Energy finance week issue 04 by NewsBase Ltd.

Week 04• 29 February • 2016

ENERGY FINANCE WEEK This week’s top stories

v Debt burdens straining US shale industry

v Under pressure, Petroceltic begins Algeria drilling p12

v Asian rig builders batten down the hatches

p14

v Kuwait’s Equate highlights Emirate’s new-found commercial approach

p22

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

ENERGY FINANCE WEEK

Week 4• 29 February • 2016

Debt burdens straining US shale industry

US shale drillers are under increasing pressure from unsustainable levels of debt, with two companies having recently missed debt repayments NORTH AMERICA TWO missed debt repayments in the US shale industry have illustrated the impact of the US$30 per barrel oil price, with drillers under more financial pressure than ever. The smaller players, which snapped up acreage at the height of the shale boom using billions of dollars in borrowed money, are now being hit the hardest. According to data compiled by Bloomberg on 61 companies in the Bloomberg Intelligence index of North American independent producers, the US shale industry must come up with US$1.2 billion in interest payments by the end of March, with nearly half of this owed by companies with junk-rated credit. Energy XXI said in a filing on February 16 that it had missed a US$8.8 million interest payment, with SandRidge Energy announcing the next day that it had failed to make a US$21.7 million interest payment. As more such payments fall due, and are missed, expectations of more impending bankruptcies have grown. One of the US’ largest shale gas producers, Chesapeake Energy, recently issued a statement denying it was planning to file for Chapter 11 bankruptcy protection, after its stock fell 50% in a day. Chesapeake has hired lawyers to help restructure over US$10 billion in debt. Data compiled by the Wall Street Journal have indicated that the total debt of US oil and gas companies, excluding Chevron and ExxonMobil, is anticipated to grow to over US$200 billion when all the 2015 financials come out, marking a 55% increase since 2010. The toll that this has taken as crude prices have fallen is illustrated by law firm Haynes & Boone, which has said that 48 North American oil and gas producers have declared bankruptcy since the start of 2015. Combined, these companies owed over US$17 billion. SandRidge said in a statement that it “has sufficient liquidity to make these interest payments, but has elected to use the 30-day grace period in connection with its ongoing discussions with stakeholders”. SandRidge’s president and CEO, James Bennett, said in the statement that the company’s actions “will preserve liquidity and flexibility” as these discussions continue. Even the bigger players are not immune to the slump, as profits dwindle and credit rating firms downgrade their debt. Dividend payments have suffered as a result. Anadarko Petroleum is among those most recently

affected, having cut its quarterly dividend by over 81% on February 16 in an effort to conserve cash. Disappearing cushions The lowest oil and gas prices in around 14 years are making it increasingly difficult for companies to find the cash needed to stay current on their debts. In 2009, crude prices rose sharply and stayed at around US$100 per barrel until 2014, since when they have fallen by around 70%. While prices were high, many drillers spent more than they earned, bridging the gap with debt. That debt has become a deadweight with the price collapse. Fort Worth-based Energy & Exploration Partners, for example, borrowed from at least 24 hedge funds to help acquire thousands of acres in Texas while oil prices topped US$100 per barrel. In December 2015, the company filed for bankruptcy, with lenders unable to agree on how to save it. Until recently, companies were able to ride out the slump using hedges to sell their output at a higher price. Now, though, only 15% of US oil and gas production is hedged, compared with 28% of output in the fourth quarter of 2015, according to IHS. And the remaining hedges are coming up for expiry. Without the cushioning from hedges, oil prices are in many cases no longer covering the costs of production – and a recovery seems unlikely until 2017. What next? The US oil and gas industry is facing US$9.8 billion in interest payments up to the end of this year, according to Bloomberg. Some companies will suffer more than others as they attempt to make their payments. Energy XXI may be unable to meet its commitments in the next 12 months, triggering “substantial doubt” about its ability to survive, according to a company filing with the US Securities and Exchange Commission. SandRidge has another payment of about US$28 million due on March 15, but had used its US$500 million credit line by January 22. Meanwhile Chaparral Energy, which has also drawn down its entire credit line, has a US$17 million payment looming next month, according to Bloomberg’s data. Both SandRidge and Chaparral are reported to have hired legal and financial advisers.

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 4• 29 February • 2016

Deloitte said in a report this month that nearly 35% of US production and exploration companies were at high risk of going bankrupt in 2016. This year “will be the year of hard decisions”, Deloitte vice chairman and US oil and gas sector leader John England said. “Access to capital markets, bankers’ support and derivatives protection, which helped smooth an otherwise rocky road for the industry in 2015, are fast waning.” According to Deloitte Center for Energy Solutions’ executive director, Andrew Slaughter, staying solvent is now the main challenge for hundreds of companies that piled on debt to grow from tiny start-ups into significant players in the US shale boom. It “will require the same level of perseverance, innovative thinking and creativity as the technology breakthroughs that led to the boom in supply we have seen over recent years”, he said. Those that fall by the wayside may be acquired, with majors that still have the ability to scoop up assets standing to benefit. Nobody expects oil prices to remain low forever, but even the average US$40 per barrel price recently forecast

for the year by the US Energy Information Administration (EIA) will not offer much relief. NewsBase anticipates the availability of credit lines for US shale producers being a major issue in the months ahead. In April, banks will carry out their semi-annual review of borrowing bases and credit lines for oil and gas producers. They will need to decide whether to cut back some lending, risking borrower defaults, or whether to maintain borrowing bases at a level sufficient to facilitate continued operations, including the drilling of new shale wells to replace depleting production. The risk for lenders is that any new loans can quickly turn into bad debt, especially if oil prices decline further. However, it is in their interest to allow producers enough breathing space to keep drilling, as new production would enable companies to make repayments. As a result, the review of borrowing bases may yet be more lenient than some expect. Eventually, the global supply glut will be reduced and the market will rebalance. In the meantime, shale producers – particularly the smaller and more debt-laden players – are set to suffer more than ever.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 4• 29 February • 2016

Centrica, Qatar Petroleum plan Canada exit NORTH AMERICA UK-BASED Centrica and state-owned Qatar Petroleum are seeking to offload their joint venture assets in Western Canada as the oil price slump continues to hurt producers and force non-core asset sales. Speaking to reporters, Centrica’s CEO, Iain Conn, said job losses would also take place as the company sought to shifts its focus towards residential energy supply and services at the expense of upstream operations. “We have said that Canada is non-core,” he said, adding that no deadline had yet been set for the sale. “It’s not a wise time given where prices are now,” Conn said. “We are not in any rush. Last year was a very challenging year for us, mainly because of the collapsing commodity prices.” Separately, it emerged that Qatar Petroleum was in the process of appointing a number of financial advisers to explore sale options, while, according to a report by Bloomberg, Centrica was working with the investment banking arm of Toronto-Dominion Bank. No potential

buyers have been named, and there is a chance that both Centrica and Qatar Petroleum may yet decide against the sale at a later date. The two firms acquired the conventional oil and gas fields, which are located in Alberta, northeastern British Columbia and southern Saskatchewan, from Suncor Energy in a deal worth C$1 billion (US$986 million) in 2013, marking the first investment by the two companies since they signed an agreement to pursue international projects jointly in 2011. It is anticipated that the two companies will receive significantly less than this sum once a buyer is found. Under the joint venture agreement, Centrica purchased a 60% share, with the remaining 40% owned by Qatar Petroleum International (QPI), the international investment arm of Qatar Petroleum. QPI has since been absorbed back into its parent company as part of an eight-month restructuring process aimed at reducing exposure to low oil prices.n

Chesapeake to focus on asset sales after quarterly loss NORTH AMERICA CHESAPEAKE Energy posted a fourth-quarter loss for 2015 after being battered by markets for weeks on bankruptcy concerns amid the oil price slump. On February 24, the Oklahoma-based producer reported a net loss of US$2.23 billion in the fourth quarter, compared with a US$586 million profit in the fourth quarter of 2014. Revenue fell from US$5.69 billion a year ago to US$2.65 billion. The results were slightly better than analysts had expected. Chesapeake said it was taking steps to boost its performance and that it had already closed or signed deals for US$700 million in asset sales this year. Not included in this was a sale announced separately on February 24, when FourPoint Energy said it had struck a deal to buy Chesapeake’s remaining Western Anadarko Basin assets for US$385 million. Overall the company is aiming to sell an additional US$500 million to US$1 billion in assets this year. Chesapeake also said it was cutting its capital budget for 2016 roughly 57% year on year to US$1.3-1.8 billion from US$3.6 billion. The

company said its 2016 budget would be targeted at more completions and less drilling. Completions are anticipated to account for roughly 70% of Chesapeake’s spending this year. “This programme, combined with the improving quality of the company’s operations, its capital efficiency and lower service costs, will provide incrementally positive economics, even in today’s commodity price environment,” the company said in a statement. Chesapeake is seeking to bring roughly 330-370 wells on line this year, resulting in total production down by around 0-5% compared to 2015, after adjusting for asset sales. The earnings report comes two weeks after Chesapeake’s shares dropped by over 50% in a day following reports that it had asked law firm Kirkland & Ellis to explore restructuring options. Chesapeake quickly issued a statement saying it had no plans to pursue bankruptcy, but the company is nonetheless facing tough times. Its debt load is eight times its market value, and shares are down 60% over the past three months.n

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Week 4• 29 February • 2016

Encana sees light at the end of oil price tunnel NORTH AMERICA ENCANA’S CEO, Doug Suttles, has said that the firm, once Canada’s largest by market value, sees the light at the end of tunnel for oil prices despite its recent losses. Speaking on a conference call to discuss the company’s fourth-quarter 2015 results, Suttles was cautiously upbeat about the company’s future prospects despite it taking a US$5.1 billion net loss for the full fiscal year in 2015. After stripping out one-time items – mainly write-downs on the carrying value of assets – the loss narrowed to a more reasonable US$61 million, but was still far short of the US$1 billion profit Encana made in 2014. Speaking to analysts, Suttles touted nearly US$400 million of cost reductions, primarily related to drilling and completing unconventional wells in four North American shale regions – the Permian Basin and Eagle Ford in the US and the Duvernay and the Montney plays in Canada. “We know the direction [of the global oil market],” he said, alluding to a recovery. “But we don’t know the timing.” Indeed, timing has not been the company’s strong suit in recent years. Encana was overhauled in 2010 to become a pure play natural gas producer, and at one point produced over 3 billion cubic feet (85 million cubic metres) per day or nearly 10% of all the gas in North America. But with the shale revolution it became a victim of its own success. In 2014 Encana decided that it needed to diversify production after gas prices had crashed. However, its push into liquids came just as oil prices began to sink. It could not have happened at a worse moment. In September 2014 Encana bought Texas oil producer Athlon Energy in a deal worth US$7.1 billion just as oil prices began to fall. Earlier, in June 2014, it paid US$3.1 billion to buy 45,000 net acres (182 square km) located in Karnes, Wilson and Atascosa counties in Texas from Freeport-McMoRan. Subsequently, Encana racked up a huge amount of debt and was forced to sell assets, often at a loss. In November 2015 it unloaded over 110,000 acres (445 square km) in the Haynesville shale for US$850 million. It also reduced transportation and midstream commitments by an additional US$450 million. A US$900 million sale of its Colorado DenverJulesburg Basin assets to the Canada Pension Plan Investment Board (CPPIB) is pending.

