Energy Finance Week Issue 02 by NewsBase Ltd.

Week 02• 15 February • 2016

ENERGY FINANCE WEEK This week’s top stories

v With oil set to fall further, SWF

position liquidations bring new crisis p2

v Permian producers attract new equity p4

v Oil price impact clear in

European majors’ results p9

v Chevron plans to sell off South African mid-, downstream business p12

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Week 2• 15 February • 2016

With oil set to fall further, SWF position liquidations bring new crisis MARKET THERE can be little doubt that Saudi Arabia’s strategy to price out high-cost oil production has so far failed. US output of around 9.1 million barrels per day is almost exactly where it was a year ago when the price war began. Judging from the state of US producers, there is no sign that the strategy will succeed any time soon. It is also true, however, that many of the larger, traditional oil companies in the US and elsewhere have shelved big investment projects, such as expensive deepwater drilling in the Gulf of Mexico. Such projects take years to realise and it takes equally long for lower levels of investment to result in lower supply, but the swing in output was expected to come from tight oil production. “Although producers cut investment by around US$40 billion in 2015 compared to 2014, this has unexpectedly proven enough to keep tight oil production close to steady for the year after peaking in early 2015,” Stefan Kreuzkamp, chief investment officer for Deutsche Asset Management told Energy Finance Week. If the price is right Tight oil producers are not only now increasingly drilling near the core of their deposits, where they know they will strike it rich, rather than on the fringes, but are also improving their cost discipline, technology and efficiency. “Not so long ago, it was widely assumed US shale producers need an oil price of US$60-90 per barrel to invest in new projects, but now in the core areas of Bakken, for example, it makes sense to increase drilling at US$50 per barrel, whilst in the Permian this number is even lower, and for some of the best operators in the best fields, break-even costs now equal approximately US$36 per barrel, and that actually includes interest on debt financing,” he added. Deutsche AM has predicted that WTI oil will average around US$40 per barrel this year, and remain below that level during the first half. Prices, though, may go a lot lower than that, both from a technical perspective and from the way in which different asset class dynamics are currently feeding into each other. Regarding technicalities, a mild winter so far in the Northern Hemisphere owing to the El Niño weather phenomenon has certainly skewed risks further to the downside. “With European heating demand a bigger driver to European winter distillate demand than in the US, this is where the greatest demand risk lies, as it would only take 50 fewer heating degree days than normal – which

for each month has a probability of between 15% and 30% – for EU distillate inventories to reach new record highs, all else remaining constant,” Damien Courvalin, Goldman Sachs’ senior commodities strategist, told Energy Finance Week. “The prospect of mild winter weather over the coming months – given current conditions – and corollary weak heating demand in the US and Europe, would likely be the trigger for adjustments through[out] the physical market, pushing oil prices down to [a level equal to]cash costs, which we estimate are likely around US$20 per barrel,” he concluded. The wait continues However, there is more downside potential than is related simply to the straight hydrocarbons supply/demand equation. “While the supply story has received significant attention over the last 18 months, it does not fully explain the fall in spot prices or the firmly negative roll yields since mid-2014, and to get a complete picture we must also look at demand dynamics, given the importance of the business cycle – that is, growth recovery - to commodity markets,” New York-based Goldman Sachs commodities economist, Michael Hinds, told Energy Finance Week. The Goldmans’ economist expected a clear reacceleration in global economic activity by the third quarter of 2015, in line with the global output gap forecasts that were firmly into the ‘recovery phase’ of the business cycle by the end of 2015, and heading into the ‘expansion phase’ by late 2017/early 2018. However, Hinds said, this recovery has proven much more elusive than initially expected, and demand weakness has been compounding the negative returns associated with the ongoing supply shift, with emerging markets having driven this growth weakness, and [lack of] private credit, sovereign debt and terms of trade shocks depressing activity. This marks the ‘Third Wave’ of the global financial crisis, he added, following the developed markets (DM) financial crisis and the European sovereign crisis, and has been characterised by the weak global growth backdrop feeding back into commodity price deflation outside the demand channel. “Weak EM growth, and worsening terms of trade, has seen significant EM FX depreciation, including among commodity producers and, as local currency costs of

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 2• 15 February • 2016

production have fallen, commodity cost curves have been pushed lower and flatter in US dollar terms, so exacerbating oversupply and making new equilibrium price levels a moving target, to the downside,” said Hinds. With the US Fed having now embarked on an interest rate tightening cycle in December, there is no longer any pause in these self-reinforcing market elements, reinforcing the view of a continued negative outlook for commodities over the coming few months.

is that although [SWFs] are having to sell these assets [banking stocks] in order to boost their budgets, they are also hitting the very people who have put them in this situation in the first place [unconventional producers], as selling bank stocks with heavy unconventionals industry loan books means these banks will, in turn, have to cut the credit lines for these shale players,” a senior Londonbased equities dealer for a major global bank told Energy Finance Week last week.

Tough pill to swallow Even at last year’s average WTI price of US$48.67 per barrel the budgets of OPEC member states lost at least US$450 billion in revenues over the 2015 12 month period, according to the International Energy Agency (IEA). This prompted a number of oil producer states’ sovereign wealth funds (SWFs) to embark on a sustained liquidation of asset holdings elsewhere, principally in their massive holdings of equities in benchmark stock indices in the US, UK, and EU. “SWFs were – are – major holders of investment portfolios abroad, bonds and equities but especially equities as they generate dividends and capital gains potential, but with deficits to plug at home quickly many have been forced into substantial liquidations of these assets in the past few weeks and months,” Christopher Cook, director of energy consultancy Wimpole International, told Energy Finance Week. Indeed, according to J.P. Morgan’s global market strategist, Nikolaos Panigirtzoglou, oil producers’ funds hold around US$2 trillion of publicly-listed equities worldwide, with around US$700 billion of this possibly invested in western European equities, and between a quarter and one-third in banking stocks. Although much SWF selling is difficult to detect as it is done through high frequency trading companies in agglomerated trades, a number of major global bank equities traders last week confirmed multi-billion US dollar selling of Western equities (mainly banks) by SWFs over the past few weeks in particular. Moreover, a lot of this, they added, has been focussed on banks that have heavy loan books out to US energy producers, especially in the tight oil segment. “It’s a clever tactic really out of a bad situation, which

Sell-off Although the vast bulk of SWF asset liquidations so far have been in the equities sector they have hit the bond markets too. The S&P 500 Index, the Euro Stoxx 50 Index, and the German DAX (which does not include a single major oil producer in its constituent companies), have lost around 10% of their value in just the last month, with individual banks having lost up to 40% of their value over the same period. Unsurprisingly, with the dramatic increase in risk that this movement implies having been most pronounced in the US energy high yield segment, the spreads of all US high-yield debt over US Treasuries has been widening markedly for months, bringing with it the familiar trading patterns that portended major financial crises in the past. “The record shows that the high-yield bond spread’s month-long average has climbed above 800 basis points [bps] on only four previous occasions: August 2008, July 2002, November 2000, and October 1990 and in three of those four incidents, the US was about to enter, or was already in, a recession,” John Lonski, chief economist for Moody’s Capital Markets Research, told Energy Finance Week. “The one exception was July 2002, which, despite how the high-yield spread’s month-long average eventually peaked – at the 1,059 bps of October 2002 – a then young economic recovery survived and would not expire until November 2007,” he added. In this context, after averaging 776 bps in January, the US high-yield bond spread has averaged 836 bps thus far in February, a figure that is widely expected to widen out even further as evidence of China’s ongoing slowdown in the rate of growth continues to gather pace over the coming year.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 2• 15 February • 2016

Permian producers attract new equity Producers in the Permian Basin continue to raise equity through share sales even as the oil price hovers below US$30 per barrel. NORTH AMERICA

THERE can be little doubt that Saudi Arabia’s strategy to price out high-cost oil production has failed so far. US output of around 9.1 million barrels per day is almost exactly where it was a year ago when the price war began. Judging from the state of US producers, there is no sign that it will succeed any time soon. It is true that many of the larger, traditional oil companies in the US and elsewhere have shelved big investment projects, such as expensive deepwater drilling in the Gulf of Mexico. Shale drillers in West Texas’ Permian Basin are selling shares in order to raise new equity as oil prices below US$30 per barrel lead to cash shortfalls. Bloomberg reported last week that drillers had raised at least US$2 billion from share sales over the previous eight weeks, with more issuances expected. Among those that have already raised new equity are Pioneer Natural Resources and Diamondback Energy, which launched sales of 12 million and 4 million shares respectively last month.

Bloomberg cited Concho Resources’ chief commercial officer, Will Giraud, as saying that there was roughly US$50 billion in private equity capital funding over 80 management teams focused on the Permian. More recently, Invictus Energy announced in mid-January that it had secured US$150 million in an equity commitment from its management and Kayne Anderson Energy Funds, the energy arm of Kayne Anderson Capital Advisors. The funds will be used by Invictus to drill in the Permian and the Eagle Ford shale, also in Texas. The move is part of a broader trend of private equity investors backing small energy companies seeking to take advantage of cheap assets. However, selling assets is not an attractive option for drillers trying to raise equity right now because of because of an oversupply of property on the auction block and pessimism about the direction of oil prices, Deckelbaum told Bloomberg. Thus, while asset sales are still likely, especially among the most distressed companies, share issuances may still be a preferable option.

