Energy Finance Weekly Issue 01 by NewsBase Ltd.

Week 01• 08 February • 2016

ENERGY FINANCE WEEK This week’s top stories

v Key factors businesses must monitor in low oil price environment p2

v PTTEP’s shock losses point to new investment cuts p6

v Repsol’s losses top US$1bn, as low prices bite p10

v Iran eyes quick return to

international bond market, with innovative structures p17

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Week 01• 08 February • 2016

Key factors businesses must monitor in low oil price environment MARKET WITH hydrocarbons prices still falling toward multiyear lows, the UK’s Association of Chartered Certified Accountants (ACCA) has released a report outlining the key factors that C-level executives need to monitor in order to achieve success in the most volatile and competitive era the oil and gas sector has ever seen. “Right now, the risk of going under is a very real one for many oil and gas companies, and three key elements have combined to create a perfect storm in the sector,” Faye Chua, Head of Business Insights for ACCA, told Energy Finance Week. “One, lower cash-flows; two, the existing debt overhang; and, three, the so-called ‘great crew change’ as the impending retirement of senior expert professionals over the next five years leaves a talent vacuum in its wake,” she added. The keys to navigating this storm are: good management of growth, costs, and funding. Management focus The first of these, managing growth opportunities, in some ways depends on the nature of the organisation, with oil majors typically having invested in huge projects and programmes, heavily dependent on expensive innovations, which are often subject to cost overruns and delays, but pulling out of them also usually presents a cost. Meanwhile, integrated oil companies – incorporating elements of upstream, midstream, and downstream activities – are more diversified than smaller exploration and production (E&P) specialists and tend to be able to withstand low oil prices better. A low oil price may hit upstream sales to third parties, but it makes oil purchases cheaper for the refining division. Interestingly in this regard, the LNG sector appears less vulnerable than others in the hydrocarbons industry. Overall, by the middle of 2015 alone, ACCA said that developers had postponed final investment decisions (FIDs) on 45 upstream oil and gas projects, while cuts to exploration budgets for the year averaged around 30%. For the LNG sector, though, because a significant part of this output was pre-sold at a relatively high price in deals struck before hydrocarbons prices collapsed, the number of prospective multi-billion-dollar LNG export projects where a FID was expected to be taken in 2015 and 2016, has not reduced significantly. “Even if the gas has not all been pre-sold, a finance director may not feel that investing in such a project is a big risk, if he or she is convinced that gas prices will go

up in a few years’ time, given that the project had always been accounted for as a long-term revenue earner,” said Chua. In this environment, cost management needs to focus on concentrating asset sales on areas of the business not central to long-term strategy as much as possible, as no upstream business boss wants to sell-off prized assets or abandon projects that could restore the company’s fortunes when oil prices pick up. According to Rob Van Velden, Finance Director of Sakhalin Energy: “While Sakhalin Energy is taking costs out, the longer-term view on oil prices has changed somewhat but nothing dramatic, therefore most of our long-term investments remain profitable and stay in the plan as before.” In the case of redundancies, the key is to manage them carefully to account for skills-gap impact, and to ensure readiness for future growth when the oil price rebounds, says ACCA. In the UK alone, between the start of 2014 and the first half of 2015 the number of jobs supported by direct, supply chain and indirect employment related to the offshore industry fell by around 15%. The report added: “Also, re-negotiate discounts with contractors to manage service costs and on-going expenditure, as there could be room here as many suppliers may prefer lower margins to idle machinery in the challenging times we are currently experiencing.” Repaying the debt With the global hydrocarbon industry’s debt repayments set to increase to US$550 billion over the next five years – with US$72 billion maturing this year, rising to USS129 billion in 2017 – funding management is clearly another key to surviving the current choppy environment. John Mitchell, an Associate Research Fellow at Chatham House, and a former BP executive, highlights two challenges in this context. “Raising funds from long-term bonds when interest rates are generally low is advantageous, but a low interest rate environment may not last so the question is ‘how much do you want to load up your company with debt?’ As long-term price prospects no longer appear to be the ever-ascending ‘golden staircase’ they once seemed to be, short-term prices restricted by surplus production and weak demand, and medium-term demand also is likely to be restricted by other factors (such as the rate of uptake