Encana has also been shedding non-core properties in Canada, and Suttles said more asset sales were coming. In total, the company has sold over US$2.8 billion worth of properties in the past 18 months, notwithstanding the US$4 billion sell-off of royalty titles it had inherited from the successors of the Canadian Pacific Railroad (CPR) – some dating back to the 1800s. As a result, the company is now a much smaller entity than it once was. On February 24, Encana announced plans to reduce its workforce by 20%, on top of the 20% reduction it made last year. The company is now half the size it was two years ago. At one point it was active in 30 plays in North America. Now it has a presence in just four. However, Suttles has now said the company’s debt is under control, with no major maturities until 2019, adding that it can now proceed with what it knows best – drilling unconventional wells. He justified the company’s spending spree on the grounds that it would allow Encana to dramatically reduce well costs and enhance efficiencies while diversifying production. The latest quarterly reports appear to bear these claims out. Encana does not typically break out production by play, but its overall liquids output was up 54% to 133,000 barrels per day from virtually nothing three years ago, despite a 15% decline in overall production to 405,900 barrels of oil equivalent per day, including 1.64 bcf (46.4 mcm) per day of gas. About 60,000 bpd came from the Eagle Ford, said Encana’s chief operating officer, Mike McAllister. Encana has long employed a “factory” approach to drilling, with batches of extended horizontal hydraulically fractured wells from pads. Suttles pointed to a location near Midland, Texas, where four rigs are simultaneously drilling 14 well laterals from a single location. In the Eagle Ford, the company has begun to delineate the upper zones, which could open up more of the play. In Canada, meanwhile, the Duvernay is starting to show promise. Well costs are below US$8 million compared with over US$20 million three years ago. The Duvernay is being touted as North America’s next big unconventional play. Encana also remains one of the largest operators in the Montney shale. With the worst behind it, one of Canada’s largest and oldest legacy companies is hoping to weather the downturn and regain its footing soon.n

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Week 4• 29 February • 2016

Chevron to sell remaining shallow Gulf assets NORTH AMERICA CHEVRON has put its remaining shallow-water assets in the US Gulf of Mexico up for sale. The company is “accelerating the sale of mature shelf properties and has begun marketing all shelf assets in the Gulf”, Chevron spokesman Cam Van Ast told NewsBase. “The divestments will begin in 2016 and are expected to be completed by the end of 2017,” he said. The California-based super-major said it planned to switch its focus in the Gulf to deepwater work in order to reduce expenses and boost efficiencies. “This process is consistent with Chevron’s ongoing efforts to align its portfolio of assets with overall long-term strategies,” Van Ast added. “Chevron is continuing to adapt to the evolving business environment by revising organisational structures,” he said, adding that the firm planned to have fewer but more complex assets in the future. Chevron is aiming to sell US$5-10 billion of global assets by the end of 2017, Van Ast said. The firm’s asset sale programme generated US$11.5 billion in cash by the end of 2015, he added. In the shallow Gulf, Chevron could sell up to 27 oil

and gas fields that produce around 46,000 barrels of oil equivalent per day in total. It has been estimated that the super-major could earn over US$1 billion from potential sales. There is still thought to be a buying market for producing assets in the US. Chevron has said that the Gulf is still a core focus area, despite weak oil prices. Chevron’s executive vice president of upstream, George Kirkland, has said that the firm anticipates significant production growth in the next two years. Chevron said in June 2015 that it had made a new deepwater discovery at the Sicily well in the Keathley Canyon. Chevron’s partner Hess has estimated gross resource potential of 300-400 million boe at the well. In 2014, Chevron and partner BP announced the discovery of a “significant” amount of oil with the Guadalupe wildcat. Meanwhile, Chevron’s Jack/St Malo deepwater project, which achieved first oil in December 2014, is anticipated to ramp up production in the next few years. The company has had less luck with its Big Foot project, at which start-up has been delayed until at least 2018 while the company investigates an equipment failure at the site.n

Devon cuts staff, spending NORTH AMERICA

CHEVRON has put its remaining shallow-water assets in the US Gulf of Mexico up for sale. Shale driller Devon Energy is cutting spending and jobs dramatically as low oil prices continue to hurt the shale industry. The Oklahoma-based company said it would cut its spending by 75% and staff by 1,000 – or 20% – in February and reduce its dividend from US$0.24 per common share to US$0.06. Devon is projecting capital spending to be between US$900 million and US$1.1 billion in 2016. “Devon’s top priority in 2016 is to protect the balance sheet,” said Devon’s president and CEO, David Hager. “We are tailoring activity to current market conditions and are prepared to adjust capital plans throughout the year to ensure we balance capital investment with cash inflows.” For the fourth quarter of 2015, the company posted a net loss of US$4.5 billion, compared with a loss of US$408 million in the same period a year before. About a week earlier, Devon confirmed to Reuters

that it had hired investment bank Jefferies Group to help with its sale of assets in four shale regions – the Permian Basin, East Texas, the Granite Wash and the Mississippian play. The company is hoping to raise US$2-3 billion through the sales. According to its fourth-quarter earnings report, Devon’s oil production averaged 278,000 barrels per day, a 16% increase compared with the fourth quarter of 2014. Devon’s core asset portfolio accounted for 247,000 bpd of this. Oil production from its core assets rose 26% year on year, which was in part driven by Delaware Basin growth. Overall, net production from Devon’s core assets averaged 571,000 barrels of oil equivalent per day during the fourth quarter, representing a 7% rise compared with the fourth quarter of 2014. In 2016, though, Devon expects lower gas production, bringing overall output for the year down 6% from the fourth quarter of 2015. “We … see no reason to accelerate production growth into these weak markets,” Hager said.n

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Week 4• 29 February • 2016

Marathon continues with Eagle Ford focus despite cutting spending NORTH AMERICA MARATHON Oil will continue to invest significantly in the Eagle Ford and other shale plays even as it scales back its capital programme to US$1.4 billion. Almost 70% of its capital spending will be spent on shale operations. Marathon said about 42% of its 2016 budget would be spent on the Eagle Ford. Meanwhile, 14% will be spent on drilling in Oklahoma’s shale plays and 13% in the Bakken. “For each of our three core resource plays, we have set specific objectives for our 2016 investment,” Marathon’s president and CEO, Lee Tillman, told analysts. “Namely, maintaining the efficiencies our Eagle Ford team has worked so hard to capture, protecting our leasehold in the STACK [in Oklahoma] while continuing to improve our understanding of the Oklahoma resource basins and focusing on our base business in the Bakken with operated drilling and completions greatly reduced,” he said. Of the US$600 million earmarked for the Eagle Ford, US$520 million will be used for drilling and completions. The company’s 2016 drilling programme will continue focusing on co-development of the Lower and Upper Eagle Ford horizons, as well as the Austin Chalk in the play’s core. Marathon said it expected to bring 124-132 gross company-operated wells to sales in the Eagle Ford and would cut its rigs from seven to five by the end of the first quarter. This compares with an average of 11 rigs in 2015 and 276 gross company-operated wells brought to sales. Marathon will scale back to a single frack crew for most of the year.

In Oklahoma, where Marathon acquired some additional acreage in 2015, around US$200 million of spending will support 20-22 gross operated South Central Oklahoma Oil Province (SCOOP) and STACK wells being brought to sales. The drilling and completions will account for US$195 million of the Oklahoma programme, including an estimated US$55 million for outsideoperated activity. An average of two rigs in 2016 will be used as Marathon focuses primarily on lease retention in the STACK and delineation of the Meramec. Marathon said it anticipated having roughly 70% held by production in the STACK by the end of the year, with the SCOOP already over 90% held by production. In the SCOOP Springer play, Marathon is planning to complete its second company-operated well in the first quarter and drill another well later in the year. In the Bakken, Marathon is planning to spend just under US$200 million, with US$150 million allocated for drilling and completions, including an estimated US$75 million for outside-operated activity. Marathon expects to average one rig in the Bakken for half of 2016, bringing 13-15 gross operated wells on line. Following encouraging results in 2015 from its first pad in the Bakken’s West Myrmidon, near the Nesson anti-cline, the company is planning to bring a second West Myrmidon pad to sales in 2016. Marathon said spending on facilities and infrastructure would be significantly lower than in 2015. However, it added that it would complete its watergathering system on schedule later this year. This will help the company further reduce the cost of water handling, which is its largest single expense in the Bakken.n