Attractive option Such moves are an attractive option for drillers facing cash shortfalls and unwilling to take on more debt. “In a world where the oil price can break you, taking on debt is an absolute no-no,” a KeyBanc Capital Markets analyst, David Deckelbaum, told Bloomberg. He added that he expected a “heavy wave” of share sales by other producers. This was echoed in a Wells Fargo Securities note last month, in which analyst Gordon Douthat said the “equity window appears to be open”. He anticipated more companies with assets and balance sheets similar to Diamondback’s to follow with their own stock sales. Deckelbaum identified several other Permian producers that may be tempted to sell new shares to help fund their 2016 drilling budgets, including Callon Petroleum, Cimarex Energy, Energen, Laredo Petroleum, Parsley Energy and RSP Permian. None of these companies have confirmed such moves thus far but the pressure to raise equity will only intensify with no end to low oil prices in sight. Adding to the pressure is the fact that some hedge funds and institutional investors have recently sold off some of their stock in companies including RSP and Parsley. Private equity players have continued to back activity in the Permian Basin, though. In November 2015,

Permian pressure Drillers in the Permian have the advantage that it is the only major shale region where production is still rising, at least somewhat and in the short term. According to the US Energy Information Administration (EIA), Permian production is projected to rise by 1,000 barrels per day between February and March. However, this marks a slowdown in growth from recent months and beyond March, the Permian looks likely to join the US’ other tight oil producing regions in declining. Nonetheless, the region has been considered the most attractive in the US for shale development even as the oil price slump has worsened, thanks to its stacked plays and rising estimated ultimate recovery (EUR) rates. This may help activity to continue even further despite the slowdown. A worrying sign is the fact that the Permian’s oil rig count has fallen to a new low of 177 according to the latest data from Baker Hughes. However, the two next largest tight oil production regions in the US – the Eagle Ford and the Williston Basin – are down to 55 and 42 oil rigs respectively, while activity remains comparatively high in the Permian. Thus, the region may finally be starting to feel the pain of the downturn more, but is still better positioned than other shale producing areas, with drillers there standing a better chance of attracting more new equity.n

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Week 2• 15 February • 2016

Chesapeake stock tanks on bankruptcy fears NORTH AMERICA CHESAPEAKE Energy shares plummeted this week on concerns that the heavily indebted natural gas producer was on the brink of bankruptcy. Trading of Oklahoma City-based Chesapeake Energy was stopped on February 8 after shares fell by over 50% following reports that the company had asked Kirkland & Ellis, its long-time legal counsel, to explore restructuring options. The stock recovered some ground later in the day, and Chesapeake issued a statement saying it “currently has no plans to pursue bankruptcy”. The company added that it was “aggressively seeking to maximise value for all shareholders”. Chesapeake, the second largest US natural gas producer after ExxonMobil, is saddled with a debt load eight times its market value. In the third quarter of 2015, it reported a loss of US$4.69 billion, down from a US$169 million profit in the third quarter of 2014. In January, Standard & Poor’s downgraded Chesapeake’s credit rating, calling the company’s debt levels unsustainable. On top of its debt, Chesapeake is committed to paying around US$2 billion per year to use pipelines owned by

several companies, including Tulsa-based Williams Cos. The latter’s stock fell 35% on February 8, partly owing to its exposure to Chesapeake. According to public records cited by international media, Chesapeake has enough money to cover its March debt payments, but there are fears that it faces a cash shortfall of over US$1 billion up to 2018. To shore up its balance sheet, Chesapeake has cut jobs and cancelled drilling projects, among other measures. The company is expected to attempt to renegotiate its pipeline contracts with Williams and others. Chesapeake is not the only US shale driller struggling with heavy debt in the low oil price environment and trying to assuage market fears. Also on February 8, Halcon Resources released a statement saying it continued to explore multiple options for restructuring its balance sheet but “does not intend to comment on inaccurate media reports related to such efforts”. It added that it “does not intend to make any further announcements concerning its review of alternatives unless and until it determines that additional disclosures are necessary or appropriate”.n

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Osage files for bankruptcy protection NORTH AMERICA CALIFORNIA-BASED Osage Exploration and Development has voluntarily filed for Chapter 11 bankruptcy protection, citing the effect of low oil prices on company operations. Crude prices have fallen by over 70% since June 2014, putting pressure on oil and gas companies globally. Many have cut back workforces and restructured debt, in some cases in efforts to avoid insolvency. However, the number of bankruptcies is rising. Crude prices are currently trading at around US$30 per barrel, with the low price environment anticipated to continue for the foreseeable future. Osage said that a combination of liquidity constraints and an inability to raise new capital had made it necessary to seek Chapter 11 bankruptcy protection in order to “facilitate a prompt sale of all of its assets”. Osage has around US$42.5 million in liabilities, including about US$26 million owed to a New York-based investment company, the firm added in a court filing. Osage, which was founded in 2004 and became a publicly traded company two years later, focuses on the

horizontal Mississippian and Woodford plays in Oklahoma. The San Diego-headquartered firm currently has a working interest in 55 wells located in Logan County, Oklahoma, and a royalty interest in 21 additional wells in the state. Osage drilled and brought on line its final well last month, and has now suspended development of all of its acreage. It said that projected prices for natural gas had made it uneconomical to develop any of its remaining acreage. The company’s assets are expected to be sold at auction around the end of March, according to media reports. “We want to have the deal closed by the middle of April,” a Crowe and Dunlevy lawyer representing Osage in the bankruptcy proceedings, Mark Craige, was reported by the Oklahoman as saying. Osage has been showing signs of financial distress for some time. In the summer of 2015 the company closed its Oklahoma City office. In October it voluntarily delisted its common stock from the NASDAQ Over The Counter Bulletin Board.n

Resource Energy announces Williston Basin purchase NORTH AMERICA RESOURCE Energy Partners, a recently formed private equity-backed upstream company, has said that it acquired Williston Basin assets back in November 2015. The move, announced in a February 3 statement, marked the first acquisition by Resource, which is a portfolio company held by global alternative investment manager Apollo Global Management. Denver-based Resource said the acquisition closed on November 23 and involved the purchase of 112 oil wells in the Williston Basin, of which 54 are operated, generating 2,300 barrels per day of oil equivalent of operated production. The terms of the transaction were not disclosed. Resource said it was “actively pursuing opportunities to expand its footprint in the Bakken play as well as in other Rockies and Texas unconventional oil plays” in the next few years, and seeking to spend US$25-500 million on such acquisitions. Resource raised US$153.6 million of equity financing

in October. The company was created to implement an acquisition and exploitation strategy principally focused on the revitalisation of existing wellbores. Apollo Global Management had roughly US$162 billion worth of assets under management as of September 30, 2015. Other players have also bought into Williston Basin assets in recent months. In December, NP Resources, a joint venture between NPR Management Holdings and Vortus Investments, acquired various assets in the Williston Basin, including 53 operated and 7 nonoperated wells, and 173 “high-quality” undeveloped drilling locations. In the midstream, in early January, Tesoro announced it had closed its acquisition of Great Northern Midstream, a crude oil logistics provider. The acquisition included the 97-mile (156-km) BakkenLink oil pipeline, which connects to several third-party gathering systems, and a proprietary 28-mile (45-km) gathering system in the core of the Bakken play.n

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Terra buys WPX’s Rockies subsidiary NORTH AMERICA HOUSTON-BASED Terra Energy Partners has agreed to buy WPX Energy’s WPX Energy Rocky Mountain subsidiary for US$910 million. Terra said on February 9 that under the deal it would also acquire natural gas hedges holding a current in-themoney value of over US$90 million. In exchange for the hedges, Terra will assume about US$100 million worth of WPX’s future firm transportation obligations that extend up to 2022. The deal includes 200,000 net acres (809 square km) in Colorado’s Piceance Basin with recent net production of about 500 million cubic feet (14.2 million cubic metres) per day of gas equivalent. The assets are estimated to hold proven, developed producing reserves of 2 trillion cubic feet (56.6 billion cubic metres) equivalent and numerous low-risk drilling locations. The transaction will also give Terra deep rights totalling 150,000 net acres (607 square km) prospective in the horizontal Mancos-Niobrara play.

Terra said it had received an increased equity commitment from existing investor Kayne Private Energy Income Fund, as well as a new equity commitment from Warburg Pincus, putting the company’s aggregate commitment at US$800 million with the two investors as equal partners. “We are excited to announce our first acquisition since forming Terra last summer,” Terra’s CEO, Michael Land, said. “The Piceance Basin is an area that we know well and one that we believe offers considerable upside potential through focused management. WPX, meanwhile, has turned its focus to its operations in the Permian Basin in West Texas. It has struck over US$5.5 billion in deals over the past two years in an effort to re-shape the company, high-grade its assets and protect its financial position as it navigates the low price environment. “Our bias for action and being opportunistic won’t change,” WPX’s president and CEO, Rick Muncrief, said. “We will pursue our very best investment options and continually evaluate how to optimise our assets.”n

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Plains All American’s earnings fall NORTH AMERICA PLAINS All American Pipeline said on February 8 that broken commitments from producers and unseasonably warm temperatures had put downward pressure on its fourth-quarter 2015 earnings. Plains is a publicly traded master limited partnership (MLP) in the oil pipeline transportation, marketing and storage business. The Houston-based company reported adjusted earnings before interest, tax, depreciation and amortisation (EBITDA) of US$563 million, down 5% compared to the fourth quarter of 2014. Adjusted EBITDA for the whole of 2015 was US$2.17 billion. Plains’ net income fell to US$247 million from US$389 million the previous year. Revenue fell to US$5 billion in the final quarter of 2015 from US$9.5 billion in the same quarter of 2014. Plains’ chairman and CEO, Greg Armstrong, said in a statement that the company’s fourth-quarter results had been negatively affected by about US$15 million related to deficiencies on minimum volume commitments and a roughly US$15 million shift in earnings recognition on some natural gas liquids (NGL) sales activities from the fourth quarter of 2015 to the first quarter of 2016. “This earnings shift is primarily the result of delayed

inventory draws due to unseasonably warm temperatures in certain parts of the US and Canada, as well as impacts of inventory pricing during the fourth quarter. Additionally, severe weather in West Texas and the Mid-continent resulted in volume shortfalls impacting results by approximately US$5 million,” he said. Armstrong added, however, that the company was well positioned to navigate near-term challenges and to grow in the intermediate and long term as industry conditions improve. “The US$1.6 billion of proceeds from our recent preferred equity placement satisfies [Plains] equity financing needs for 2016 and substantially all of 2017 and enables [Plains] to complete its multi-year, multibillion dollar capital expansion programme, while maintaining substantial liquidity and a solid balance sheet,” he said. Armstrong said Plains had “visibility for incremental cash flow contributions over the next 24 months from the completion of these projects, the majority of which are backed by minimum volume commitments and other contractual support.”n

Suncor Energy reports Q4 loss NORTH AMERICA CANADA’S Suncor Energy has reported a C$2 billion (US$1.4 billion) net loss in the fourth quarter of 2015 compared to a C$84 million (US$60 million) profit in the same period of 2014. The loss was attributed to the collapse in crude prices, as well as impairment charges worth nearly C$1.6 billion (US$1.1 billion) and a C$382 million (US$274 million) foreign exchange loss. Suncor posted a C$26 million (US$19 million) operating loss, or C$0.02 (US$0.01) per share, in the fourth quarter of 2015, against a C$386 million (US$277 million) or C$0.27 (US$0.19) per share, profit in the same period a year earlier. Cash flow from operations totalled C$1.294 billion (US$928.7 million), compared with C$1.492 billion (US$1.1 billion) a year earlier. Suncor’s total production rose to 582,900 barrels of oil equivalent per day in the fourth quarter of 2015 from 557,600 boepd in the same quarter of 2014, which the company attributed mainly to the “strong reliability” of its oil sands operations. The firm’s oil sands production rose

to 439,700 barrels per day in the quarter from 384,200 bpd the previous year, and included record in situ output. The company also announced that it was cutting its capital spending for 2016 to C$6.0-6.5 billion (US$4.34.7 billion) from C$6.7-7.3 billion (US$4.8-5.2 billion) previously announced in November 2015. “We have surpassed the reliability and cost reduction targets we established in early 2015,” Suncor’s president and CEO, Steve Williams, said. “Operating costs across the organisation are down almost C$1 billion [US$718 million] from last year, while oil sands upgrading reliability exceeded 90%, more than a year ahead of our original plan.” Suncor’s quarterly earnings fell short of market expectations of operating earnings of C$0.10 (US$0.07) per share, illustrating the fact that even the largest players are struggling in the current low price environment. The company launched a takeover bid for Canadian Oil Sands in October 2015, with the companies reaching an agreement in January.n