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 01• 08 February • 2016

for renewable energy and alternatives to oil for transport, improvements in energy efficiency and the requirements of climate change policies), firms with promising acreage in a developing country would typically hope to draw in substantial investment – and expertise – from large partners. Another solution is likely to come from experienced private equity firms prepared to take on higher-risk investments with longer payback times. Colin Welsh, CEO of investment bank Simmons & Company International, said: “It is impossible to predict the near-term profitability of any oil service company just now, so that makes deal pricing difficult,”

He added: “The generalist investors are very nervous when the industry is in a prolonged downturn, but for specialist private equity investors who understand the cycle, and know that the industry will recover, low oil prices represent an opportunity.” Until crude prices recover and activity picks up, oil service companies will be under significant pressure, especially those that are highly levered. However, for experienced oilfield investors who have faith that it is only a matter of time before the sector bounces back, the next 12 months will be ripe with opportunities for acquiring quality businesses at prices that, in time, will look cheap.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 01• 08 February • 2016

Sasol warns of tough times AFRICA SASOL has warned its earnings have come under pressure in the second half of 2015 and that it was in the process of taking further steps to adjust to the new, lower oil price environment. A statement from the company, on January 28, said the six month period – the first half of the 2016 financial year – had enjoyed “strong business performance across most of the value chain”. However, it also further commented that performance had been “negatively impacted by challenging and highly volatile global markets, marked by a steep decline in global oil and commodity chemical prices, partly offset by a weaker rand exchange rate”. Headline earnings per share were expected to fall by 23-28%, while earnings per share were expected to fall by 62-67%. On a normalised basis, earnings per share will fall by 8-13%, it said. The decline was driven by the 47% fall in Brent prices, Sasol said, while a basket of commodity chemicals was down by 23%. Taking some of the sting out of this, though, was the weak rand against the US dollar, down by an average of 24%. The company’s underlying performance was strong, with Secunda Synfuels throughput up 3%,while total liquids were up by 4%. The Oryx gas-to-liquids (GTL) plant, in Qatar, provided a performance described as “solid”, with an average utilisation rate of 90%. In the six months ending on December 31, 2015, Sasol’s production in Mozambique was 57.7 billion cubic feet (1.63 billion cubic metres), up from 53.6 bcf (1.52 bcm) year-on-year. This benefited from the start-up of the Central Termica de Ressano Garcia (CTRG) gas-to-power plant, on January 1, 2015. Condensate production was 163,000 barrels, down from 167,000 barrels in the

previous year. External sales of Mozambique gas increased to 8.3 bcf (235 million cubic metres), from 4.2 bcf (119 mcm), while condensate sales were virtually unchanged at 153,000 barrels, compared with 158,000 barrels. Oil production in Gabon increased to 913,000 barrels in the period, from 664,000 barrels. Additional production was driven by new wells from the Etame Expansion Project (EEP), while South East Etame and North Tchibala (SEENT) came on line. Output at the Escravos GTL plant reached 220,000 barrels in the second half, up from 80,000 barrels. The facility ran at 35% of capacity, Sasol said, ahead of 13% last year. The plant is “still in its ramp-up phase”, the company explained, and working towards stable operations to maximise diesel and naphtha production. Sasol said its cost savings programme, targeting 4.3 billion rand (US$267.3 million), was making good progress and was on track for the financial year. The response plan was intended to position the South African company for an oil price of US$45-50 per barrel. Given the continued price decline, Sasol said it was considering the scope of its plan and would provide a potential update on March 7, at the same time as tabling its full results. There were a number of one-off items that also had an impact, it said, including changes to its shale gas project in Canada. In addition, the company said a tax provision of 2.3 billion rand (US$143.1 million) had been reversed based on a ruling from Nigeria’s tax appeal tribunal on the Escravos GTL project.n Ed Reed, Editor, Africa Oil & Gas, NewsBase Ltd. Any questions? Please get in touch Email: edreed@newsbase.com

SASOL VS. BRENT (NYSE)