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Week 4• 29 February • 2016

EU suspends deadline for review of Halliburton deal EUROPE EUROPEAN Union anti-trust regulators have suspended the deadline for their review of US oilfield services provider Halliburton’s proposed US$35 billion takeover of rival Baker Hughes. The European Commission reportedly took the decision because the companies failed to provide some details about the proposed deal. “This is a standard procedure on merger investigations which is activated if the notifying parties do not provide an important piece of information that the Commission has requested from them,” EC spokesman Ricardo Cardoso was reported by Reuters as saying. The EU is anticipated to set a new deadline for the decision once the companies have provided the necessary information. Halliburton originally agreed to buy Baker Hughes in November 2014. The deal was due to close by the end of 2015, but has been slowed by anti-trust delays in the US and Europe. Halliburton said it would be prepared to sell some of its businesses in order to make the deal acceptable to competition authorities. Regulators in six countries including Canada, South Africa and Turkey have approved

the takeover. However, EU as well as US regulators are still examining the deal. In January, Halliburton posted a 2015 net loss of US$666 million, compared with a profit of US$3.4 billion for 2014, citing the continued impact of depressed oil prices on the business. The firm also said in January that it had laid off a further 4,000 workers in the fourth quarter of 2015. In October 2015, Halliburton said it had cut around 18,000 jobs in total, representing 21% of its workforce. The pain has continued, with Halliburton announcing this week that it would cut a further 5,000 jobs globally, representing 8% of its workforce. The company has said it remains committed to closing the deal with Baker Hughes, the world’s third largest oilfield services provider. Halliburton and Baker Hughes have extended the closing of the deal to April 30. The EC said in January that it would conclude its investigation into the deal by May 26, but this week’s deadline suspension is likely to mean that its decision will be delayed beyond that date. Halliburton has said that work on the deal cost the company a total of US$308 million in 2015.n

Ocean Yield profits increase EUROPE IN a rare sign of strength in the oil services industry, Norway’s Ocean Yield enjoyed a 5% profit uptick in the fourth quarter. The company also pledged to hold firm on its dividend policy. During the Q4, Ocean Yield’s earnings before interest, taxes, depreciation and amortisation (EBITDA) lifted to US$56.6 million from US$53.9 million in the same period a year earlier. They fell short, however, of the US$57.9 million that analysts polled by Reuters predicted. Ocean Yield, which invests in vessels for long-term charter, also flagged up potential problems facing its customers, predicting that some would be hit hard by current low activity levels in the market and might even enter restructuring. “We have all our units on long charters, so the question for us is whether our counterpart can perform according to contracts,” said CEO Lars Solbakken. But he added that while he expected 2016 and 2017 to be challenging, Ocean Yield is hopeful that only a small number of industry players will face bankruptcy this year, as both companies and creditors are

keen to minimise losses. Despite these headwinds, Ocean Yield remains financially strong enough to maintain its dividend policy, Solbakken said. “We’re in a financial position where we could handle a couple of restructurings among our customers and keep today’s dividend,” he said. “We have not changed our dividend guidance, but we have not wanted to provide any guidance on dividend growth.” The company proposed to pay a dividend of 16.25 US cents per share for the fourth quarter, up from 15.75 US cents in Q3 and 14.25 cents a year earlier. Sounding an upbeat note, Solbakken said he expected Ocean Yield to increase its earnings in coming years. The company also announced last week the delivery of the LR2 product tanker Navig8 Symphony from South Korea’s Sungdong Shipyard. It is the first vessel out of four product tankers that Ocean Yield will charter to Navig8 Product Tankers. Ocean Yield currently has 14 vessels in operation and another 13 newbuilds on order.n

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Week 4• 29 February • 2016

OMV to focus on Russian market EUROPE

AUSTRIA’S OMV will place Russia at the heart of its upstream strategy by 2020 as it tries to fight back from a near 50% fall in net profits in the fourth quarter of 2015. OMV on February 18 posted a net profit of 180 million euros (US$201 million) for the period, and said it would slash its shareholder dividend by 20% year on year to 1 euro (US$1.10) per share. Its upstream segment’s earnings before interest and tax (EBIT) for 2015 swung to a 2.4 billion euro (US$2.53 billion) loss, from a 1.46 billion euro (US$1.61 billion) gain registered in 2014. This more than offset a 28% cut in spending on exploration and production to 2.1 billion euros (US$2.31 billion) last year. OMV is still lumbered with high production costs at its European upstream assets, with reports suggesting its breakeven price in Europe last year was around US$43 per barrel versus US$10 and US$11 per barrel in Russia and the Middle East respectively. OMV was forced to write 3 billion euros (US$3.33 billion) off the value of its assets in 2015, to reflect the impact of low oil prices. In the fourth quarter, OMV booked 1.475 billion euros (US$

1.62 billion) in impairment charges, which it was said was partially owed to realigned gas price assumptions because of the depressed European market. CEO Rainer Seele told investors that OMV must recast itself as a “regional player”, highlighting plans to re-centre OMV’s portfolio around the Iranian and Russian markets. OMV would focus on “cash and costs”, while chasing value rather than volumes to attain a “sustainable” upstream position, he said. OMV is holding talks with Gazprom about an asset share swap which would see the company take a stake in the Urengoy oil and gas development in Siberia. According to the firm, its Urengoy stake will initially net 40,000 barrels of oil equivalent per day for OMV, with some analysts suggesting output could rise to 60,000 boepd. Gazprom is eyeing expansion in Europe, and its wish list has previously been reported to include stakes at OMV’s refining assets in Austria and Germany. In January, OMV said Austrian media speculation about its side of the bargain was premature, stressing that it had only agreed to discuss the sale of assets.n

OMV Petrom records net loss EUROPE OMV Petrom last week unveiled a 690 million leu (US$169.2 million) net loss for 2015, its first full-year loss since Austria’s OMV took control of the company in 2004. The result included a 1.7 billion leu (US$411.1 million) loss in the fourth quarter, down on the 307 million leu (US$75.2 million) loss recorded in the same period last year. OMV Petrom’s upstream segment recorded a 1.82 billion leu (US$448.07 million) EBIT for the full year, compared with a 3.93 billion leu (US$967.53 million) earnings gain posted in 2014. Petrom’s downstream unit swung to a positive EBIT of 1.01 billion leu (US$248.7 million) for the year, from an 897 million leu (US$220.8 million) earnings loss in 2014. Downstream benefited from lower crude input costs and higher gasoline spreads in the quarter, with retail sales volumes up by 7% year on year because of higher demand. The slump saw OMV Petrom cut costs of production to US$13.16 per barrel of oil equivalent, 24% lower than the US$17.27 per boe spent in 2014. OMV Petrom said the improvement was down to structural adjustments and favourable foreign exchange rates.

OMV Petrom’s total output fell by 3% year on year during the third quarter to 15.97 million boe, with fullyear production totalling 65.19 million boe. OMV Petrom sliced 37.5% from its capital expenditure bill in 2015, spending 3.89 billion leu (US$958 million) in total while saving 35% on upstream activities through the “prioritisation of investments”. The firm reportedly closed 350 onshore oil wells last year, and said it could shut that number again in 2016 in response to low crude prices. OMV Petrom’s upstream director Gabriel Selischi last week told Economica.net the firm would reduce oil output in Romania by 4% in 2016. The company is understood to be considering closures at 1,000 of the company’s 7,500 Romanian wells if oil prices fail to cover their production costs. In the downstream segment, OMV Petrom spent 393 million leu (US$96.7 million) on capital commitments, around half of the 794 million leu (US$195.5 million) invested in 2014. Most of this spending was directed towards upgrades, including the 18 million euro (US$19.8 million) overhaul of the Cluj fuel terminal.n

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Week 4• 29 February • 2016

Norwegian central bank governor anticipates further pain EUROPE THE head of Norges Bank has warned that Norway will again need to dip in to its sovereign wealth fund, as economic growth continues to be hampered by low oil prices. In his annual speech in Oslo last week, Oeystein Olsen said that the depressed cost of crude on the international market “will reduce Norway’s national wealth”, and that more than US$9 billion would be taken from the fund this year, which “may be close to its peak”. “We have always known that the long oil-driven expansion would come to an end. We have now reached that juncture,” he continued. “The Norwegian economy has enjoyed an exceptionally long summer. Winter is coming.” In October Norway’s government announced it would withdraw cash from its US$850 billion reserve for the first time in order to meet planned spending and provide stimulus through tax cuts in its latest budget.

However, the amount removed was just 3.7 billion kroner (US$436 million) – well within the 4% limit on predicted return that Oslo’s spending rules allow. This latest drawing of funds would represent the first net withdrawal in the fund’s history. These, Olsen continued, will be used “to finance temporary measures that are easy to reverse”, although no further details of these were provided. Meanwhile, Norway’s leadership is also considering a revision of the fund’s investment criteria, which currently target roughly 60% in equities, 35% in fixed income and 5% in real estate, with the latter increased to up to 15%. “We are also prepared to invest in foreign infrastructure,” Olsen said. “The return on real estate and infrastructure tends to follow a slightly different pattern than the return on equities and bonds. Investing in these asset classes is therefore expected to improve the fund’s risk-return trade-off.”n

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Seven lines up equity backing for Nigerian gas plans AFRICA

TRANSOCEAN has received notice of Vaalco Energy’s decision to terminate work early, adding to the drilling company’s difficulties. The GSF Constellation II was under contract to US-listed Vaalco for work in Gabon, Transocean said on February 11. Seven Energy has secured US$100 million of fresh equity capital to finance its pipeline project in Nigeria and increase gas supplies to the domestic market, it announced last week. The cash is made up of US$50 million from existing shareholders including Temasek, Petrofac, Capital International Private Equity, Standard Chartered, International Finance Corp. (IFC) and the IFC African, Latin American and Caribbean Fund by way of an open offer. It also includes a US$50 million investment from the

Islamic Development Bank’s IDB Infrastructure Fund II. “I am pleased by the continued support shown by our leading shareholders and the vote of confidence in our business plan demonstrated by the investment from the IDB Infrastructure Fund II,” Seven Energy’s CEO, Phillip Ihenacho, said in a statement. “This new funding enables us to complete our current development phase, enhancing our pipeline network”, which will be capable of transporting 600 million cubic feet (16.99 million cubic metres) per day of gas to the regional market. Over the next few months, the company intends to complete a gas pipeline, integrating its existing links within southeast Nigeria. On completion of the project, it will have a gas transportation network running from Ukanafun and Ikot Abasi, in the west, to Calabar in the

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east. The company’s gas deliveries more than trebled last year and are currently running at more than 110 mmcf (3.1 mcm) per day. It predicts that deliveries will increase further, to 200 mmcf (5.66 mcm) per day over the coming year, as the three power stations it supplies – Alaoji, Calabar and Ibom – compete their commissioning work and electricity transmission infrastructure.