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Oil price impact clear in European majors’ results EUROPE Statoil One of the first to announce its results was Statoil. For the full 2015 year, its pre-tax adjusted earnings were 77.0 billion kroner (US$9.02 billion), and 19.5 billion kroner (US$2.28 billion) after tax. Adjusted quarterly earnings were 15.2 billion kroner (US$1.78 billion), down 44% compared to 2014. Adjusted earnings after tax, excluding financial and other items, were 1.6 billion kroner (US$187 million), compared with 4.3 billion kroner (US$500 million) in the same period last year. But the company’s net income was affected hugely by 10.1 billion kroner (US$1.18 billion) in impairment charges related to its assets, as well as by provisions and asset sales. With these factored in, the quarterly net income showed a loss of 9.2 billion kroner (US$1.08 billion), and this resulted in a net loss of 37.3 billion kroner (US$4.37 billion) across the full year. Shell Royal Dutch Shell fared no better. It reported fourthquarter profit (adjusted for one-time items and inventory changes) that was down 44% year on year at US$1.8 billion. Its quarterly current cost of supplies (CCS) earnings were down 56% at US$1.84 billion, while full-year earnings were 80% down at US$3.84 billion. Fullyear 2015 earnings excluding identified items fell from US$22.6 billion to US$10.7 billion. Shell’s upstream CCS earnings excluding identified items were US$1.78 billion in 2015, a major drop on the US$16.5 billion reported in 2014 owing to various impairment charges. Offsetting this, however, downstream earnings climbed to US$9.74 billion, up from US$6.26 billion in 2014. Dong Energy In Denmark, Dong Energy announced an increase in its group-wide operating profit in 2015. But it too took a massive impairment loss of 15.8 billion kroner (US$2.4 billion) after tax, 14.8 billion kroner (US$2.24 billion) of which was related to its oil and gas operations. This resulted in its net income for the year amounting to a loss of 12.1 billion kroner (US$1.83 billion) – the largest corporate financial loss ever recorded in the country’s history. Dong had previously announced its intention to focus on renewable energy, but it also said it would hold on to its oil and gas exploration and production division and use it to finance renewable energy projects. If its

current losses persist, however, it may have to rethink those plans. Total France’s Total struck a more positive note, boasting that it had achieved the “best performance among the majors” when it unveiled its results on February 11. Adjusted net income dropped by 18% to US$10.5 billion in 2015, while fourth-quarter income fell to US$2.08 billion, and its quarterly income also slipped into the red, showing a net loss of US$1.63 billion, when write-downs on its assets in Canada and Nigeria and elsewhere are factored in. This was better than most analysts had anticipated, and the company’s chairman, Patrick Pouyanne, said he was pleased with the way it had responded to the current climate by cutting costs and capital expenditure. Few others could match Total’s relative robustness. BP’s adjusted profits dropped 91%, ExxonMobil’s fell by 58% and Chevron reported its first loss since 2002. Independents squeezed In the UK, insolvency specialists Begbies Traynor painted a grim picture of the small business end of the industry. It warned that oil price volatility, collapsing valuations and mounting debt had knocked 27% off the valuations of the UK’s independent oil and gas companies, and had left most in trouble. The firm analysed the financial health of 80 companies trading on the AIM stock exchange, and found that 64 had reported losses at the end of 2015. It also said that 58% were “suffering from significant financial distress,” and that they had almost GBP1 billion (US$1.45 billion) of combined debt on their balance sheets – a rise of 653% on 2014. “While the chronic oversupply of crude will continue to challenge the global oil industry, it is the smaller oil and gas companies [that] are the most vulnerable and being squeezed most,” Begbies Traynor partner Julie Palmer said in a statement. At the other end of the scale, companies like Statoil, Shell and Total have all cut spending as they seek to ride out the price crash. Statoil intends to reduce capex to US$13 billion in 2016 from US$14.7 billion in 2015, and has indicated it could trim this further to below US$10 billion in 2018 and 2019. Cutting costs can only go so far. The only thing that will ease the industry’s pain in the long term is a rebound in prices, which looks like a distant prospect for the time being.n

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Statoil proposes scrip dividend scheme EUROPE NORWAY’S Statoil pledged last week to continue paying dividends throughout the oil price downturn. But the company has proposed a scrip dividend scheme under which shareholders could receive the dividend in the form of new shares at a 5% discount. Shareholder acceptance of the proposal would save cash for New York-listed Statoil, which also unveiled its first ever full-year loss and said it would slash capital expenditure by a further 12% this year to US$13 billion. The company has pledged to keep its quarterly dividend at US$0.22 – or its stock equivalent – at least until the end of September. The Norwegian government, which owns 67% of Statoil, backs the scrip dividend proposal, which also needs to be approved by Parliament. Statoil’s CEO, Eldar Saetre, said last week that although it would have been easier to simply cut the dividend, “consistency for shareholders is extremely important, and we want to run the company in a prudent manner.” The markets were less impressed. “Ultimately we see this as an admission that the dividend at current levels is not sustainable, and we would have preferred to see a rebasement rather than share dilution,” said Biraj

Borkhataria at RBC Capital Markets. However, “this now brings Statoil in line with most of the sector.” Paying dividends in stock would also deeply dent Norway’s state revenues from Statoil and could force the government to take even more out of the country’s US$810 billion wealth fund in its planned first ever withdrawal. The government has said it will opt for its dividends from Statoil to be paid in stock as necessary to maintain its stake in the company at the same size. If other shareholders also choose to be paid in equity, state revenues would shrink further. It is not clear what proportion of shareholders will opt for an equity payment. Pareto Securities has assumed 50% of Statoil’s dividend will be paid in shares, “but it could probably be even higher,” according to its analyst Trond Omdal. If his assessment is correct, Norway’s government could receive 8 billion kroner (US$940 million) less in hard cash from Statoil in the year to end-September. Statoil’s CFO said last week that it would be “very hard to say” what proportion of dividends would be paid in shares. “We’ve seen others do this and get a varying response from quarter to quarter.”n

LUKoil offloads petrol stations EUROPE RUSSIA’S largest independent energy concern, LUKoil, has signed a deal to sell around 230 of its petrol stations in Lithuania, Latvia and Poland. The acquisition was announced on February 4 by Austrian private equity firm and buyer AMIC Energy Management, which is focused on the Eastern European energy sector. “The decision to sell the retail network in Lithuania, Latvia and Poland was taken as part of the programme to optimise LUKoil’s retail asset structure in Europe,” LUKoil said in a statement. The agreement should be closed in the second quarter of 2016, pending local regulatory approval, the firm added. In December 2015, LUKoil CEO Vagit Alekperov signalled the firm’s intention to withdraw from the Baltic region owing to local anti-Russian sentiment. “We began to lose money and felt a negative attitude towards us,” he said. In June 2015, the Russian producer sold its wholly owned Estonian subsidiary to local energy firm Olerex. The Latvian forecourts will be operated under the LUKoil brand by local firm VIADA Baltija, according

to the terms of a five-year trademark agreement. The petrol stations in Lithuania will be managed by operator Luktarna. Luktana, which holds an 80% stake in VIADA Baltija, is controlled by Ivan Paleisik, who heads LUKoil’s Baltics-based subsidiary Lukoil Baltija, the previous owner of the Latvian and Lithuanian petrol stations. AMIC Energy Management said it would decide later in 2016 whether it will re-brand the Polish petrol stations under its own AMIC Energy handle. LUKoil has been shedding fuel retail assets in recent years. In August 2014, LUKoil reached an accord with Hungarian oil firm MOL to sell 44 petrol stations in the Czech Republic. Later that month, 75 LUKoil petrol stations in Hungary and 19 in Slovakia were also sold to Hungarian firm Norm Benzinkut. It sold its Ukrainian subsidiary with 240 petrol stations and six oil depots to AMIC in April 2015. Alekperov told reporters in 2014 that LUKoil wanted to divest assets in Eastern Europe in order to focus on its resources in Russia and make significant cost savings.n

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Unipetrol posts bumper profits, plots further expansion EUROPE CZECH oil refining, petrochemicals and fuel retail group Unipetrol reported a fall in revenues in 2015. But the company achieved a marked improvement in profitability owing to strong refining margins and healthy underlying conditions. It was an eventful year for the company, marked by the finalisation of a takeover of rival Czech oil refiner, Ceska Rafinerska, through a buyout of Italian oil group Eni’s stake, and a fire at its Litvinov oil refinery’s steam cracker unit. Unipetrol’s 2015 sales fell to 4 billion euros (US$4.5 billion) from 4.6 billion euros (US$5.2 billion) in 2014. But the company posted a net profit of 260 million euros (US$292 million) for last year. This was a significant turnaround from the loss it posted in 2014. Commenting on the 2015 results, Unipetrol CEO Marek Switajewski said: “We prospered from the favourable macro environment, especially in the form of very good refining as well as petrochemical margins and also managed to increase sales of refined products after the completion of [the] acquisition of Ceska Rafinerska.” Unipetrol is a subsidiary of Polish oil refining group PKN Orlen, which controls significant downstream and refining assets in Poland, the Czech Republic and Lithuania. PKN Orlen’s own 2015 results were favourable on the back of Unipetrol performance, its own domestic Polish activities and a strong showing by its Mazeikiai refinery in Lithuania. What next Moving forward, Unipetrol will focus on the recovery from the accident at the steam cracker unit, which has curtailed output from the Litvinov refinery since August

2015. The firm will also embark on further expansion in the fuels sector. It said that the partial restart of the steam cracker (to a level of 65%) and an increase in the utilisation rate would be achieved by July 2016, based on current estimates. The Litvinov refinery’s ethylene unit is anticipated to reach maximum capacity utilisation by October. Building on the 2015 buyout of Ceska Rafinerska, Unipetrol agreed last month to purchase Austrian oil group OMV’s retail fuel network in the Czech Republic, which comprises a chain of 68 petrol stations. The market outlook is also favourable for Unipetrol and its peers in the CEE refining sector. As well as the recent improvement in operational performance, which is reflective mainly of lower oil prices, CEE refiners have a competitive advantage over integrated Russian oil groups, since they generally have little or no upstream exposure. This means they are in a stronger relative position to seize market share in the pan-European oil products market. Parent company PKN Orlen wants to secure a 20% market share in the CEE region and is clearly seeking to achieve this through acquisitions. Other companies are likely to follow the Polish group’s lead. The increased attractiveness of the CEE region’s downstream market has made it a target for investors. Among those seeking to make a move could be Russian oil companies. They would view downstream CEE acquisitions as a hedge against competition in the sector and also as a form of diversification into lucrative downstream activities. Rosneft has already expanded its presence in the German oil refining industry, suggesting it has identified the CEE market as a source of possible acquisitions, as Western European oil majors continue to exit the sector.n