Brent

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Week 01• 08 February • 2016

Chinese to build Kenyan wind farm AFRICA KENYA’S Kipeto Energy has awarded China Machinery Engineering Corp. (CMEC) an engineering design, procurement and construction (EPC) contract for a USfunded, 102-MW wind farm and 220-kV transmission line in Kajiado county in southern Kenya. The 22.6 billion shilling (US$221.1 million) project is one of the largest US foreign direct investments in Kenya and will be completed within two years from the date of commissioning, which was not disclosed. “The company, as the EPC general contractor, will be responsible for the design, supply, civil engineering and construction, installation, training, commissioning, technical services and other works of the project on a turnkey basis. The contract value amounts to US$221 million” Hong Kong-listed CMEC said in regulatory filings, Business Daily newspaper reported on January 29. “As stipulated in the contract, the project construction will commence upon the satisfaction of certain conditions precedent. The construction period of the project will

last approximately 22.5 months once the construction is commenced,” said the filing. In 2015, CMEC signed a 20-year power purchase agreement with electricity distributor Kenya Power for an undisclosed amount. Last year, Kipeto Power signed an agreement with GE for the supply of 60 GE 1.7-103 wind turbines at the site. The US’ Overseas Private Investment Corporation (OPI C) is providing US$233 million of debt financing. The African Infrastructure Investment Fund II is the largest project shareholder with a 55% stake, followed by Craftskills Wind Energy International Ltd and the International Finance Corporation, which hold 20% each. The Kipeto Local Community Trust holds the remaining 5%. Only about 25 MW of wind energy, produced at the Ngong Hills-based wind farm operated by Kenya Electricity Generating Company (Ken- Gen), is currently connected to the Kenyan grid. However, the Lake Turkana Wind Project, currently under construction, will produce 310 MW when completed in June 2017.n

Private investors to develop 120-MW hybrid plant in Kenya AFRICA THE Kenyan Coast Water Services Board (CSWB) has signed up four private investors to develop a 120-MW hybrid renewables plant in a US$12.3 million deal that will help power the Baricho waterworks in Kilifi County. CWSB hopes the wind and solar plant will solve electricity shortages at the region’s main water source after Baricho was taken off line by Kenya Power because of unpaid electricity bills. Zormar Group will lead a consortium including Shelter Solutions, BCleantech and Siemens in a private-public partnership with CSWB. The first phase will install wind turbines and solar panels at the plant and is expected to generate 46.5 MW at a cost of 10.5 billion shillings (US$102.72 million). A second development stage will eventually see wind turbines generate 80 MW, while solar energy will provide 40 MW. The development will also involve the construction of power lines, including two high-voltage substations. Martin Okore, vice president of Zormar, said Baricho would need 7 MW of electricity, leaving the balance of generated electricity available for the national grid.

Residents in Kilifi County had been left without water supplies after CWSB cut supplies to local water suppliers because of an outstanding 344 million shilling (US$ 3.26 million) debt. While households in Kilifi were reconnected last week, the Baricho waterworks has often struggled to operate at its full potential because Kenya Power repeatedly disconnects the power supply over unpaid electricity bills. Baricho has a daily capacity of 90,000 cubic metres of water, but regularly pumps 35,000 cubic metres because of electricity supply problems. Okore said that energy costs at the Baricho accounted for 73% of total revenues at the plant, making it difficult for Baricho to “sustain itself and play its mandate of meeting the region’s water needs.” Kenya’s The Nation reported comments from CWSB project engineer David Kanui suggesting that the utility faces electricity bills of more than 35 million shillings (US$34,000) each month. Kanui, who has served as acting CEO at CWSB, said that the utility had started negotiations with Kenya Power to conclude a power purchase agreement for the new plant.n