Seven also supplies a cement plant and a fertiliser factory in Nigeria. It has invested more than US$1 billion in gas production, processing and distribution infrastructure. The new capital injection will also see Stephen Vineburg, the CEO of ASMA Capital Partners, which manages the IDB Infrastructure Fund II, join Seven’s board of directors.n

Eland continues on low-cost workovers AFRICA

NIGERIA-FOCUSED Eland Oil & Gas hopes to repeat the success of its low cost workover at the Opuama field, in Oil Mining Licence (OML) 40, aiming to double production at Opuama-3. In an operational update of February 16, the Londonlisted junior said it was placing “renewed focus on lowcost workover potential in the licence” this year, having increased production by more than 50% – to 4,500 barrels per day– at Opuama-1 during the fourth quarter of 2015. Eland said it had only drawn US$15 million of a US$35 million committed facility in 2015. Its shortterm focus is on what it described as “highly accretive workovers”, in order that this year’s capital expenditure requirements “remain modest”. Although Eland’s joint venture company, Elcrest Exploration and Production Nigeria, is to be formally appointed as operator, the statement said its “ability to substantially boost production via workover operations” was extremely encouraging. Outlining Eland’s plans, the company’s CEO, George Maxwell, said a low-cost, high-production workover of

both strings at Opuama-3 would start within the next two months. This is expected to increase the well’s output by 50-100%, to 2,000-4,000 bpd gross. Having completed detailed technical work, including interference testing this January, Eland intends to start production from the undeveloped D1000 Upper and D2000 reservoirs using a directional perforating system. This year also offers potential to re-enter, complete and start production at the Gbetiokun-1 well, the statement added, noting that neither workover project was expected to use a drill rig. Additional workover opportunities at the licence would also be considered, the statement said. “It is most welcome that we have seen a material and sustainable increase in production from this initiative. With further workovers planned, we have a number of options to continue these production increases prior to commencement of the development drilling campaign,” Maxwell said. In line with much of the industry, Eland is working to cut costs. The company said operating costs should be reduced by 30% by the end of this quarter.n

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Under pressure, Petroceltic begins Algeria drilling AFRICA INCREASED production has hit LNG pricing over the last 24 months but competition is also having a broader impact. LNG supply has traditionally been governed by long-term supply contracts, often spanning 10 or 20 years. These have provided predictability and security of supply to both buyers and sellers. Attitudes to these deals are Ireland’s struggling Petroceltic International has begun development drilling at its Ain Tsila field, in Algeria, even while financial pressure continues. The company, on February 22, said it had begun drilling the AT-10 the day before. This first well on the development programme is being drilled by Sinopec Rig 50117, which arrived at the Isarene permit in November. It was assembled on site and passed acceptance testing. The company had hoped to begin drilling in the last quarter of 2015. The well is in the north of the gas and condensate field, around 3.4 km from the AT-1 well, which discovered Ain Tsila, and 2 km from the AT-8 appraisal well. Both of these previous wells flowed at more than 30 million cubic feet (850,000 cubic metres) per day during tests. The AT-10 is a vertical well, targeting the Ordovician reservoir with a planned depth of 1,989 metres. This is the first of 24 wells that are to be drilled on Ain Tsila, in order to meet the targeted production of 355 mmcf (10.1 million cubic metres) per day of wet gas. Petroceltic also said the engineering, procurement and construction (EPC) tender for the main field facilities and pipelines was “progressing”. The company has a 38.25% stake in the Isarene licence, while Sonatrach has 43.38% and Enel has 18.38%. Some of Petroceltic’s development costs are carried under its deal with Sonatrach, which dates from July 2014. “We are delighted to start development drilling on Ain Tsila and look forward to building on the success of earlier wells in the highly productive northern part of the field,” said Petroceltic’s CEO, Brian O’Cathain. “Ain Tsila is a world-class asset and the main focus of our business. We are collaborating with our partners on a number of opportunities to reduce overall development risk and enhance long-term field recovery and value, and these will be progressed in parallel with the EPC award process.”

Ain Tsila holds an estimated 2.1 trillion cubic feet of gas (59.46 billion cubic metres). “Obviously it’s our flagship activity, so I think in this current oil climate it makes sense to focus on that,” a Petroceltic representative, Molly Stewart, told Energy Finance Week. Financing hurdles Petroceltic is facing challenges in terms of finding the funds needed to cover its share of Ain Tsila’s costs. The deal from 2014 provides for Sonatrach contributing up to US$180 million. This includes a US$20 million payment on completion and a carry of US$140 million on project costs. The remainder is a contingent payment based on project targets. Edison Investment Research has previously estimated that Petroceltic would require around US$580 million of debt financing between 2016 and 2018 to develop Ain Tsila and reach first gas. The company has been taking steps to tackle this shortfall, but the challenge remains. Last week, Petroceltic said it had finalised the sale of three Egyptian exploration interests to its partner, Edison International, for US$9.5 million of cash. The Dublin-based firm expects to record a loss of around US$1.5 million on the divestments. Edison will assume full control at two offshore licences, North Thekah and North Port Fouad, and the onshore South Idku, all of which are located in the Nile Delta region. Petroceltic owned a 75% operated stake at South Idku and 50% at Edison-operated North Thekah and North Port Fouad. Petroceltic believes the sale will save US$20 million earmarked for exploration this year. It plans to use the proceeds to repay its considerable debt load. In December, the company said the amount outstanding under its senior bank facility was US$217.8 million. At that point it had cash of US$28.1 million, although US$24.6 million of this was in local currencies and “not readily convertible”. As a result, it warned, it faced liquidity problems beyond January of this year. As such, it began a strategic review, potentially including a sale. One potential suitor may be its activist shareholder, Worldview Capital Management. As of February 22, Petroceltic said its lenders had agreed to a further waiver of debts until March 4.n

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Egypt plans to cut electricity subsidy AFRICA THE Egyptian Ministry of Electricity and Renewable Energy announced last week that it would cut subsidies for electricity by 50% by 2020 and aim to abolish them entirely by 2025. The government has prepared a long-term strategy to invest US$135.3 billion in the power sector by 2035, raising generating capacity to 51,000 MW. The ministry said a study carried out by international consulting firm SOFRECO had determined Egypt’s energy needs for different purposes in the years ahead. The government began to take steps to reduce electricity subsidies two years ago, increasing retail tariffs by 10-15% in July 2014. That step was carried out as part of a five-year plan to end subsidies, which currently cost the government US$3.59 billion per year. The plan calls for subsidies to fall to US$2.65 billion in the next fiscal year. The government aims to build more coal-fired thermal

power plants (TPPs) and develop nuclear capacity in order to meet the expansion target. The Electric Utility and Consumer Protection Regulatory Agency has also carried out a study on how Egypt generates its power. The agency said natural gas fired 58.8% of capacity, while diesel accounted for 32.5%. Wind and solar provided 1.1%, while 7.5% came from hydro. Egypt is intending for much of the investment in the electricity sector to come from the private sector. The country is planning to open tenders soon for power generation, transmission and distribution projects. Last November, Egypt opened a huge wind farm with 100 turbines and 200 MW of capacity at a cost of US$359 million. Egypt is also in talks with Russia’s Rosatom to build a nuclear power plant (NPP) in Dabaa, the country’s first. The plant will generate 4,800 MW from four 1,200-MW reactors. n

Algeria’s Sonelgaz to borrow on global markets AFRICA ALGERIAN state power company Sonelgaz aims to enter international lending markets as it tries to plug a huge budget shortfall. Sonelgaz CEO Noureddine Bouterfa said the company urgently needed to address a financing gap of 1.1 trillion dinars (US$10.3 billion) its investment programme until 2018, the APS state news agency reported on February 16. Sonelgaz is suffering from the plunge in world oil prices, forcing the parastatal firm to resort to foreign loans for the first time in decades, Bouterfa said. “Our problem in the short term is to find a solution to a gap of 1.1 trillion dinars. This is an urgent issue and ... this is why we plan to go to the international market,” Bouterfa told reporters on February 15, APS reported. The Algerian government cut budget spending by 9% in 2016, following a previous cut in 2015 as energy revenues fell. Energy earnings plunged by around 50% in 2015,

forcing the state to raise certain subsidised fuel prices and freeze major projects. Sonelgaz has raised some subsidised gas and electricity tariffs in 2016 as part of plans to finance investment in generation and transmission even the current fiscal environment. Bouterfa said that the recent rise in electricity and gas prices, applicable from 2016, would only generate 25 billion dinars (US$235 million) per year, while a planned domestic bond issue could only raise 30 billion dinars (US$282 million). Consequently, Sonelgaz has to find 1.1 trillion dinars to finance its investment programmes, he said. In the past decade Sonelgaz has built an additional 8,700 MW of generating capacity, increasing total output by 123%. It has also extended the power transmission grid by 59%, the gas transmission network by 168% and the gas distribution network by 152%.n

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Asian rig builders batten down the hatches ASIA RIG builders across Asia have seen their sales nosedive over the past 18 months as a roughly 70% slide in oil prices takes its toll on the entire energy value chain. Yards in Singapore and South Korea, in particular, are suffering as their order books shrink and profits plunge. This could present an opportunity for Chinese rivals to win market share. Singapore’s Sembcorp Marine and Keppel have in recent years come to dominate the global market for jack-up rigs but are both now feeling the pain of lower oil prices. “The year 2015 has turned out to be one of the toughest in recent history, with billions of dollars’ worth of oil and gas exploration projects being curtailed globally,” according to Sembcorp CEO Wong Weng Sun. “The resulting contagion effect on the entire [exploration and production] value chain has been swift and severe. Offshore and marine engineering yards around the world are faced, not just with the lack of new projects to replenish their order books, but also deferment or cancellation of some of their existing rig deliveries.” Tough times Sembcorp tumbled into the red in 2015, it announced earlier this month, booking a net loss of S$290 million (US$206.3 million) compared with a year-ago profit of S$560 million (US$398.5 million). It supplied just one jack-up rig during the year, down from eight in 2014, and warned that it expected the downturn in Singapore’s US$10 billion rig industry to last longer than in previous cycles. Keppel delivered only seven jack-up rigs last year, down from the 15 it had originally anticipated, as a number of its customers requested delayed delivery. Temasek Holdings, the biggest shareholder in both Keppel and Sembcorp, is pessimistic, with an unnamed official telling Singapore’s Straits Times last month that it expected the industry to remain weak for the next three years. It is considering pushing the two companies to divest non-core assets or sell shares through rights offerings, the official said. The market is just as tough in South Korea. Hyundai Heavy Industries (HHI), Samsung Heavy