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Week 2• 15 February • 2016

Chevron plans to sell off South African mid-, downstream business AFRICA THE US’ Chevron Corp. is seeking buyers for its South African business, comprising a refinery in Cape Town, a lubricants plant in Durban and a nationwide fuel retail network. The move forms part of a wider process of divesting the company’s non-core assets dating back to before the current oil market slump but made more urgent by the downturn, which saw the firm in late January post its first quarterly loss for 14 years in the period covering the last three months of 2015. However, the withdrawal also reflects the particular challenges of the South African market – where Chevron only recently abandoned trenchant opposition to a new storage terminal project that the company claimed would render its refinery uncompetitive and where efforts to persuade Pretoria to fund the ageing facility’s upgrade have failed. Chevron announced the decision to solicit expressions of interest (EOIs) in late January, without putting a timeframe on the process and billing the sale as part of the wider three-year divestment programme launched in 2014, which realised US$6 billion that year and a similar amount during 2015 – through disposals including that completed last month of three Nigerian upstream concessions. “[The South African sale plan] demonstrates Chevron’s continuing focus on balancing our global portfolio with our long-term business priorities,” Mark Nelson, Chevron’s president of international products, said in a statement. However, the timing of the move to exit South Africa – where its presence dates back to 1911 – also reflects current conditions in the country’s downstream energy sector. Chevron’s main asset comprises a 110,000 barrel per day refinery near Cape Town, which supplies gasoline, diesel, jet fuel and LPG mainly to the local market. The company’s pitch to prospective investors will be rather tainted by the company’s concession of defeat in October following a lengthy and bitter battle against Pretoria’s approval for the establishment of a major new fuel storage and distribution depot at Cape Town Port by a joint venture led by Dutch storage giant VTTI, which Chevron claimed could be sufficiently detrimental to their own refinery’s competitiveness to force the plant’s closure. The contention was based on the perceived likelihood

of the Burgan Cape Terminals JV enabling the import of high-value cleaner products that the 50-year-old Chevref facility lacks the means to produce. Burgan accused Chevron of simply attempting to defend a near-monopoly on the fuel supply infrastructure of the Western Cape and claimed that the two facilities would be complementary, with most of those leasing space at the depot likely to be souring their products from the Chevron refinery. While the American firm eventually professed a willingness to co-operate, the arguments about the potential damage to the business will do little to encourage buyers. The 118,000 cubic-metre multi-product Burgan terminal is scheduled for completion in 2017, which is the same year that new Euro V fuel standards are due to come into force in the country. Chevron has been leading calls from incumbent local refiners for the government to fund the full cost of the required upgrades at their facilities. The company has estimated the cost of conversion work at Chevref at around US$1 billion and asserted in March last year that such an outlay was “in the absence of a mechanism to recover these costs from the consumer … simply not commercially viable”, in the words of Chevron South Africa’s outgoing chairperson Nobuzwe Mbuyisa. A third threat identified in October 2015 by her replacement, Shashi Rabbipal, was Pretoria’s renewed enthusiasm for the establishment of a new refinery in the country, possibly to process newly-available Iranian crude. State-owned PetroSA has had development of a greenfield refinery on the drawing board for several years but the scheme seems unlikely to proceed imminently given the company’s current financial difficulties and while a new refinery remains a stated government aim, the country’s economic condition – with the IMF last month reducing its GDP growth forecast to an anaemic 0.7% and fuel demand expected to remain commensurately stagnant – serves as a deterrent to investment in either new or existing refineries. Nevertheless, Chevron’s desire to cut both capital and operating expenditure has been strengthened by recent financial results. The major posted a US$588 million loss for the fourth quarter of 2015 – the first since 2002 – while full-year net income collapsed to US$4.6 billion from US$19.2 billion in 2014.n

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Class action pressure on Cobalt AFRICA LAWYERS in the US are working on class action suits against Cobalt International Energy, over potential mismanagement by the company’s board. A number of law firms have got in on the action – including Faruqi & Faruqi, Schubert Jonckheer & Kolbe, Harwood Feffer. Statements last week urged investors to contact the various lawyers, in addition to asking for whistleblowers. Sparking the recent move is a mid-January finding from Judge Nancy Atlas, denying Cobalt’s plea of ignorance about the potential links of Nazaki Oil & Gaz, one of its local partners in Angola. She further found, according to Faruqi & Faruqi’s notice, that the defendants “knew ‘fairly early on’ that [the] Lontra [well] was primarily gas, to which Cobalt had no rights, and there was ‘not even a remote chance’ that [the] Loengo [well] would be successful”. Cobalt signed risk-service agreements (RSAs) with Sonangol in February 2010 on Blocks 9, 20 and 21. The US company took 40% stakes in the blocks, while the remaining equity was held by Nazaki, Sonangol P&P and Alper Oil. An investigation was launched into Cobalt’s partner, Nazaki, in March 2011 by the Securities and Exchange Commission (SEC). Cobalt contacted the US Department of Justice (DoJ) and the two US bodies worked on the Foreign Corrupt Practices Act (FCPA) investigation. The SEC ended its investigation in January 2015 while, unusually, the DoJ’s continues. The Lontra well was drilled on Block 20 and the Loengo on Block 9. The case against Cobalt notes the company had no rights to gas discoveries found in Angola, only to oil. Lontra was found to hold more gas than had been thought and Loengo failed completely. In addition to complaints about its local partners and the poor results, concerns have also been raised about payments to the Angolan government for a research centre that does not exist. An August 2014 statement from Global Witness said Cobalt – with BP – had agreed to pay US$350 million for a centre on which no progress had been made. In related news, questions have also been raised in Norway over Statoil’s payments to Angola. Norwegian media reported parliamentary interest in social payments made by Statoil in the West African country, also referencing an unbuilt science and technology research centre. Statoil declined to shed light on its social payments and any support for the technology centre to the Dagens Naeringsliv (DN) newspaper.

under which the US-listed company would sell Blocks 21 and 20 to the Angolan company for US$1.75 billion. The deal was to have an effective date of the beginning of January 2015 and should have received approval from Luanda by the end of 2015. A note from Stifel, on February 3, raised concerns about the sale of the 40% stakes. Cutting Cobalt’s rating to a hold, based on “increasing risks to the close of the transaction”, the analysts said they were unable to “confidently predict a sale price haircut”. Taking a more relaxed stance on Cobalt’s outlook, though, Tudor Pickering Holt [TPH] said that while there was completion risk on the Angolan sale, it believed another buyer would emerge should Sonangol fail to close, although at a lower price. “We estimate a breakeven price of US$45-50 per barrel for the assets and the government of Angola has indicated it’s willing to revise fiscal terms to improve economics, as exemplified by ongoing discussions around Total’s Kaombo project, with press reports suggesting Total as a potential farminee to [Cobalt’s] assets,” TPH said. It is clear Angola, and Sonangol, are struggling to pay some of their bills. Recent research from Bernstein on default risk from national oil companies put Sonangol as a runner up to Venezuela’s PDVSA. Sonangol has US$7 billion of high-yield bank debt, it said, while PDVSA has US$28 billion of bonds.n

Asset sale Cobalt announced a deal with Sonangol in August 2015,

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Minnows under pressure AFRICA WARNING signs are starting to flash at a number of companies, in the light of continued low prices. Circle Oil, in a statement on February 8, said it was under “significant pressure”, and the same day, Petroceltic International said its talks were continuing with its lenders while Madagascar Oil, last week, said it was in talks with its financial backers. Circle Oil said that it was in discussions with the International Finance Corp. (IFC), as noted in midDecember. “Given the further fall and continued volatility in oil price, both parties are continuing discussions on the redetermination and working together to find a solution to right-size the balance sheet,” it said. The UK-listed minnow went on to say dollar receipts in Egypt, from Egyptian General Petroleum Corp. (EGPC), were “limited and unpredictable”, making it more reliant on operations in Morocco. Circle has signed up a new offtaker in Morocco, which has committed to paying US$12 per 1,000 cubic feet (US$340 per 1,000 cubic metres). The volumes are small, at only 10,000 cubic metres per day, but pricing is independent of an oil link. Supplies are due to start up in the fourth quarter of this year. The company’s CEO, Mitch Flegg, said the price was 40% higher than the average, expressing the hope that this would set a benchmark for future sales. The same day, Petroceltic said it had received a waiver

on repayments until February 19. The company’s lenders may provide further waivers, it said, based on progress on its strategic review. Petroceltic has struggled with an activist investor, Worldview Capital Management, which had been mooted as a potential bidder. Madagascar Oil, in a statement last week, said it continued to hold talks with potential partners for its Tsimiroro field but confirmed that it had not yielded any concrete proposals as yet. The company reached a bridge financing deal in September 2015. Providers of the facility were the company’s major shareholders, which committed up to US$21.9 million. According to the terms of the financing, should two-thirds of these lenders decide that Madagascar Oil was making insufficient progress on finding a partner, the facility could be made repayable by January 31. The minnow, in September, said it hoped to finalise the transaction by the end of the first quarter of 2016. The update last week said there was no guarantee that a deal would be reached this quarter, “if at all”. Also having raised the prospect of “strategic alternatives” was US-listed Vaalco Energy, on January 26. The company, which operates in Gabon, said it had formed a committee to consider its options, which might include a sale, a farm-out or a merger. Vaalco said it had engaged Scotia Capital (USA) to advise on such alternatives.n

QP signs Morocco deal with Chevron AFRICA QATAR Petroleum has struck a deal with Chevron, taking stakes in the US super-major’s interests in Morocco. A statement from QP, on February 8, said it would take a 30% stake in the Cap Rhir Deep, Cap Cantin Deep and Cap Walidia Deep licences. The licences are around 100200 km west and northwest of Agadir, covering 29,200 square km. Water depths on the concessions are 100 to 4,500 metres. The agreement leaves Chevron Morocco Exploration with 45%, and it will continue as the operator. The remaining 25% is held by state-backed Office National des Hydrocarbures et des Mines (ONHYM). The terms of the agreement, which has been approved by the local government, on the deepwater leases were not disclosed. QP president and CEO, Saad Sherida Al-Kaabi, said the deal was “an important step towards building a mutually beneficial relationship with Chevron, with particular emphasis on international upstream activities. It is no coincidence that QP’s international presence is now extended to Morocco, a country which