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Week 01• 08 February • 2016

PTTEP’s shock losses point to new investment cuts Low oil prices have taken their toll on the state-run company’s balance sheet and fresh budget cuts seem likely. ASIA THAILAND’S state-dominated oil and gas sector is bracing itself for new cuts after upstream leader PTT Exploration & Production (PTTEP) signalled shock net losses for 2015 of US$884 million. The deficit, compared with a net profit of US$677 million in 2014, comes despite hefty cuts in the stateowned firm’s 2015 budget on the back of the oil price collapse. PTTEP announced its 2015 losses in an unaudited financial statement to the Stock Exchange of Thailand (SET) last week. Consolidated assets totalled US$19.6 billion with liabilities of US$8.3 billion, it said. Proven reserves are 738 million barrels of oil equivalent. With the price of oil dipping below US$30 per barrel in January, Energy Finance Week understands that PTTEP is now mulling new cuts to its 2016 budget, which it revealed in December 2015. This is expected to lead to the suspension of several overseas ventures, including at least one gas development in neighbouring Myanmar. This year’s budget had involved a total outlay of US$3.44 billion, of which US$2.09 billion had been earmarked for capital expenditure and US$1.35 billion for operating expenses. Cutbacks “PTTEP will focus activity this year in its Gulf [of Thailand] interests and operational offshore gas blocks in Myanmar,” a company official speaking on condition of anonymity told Energy Finance Week. “Exploratory work on the M3 gas development in Myanmar will be halted, as will activity at Cash Maple [gas field in Australia]. Expenditure cuts still to be announced will reflect these actions.” PTTEP will adopt a flexible policy in its 2016 budget, which could rise if oil prices improve. Although PTTEP has assets and projects on five continents – Africa, Australia, North and South America, as well as Asia – more than 80% of this year’s budget will be in Thailand (55%) and Myanmar (27%). This will leave little left to invest in the Rovuma offshore gas project in Mozambique, the Mariana oil sands concession in Canada, or PTTEP’s minority shares in two oil developments in Brazil. When the developer began cutting its five-year capex

plan a year ago it described the M3 block as promising. In 2013, gas was discovered at the block, which is located in the Gulf of Martaban, and there was a plan in 2014 to begin production by the end of 2016, but progress has slowed. PTTEP holds an 80% stake, while Japanese partner Mitsui Oil has the remaining 20%. The Cash Maple block, meanwhile, is one of several plays in the Bonaparte Basin off Australia’s northwest coast, where the producing Montara oilfield also lies. It has been under “development option study” status for more than a year. Another plan to build a floating LNG (FLNG) production platform attached to Cash Maple was abandoned at the beginning of 2015 when PTTEP also liquidated its subsidiary PTT FLNG, which had been formed in 2010. The state oil firm has previously said it wants to deliver more natural gas to meet Thai domestic demand. The country’s power generation relies heavily on the fuel. Gas focus Energy Finance Week understands that near-term expenditure in Thailand will be concentrated in existing Gulf of Thailand producing fields – the Arthit and Bongkot fields and the Malaysia-Thailand Joint Development Area. PTTEP’s new Zawtika offshore field in Myanmar’s Gulf of Martaban is also predicted to increase output. The company has declined to comment on a proposed more than US$1 billion bid for UK major BG Group’s 22% stake in the Bongkot gas field. While the acquisition of BG’s stake would augment PTTEP’s gas production, bringing the Thai firm’s stake in the field to about 67% with France’s Total holding the rest, it would not raise domestic supply. All of Bongkot’s gas is already sold within Thailand, meeting 20% of domestic demand. It seems unlikely that such a deal will proceed in the near future, given the company’s financial obligations to the state and mounting government pressure to step up gas production Pressures Southeast Asia’s national oil companies (NOCs) are struggling to deal with the oil price slump, but are bound by their state ties and must try to deliver both energy

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resources and income. PTTEP is no different and, despite a sizable loss last year, is set to recommend a shareholder dividend of US$0.08 per share in its presentation to the next annual general meeting at the end of March. The company’s biggest shareholder, with 65%, is parent state-run PTT, which is 66% owned by the Thai Ministry of Finance and two state funds. The trade-off, though, is that under the company’s existing five-year plan oil and gas production is actually forecast to slide every year until 2020. The company is anticipated to produce 302,000 barrels of oil equivalent per day in 2020, down from 333,000 boepd this year. PTTEP’s financial pain is likely to see the indefinite

suspension of a new upstream bid round that has been on hold since March 2015. Moreover, the Thai economy in general is hurting from declining foreign investment, a problem blamed in part on the continued control of the country’s politics by the military since a coup in May 2014. All this paints a dire picture for the country and suggests that there is little chance of any other outcome but declining oil and gas reserves and production in the years to come.n Andrew Kemp, Editor, Asia Oil & Gas, NewsBase Ltd. Any questions? Please get in touch Email: andrew.kemp@newsbase.com