Industries (SHI) and Daewoo Shipbuilding & Marine Engineering (DSME) all saw their orders for offshore oil infrastructure including rigs shrink in 2015. Daewoo was hit the hardest, with its orders plunging to US$4.5 billion in 2015, down from US$14.9 billion the previous year. HHI failed to secure a single new order for offshore oil rigs and production facilities last year, as oil companies cancelled orders or requested delayed delivery. The scale of the problem was underlined by the company’s announcement in January that it would temporarily close its Onsan factory – one of two that makes offshore rigs – owing to a lack of orders. Chinese yards, meanwhile, appear poised to win business from South Korean and Singaporean rivals at a time when the latter have already cut costs as low as they can feasibly go. Consolidation A hotly anticipated merger between the offshore engineering businesses of China International Marine Containers (CIMC) and China Merchants Heavy Industry (CMHI) would create a new company with a broader product offering that would position it well to compete for international projects, according to DBS. Currently, CIMC focuses on deepwater semi-sub rigs, while CMHI focuses on jack-up rigs. Although this could force Keppel and Sembcorp into each other’s arms, a mega-merger of the two Singaporean firms could have disastrous consequences on their smaller suppliers, some of whom would be bumped off the combined group’s list of approved vendors, OCBC Investment Research has cautioned. Regardless of whether Chinese yards manage to win a bigger slice of the pie for offshore rigs, however, the pie itself is unlikely to expand for several years. Oil majors are unlikely to start placing new orders until oil prices rebound to around US$60 per barrel. But even then it is unlikely that there will be an immediate bounce back in order volume, given that upstream players will surely want repair their balance sheets, and appease shareholders, before embarking on any major new projects. Consolidation may be the industry’s only option in the years to come.n

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Origin cuts dividend after posting second-half loss ASIA THE Australia-based Origin Energy has cut its interim dividend after posting a A$254 million (US$183.5 million) net loss in the second half of 2015, down from a A$25 million (US$18 million) loss recorded a year ago. Origin will pay investors A$0.10 per share (US$0.07), less than half of the A$0.25 (US$0.18) a share paid to shareholders last year. CEO Gordon Cairns warned on February 18 that shareholders might have to forego their dividend altogether if low oil prices persist this year. Origin conceded A$282 million (US$203.7 million) in impairments during the period, with A$55 million (US$39.7 million) of that total owed to restructuring costs. Cairns pointed to A$5.5 billion (US$3.97 billion) in debt reduction, which helped the company reduce its net debt by 21% year on year to A$9.3 billion (US$6.72 billion). There was good news from the firm’s Energy Markets division, which managed to grow underlying earnings before interest, taxes, depreciation and amortization (EBITDA) by 16% year on year to A$721 million (US$520.1 million). Origin’s balance sheet has been stretched by investment at the A$25 billion APLNG project in Queensland, Australia, which shipped its first cargoes to Asian customers in January. The firm undertook an A$2.5 billion (US$1.8 billion)

equity raising in October 2015, and wants to shed A$800 million (US$578 million) of non-core assets this year. Origin aims to bring debt under A$9 billion (US$6.5 billion) by the next financial year. Excluding Australia Pacific LNG (APLNG), Origin anticipates underlying EBITDA for the current financial year, ending June 30, to range between A$1.45-1.55 billion (US$1.04-1.12 billion). The guidance suggests this would increase to A$1.92.1 billion (US$1.37-1.52 billion) in the financial year ending June 30, 2017. APLNG is anticipated to contribute between A$30-80 million (US$2.16-5.78 million) in the current financial year, rising to between A$650-750 million (US$470-542 million) in 2017. Moody’s Investors Service on February 18 announced that Origin’s BAA3 investment grade remained under review following the results. Moody’s vice president, Spencer Ng, said Origin’s underlying EBITDA from continuing operations was down 5% year on year when accounting for the NZ$1.8 billion sale (US$1.2 billion) of Contact Energy in August 2015. The service warned that Origin’s financial metrics had been damaged by the costs of “risk management services” such as an oil put established for APLNG in December 2015 to guard against low oil prices.n

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Santos books heavy impairment charges ASIA AUSTRALIA’S Santos has sank deeper into the red after writing further value off its assets as oil prices remain low. Its net loss swelled to A$2.7 billion (US$1.93 billion) last year, from A$935 million (US$668 million) in 2014. The Adelaide-based producer blamed this on A$2.8 billion (US$2 billion) in impairment charges largely linked to its gas operations in the Cooper and Gunnedah Basins, as well as its Gladstone LNG (GLNG) assets. This compares with A$1.5 billion (US$1 billion) of charges which the firm booked in 2014. Its overall performance also weakened. Underlying profit was down 91% year on year to A$50 million (US$35.7 million). This was on the back of a 20% slide in revenues to A$3.2 billion (US$2.3 billion), as the company’s average selling price per barrel of oil equivalent fell 48% to US$54. This more than offset a 10% drop in production costs per barrel to A$14.40 (US$10.30) and a 54% cut in capital spending to A$1.7 billion (US$1.2 billion) during the year. The company also abandoned its policy of maintaining or increasing dividend payouts, announcing it would slash dividends from 15% to 5% per share. “My priority now is to assess our operations and put in place the right strategy to ensure that Santos is sustainable in a low oil price environment,” said Kevin Gallagher, who

took over as Santos’ CEO this month. In January, Standard and Poor’s downgraded Santos’ credit rating from BBB to BBB-, on account of its debt, which totalled A$6.5 billion (US$4.65 billion) at end of 2015. The company has borrowed heavily in recent years to establish itself as major regional gas supplier. Despite the poor results, Santos chairman Peter Coates reassured investors in a conference call that the firm was not considering further asset sales. In November 2015, Santos sold its stake in the Kipper gas field in southeast Australia to a unit of Japan’s Mitsui for A$520 million (US$372 million). It also raised cash by issuing new shares. Coates said Santos’ debt was not anticipated to rise this year, adding it had access to A$4.8 billion (US$3.43 billion) in cash and undrawn debt facilities. Santos’ breakeven point for operations had been cut to US$32 per barrel, he said. The company also reported a 7% rise in average yields to 158,000 boe per day in 2015, its highest output level in seven years. This was largely thanks to the fullyear production from its PNG LNG in Papua New Guinea (PNG) and the GLNG coming on stream in October 2015. The company said it would cut capital spending to A$1.1 billion (US$786 million) this year while retaining its production target of 156,000-173,000 boepd.n

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Southeast Asia is destinationin-waiting for green investors ASIA SINCE the lifting of sanctions on January16, Iran has been vocal about its plans to make the Euro the priority currency both for the payment of the vast sums still owed it by buyers of oil accrued over the sanctions era and for all new crude oil sales. This policy is in line with its previous efforts to undermine the US dollar as the principal pricing currency for oil transactions. Southeast Asian pension funds are increasingly attracted to renewable energy investments as carbonintensive fossil fuel-fired projects pose greater reputational risks, according to Singapore’s Asia Green Capital. Opportunities are growing across Asia-Pacific, with Indonesia emerging as the major investment destinationin-waiting, Capital’s chief executive Edgare Kerkwijk said in a recent interview. As a result, he added, renewable energy is becoming a mainstream investment commodity. “In Southeast Asia we see a number of pension funds with a very strong mandate to invest in renewables. Many of these firms had to divest from coal and traditional fossil fuels,” Kerkwijk noted during an interview with CNBC television. China will remain the biggest market for wind and solar, especially the growth area of offshore wind projects. Yet Indonesia will attract a lot of foreign investment too, largely as a result of the government’s mandate to ensure 25% of its 25,000-MW expansion programme comes from renewables. Asia Green Capital is already investing in two wind farms in Indonesia, with a total generating capacity of 182 MW. It expects to make further investments in the region, though the company could not provide any more information. The Jeneponto 1 and 2 wind projects near Makassar on Sulawesi Island will have a total 162 MW of capacity, while a smaller project in West Timor will have 20 MW capacity. The former is backed by equity and loans from the International Finance Corporation (IFC), as well as loans from the Asian Development Bank (ADB),

Denmark’s EKF and others. Financial close for the first phase of Jeneponto is due during Q1 2016, with construction scheduled to begin in May. According to Asia Green’s last update, the project is “currently under advanced development with ongoing community consultation and environmental assessments.” Its subsidiary, Indo Wind Power Holdings, will build the farm. Kerkwijk also said that more regulatory stability was needed in the Southeast Asian renewable energy market. NewsBase agrees that if more long-term investors such as pension funds are to join the market, greater certainty can be no bad thing. Kerkwijk’s optimism contrasts with a recent note from business risk assessor Verisk-Maplecroft. The firm told investors that acquisition of renewable energy assets was “not a panacea for the operational and financial setbacks that financial institutions have incurred due to the human rights impacts of fossil fuels.” In a study of the renewables market, the firm said that social and environmental issues associated with renewable energy projects – especially land rights – meant that the human rights risks associated with green energy project finance would continue. Indeed, Indonesia has had its own issues with hydropower plants (HPPs), biofuels production and other power projects in protected areas, Other forms of generation may cause problems for investors and local communities. “In states or regions where land tenure is disputed or poorly enforced, those who invest in solar and wind projects may be at significant risk of litigation or social unrest,” Verisk-Maplecroft added. With that in mind, it suggests that green energy companies look to the precedents set by responsible operators in industries such as mining, oil and gas, and forestry in order to demonstrate best practices and mitigate risk.n

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Rosneft raises stake in Petromonagas JV with PDVSA FSU RUSSIA’S Rosneft has arranged to take a larger stake in its Petromonagas joint venture with Venezuela’s PDVSA. In a statement dated February 22, governmentcontrolled Rosneft said it had signed documents outlining the “indicative terms and conditions” of the deal with PDVSA. Under this deal, the Russian firm will increase its share in the venture, which is already producing oil, from 16.67% to 40%. The Venezuelan state company, meanwhile, will see its holdings drop from 83.33% to 60%. The value of this transaction has not been revealed. Rosneft said in its statement, though, that the new agreement would serve as a continuation of a memorandum of co-operation signed between the two companies in June 2015. Petromonagas is developing a section of the Orinoco Belt. Its shareholders are working together to extract extraheavy oil from the contract area and are also operating an upgrader unit that converts the crude into a synthetic product that can be exported and processed in refineries. The joint venture is currently extracting about