Qatar enjoys special relations with.” Chevron Africa and Latin America Exploration and Production’s president, Ali Moshiri, described it was a “milestone in both companies’ efforts to maximise the value of exploration and production assets through longterm relationships. We are pleased to partner with QP in offshore Morocco and are looking forward to use our joint capabilities in this exciting sub-salt play for the benefit of Morocco”. Chevron acquired the blocks in January 2013. Morocco had made a major push to secure investment from oil and gas companies, which was successful, but drilling has been largely disappointing in the offshore. The US super-major has also signed up to work with Kosmos Energy offshore Mauritania. QP has also been working onshore in Mauritania with Total. The Qatari company also struck a deal with the French super-major, in 2013, to acquire a stake in Total E&P Congo, which operates the Moho Nord development. Chevron is also a partner in the Congolese development.n

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Week 2• 15 February • 2016

Sokhna bulk terminal gets finance AFRICA SONKER Bunkering Co. signed a US$341 million financing package with development banks in January to develop a bulk liquids terminal at Eqypt’s Red Sea port of Ain Sokhna. The deal finally paves the way for the 10-year-old project to proceed. In the short-term, the facility is aimed at easing domestic fuel supply problems created by a shortage of gas, insufficient refining capacity and fast-growing demand, while over the longer-term the scheme forms part of a wider government vision of transforming Egypt into an energy-trading hub. With the state finances in a parlous state, foreign currency in short supply, and commercial funders remaining wary of the country, Cairo has been forced to turn to alternative sources to realise its downstream plans – recently securing Italian export credit agency (ECA) backing for two refinery expansions. The International Finance Corp., the private-sector lending arm of the World Bank, will provide a US$70 million senior loan to the estimated US$500 million Sonker venture, in addition to US$52 million mobilised from partners and a US$22 million mezzanine tranche. Sonker is a public-private partnership that was established to develop the terminal. The European Bank for Reconstruction & Development (EBRD) is extending a US$72 million senior loan and a US$22 million mezzanine facility, while the local Commercial International Bank is providing US$72 million split between dollar and local-currency portions, as well as a US$30 million credit support instrument facility. The senior loans have a 10-year tenor. Both development banks explained their involvement with reference to the project’s potential to enhance Egypt’s energy security and meet growing demand for fuel for use in power generation. The proposed petroleum liquids import and storage terminal will comprise three gasoil tanks with total capacity of 100,000 cubic metres, three LPG tanks with combined capacity of 150,000 cm, a 37.5-km gasoil pipeline connecting to the local grid via Mina Sadat, berthing facilities for two floating storage and regasification units (FSRUs), and facilities to handle and transfer the LNG imports to the national grid. The project has been allocated a 400,000-squaremetre site in the third basin of Sokhna Port, located at the southern end of the Suez Canal around 120 km from Cairo and operated by the UAE’s DP World since 2002. Sonker is majority-owned by local private-sector energy logistics firm Amiral, which signed an agreement in 2004 with the Dutch/UAE Vopak Horizon to establish the Sokhna terminal. The venture is now owned 63% by Amiral and 12% by the Ministry of Finance, with the

remainder held by other local investors. Momentum gathered behind the stalled scheme during the Egypt Economic Conference in March 2015, when DP World – which had been threatened with withdrawal of its concession the previous year for failure to implement promised expansion plans – recommitted to the bulk terminal project. More immediate impetus was provided by an agreement signed in late November between DP World, Sonker and the government’s Suez Canal Authority and Red Sea Ports Authority for an upgrade and expansion of the port. Initial work on the engineering, procurement and construction (EPC) contract was launched in June 2015 by the local Petrojet. Announcing finalisation of the financing on February 4, the parties highlighted the strains being experienced by Egypt’s current energy import system – as the country undergoes the unwelcome transition from oil and gas exporter to importer. The 2015/16 budget starting on 1 July envisages 28.5 million tonnes of oil and gas imports over the year, including a projected 6.4 million tonnes of crude and 7.8 million tonnes of LNG – delivered to FSRUs at Ain Sokhna leased over the past two years from Norway’s Hoegh LNG and Singapore-based BW Gas. Refined products are imported mainly from the Gulf Co-operation Council (GCC). Oil consumption in 2014 averaged 813,000 barrels per day, while production stood at 717,000 bpd. Gas supply and demand were almost equal at around 48 billion cubic metres. Meanwhile, projects to boost refining capacity have stalled on lack of either private-sector or state funding. However, the return of political stability has induced other international lenders to return to the country and backing from Italian ECA SACE enabled the long-awaited Middle East Oil Refinery (MIDOR) plant expansion at Alexandria to secure financing late last year. The deal was hailed by Italian Economic Development Minister Federica Guidi during a visit to Cairo in early February as an example of the two countries’ fruitful energy sector co-operation. SACE is also considering providing backing for the upgrade of the Asyut refinery in Upper Egypt. The longer-term aim voiced by Sonker managing director Ossama al-Sharif that the Sokhna area could become “a regional hub for trading petroleum products” rests both on implementation of the various refining projects on the drawing board and on the development by Italy’s Eni of the supergiant Zohr gas field discovered last year.n

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Teapots to pool resources for upstream asset hunt ASIA CHINESE teapot refineries in the eastern province of Shandong are working together to set up a fund in order to invest in overseas upstream assets. China’s largest independent refinery, Shandong Dongming Petrochemical, kickstarted the plan, which requires up to 3 billion yuan (US$455 million) of seed money. Funding is to come from Dongming and the province’s other independent refineries. It is not clear which refineries are ready to invest in the fund. Shandong-based industry officials said they were setting up the rules for the fund, which could be launched within six months’ time. Smaller refiners are keen to take advantage of the downturn in crude oil prices to farm into assets when they are cheap. Chinese independent refineries had suffered from insufficient crude supply until last year, when the central government started granting crude import quotas and licences to some. By the end of last year, there were

14 teapot refineries licensed to process 58.19 million tonnes per year (1.16 million barrels per day) of foreign crude. Of these, eight were also allowed to import crude up to 43.89 million tonnes per year (878,000 bpd) directly. Dongming, with an annual crude distillation capacity of 15 million tonnes (300,000 bpd), was granted a 7.5 million tonne per year (150,000 bpd) import quota by the Ministry of Commerce (MOCOM) and another 7.5 million tonne quota by MOFCOM under the World Trade Organisation’s (WTO) trading system. In addition to crude imports, MOFCOM allowed the company last year to export oil products to become China’s first small-scale refiner to sell products in the international market. Sources said the first cargo of 10,000 tonnes of gasoline was loaded for export to an unnamed buyer in Singapore at the end of 2015.n

Another Chinese yard struggles to stay above water ASIA ANOTHER private Chinese shipyard providing services to the offshore oil and gas sector is in financial trouble in the wake of oil price-linked cuts by upstream players. Workers from the Dayang shipyard of Sinopacific Shipbuilding were advanced money from local government coffers in time for Chinese New Year this week after 100 of them staged a public protest in the southern coastal city. The workers said they had not been paid for several months, maritime news service Splash 24/7 said. Splash said local authorities had paid the employees from a government account after talks were held with the employees and the shipyard. The protest followed a much bigger one in September 2015 involving about 1,000 yard employees. Sinopacific builds offshore support vessels (OSVs) for oil and gas platforms at two yards, one each in Guangdong and Zhejiang Provinces. At least five private Chinese shipyards filed for bankruptcy in 2015 and even some state-owned

enterprises (SOEs) are in trouble as orders for rigs and accommodation and supply vessels are cancelled or the buyer stalls on payment and delivery. The chairman of Sinopacific, Simon Liang, told the South China Morning Post recently that private yards faced a tougher time in the industry downturn because they cannot call on state aid to help out. The National Development and Reform Commission (NDRC) is pushing more state-owned yards into mergers to create bigger units, supposedly to weather the downturn, while some of the bigger shipyards are being elevated to a so-called white list, qualifying them for state aid. The crisis in the offshore upstream sector was underlined by a Splash report this week that international rig operators were being squeezed out of Southeast Asia as the “market faces inward during the prolonged oil downturn” and state-owned oil companies such as Petronas of Malaysia and Indonesia’s Pertamina were hiring only local support firms.n

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Japanese solar plant for sale online ASIA AN under-construction solar power plant in Japan is being auctioned on the internet, marking a potential trend in online secondary market selling of renewable assets and licences. The 500-kW plant, scheduled for completion in November, is being sold by West Energy Solutions on Japan’s Yafuoku auction website over an eight-day bidding period, which began on February 12. The plant, located at Mihara in Hiroshima Prefecture, has a starting price of around US$1.4 million. Although the auction is online, the number of participants will be limited to registered members of Yafuoku, the Japanese auction subsidiary of Yahoo. West Energy Solutions is a subsidiary of West Holdings, a housing construction firm that moved into renewable energy when the Tokyo government introduced a generous feed-in-tariff (FiT) system in 2012 to encourage more non-fossil fuel power generation. The firm is now one of the biggest solar energy developers in Japan. The auction highlights the growing secondary

market in renewables, where rich individuals and companies are now moving into solar plant ownership because of its attractive tax discount benefits, the Financial Times commented. The last three years have seen a flurry of both small and large solar projects made highly attractive by generous state incentives, and investors are eager to gain a piece of the action. West Holdings intends to hold more such solar auctions via the Yahoo website in future. “According to West Holding, finding buyers for the [Mihara] solar power plant and its equipment is a tedious task, involving meetings, paperwork, processes and negotiations, while internet bidding reaches out quickly to a wide range of bidders from individuals to small and medium businesses,” the International Business Times reported. In December, West Energy announced plans to build what it termed the biggest floating solar power project in Japan, covering 250,000 square metres of a reservoir in Kawanaihara. n

Ukraine’s Burisma buys 70% stake in KUB-gas FSU CANADA’S Serinus Energy announced on February 8 it had closed a deal to sell its 70% stake in Ukraine-focused KUB-Gas, to Resano Trading, an affiliate of Burisma Group. KUB-Gas owns five production licences and one exploration licence in the eastern Ukrainian province of Luhansk, an area badly affected by the ongoing conflict between Kyiv and Russian-backed rebels. Burisma, which is headed by Ukraine’s former environment minister, said the US$32.9 million deal was prompted by Kyiv’s decision to slash tax on gas extraction last month. As of January 1, Ukrainian firms pay a tax rate of 29% for production from deposits less than 5,000 metres deep, down from a previous rate of 55%. The rate on extraction from deposits at deeper levels has been lowered from 28% to 14%. Serinus said it would use the proceeds of the deal to repay US$19.2 million of debt to the European Bank for Reconstruction and Development (EBRD). The rest would be invested in the firm’s Moftinu gas discovery in Romania, it said. Serinus, which has upstream assets in Ukraine, Brunei, Tunisia, Romania and Syria, was owned by Poland’s former richest businessman,