Lundin agrees farm-out deals in Malaysia ASIA LUNDIN Petroleum has agreed to farm out part of its interest in three blocks off the east coast of Malaysia to Netherlands-based Dyas. The deals, announced on February 1, will see the Swedish independent hand over a 20% stake in SB307/308, located in the Sabah Basin. In exchange, Dyas will help fund an ongoing exploration programme at the block. For an undisclosed sum, the privately owned Dutch player will also pick up a 20% stake in SB303, also at the Sabah Basin, and a 15% stake in PM328, which is targeting the Malay Basin. Once the transactions are completed, Lundin will be left with a 65% interest in SB307/308, a 55% interest in SB303 and a 35% share in PM328. Lundin has slashed spending for this year by 26% in an effort to improve its cash flow. Exploration and appraisal activity will be hardest hit, with spending set to fall by 64% from last year’s level to US$145 million. Development spending will be cut by 12% to US$935 million, with much of this sum going towards further drilling at Norway’s Johan Sverdrup and Edvard Grieg fields. In a recent statement, the company said it intended to drill five exploration wells during the year, down from a total of 12 wells in 2015. The Swedish company completed a well at the Bambazon prospect in Block SB307/308 earlier this

month, resulting in a minor oil discovery. Last week, it spudded a second well at the licence, this time targeting 94 million barrels of oil equivalent in potential resources at the Maligan prospect. Lundin has also put aside funding for a development well targeting additional reserves at its sole producing asset in Malaysia, the Bertam oilfield. The field, which came on line in April 2015, netted the company 8,100 boe in the third quarter. Lundin expects to see its average output rising to 60,000-70,000 boepd in 2016 on the back of greater contribution from Norway. Its proven and probable reserves were 685 million boe as of December 31, 2015, up 292% from a year earlier. But Oslo-based Arctic Securities (AS) forecasts the Swedish firm to book a loss of US$739 million for 2015, up from US$365 million for 2014. Its debt, meanwhile, is set to expand by 43% to US$3.64 billion, according to AS. This debt mountain, together with the company’s large reserve base, makes it an attractive target for acquisition. Norway’s Statoil announced it would buy an 11.9% stake in the company in January. Lundin operates a total of six licences in Malaysia – PM307, PM319, PM308A, PM308B, PM328 and SB307/308. Dyas holds minority stakes in a diverse range of assets in the Netherlands, the UK North Sea, Germany and Australia.n

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China to invest US$348m in renewables ASIA THE Chinese government is ready to invest 2.3 trillion yuan (US$348 billion) in renewables during the country’s 13th five-year economic development period (20162020) in an effort reduce carbon dioxide (CO2) emissions and fossil fuel consumption. The National Energy Administration (NEA) has released a draft of the country’s renewable energy strategy to government and industry bodies for review and comment. The document states that China will try to raise renewables’ share of the energy mix to 15% by 2020 and 20% by 2030, up from 12% in 2015. Non-fossil fuel consumption by 2020 will include 380,000 MW of hydro, 160,000 MW of solar and 250,000 MW of wind. Southwestern Chinese regions, including Sichuan, Yunnan and Tibet, will focus on

developing hydropower, the draft states. In northeastern, northern and northwestern Chinese provinces, the government is to promote the construction of wind projects and aims to build 170,000 MW over the next five years. Another 70,000 MW of wind projects will be constructed in the central and southern provinces. In the meantime, a total of 10,000 MW of offshore wind power projects will also be built during this period, while the government will also promote pilot onshore wind projects in other regions. China, as the world largest carbon emitter, aims to cut greenhouse gas (GHG) emissions per unit of gross domestic product by 60-65% from 2005 levels. This target forms part of China’s plans submitted to the United Nations ahead of the COP21 talks in Paris in December 2015.n

Japanese power profits return to pre-Fukushima levels ASIA JAPAN’S 10 major power companies all posted pre-tax profits in the nine months to December thanks to sharply lower fuel costs. Pre-tax profits reached 1.11 trillion yen (US$9.17 billion) for the first nine months of the 2015 fiscal year, exceeding levels last seen before the 2011 Fukushima disaster. The 10 power companies’ pre-tax profits in the first nine months of the 2010 fiscal year amounted to 950 billion yen (US$7.8 billion). The Fukushima nuclear disaster led to the shutdown of Japanese nuclear power plants (NPPs) and sharply higher fuel costs for thermal power generation. Japanese power companies have significantly boosted generation at thermal power plants (TPPs), especially LNG-fired ones, to make up for lost output at NPPs. A sharp decline in fuel costs for thermal power generation amid falling oil prices contributed to the profits. Tokyo Electric Power Co. (TEPCO), the Japanese industry leader and operator of the Fukushima No. 1 NPP, posted a record pre-tax profit of 436 billion yen (US$3.6 billion) for the April-December period. Chubu Electric Power, which relies particularly heavily