130,000 barrels per day of extra-heavy crude from its section of the Orinoco Belt. Rosneft called it “one of the most prolific partnerships in Venezuela” and said it hoped to work with PDVSA to increase production by “introducing state-of-the-art technologies and raising E&P management efficiency.” The Russian company is also working with its Venezuelan counterpart to develop four other licence areas. It owns minority stakes in the PetroVictoria, PetroMiranda, PetroPerija and Boqueron joint ventures, which control reserves of more than 125 billion barrels of oil in place (OIP). Additionally, it has purchased refined petroleum products from PDVSA. Rosneft has said it wants to expand co-operation with the Venezuelan company. In a statement dated February 20, it reported that it had signed a heads of agreement (HoA) with PDVSA on the creation of a joint venture to extract natural gas from the Mejillones and Patao offshore fields. The venture may also develop Rio Caribe, another Venezuelan site, it added.n

Russia wants premium price for controlling stake in Bashneft FSU MOSCOW will reportedly only relinquish a controlling stake in Bashneft if the prospective buyer offers a high enough premium on market prices. A source quoted by Reuters on February 18 suggested Moscow was considering the sale of either a 25%, 50% or 75% stake in the mid-sized oil producer, depending on the offered price. “We need to see how much money we can get for the premium which goes along with having control or full control,” the source said. Moscow owns 75% interest in Bashneft, while Russia’s Republic of Bashkortostan holds the remaining 25%. Bashkortostan premier Rustem Khamitov has confirmed his government will not sell its stake. So far, LUKoil is the only firm to have publically marked its interest in buying a share in Bashneft. The independent producer said last week it would consider purchasing a controlling stake in the firm but had not yet made a formal proposal to the government.

Moscow renationalised Bashneft in December 2014, and has since been reluctant to offload its stake until market conditions improve. Unlike state-run Rosneft, LUKoil has enough cash to afford the purchase. As of September 2015, its cash balance was recorded at around US$4 billion, with total current liabilities of US$10.2 billion. This is a reasonably healthy position given that the company also registered US$7.17 billion in net receivable accounts and US$6 billion from the value of its inventories. Rosneft, which is also awaiting partial privatisation, has said it is not interested in taking a share in Bashneft. LUKoil apparently has the blessing of Russia’s Federal Antimonopoly Service (FAS) chief Igor Artemyev, who last week said that a LUKoil bid was likely to be approved because the firm held less than 10% of the market. LUKoil is already partnered with Bashneft at the Trebs and Titov oilfields in the Timan-Pechora Basin, and

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provides more crude to Bashneft’s refineries than any other supplier. Bashneft holds 2.15 billion barrels in total proven reserves, and buying a stake in the company could protect LUKoil’s portfolio against declining Russian output levels. LUKoil vice president Leonid Fedun warned last month his company was unlikely to sustain output this year at the record level of 2 million bpd which it recorded in 2015. By insisting on a premium price, Moscow could risk

deterring would-be investors such as LUKoil from buying into Bashneft. The latter is worth around US$4.5 billion, just over a third of the US$13 billion it was valued at before the collapse in oil prices. LUKoil has other reserve-boosting opportunities available internationally, having reportedly closed a US$6 million deal with the National Iranian Oil Company (NIOC) last month to develop two Iranian deposits.n

Bashneft’s assets

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Week 4• 29 February • 2016

Petrobras rescue operation under consideration

A debt-for-equity plan could be one way for the embattled state-run company to tackle its debt pile LATIN AMERICA THERE are growing signs coming out of Brazil that some sort of official rescue operation will be mounted for Petrobras. This week Reuters ran a story saying Brazilian state banks were considering converting part or all of their considerable loans to Petrobras into equity. The report, citing two sources familiar with the plan, said state banks BNDES, Banco do Brasil and Caixa Economica Federal were analysing the debt-to-equity move that would be a further hammer blow to the company’s already battered minority shareholders. Banco do Brasil has lent Petrobras US$6.5 billion. Meanwhile, Caixa has stumped up US$2.75 billion, while BNDES has lent US$12.5 billion to the company and its subsidiaries, according to Brazilian media. An unnamed BNDES executive said the bank would seek to convert debt into equity and then sell the shares at a later date when Petrobras’ share price recovers. The state-run oil company’s debt is currently around US$135 billion. The plan, which a government official confirmed was being studied, follows January’s admission by Brazilian President Dilma Rousseff that her administration was looking at ways of injecting capital into the troubled company. BNDES, Banco do Brasil and Caixa Economica Federal are all tightly controlled by Brazil’s federal government and were central to Rousseff’s failed countercyclical economic policy of pumping cheap credit into the economy during her first term. The policy ended in a crushing recession, falling output and rising debt. The first bank to suggest the debt-to-equity plan was BTG Pactual which, though private, has worked closely with Petrobras in recent decades. Its former president is under house arrest for his alleged role in trying to obstruct the Car Wash investigation into corruption in Petrobras. BTG Pactual has around US$22 billion worth of loans to Petrobras. Though financial analysts all say that a potential debt swap is contractually possible for loans made by BNDES, Caixa Economica Federal and Banco do Brasil, the latter has reacted to the report by saying that it is not considering the move. A debt-to-equity swap would help Petrobras ease

its debt burden, which the markets fear is becoming increasingly tricky to manage owing to the collapse in the oil price, the rout of the Brazilian real in which Petrobras receives most of its receipts and a series of downgrades. Figures released last week by the country’s energy regulator showed that the profitability of Brazil’s larger oilfields fell by half last year because of the drop in the international price of oil. The use of state banks would allow the federal government to bail out the company without further compromising its own precarious fiscal situation. A deficit at 10% of GDP with no viable plan on the horizon to plug the gap and a further downgrade last week deeper into junk territory have left many wondering if the government is even in a position to rescue Petrobras without further aggravating its own precarious position. In its most recent downgrade Standard and Poor’s (S&P) mentioned the difficulties at Petrobras as one of the factors weighing on its latest decision to cut the country further into junk territory, underlying how the crisis in Petrobras is causing wider problems in the economy. But it would be another blow to minority shareholders, many of whom are now suing the company in the US for misleading them. This probably explains the mixed signals coming out of Petrobras itself. Speaking off the record to local media about the debt-for-equity plan, some denied the operation was being mooted, while others confirmed discussions were already in train. The operation would also be politically delicate, as Petrobras is a popular shareholding for small Brazilian investors and a backbone of pension plans and the country’s workers unemployment fund as administered by Caixa Economica Federal. A further dilution of shareholder value to follow the oil-for-equity operation in 2010 would be politically unpopular and underscore the scale of mismanagement overseen within Petrobras by Rousseff. The operation could also risk the balance sheets of Brazil’s state banks, which have also been downgraded in recent months because of their exposure to the country’s rapidly contracting economy. But it would be a boon for private investors, who would see the company’s debt reduced, and increase its immediate capacity to service its remaining debts.

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Remedial steps Whether it proceeds or not, the debt-to-equity rumours underline that the crisis in Petrobras is forcing Brazilian authorities to consider severe remedial action. Further proof of this came with signs that the government might abandon its requirement that Petrobras be operator and majority stakeholder in the country’s deepwater pre-salt projects. Brazil’s Senate is itching to take advantage of Rousseff’s weakness to strip the company of its pre-salt monopoly, which has been deemed a strategic error that

has deterred investment by international oil companies (IOCs). In a signal of his own support for a change, Petrobras’ president Aldemir Bendine said last week that the company did not have the resources to participate in any future auction rounds in Brazil. He said that retaining the monopoly would potentially lock billions of barrels of crude in the pre-salt deep under the South Atlantic. With the country desperate to raise new funds and somehow spark its economy into life, it was another veiled vote in favour of having the monopoly lifted.n

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Kuwait’s Equate highlights Emirate’s new-found commercial approach MIDDLE EAST THERE has been stark contrast in the recent Middle East ratings actions of the ‘Big Two’ agencies – Standard & Poor’s (S&P) and Moody’s – with Kuwait coming out best of the lower Gulf states. Saudi Arabia’s long-term foreign currency rating was spectacularly cut by two notches (to A- from A+), Bahrain lost its coveted investment grade status, and Oman cut to the last rating above junk status, whilst Kuwait’s was affirmed at AA with a stable outlook. As highlighted in Energy Finance Week Week 01, Kuwait’s approach can be broadly characterised as taking a more focused approach to navigating a sustainable way through the current oil crisis, and a key part of this involves adopting a more global commercial view of operations, exemplified in its first international joint venture (JV) firm in the value-added petrochemicals sector, Equate Petrochemical Co. Equate’s last fiscal year, ending on December 31 2015, saw net profit drop to US$709 million from US$1.04 million in 2014, as a result of the low oil price environment. The firm’s president and CEO, Mohammad Husain, highlighted that the per-tonne budget forecast for its products was an average of nearly US$960 for the year, whilst the actual global market price finally came in at an average of around US$870 over the period. But in response to an evidently deteriorating price pattern, the firm has proactively sought to mitigate against this effect recurring with the late-2015 purchase of international petchems firm, MEGlobal, from Dow Chemical Co. and Petrochemical Industries Co. (PIC) – part of Kuwait Petroleum Corp. (KPC) – for US$3.2 billion. “It was a great move to push Kuwait’s petchems business straight into a real competitive international environment, rather than the sort of state-run stagnation that we see with a lot of these operations, especially in the Middle East, and the price itself looked exceptionally good, given the opportunities for expansion that it brings, presumably because of the leverage that Kuwait has with Dow,” Sam Barden, CEO of energy consultancy and trading firm SBI Markets, told NewsBase. Branching out The firm already contributes nearly 60% of all Kuwait’s non-oil exports, in line with the country’s economic strategy of diversification. Its recent purchase of MEGlobal will not only compel it to upgrade its