Jan Kulczyk, who died last year. The acquisition will transform Burisma into one of Ukraine’s biggest private gas firms. One of its owners, Mykola Zlochevsky, served as Ukraine’s environment and natural resources minister under ousted pro-Russian President Viktor Yanukovych between 2010 and 2012. Zlochevsky is a controversial figure. Ukrainian prosecutors issued a warrant for his detention last year, on suspicion of embezzlement. In 2014, British prosecutors froze US$23 million on accounts linked to him, but Ukrainian lawyers failed to provide enough evidence on time to make the charges stick, so a UK court ordered investigators to unfreeze the assets. On February 4, the Ukrainian Prosecutor-General’s Office reported that Zlochevsky’s personal property, including several mansions and a Rolls-Royce, had been seized by the court. The office said it had resumed an investigation into the case after a break caused by to an institutional reshuffle. Despite his tarnished image, Zlochevsky has close ties to Polish President Aleksander Kwasniewski and US Vice President Job Biden’s son, Hunter Biden. Both sit on Burisma’s board of directors.n

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Week 2• 15 February • 2016

Rosneft, Bashneft may face privatisation this year FSU ROSNEFT, Bashneft and diamond producer Alrosa are the most likely candidates for privatisation this year, Russia’s Economic Development Minister Alexei Ulyukaev said on February 3. The sell-off of government stakes in some of Russia’s largest companies could raise 1 trillion rubles (US$13 billion) in the next two years, Finance Minister Anton Siluanov recently said. This comes at a time when Russia’s budget deficit for 2016 risks reaching 6% of GDP. Moscow’s 50% stake in Bashneft and shares in Alrosa were worth around 600 billion rubles (US$7.5 billion) at current markets prices, Ulyukaev was reported as saying by TASS. He added that the 19.5% share in Rosneft which the state was putting up for sale could be valued at as much as 500 billion rubles (US$6.5 billion). His comments were made after a meeting he held with Austrian Vice Chancellor Reinhold Mitterlehner, during which he extended an invitation to Austrian businesses to take part in the process. Russian President Vladimir Putin confirmed the sales would go forward in a meeting on February 1 with the heads of Rosneft, Bashneft, Aeroflot, VTB Bank, Russian Railways and Alrosa. He stressed, however, that the state would retain overall control of the companies in question. Plans for the privatisation of 19.5% of the Russian government’s share (69.5%) in Rosneft were approved in late 2014. The order for the privatisation was signed by Prime Minister Dmitry Medvedev and called for the sale of its shares “at a price no lower than market [value].” Rosneft head Igor Sechin said that the market price for the shares should be US$8.12. This was the price at which BP obtained 12.5% of shares in the company in 2013, when it sold its stake in TNK-BP. As of

mid-day Monday, Rosneft GDRs were selling at US$3.59 on the London Stock Exchange (LSE). Rosneft has continued to post profits despite the impact of Western sanctions, and is confident it will be able to meet the US$13.7 billion in debt payments that are due this year. Last week, VTB Bank announced that it had approved an 85.4 billion ruble (US$1.1 billion) five-year credit line to the company. The privatisation plans appear unlikely, considering the sanctions against the companies heading for the auction block, complications with financing and poor market conditions. Maxim Osadchy, head of analysis at Corporate Finance Bank in Moscow, went so far as to tell The Moscow Times that the plan was “comical.”n

Bashneft’s assets

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Full steam ahead for geothermal power in Turkey Turkey looks set to exceed its modest plans for geothermal power generation easily with help from the EBRD. MIDDLE EAST TURKEY’S first National Renewable Energy Action Plan, launched a year ago, outlined a strategy to source 20% of its energy needs from renewable resources by 2020 but left many questions unanswered. Although the plan would bring Turkey in line with European Union directives, it was unclear as to how this strategy would be achieved. Yet one point was made clear: Turkey was on target to meet its planned 1 GW of geothermal generating capacity. At the time of the strategy’s publication, Turkey already boasted 405 MW of operational geothermal capacity, with a further 334 MW worth of generating licences. A further 301 MW of capacity had been awarded “pre-licences” which guarantee that generating licences will be issued once funding has been secured. The total of 1,040 MW would suggest that it had already exceeded its planned target. As of the end of January 2016, operational geothermal capacity has reached 635.1 MW, with another 194 MW licensed, 430 MW holding pre-licences and 71 MW of applications being assessed. So far, so good: the only question appears to be why such a low target was chosen. This is all the more confusing given that the report was drafted with the help of the European Bank for Reconstruction and Development (EBRD), which has also been very active in helping fund renewable energy projects in Turkey, Hot money Awards have been issued through the bank’s Mid-size Sustainable Energy Financing Facility (MidSEFF) which provides loans and capital market instruments to private sector companies through Turkish banks. Since it began investing in Turkey in 2009 the bank has spent over 7 billion euros (US$8 billion), of which 2.9 billion (US$3.3 billion) has been for renewable energy projects. US$1.12 billion of this has been directed to six geothermal projects totalling 232 MW, provided through Turkish banks. In addition, the EBRD has directly funded the

170-MW Efeler geothermal plant being developed by Turkey’s Guris Holding. Located in Turkey’s southwestern geothermal hot spot, it is hoped that when complete, it will be the second largest geothermal plant in Europe, and one of the ten largest in the world. The EBRD itself provided a US$200 million loan for Efeler and was active in helping secure a further US$325 million from Turkey’s Is Bank, US$130 million from Turkiye Sinai Kalkinma Bank 7 and US$65 million from the Black Sea Trade and Development Bank (BSTDB). That capital is also supported by a well-designed feedin tariff (FiT) scheme. Limited to 10 years and issued in US dollars, it is helpful in providing certainty to developers and in reducing risk to investors and financiers. A recent Climate Policy Initiative report noted: “The US$0.105 per kWh FiT provides certainty over a ten-year period that revenues will be 28% higher than current market rates and allows the project to achieve payback of all investment costs within eight years. Expected returns of 16% on the project equity and 12% on the project investment as a whole are similar to other geothermal projects in Turkey, where returns range from 11-14%.” For that reason, the 13.2-MW Gümüşköy plant, commissioned in 2013, offers power “12-17% cheaper than comparable geothermal plants globally and other power projects in Turkey. With loans at current market rates, the lifetime cost of power would be US$0.106 per kWh, close to the current FiT rate,” the CPI said. Journey to PLUTO In partnership with the Clean Technology Fund (CTF), January also saw the EBRD launch its PLUTO initiative which will make US$125 million available to private developers of new geothermal projects – in addition to the existing MidSEFF facility. Named after the Roman god of the underworld, PLUTO will offer both finance and expert advice to geothermal developers in order to offset the high investment costs and developmental risks that the projects

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face in their early stage. This should also help them overcome the difficulties experienced in securing project finance once geothermal reservoirs have been located. Combining US$100 million from the EBRD and US$25million from the CTF, PLUTO is structured in two phases: one finances prospecting for new geothermal resources for which funds will be supplied the CTF, and the second phase sees the EBRD providing finance for drilling and construction for projects developed on viable reservoirs. The initiative aims to help develop five new geothermal plants, totalling 60 MW and capable of generating 450 GWh of electricity per year. According to EBRD Energy Efficiency and Climate Change senior manager Adonai Herrera-Martinez, the EBRD sees its role as helping geothermal energy developers bridge this notorious equity gap. “Our goal is to unlock the vast amounts of renewable energy trapped deep underground and to attract more private investment and bank financing in the sector, moving away from reliance on purely public funds,” he said. This month the EBRD announced yet more support through the expansion of the MidSEFF facility by 500 million euros (US$566 million), to 1.5 billion (US$1.7 billion). Turkey’s Akbank will be the first beneficiary, with an additional US$110 million allocated for funding renewable energy projects in addition to the US$100 million the bank received in 2011. Great expectations Such optimism in Turkey’s geothermal potential is not confined to the EBRD. Speaking to NewsBase, Sinan Ak,

CEO of Turkey’s Zorlu Enerji, was similarly upbeat about the prospects for further development in Turkey, and suggested that the 1-GW target would be easily exceeded. Ak ought to know. Having been active in geothermal development for a decade, Zorlu is Turkey’s biggest developer, with three operational plants totalling 140 MW, one 95-MW plant under construction and three more totalling 80 MW licensed and under development. In an interview in late 2015, he said that “[Zorlu] spearheaded geothermal. No other major companies exist in the field, and we want to do the same thing with solar. “By 2020 we should have at least seven [geothermal] plants and around 350 MW,” he said, pointing out that the company was still assessing its existing reservoirs with a view to further expanding existing plant, as well as looking further afield. “We are actively looking for new reservoirs and for new projects to develop – we know the reservoirs are there,” he adds. While Turkey’s conventional power sector still ponders whether to pursue coal or gas, new geothermal capacity is rapidly meeting the demand for reliable, renewable baseload power. With much of Turkey yet to be prospected for geothermal steam and hot rocks, and new exploration tenders being opened on an almost monthly basis, his optimism appears to be justified. Ak’s market forecasts are equally bullish. “We think the current potential is around 2 GW, but it could easily go much higher than that,” he added. With the finance and policy already in place, and developers keen to take advantage, the sector looks likely to proceed at full steam ahead.n

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EIB gives US$1.1bn loan for TANAP MIDDLE EAST THE European Investment Bank (EIB) will provide a 1 billion euro (US$1.1 billion) loan to Turkish state-owned pipeline operator Botas for the construction of the TransAnatolian pipeline (TANAP), Bloomberg’s Turkish outlet reported last week. “The Bank will approve the loan by [the] end of April 2016, and the first tranche will be allocated in August,” EIB’s vice president Pim Vank Ballekom was quoted as saying last week. According to Bloomberg, an equal amount of funding is anticipated from the World Bank (WB). Turkey’s Botas will use both loans to finance its stake in the pipeline project. The state-run company had been in talks with the two international lenders since last November. TANAP is one of three conduits that form the Southern Gas Corridor, a project to pump Caspian gas westwards to European markets. TANAP will connect with the South Caucasus Pipeline (SCP) at the Georgian-Turkish border and the Trans Adriatic Pipeline (TAP) at the Greek-Turkish border. Botas and a second state-controlled company, Turkish Petroleum, together hold a 30% stake in the TANAP consortium, while Azerbaijan’s SOCAR owns 58%. BP, which operates the Shah Deniz project and the primary source of gas for the pipeline system, has the remaining 12%. The cost of building the pipeline is anticipated to reach US$11-12 billion. Construction started last year and is due to finish in 2018.