on LNG for electricity generation, saw its pre-tax profit swell elevenfold year on year to 215 billion yen (US$1.8 billion). Yet eight of the 10 companies actually saw sales decline in the first nine months of the 2015 fiscal year as they lost customers to new market entrants. Cut-throat competition is anticipated in the Japanese power industry after the nation’s retail electricity market is fully liberalised in April. Japan’s 10 regional power companies have effectively monopolised their respective service areas for many years. They are currently the sole providers of power to households and small businesses in their respective service areas. The April opening up of the market will allow users to choose their power suppliers. The retail market for large business users such as factories has already been liberalised.n Richard Lockhart, Editor, Asia Power, NewsBase Ltd. Any questions? Please get in touch Email: richardl@newsbase.com

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Total, Pertamina strike trading deal ASIA FRANCE’S Total has struck a trading deal with Indonesia’s Pertamina on LNG supplies. Total has committed to buying some of Pertamina’s volumes contracted from the US, while also agreeing to supply the Indonesian company with supplies from the French company’s portfolio. Effectively, the agreement reduces shipping needs, allowing both companies to secure supplies closer to their domestic markets. Announcing the deal on February 2, Total said it would begin by supplying 400,000 tonnes per year and increase this to 1 million tonnes per year. The accord would run for 15 years, starting in 2020. Supplies will come from its “global portfolio”, the company said. Pertamina, meanwhile, will sell 400,000 tonnes per year of its contracted volumes from the US’ Corpus Christi project. This would also begin in 2020. Total’s head of gas, Laurent Vivier, said this would allow the company “to further expand its longstanding cooperation with Pertamina and to enhance both companies’ LNG portfolios. Strengthening our presence in Asia, in particular through innovative relationships with new LNG buyers such as Pertamina, is an important part of our strategy.” Total produced 10.2 million tonnes of LNG in 2015, with stakes in a number of liquefaction plants. It does not have stakes in US projects but has signed up purchase agreements. Pertamina secured the supplies from Corpus

Christi with a fixed fee of US$3.5 per million British thermal units (US$96.8 per 1,000 cubic metres) and an LNG cost of 115% of Henry Hub. The contract will run for 20 years. Supplies to the Indonesian company come under two agreements, announced in December 2013 and July 2014, for a total of 1.52 million tonnes per year. A note from Tudor Pickering Holt (TPH) said the deal demonstrated the value of scale in the LNG business and that deals can still get done. Total will probably use volumes from Corpus Christi to meet its obligations in the Atlantic Basin, it said. “Total will supply Pertamina with LNG from its AsiaPacific portfolio, which should be more cost effective from a logistics (shipping cost) perspective and the contract linkage is likely to be oil linked rather than Henry Hub linked [unlike Corpus Christi], which we believe would be preferable for Pertamina,” TPH said. The first two trains at Cheniere Energy-backed Corpus Christi are under construction, which began in May 2015. Other customers for the first two trains include Endesa, Iberdrola, Gas Natural Fenosa, Woodside, EDF and EDP. According to a Cheniere presentation in January 2016, first LNG is expected to be achieved in late 2018.n Ed Reed, Editor, LNG, NewsBase Ltd. Any questions? Please get in touch Email: edreed@newsbase.com