management structures, financial operations, and accounting procedures, in line with the norms of Western hydrocarbons operations, but will also allow it to more easily create and capitalise on value-added sectors across the globe. “Importantly as well, there are now significant economies of scale available to it with a larger and more diversified distribution platform through Kuwait, Germany, Canada and the US, and in this latter regard particularly MEGlobal has provided Equate with a major growth opportunity through a new world-scale project in the US Gulf Coast utilising advantaged shale gas feedstock,” he said. More specifically, MEGlobal is to build a monoethylene glycol plant on the US Gulf Coast, immediately positioning Equate as a global leader in the ethylene glycol (EG) sector in which MEGlobal already has a 12% market share. Prior to the purchase, Equate principally operated an integrated manufacturing facility producing around 5 million tonnes per year of petrochemical products, including polyethylene and ethylene, marketed throughout the Middle East, Asia, Africa and Europe. On the question of bringing capital-raising and debt management into the same competitive standalone environment as other global commercial ventures – in line with recently announced plans by Equate’s parent, KPC, even to selling loss-making assets to cut costs if required – the firm is currently in talks with a range of local and international banks to refinance the US$6 billion bridge loan that it secured last year. This was partly used to fund the MEGlobal deal and to restructure other operations in line with the purchase, and it is expected to mature in December this year (albeit with a six-month extension option beyond that date), Energy Finance Week understands. “The plan is for the funding to be restructured initially in three equal amounts of two billion dollars or so adjusted for interest increases over the periods, and the tenors of each [tranche] will be split between the two and five year points, as it currently stands,” a Middle Eastern industry source said last week. “In terms of the structures, it [Equate] is considering anything from revolving credit facilities to straight term loans from single sources, and even syndicated loans if the terms are better, maybe even some type of bond or equity issue when markets are better, so all the proper options are being thought about,” he added.n

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Turkish groups invest in 510 MW of Balkans renewables MIDDLE EAST TURKEY’S Capital Group is to invest 370 million euros (US$408 million) in 510 MW of new renewables projects in the Balkans, with the aim of exporting up to half the power back to Turkey. The private equity group, established in Turkey three years ago, plans to construct 380 MW of wind capacity and 130 MW of solar capacity in Bosnia-Hezegovina and Maccedonia over the next three and a half years, capable of generating up to 180 GWh a year. Work has already started on a 60-MW solar plant on a single site at Ljubinje in southeast Bosnia-Herzegovina. which when completed will be the largest in the Balkans. Plans are also underway for a further four solar projects in the country, taking capacity up to 100 MW, and at a cost of around 150 million euros (US$165 million), all of which is scheduled to be completed within two years. In addition, Capital is planning to develop 200 MW of wind power here, as 180 MW of wind plant and 30MW of solar plant in Macedonia at a cost of around 120 million euros (US$132 million). Capital reports that it already has all the necessary generation licenses for the planned wind and solar plant and is benefiting from a 15 year tax exemption for foreign investors in both countries. In an unusual move, the company plans for at least 50% of the power generated from these projects to be exported to Turkey, which having been synchronised with the pan European ENTSO-E transmission grid since September 2010, is able to trade power with neighbouring and regional countries. As such, it will also be eligible for support from Turkey’s Eximbank. That may come in useful during the EPC and development phases. Capital plans to source most of the equipment in Turkey and to manufacture much of the rest via its newly acquired Bosnian subsidiary, the recently privatised Energoinvest. The latter was founded in 1947 as Yugoslavia’s state energy equipment manufacturer and

remains Bosnia’s biggest energy equipment company. The investment group’s plans are just the latest example of Turkish companies looking beyond their borders to countries with more favourable regulatory and taxation systems to make energy investments with the aim of exporting power back to Turkey. To date, eight Turkish companies have invested in developing over 1 GW of hydro power plant in Georgia, taking advantage of a favourable investment and regulatory regime as well as a complimentary power demand cycle which sees Georgia’s electricity demand peak in winter for heating, and Turkey’s in mid summer thanks to the growing use of air-conditioning. Another Turkish company, Guris, had made plans for a 250-MW wind farm in Crimea, which have been on hold since Russia annexed the territory. That said, the halt is not the result of a shortage of demand for power in either Turkey or Crimea, but rather because Russia lacks renewable energy legislation. Turkish investors have now been looking at other regional countries including Azerbaijan and Iran, again with the aim of exporting power back to Turkey. In In part, this interest is cost-focused, given these neighbouring countries offering cheaper labour as well as incentives for foreign investment. But a large driver is Turkey’s difficult regulatory environment. Many companies in Turkey which have been awarded the necessary permits for renewables schemes, are interested only in selling on licensed projects for a profit. Although new licensing procedures have made it more difficult for “secondary marketeers” it has not made it any easier for genuine investors, while at the same time the cancellation of licenses for undeveloped plant can take up to nine years, effectively preventing development of prime wind sites. But while that environment may stall national renewables progress, its demand for power and the availability of Turkish capital offers a win-win proposal for many of the country’s neighbours.n

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AFRICA

expected to be about US$92 million, which is to be fully covered by a yen loan to be paid back over a long period at a low interest rate.

Japanese government to back solar plant in Egypt Ghana advised to put GNPC and TOR on bourse

THE JAPAN NEWS (JAPAN), February 21, 2016

The Japanese government has decided to offer a loan of about 10 billion yen (US$88.82 million) to support construction of a gigantic solar power plant with a largecapacity storage battery system in Egypt. A large-capacity storage battery system is a large-scale recharge and discharge equipment built into the electrical system of a power plant and other facilities. This equipment is seen as essential to ensuring a stable supply of electricity from renewable sources, as weather can greatly affect the amount of power generated. There are several types of equipment, including lithium-ion and sodiumsulphur batteries. Japanese companies such as Sumitomo Electric Industries and NGK Insulators have made progress in technology for high-capacity power storage. Egypt is expected to hold a public tender open only to Japanese companies with advanced battery technology. The government hopes this will give the Japanese firms a leg up in the rapidly expanding renewable energy markets in the Middle East and North Africa. Egyptian President AbdelFattah el-Sissi is scheduled to make his first visit to Japan from February 28 to March 2, during which a written agreement on the project is expected to be signed. According to sources, the plan is to build a 20 MW solar power plant with a 30 MW capacity storage facility in the eastern Egyptian city of Hurghada. The plant is to be completed by 2019 and would supply electricity to about 7,000 households. The total construction cost is

The Ghanaian government has been asked to offload not less than 70% each of the shares in Ghana National Petroleum Corporation (GNPC) and Tema Oil Refinery (TOR) on the Ghana Stock Exchange (GSE) for Ghanaians to buy into these companies. “Offloading the companies on the Ghana Stock Exchange (GSE) will help the management and board of these companies to raise enough money to boost the standard of the companies,” co-chair of Ghana’s Extractive Industry Transparency Initiative (GHEITI) Dr Steve Manteaw said. According to him, this will also save the companies from collapsing. “This will let Ghanaians to become part owners of the companies and make decisions as well. The process will also enhance efficiency,” he added. At a political forum in Accra recently, some political parties were of the view that GNPC should be scrapped off, reason being that the company is not serving the interest of Ghanaians and not performing as well. Others also believed that the GNPC should have the capacity to own it oil blocks if it wants to be a player in the industry. But Dr Manteaw said he is against any decision to scrap off institutions because they are not performing. “I believe that whatever is broken can be fixed,” he added. DAILY EXPRESS (GHANA), February 19, 2016

ASIA

Russia ready to offer Japan majority stakes Moscow is willing to let Japanese investors take significant ownership in major oil and gas ventures, according to Russian Deputy Prime Minister Arkady Dvorkovich. The proposal also applies to “Japanese investors with strategic development plans,” Dvorkovich said. “[Russia has held] very constructive exchanges with Japanese companies [which] creates a good environment for political dialogue,” the Russian deputy prime minister added. According to Dvorkovich, the two countries are still set to sign several agreements to boost bilateral economic co-operation before Russian President Vladimir Putin’s long-awaited visit to Japan could take place. Putin was due to travel to Japan in autumn, 2014, but the crisis in Ukraine and Moscow’s strained relations with the West caused the trip to be postponed. A visit was later planned for 2015, but the two sides never announced a set date. Relations between two countries deteriorated after Tokyo announced support for certain Western economic sanctions against Russia imposed in2014 over an alleged Moscow’s interference in the armed conflict in eastern Ukraine. The Kremlin has repeatedly denied the claims. NIKKEI (JAPAN), February 22, 2016

China likely to invest in Pakistan renewable sector Pakistan expects US$1 billion investment in its renewable energy sector this year with about half of it likely to come from China. Director of Pakistan’s Alternative Energy Development Board Syed

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Aqeel Hussain Jafri recently stated that China is expected to invest around US$500 million to develop renewable energy projects in Pakistan. China will make the investments through the China-Pakistan Economic Corridor, a US$45 billion agreement between the two countries to build infrastructure projects in the latter. According to Jafri, Pakistan targets 800 MW renewable energy capacity addition this year, apart from hydropower capacity. This is around double the renewable energy capacity currently operational in Pakistan.

two more hydro projects in Mindanao that “will be rolled out in the next couple of years”. For solar, AREC is looking at developing 20 MW to 30 MW of capacity for US$40-45 million. “The solar projects will be in General Santos,” Nocos added. ACR, which is expected to contribute 600 MW of capacity to Mindanao, is shifting its focus to RE. BUSINESS MIRROR (PHILIPPINES), February 23, 2016

AUSTRALASIA

prices flowing through to a steep reduction in earnings. While Santos and Origin have raised big lumps of equity, carved into planned investment, slashed costs and sold assets, the big question mark over their future prospects and stability is the future course of oil prices. Woodside, with a far more mature portfolio of assets and relatively low debt levels, is in a stronger position to ride through whatever the next few years might bring. BUSINESS SPECTATOR (AUSTRALIA), February 19, 2016

Australian gas batten down Alsons allots US$650 producers Trafigura sees profit million for Philippine the hatches in WTI oil arbitrage to hydro, solar projects European refiners CLEAN TECHNICA (US), February 23, 2016