Last December in a joint press conference in Baku with Azeri President Ilham Aliyev, Turkish Prime Minister Ahmet Davutoglu said the project would be completed earlier than the previously planned date of 2018. But it is uncertain whether this timetable is realistic, given market volatility and Azerbaijan’s economic difficulties, both of which will make it harder to secure sufficient funding for the scheme. TANAP will have an initial capacity of 16 billion cubic metres per year. Of the total, some 10 bcm per year will be sent on to Europe and the remaining 6 bcm will be delivered to Turkey’s domestic market. It could carry up to 31 bcm by 2026, assuming that other supply sources besides Shah Deniz are secured. Last year, Brussels included TANAP in its list of infrastructure development schemes designated as Projects of Common Interest (PCI) for the European Union. It is expected that TANAP, like other PCIs, will be fast tracked and enjoy a number of other advantages, including regulatory and political support. The project may also be eligible for financial support from the Connecting Europe Facility (CEF) and the European Fund for Strategic Investment (EFSI). This January the European Energy Commission announced it would invest 217 million euros (US$241 million) in 15 key trans-European energy infrastructure projects, mainly in Central and Southeastern Europe. The TANAP project will receive 2.22 million euros (US$2.47 million).n

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Kuwait budgets for increased project spending MIDDLE EAST A limited breakdown of the spending intentions enshrined in Kuwait’s 2016/17 budget, unveiled by the Finance Ministry in late January, has revealed plans for a strong increase in capital expenditure despite the presumed slump in revenues. The policy has been welcomed in many quarters, despite the fiscal strain incurred, as a signal that the much-improved record on project implementation evident in 2015 is likely to continue. However, with the government lacking control of income that is almost entirely dependent on the uncontrollable and wildly fluctuating oil price, debate is intensifying over the means to cut exorbitant current spending and fund the shortfall. Revenues in the year starting on April 1 are projected to slide by 39% to 7.4 billion dinars (US$24.6 billion), based on an assumed average oil price of US$25 per barrel – the typical caution built into such projections being validated by events over the first eight months of the current budget, which assumed a US$45 per barrel average. Based on April-November earnings of around 10.4 billion (US$34.6 billion), National Bank of Kuwait (NBK) forecasts full-year income at 12.9 billion dinars (US$42.9 billion) – unusually close to the 12.2 billion dinars (US$40.5 billion) budgeted. Oil revenues are predicted to account for 78% of state revenues in 2016/17, compared with more than 90% in previous years, and crude production is expected to average 2.8 million barrels per day – slightly lower than the 2.9 million bpd reported by the authorities in December and therefore apparently presuming that production from the Partitioned Neutral Zone (PNZ) will remain shut-in for a large part of the year. However, that the emir, Shaikh Sabah Al Ahmad Al Jaber Al Sabah, addressed the issue in a rare public statement in January – predicting imminent resolution of the dispute – indicates commitment at the highest level to reaching a settlement. John Watson, CEO of the US’ Chevron – which operates Saudi Arabia’s onshore portion of the zone – said during a results presentation in late January that he expected output to resume by mid-2016. Salaries and associated costs continue to account for 55% of total spending, at 10.4 billion dinars (US$34.6 billion) from total outlay set at 18.9 billion dinars (US$62.8 billion) – a mere 1.6% lower than that projected for 2015/16. The increasingly controversial spending on subsidies is budgeted at 2.9 billion dinars (US$9.6 billion).

While Kuwait has so far maintained fuel subsidies at existing levels in the face of vehement popular and parliamentary opposition to the reform enacted across the rest of the Gulf Co-operation Council (GCC), the indications are that a limited cut in fuel price support is looming. The issue was another raised in the emir’s recent speech and the topic is due to be debated in the National Assembly this month. According to local press reports, the plans on the table would see the price of higher-quality gasoline rise from 65 fils (US$0.22) to 90 fils (US$0.3) and of lower-grade fuel from 60 fils (US$0.2) to 85 fils (US$0.28) – thus maintaining price levels among the lowest in the region but nevertheless highly controversial among MPs perennially critical of the government’s fiscal stewardship and alleged profligacy. Finance Minister Anas al-Saleh is currently under threat of a parliamentary interrogation over misuse of public funds. However, while failing thus far to heed economists’ counsel of fundamental reform in current spending, the Kuwaiti authorities are following the parallel advice to maintain capital spending on projects contributing to wider economic development. Contract awards on such ventures reached 9.7 billion dinars (US$32.2 billion) in 2015, according to NBK – a 20% year-on-year increase that is set to continue: capital spending in 2016/17 is budgeted at 3.3 billion dinars (US$10.9 billion), up from the 2.2 billion dinars (US$7.3 billion) allocated this year. The government has also moved with greater commitment over the past 12 months to bolster private-sector participation in capital projects, issuing new public-private partnership regulations and now in the process of tendering two independent water and power projects among developers. In the medium term, such an approach will be crucial in spreading the costs of the government’s ambitious infrastructure development plans. In the short term, however, the infrastructure spending will contribute to a record 12.2 billion dinar (US$40.3 billion) budget deficit – equivalent to around 30% of GDP and up from the 8.2 billion dinars (US$27 billion) set out in the figures for this year belatedly approved in July. The Finance Ministry statement gave no indication as to the envisaged means of financing the shortfall but Al-Saleh has previously mooted an approach to local and international debt markets to limit depletion of plentiful state reserves.n

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Nigeria seeks loans A S I A Mambilla, Zungeru Dividends in danger at Egypt sees World Bank for funds arriving soon, power projects China’s big three oil eyes more Saudi aid majors AFRICA

Egypt expects to receive a US$1 billion World Bank loan approved in December once outstanding paperwork is finalised and is negotiating to secure more aid from Saudi Arabia, International Co-operation Minister Sahar Nasr said on February 4. Egypt has been negotiating billions of dollars in aid from various lenders to help revive an economy battered by political upheaval since the 2011 revolt and ease a dollar shortage that has crippled import activity and hampered recovery. The first US$1 billion tranche of a three-year, US$3 billion loan from the World Bank to support Egypt’s budget was approved by the lender in December and was expected to arrive soon after. But Egyptian media has questioned whether the money would come as the programme is linked to the government’s economic reform programme, including plans for VAT. Egypt’s new parliament, which held its first session last month, ratified the vast majority of economic laws passed by presidential decree during the three years in which Egypt did not have a legislative house. But it has yet to ratify the government’s economic plan or the World Bank loan itself. “We are just working on submitting the required documentation. It is nothing. We are normal. There is nothing (to say) about it,” Nasr said. Egypt was in talks with Saudi Arabia to secure more aid, Nasr said, declining to give details. Egypt was also working to iron out the details of a Saudi pledge to invest US$8 billion in Egypt but Nasr said she was taking time to approve projects that were ready to go. THE AFRICA REPORT (FRANCE), February 4, 2016

Nigerian Minister of Power, Works and Housing Babatunde Fashola has disclosed that the federal government has accessed the second tranche of US$50 million African Development Bank (AfDB) budget support facility while negotiation is ongoing on US$100 million HSBC and US$200 million Rand Merchant Bank facilities to fund the completion of its major power projects. Fashola, who spoke at the hearing of House of Representatives committee on power, identified the projects that the federal government has set 2016 completion deadline, including the ongoing 3,050 MW Mambilla hydroelectric power project and Zungeru 700 MW hydroelectric power project. Other projects are the 215-MW Kaduna power project, the 10-MW Katsina wind farm project and 81 transmission projects to ensure available stranded power stations can evacuate their capacity. The minister who was represented by Permanent Secretary of the Ministry Louis Edozie explained that ministry had proposed a total sum of 431.6 billion naira (US$2.16 billion) for capital projects while 741.9 million naira (US$3.72 million) was for overheads for the 2016 fiscal year. To fund the capital component of the budget, the federal government is to provide 99.3 billion naira (US$498.3 million) while the additional sum of 309.7 billion naira (US$1.55 billion) would be provided by Debt Management Office (DMO) and or Central Bank of Nigeria (CBN) to ensure payment assurance for the entire electricity industry would be obtained from various sources. SUNNEWSONLINE.COM (NIGERIA), February 4, 2016

For years, China was bullish on oil. In just four years after the financial crisis of 2009, the state-owned big three energy companies ramped up their annual capital expenditures by half, to more than 400 billion yuan (US$60.8 billion) in 2013 and 2014, and almost doubled their crude exploration outlays. But now, if oil stays under US$30, investors will probably see ugly asset write-downs and dividend cuts. The worst is not over. After this year’s selloff, upstream producer CNOOC and its integrated peers Sinopec and PetroChina, which have larger refining operations, now trade at only 0.5 to 0.6 times book, a level equal to their 2008 lows, reached when Brent crude hit US$36 per barrel. Value investors might be tempted to jump in. But this is not a repeat of 2008. After plunging that year, oil was able to bounce back to average more than US$110 per barrel in 2013 and 2014. Will we see such a comeback again in five years? According to Credit Suisse, CNOOC’s share quote implies a long-term oil price of US$60 per barrel; Sinopec’s, US$65, and PetroChina’s, US$75. In contrast, Thailand’s PTTEP prices in only US$30 per barrel. BARRONS ONLINE (US), February 6, 2016

India willing to consider long term fixed price contracts for gas supplies The Indian government has indicated willingness to consider long term fixed price contracts for the supply of gas,

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which will enable power producers to enter into a power supply contract at an affordable price. Minister of State for Coal, Power and New and Renewable Energy Piyush Goyal said opportunities to control the entire value chain right from gas production, liquefaction, shipping, re-gasification and power generation can be evaluated at the current historic low prices of many of these activities. The minister is leading a delegation for the third India-Australia Energy Security dialogue in Australia. India is running one of the world’s largest renewable energy programme which aims to increase the capacity five times to 175 GW over the next seven years. This will require gas based plants which can act as spinning reserve and supply power during deficit times of day (like evenings) when renewable energy production reduces while stabilising the grid. Since coal based power is available in India at less than five cents per unit, the LNG providers should consider supplying gas to India at a price that is comparable. COMMODITYONLINE.COM (INDIA), February 9, 2016

