistan has been independently exporting crude via Turkey from northern territory it controls since a deal with Baghdad on oil and revenue-sharing collapsed last year, a move the federal government considers illegal. Abadi, who has previously put Kurdistan’s oil exports at over 600,000 bpd, said this amounts to the region’s share of the federal budget, which Baghdad is withholding.

“Exports from the region represent around 16% of the oil exported... from all Iraq, so the region has obtained its (share of the) budget,” he said. The Kurdish austerity measures have sparked widespread anger among regional government employees, some of whom have protested or gone on strike. The region’s de facto president, Massud Barzani, has called for a referendum on independence, but Kurdistan’s financial woes effectively rule out a viable state for now. AFP, February 16, 2016 Qatar’s private consumption to increase on stable spending Qatar’s investments as a share of its gross domestic product (GDP) rose to 39.6% in the second quarter of 2015 from 32.4% in 2014 on stable government capital spending. The country’s private consumption rose to 20.8% of GDP in the second quarter of 2015 from 14.8% of GDP in 2014, with imports similarly increasing from 30.5% to 36.1% of GDP on growing population needs, QNB Group’s monthly report noted. QNB expects the share of private consumption and investment to increase on high population growth and strong government investments; lower expected oil prices in 2015 should reduce the share of exports. Qatar’s crude oil production decreased to 683,000 bpd in November 2015 from 639,000 bpd in October. QNB expects oil prices to stabilise as excess supply in the global market is reduced by both higher demand and production cuts among highcost producers, such as US shale oil producers. THE PENINSULA (QATAR), February 13, 2016

NORTH AMERICA

BC LNG investment will yield long-term profits says energy analyst The BC government made the right decision putting their eggs in the LNG basket, because the move will yield long-term profits, says one energy analyst. The BC Liberals are putting C$100 million of taxpayers’ money into a LNG prosperity fund and say more money will be added when the LNG industry takes off in BC. But the industry itself is warning that with oil prices falling the window of opportunity is rapidly closing. Some economists, however, maintain the future is bright for the natural gas industry because of climate change agreements. “It is a very long term industry and there is significant demand ... which is motivated by the Paris agreement and the commitments that Asian countries made to clean their energy systems, said KPMG Global Head of LNG Mary Hemmingsen. She admits it is too late for BC to cash in on current demand, but there is still a chance for Canada to be the world’s North American supplier of LNG. “We have an approval process that provides 40-year supply and it sets us apart in terms of a long-term secure supply for buyers of LNG globally.” Hemmingsen says the BC government will have to wait and see whether their prosperity fund pays off. “As [Finance] Minister de Jong said, hopefully it’s not if but when, and it’ll be keyed-off of the decisions that some of the leading projects make this year.” CBC NEWS (CANADA), February 17, 2016

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