Alson Renewable Energy Corp (AREC), a subsidiary of Alsons Consolidated Resources (ACR), is earmarking US$650 million to pursue investments in hydro and solar projects, with a total generating capacity of 205 MW. “Alsons has a clear strategy for developing RE [renewable energy], starting with hydro,” Alsons vice-president for business development Joseph Nocos said. He said investments in hydropower projects will amount to US$600 million. “We have 80-MW to 90-MW hydroservice contracts under application with the DoE [Department of Energy], which we expect the DoE to decide on within the year. If all of those are approved, then we will end up with a total hydro portfolio of 180 MW, which we hope to implement in the next five years,” Nocos said. AREC is set to construct this year a 15 MW run-of- river hydroelectric plant along Siguil River in Maasim, Sarangani. Nocos said this will be followed by a 40 MW hydropower project in Negros Occidental, and

EUROPE

Amid heightened uncertainty about the future shape of energy markets, Australia’s oil and gas majors are focusing on the things they can control. Santos has capped off a horrid week for Australia’s big oil and gas producers, reporting a A$2.7 billion (US$1.91 billion) loss to follow Origin Energy’s A$254 million (US$180.2 million) loss and Woodside Petroleum’s meagre US$26 million profit. Between them, the results of the three big local LNG players included about A$5.7 billion (US$4.04 billion) of mainly non-cash losses, predominantly asset impairments, with Santos writing down the value of its assets by a whopping A$3.9 billion (US$2.77 billion). For Santos and Origin, of course, the big influence on the extent of the red ink flowing through their finances (Origin’s more diversified and stable revenue base meant far less of it) was the timing of the developments of their massive debt-funded exportLNG projects in Queensland, which have come on stream in the context of plunging oil prices. For Woodside, the impact has not been balance sheet stress but simply the lower

Oil traders are shipping West Texas Intermediate to refiners in the Mediterranean to profit from the difference in crude prices between the two regions following the end of a four-decade ban on US exports. Trafigura Group sold a cargo of WTI to a refinery in Israel, said global head of crude oil at the commodity trader Ben Luckock. The 700,000 barrel cargo of US benchmark crude will be delivered in March. “The arbitrage to European refiners for WTI loading promptly currently seems to be open,” Luckock said. “A number of vessels of WTI crude oil have recently been fixed to Europe.” The world’s largest independent oil traders from Trafigura to Vitol Group are booking vessels to move US crude to Europe following a congressional deal in December to lift a 1970s-era prohibition on overseas shipments. A glut of WTI has pushed up US stockpiles to a record and cut prices to 12-year lows, widening the spread with benchmark European Brent

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crude. Trafigura is not the first trader to ship US oil to the region since the ban was lifted. Vitol, the largest independent oil trader, lifted a crude cargo from the US in early January that arrived in Italy later that month.

fall by 9%, the survey showed. “The fall in total investments is moderated by higher expected investments within electricity supply and manufacturing investments,” Statistics Norway said.

BLOOMBERG, February 22, 2016

REUTERS, February 24, 2016

Norway oil firms Poland could scrap deepen cuts to 2016 mining tax investment plans, rate cut seen Norway’s oil companies have deepened cuts to their 2016 investment plans, the latest survey by Statistics Norway showed, weakening the Norwegian crown and heightening expectations of a rate cut by the central bank next month. Norway’s leading industry has hit the brakes due to a 70% drop in the price of Brent crude since mid-2014 that has brought the Norwegian economy to a standstill. The country’s oil companies now plan to invest 163.9 billion krone (US$18.89 billion) this year, against the 171 billion krone (US$19.77 billion) they expected to invest when surveyed in November by Statistics Norway. “We expected an adjustment downwards, but not as big as this. It is significantly weaker than what (the central) Norges Bank has expected,” Handelsbanken chief economist Kari Due-Andresen said. “That means the activity in the Norwegian economy will be weaker than they have estimated ... This confirms our expectations that there will be a rate cut in March. We believe Norges Bank will start to guide rates towards zero,” DueAndresen said. The key policy rate is currently 0.75%. The next rate decision will be announced on March 17. The oil sector is planning to slash investments by 13% in 2016 against 2015, while overall investments by Norwegian firms were expected to

Poland’s mining tax, which has hit state-run copper miner KGHM, will eventually be scrapped and in the meantime could be reformulated or cut, Polish treasury minister Dawid Jackiewicz said. The mining levy, which was introduced in 2012 and is assessed using a complicated formula based on local production volumes and prices, primarily targets KGHM, Europe’s second-biggest copper producer and the world’s top silver miner. The group expected to pay 1.3 billion zlotys (US$327 million) in the tax this year, equal to its net profit reported for the first nine months of 2015. “Eventually the tax should be scrapped,” Jackiewicz said. “In the meantime, we will either reduce it or change the calculation formula.” KGHM is struggling to cope with the slump in world metal prices, with copper trading below the US$5,000per-tonne level seen as the breakeven point for its domestic output. Earlier this month, the company also said it would write down the value of its key foreign interests by US$1 billion in its final results for 2015. The main impairment is the Sierra Gorda mine in Chile, which KGHM co-owns with Japan’s Sumitomo. The mine, bought in 2011, started commercial production last year. “We have to verify this investment,” Jackiewicz said. “We are not crossing it off. Billions of zlotys have been invested. We are working on a rescue plan which will enable KGHM to save this investment.” REUTERS, February 25, 2016

Ukraine must separate storages facilities from GTS to attract investment Ukraine would not be able to attract a foreign investor to the management of the gas transport system without its separation from underground storage facilities, Naftogaz Ukrainy has said. Naftogaz said that the gas storage segment in 2014 brought a loss of 3 billion hryvnia (US$109.6 million), compared to 700 million hryvnia (US$25.59 million) a year ago, under international financial reporting standards. “The cost of our underground storage services [the largest in Europe] is very high, while investors are not interested in investing much in the segment, as business is lossmaking, there is no a development strategy, and Gazprom is blocking interconnectors,” the company said. INTERFAX UKRAINE (UKRAINE), February 20, 2016

LATIN AMERICA

Argentina awards US$582 million gas pipeline project Argentina’s Cordoba province has awarded contracts to three groups for the construction of a 2,336 km, 8.64 billion Argentine peso (US$582 million) natural gas pipeline. Contracts were awarded to Brazilian construction giant Odebrecht, as well as the China Petroleum Pipeline Bureau-Electroingeniería and China Communications Construction Company-Iecsa groups. The pipeline will serve 700,000 residents in 166 towns, with construction set to begin in July and last 33 months, the local government said. The pipeline

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will cost US$58 per inch-metre to build, said governor Juan Schiaretti, compared to US$103 per inch-metre for the US$3 billion GNEA pipeline under development in the country’s northeast. BUSINESS NEWS AMERICA (CHILE), February 19, 2016

Venezuela printing bills to tackle inflation As Venezuelan inflation soars, the country’s Central Bank has announced that it is to print 500 and 1,000 Bolivar bills while phasing out smaller bills. The announcement comes after President Nicolas Maduro announced an economic emergency last week, allowing him to impose measures such as changing the exchange rate and upping petrol prices by as much as 6,000%. Venezuela’s collapse has been triggered by a huge drop in the price of oil. Maduro has been pushing for an OPEC production freeze but negotiations have stalled, with Iran refusing to consider halting production. VENEZUELA ANALYSIS (US), February 22, 2016

to stabilise the market could be considered in the next few months, he added. Saudi Arabia’s balance sheet is very healthy with very low debt and reserves equal to 100% of its economy, he pointed out. “There will be no change in the currency status quo. There will be no devaluation and no depegging,” said Sfakianakis. Russian Energy Minister Alexander Novak said consultations on an oil output deal between leading producers should be concluded by March 1 after they reached a common position at a meeting in Doha. Novak also said it was “discussed with colleagues” that an oil price of US$50 per barrel would suit consumers and exporters in the long term. Sfakianakis said: “Saudi Arabia still holds more than 100% of its GDP in foreign assets and the budget deficit is estimated to be lower in 2016 by two percentage points compared to 2015.” ARAB NEWS (SAUDI ARABIA), February 21, 2016

NORTH AMERICA

US shale faces March madness with US$1.2 Saudi Arabia is among billion in interest due the healthiest of oil producing countries MIDDLE EAST

Saudi Arabia is among the healthiest of the oil producing countries of the world, a top Riyadh-based economist asserted as reports said the country, Russia, Qatar and Venezuela will monitor the oil market following the recent agreement in Doha to freeze production and potentially take additional measures to rescue prices. “The Doha agreement was an important step forward,” John Sfakianakis said. New steps

The US shale industry must come up with US$1.2 billion in interest payments by the end of March as US$30 oil makes it harder for companies to scrape up the cash needed to stay current on their debts. Almost half of the interest is owed by companies with junk-rated credit, according to data compiled by Bloomberg on 61 companies in the Bloomberg Intelligence index of North American independent oil and gas producers. Energy XXI said in a filing that it missed an US$8.8 million interest payment. The following day, SandRidge Energy announced that it did not make a

US$21.7 million interest payment. “You’ve seen two of these happen in two days, and I wouldn’t be surprised to see more in the next month as these payments come due,” said energy analyst at Wunderlich Securities Jason Wangler. BLOOMBERG, February 17, 2016

Senators criticise budget for ending offshore revenuesharing Oil-producing Gulf Coast states would lose hundreds of millions of dollars if Congress approves the Interior Department’s budget request, which proposes a repeal of offshore oil and gas revenue-sharing allotted to four states, Louisiana, Texas, Mississippi and Alabama. The Interior’s 2017 budget would divert more than half the money now paid to those states under the Gulf of Mexico Energy Security Act, US$375 million annually, according to Louisiana Senator Bill Cassidy, to the Coastal Climate Resilience programme, a new initiative that would provide coastal states with resources over 10 years to prepare for and adapt to the effects of climate change. Critics of the Gulf of Mexico law say the money belongs to the federal government because the oil is taken from federal waters. But at the Senate Energy and Natural Resources Committee hearing, Chairman Senator Lisa Murkowski said otherwise. “Depriving the Gulf States of revenue-sharing from offshore production is just a nonstarter,” she said. “It would upend a deal that 71 senators supported and take money away from states that are depending on it to protect their coastlines.” UPI, February 23, 2016

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