Cheap oil boosts Japan’s 2015 current account surplus six fold Japan’s current account surplus grew more than six fold in 2015 from the previous year to 16.64 trillion yen (US$145.4 billion), boosted by a plunge in crude oil imports and a travel surplus amid the yen’s depreciation, government data showed. Goods trade registered a deficit of 643.4 billion yen (US$5.62 billion), down 93.8% from the deficit of 10.4 trillion yen (US$90.8 billion) in 2014, thanks to plunges in oil prices that helped improve the trade balance despite slow growth in

exports. The current account surplus, one of the widest gauges of international trade, grew for the first time in five years, as imports dived 10.3% to 75.82 trillion yen (US$662.4 billion), while exports rose 1.5% to 75.18 trillion yen (US$656.8 billion), the Finance Ministry said in a preliminary report. Japan has been relying heavily on energy imports since the March 2011 Fukushima nuclear disaster, with most of the country’s commercial reactors remaining offline amid heightened public concern about their safety. Economist at Barclays Securities Japan Yuichiro Nagai said oil prices are likely to continue to be a major factor influencing Japan’s trade balance, as exports are expected to remain sluggish this year. “Export demand for China and other Asian regions was weak in 2015, while shipments to the United States also fell on a volume basis,” Nagai said. “The weakness in exports seen in the latter half of 2015 is likely to remain.” JAPAN TIMES (JAPAN), February 8, 2016

Pakistan not to privatise power firms, angering IMF Pakistan has shelved plans to privatise its power supply companies and will miss deadlines to sell other loss-making state firms, reneging on promises Islamabad had made to the International Monetary Fund (IMF) in return for a US$6.7 billion bailout three years ago. Two government officials said IMF officials meet with Pakistani officials in Dubai this week and were angered by the backtracking, but they expected the IMF would still release the remaining US$1.6 billion to be disbursed. The IMF is due to announce its decision on the next tranche, expectedly of US$500 million, at a news conference later on February 4 in

Dubai. For all the IMF’s frustration over the privatisation delays, the government has pushed ahead on other reforms, the Pakistani officials said, though there is another unspoken reason why Islamabad can expect the money to keep coming with little more than a reprimand. Western allies, and neighbours Afghanistan and India, fear an economic meltdown would create a witches brew in the nuclear-armed Muslim nation of 190 million, mostly poor people, whose fragile democracy is under internal attack from Islamist militants. TIMES NEWS NETWORK (INDIA), February 4, 2016

EUROPE

Smolenskenergo to invest 1.264 billion rubles in Smolensk grid Smolenskenergo division will invest about 1.264 billion rubles (US$16.07 million) in the electric grid complex of the region. Of these, the branch plans to invest 794.2 million rubles in technical re-equipment and reconstruction of the electric grid complex and 470 million rubles in construction of new energy facilities. To maintain a reliable state of existing power grids, grid connection of new customers it is planned to construct and reconstruct 0.4-10 kV power lines in the amount of 665.4 million rubles. Modernisation and reconstruction of high-voltage substations will allow improving reliability in some districts of the city and the region. The total amount of funds allocated for the implementation of these activities is 166.6 million rubles, including the reconstruction of the 110/35/10 kV substation Vyazma-1, which will cost

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89.4 million rubles. REGIONS.RU (RUSSIA), February 8, 2016

BG Group profit up ahead of takeover Oil and gas firm BG Group, whose takeover by Shell is almost complete, has reported a rise in its final full-year earnings. BG said pre-tax profits for the full year were US$2.97 billion, compared with a loss of US$2.3 billion in 2014. On a quarterly basis, BG’s losses improved from US$8.3 billion in the final quarter of 2014 to a loss of US$1.17 billion for the same period in 2015. BG’s results have been affected by the falling oil price. BG Group chief executive Helge Lund said: “We are pleased to have delivered an excellent operational performance in 2015 with results in line with, or ahead of, our guidance for the year. This strong operational performance is the result of the capability and commitment of our teams across the organisation and we will deliver a high-performing business into the combination with Shell.” BG’s results come in the same week as those from other energy giants, BP and Shell. Both maintained their dividend payout to shareholders. BG said its shareholders would receive Shell’s 2015 fourth-quarter dividend and would not receive a further BG Group dividend for 2015. BBC NEWS (UK), February 5, 2016

FSU

Watchdog says Russia’s Rosneft ready for privatisation Russian oil major Rosneft is almost ready for the privatisation of a 19.5% stake, which belongs to state oil and gas holding Rosneftegaz but conditions must be created

for the shares to be sold at a fair price, the Federal State Property Management Agency said. “In Rosneftegaz’s opinion, the fulfilment of the president’s order regarding the minimum price of the deal at a level not lower than the price of the primary placement is possible in the medium term only if conditions ensuring growth of the market price of Rosneft’s shares are created,” the agency said. The agency said that the fair price of Rosneft’s shares is US$8.12, because this was the price of a stake sale to BP, the most recent large deal with the shares of the company. Authorities decided in 2014 to set the minimum price for the state stake in Rosneft at the level of the initial public offering in 2006 and not below the market price. The IPO took place at 203 rubles per share in Russia and at US$7.55 per global depositary receipt in London. PRIME (RUSSIA), February 9, 2016

L AT I N A M E R I C A

Colombia’s central bank to keep raising interest rates Colombia’s central bank looks set to continue with its invasive monetary policy, with co-director Carlos Gustavo Cano saying interest rates will continue to rise. At an entrepreneurs’ meeting on February 3, Cano said “additional adjustments are necessary and unavoidable”. He added that an active monetary policy is necessary in order to reach the Bank’s target inflation rate. The Consumer Price Index closed at 6.77% at the end of 2015, far from the target of 4%. This caused the bank to raise interest rates for the fourth consecutive quarter, to 6%, the highest level since March 2009. EL COLOMBIANO (COLOMBIA), February 4, 2016

Central bank calls for Pemex cuts The governor of Mexico’s central bank, Agustin Carstens, has publicly called for steep cuts to public spending, including transferences to state-owned Pemex. The start of the year would be a good time to adjust prices to what he called “the new reality” given that oil prices are 70% below the targets set out in the 2016 budget, he said. EL UNIVERSAL (MEXICO), February 7, 2016

MIDDLE EAST

Indian billionaire Ruias said to hold refinery talks with Aramco, NIOC Essar Group, controlled by India’s billionaire Ruia brothers, has held preliminary discussions with the national oil companies of Saudi Arabia and Iran about selling a stake in its refinery business, people with knowledge of the matter said. Exploratory talks began last month between Saudi Arabian Oil Co and the Indian conglomerate about a stake in Essar Oil, which has a market value of about US$5.5 billion, according to the people. Essar Group officials discussed a potential deal during a meeting with Aramco executives at the World Economic Forum in Davos, three of the people said, asking not to be identified as the information is private. National Iranian Oil Co also met Essar Group recently about a possible purchase of a stake in Essar Oil, according to three people. The talks, which touched on the refinery deal as well as a potential increase in purchases of Iranian crude by the private Indian refiner, took place two to three weeks ago in Iran, one of the people said. Essar Group is selling

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assets after earnings were hurt by a fall in commodity prices, weak demand and lower capacity usage at its businesses. Saudi Aramco, the world’s biggest oil producer, is moving beyond producing and exporting crude and expanding into the processing and sale of oil products, which can fetch higher prices on world markets. BLOOMBERG, February 3, 2016

Abu Dhabi to take billions from ADIA for debt Abu Dhabi Investment Authority’s (ADIA’s) assets will probably shrink by billions of dollars by the end of this year as the emirate’s government taps its sovereign-wealth fund to bridge a deficit brought on by low petroleum prices, Fitch Ratings said. Assets will drop to US$475 billion at the end of this year, from an estimated US$502 billion at the end of 2014, Fitch said, adding that it expects them to rise again in 2017. The government may also issue local and foreign currency bonds to finance its deficit this year and next, according to the ratings company. Abu Dhabi’s department of finance has “intensified” talks with the central bank and commercial banks on a local debt sale, it said. Governments from Moscow to Oslo have tapped reserve funds built up during the days of high oil prices to help sustain spending during a slump in crude caused by oversupply and China’s economic slowdown. Saudi Arabia, the world’s largest oil exporter, has taken unprecedented steps to counter the drop in revenue and has raised the possibility of selling a stake in government-owned entities, including state oil giant Aramco. Abu Dhabi’s government relies on oil dividends that come through state-owned Abu Dhabi National Oil Co (ADNOC) for much of its revenue. ADIA is set up to have liquid and semi-liquid assets that the government can tap as needed. The fund has seen government withdrawals “infrequently and usually during periods of extreme or prolonged weakness in commodity prices,” according to the fund’s annual

report. BLOOMBERG, February 3, 2016

NORTH AMERICA Texas shale drillers lure US$2 billion in new equity to Permian Oil producers in West Texas, defying expectations they would fall victim to OPEC’s price war, are instead selling investors on the idea that they can still profit with prices below US$35 per barrel. Drillers in the Permian basin, the biggest US shale field, have raised at least US$2 billion from share sales over the past eight weeks. And more issuances are on the way as producers try to avoid piling on additional debt. Pioneer Natural Resources Co’s 12 million-share issuance on January 5 was followed a week later by Diamondback Energy’s announcement of a 4 million-share sale. Private equity is getting in on the act, too, Kayne Anderson Capital Advisors is bankrolling a startup called Invictus Energy with US$150 million to drill the Permian and the Eagle Ford shale. Crude’s crash below US$30 per barrel for the first time in 12 years means explorers are facing cash shortfalls, and selling shares is less painful than adding debt or auctioning off assets that would attract weak prices in the current environment, said analyst at KeyBanc Capital Markets David Deckelbaum. “In a world where the oil price can break you, taking on debt is an absolute no-no,” said Deckelbaum, who pegged Diamondback as a likely stock seller six days before the company’s announcement. He foresees a “heavy wave” of new share sales. BLOOMBERG, February 2, 2016

Obama seeks US$12.8 billion to expand clean-energy research President Barack Obama wants to double US investment in clean

energy research and development, to US$12.8 billion by 2021, as part of a broader commitment to curb the effects of climate change. The administration is seeking US$7.7 billion in discretionary funding in fiscal 2017 to boost funding for the research at 12 federal agencies, according to a White House fact sheet. The funding would increase by 15% a year through fiscal 2021. Republican leaders in Congress have already said they do not plan to help enact Obama’s budget plan. Obama is using his final budget request, to be unveiled February 9, to showcase his efforts to curb greenhouse-gas emissions, a push criticised by lawmakers in coal and oil rich states. The investment in clean energy research stems from a commitment reached with other nations at international climate talks in Paris in December. BLOOMBERG, February 6, 2016

Obama’s US$319 billion oil tax plan raised to US$10.25 per barrel President Barack Obama proposed to raise US$319 billion over the next decade for transportation and other needs with a US$10.25 per barrel tax on crude, up from US$10 that was announced last week. The higher amount, along with other details, were released February 9 as part of the president’s US$4.1 trillion budget request to Congress. While major questions still remain unanswered, including how and when the fee would be charged, the White House envisions collecting the tax from an estimated 4 billion barrels of domestic and imported oil in 2022, once it is fully phased in. The money would be steered to a “21st Century Clean Transportation Plan to upgrade the nation’s transportation system, improve resilience and reduce emissions,” according to budget documents. BLOOMBERG, February 9, 2016

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