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Repsol’s losses top US$1bn, as low prices bite The Spanish company has been forced to scale back capex and divest itself of non-core assets, with speculation that it could look to sell part of its stake in Gas Natural. EUROPE TUMBLING oil and gas prices have forced Europe’s fifthlargest oil company, Repsol, to tighten its belt in recent months. In October the Spanish firm unveiled a strategic plan for 2016-20 which entailed cost-cutting, synergies and the disposal of non-strategic assets. The plan has been based on an adverse scenario of US$50 per barrel. But with front month Brent now trading at around US$35, and the company’s share price having meanwhile fallen 25%, on January 27 Repsol announced impairments of 2.9 billion euros (US$3.2 billion), or about 10% of shareholders’ funds. This was mainly the result of a write down in the value of its reserves. The company predicted this would lead to a net loss of some 1.2 billion euros (US$1.34 billion) for the full-year 2015 when results are posted on February 25. Repsol also said it had cut planned investment by a further 20% for this year, with capex now slated at 4 billion euros (US$4.5 billion). However, in a bid to soften the blow, the company forecast that underlying net profit for 2015 – after adjusting for the write down – would be about 1.85 billion euros (US$2.06 billion), a rise of 8% from 2014. Estimated upstream losses for the fourth quarter were also below expectations, though downstream was mixed, with lower refining utilisation weighing down higher margins. Repsol added that estimated synergies from buying Canadian firm Talisman in December 2014 had jumped to US$400 million from US$220 million, half of which had already been harnessed. The Spanish company also noted that in future the bottom line would, conversely, benefit from revaluing reserves should oil prices recover. Moreover, the firm said it had lopped 1 billion euros (US$1.12 billion) off its debt pile in 2015. “This reduction shows that, even in an adverse scenario such as that of 2015, the company has maintained its capacity to generate cash and shareholders’ compensation,” Repsol said in a regulatory filing.

Investors seem to have taken the guidance in their stride because Repsol shares inched up 0.06 euros (US$0.07) on the Madrid stock exchange on the day it published guidance, with the price remaining roughly flat since then. Ratings game “At current prices I think they [investors] are discounting the scenario, and it is even below fundamentals, being very conservative,” Alvaro Navarro, an energy analyst with the Intermoney brokerage in Madrid, told Energy Finance Week. “It [the write down] is quite a hit but still, shall we say, reasonable. Now they have to continue talking to ratings agencies to see whether they can maintain investment grade. The main thing is to quantify this impairment,” he added. Repsol has said it will be meeting with ratings agencies after it posts results later this month. Standard & Poors, for example, maintained its corporate credit rating for Repsol at “BBB-/A-3” in October, but revised its outlook to “negative”. Fitch meanwhile currently rates Repsol at “BBB/ Stable” and in a review of oil companies in December, the agency estimated that even at an average oil price of US$45 per barrel in 2016, Repsol would need to cut discretionary spending by 37% to avoid triggering a downgrade, assuming no further disposals. “In reality, it is unclear that this will be enough to save the credit rating and perhaps the most surprising news from the statement was what was not included – a cut in the dividend – which may be an easier source of saving cash than some of the measures being implemented,” Barclays Equity Research said in response to the guidance. Two of Repsol’s core shareholders – lender Caixabank and construction firm Sacyr – have usually favoured maintaining the dividend payout of about 1 euro (US$1.12) per share in the past, because it has helped

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REPSOL VS. BRENT (US$)

Brent

boost their profits amid an extended slump in both their sectors during Spain’s economic malaise. “In the strategic plan, we said we aimed to keep a competitive dividend. That is, to date, still our stated intention,” said Kristian Rix, a Repsol spokesman. Societe Generale remarked in a research note that Repsol’s dividend payout of around 500 million euros (US$559 million) per year was offset by the 300 million euros (US$335 million) it receives from its 30% holding in Gas Natural, which made the policy less onerous. “Even if it fully eliminated the dividend, a 200 million euro [US$224 million] cash saving would not make a material dent in the 12 billion euros [US$13.4 billion] of net debt; and to us, what is encouraging is that net debt declined by circa 1 billion euros [US$1.12 billion] in 2015 despite the oil price crash,” Societe Generale said. Other analysts felt Repsol’s debt was still high in relation to its operating earnings (EBITDA), and the obvious way to pay it off would be to shed at least part of its Gas Natural stake, which is worth some 5.4 billion euros (US$6 billion) at current market capitalisation.

leverage,” N+1 Equities said in a research note. “In our view, the only way forward to cutting leverage significantly is eliminating the dividend and accelerating asset disposals of non-core assets, and of the 30% stake in Gas Natural and probably part of the downstream assets. And we think this should be done the sooner the better,” it added. Rix said of Repsol’s stake in Barcelona-based Gas Natural: “Is not an asset that we’re looking to sell. It’s a good asset, we want to keep it.” He added that the stake: “Gives us a nice stable income, a nice stable basis for the group’s earnings. It gives the company exposure to other forms of energy and it does give you a silver bullet optionality should you ever need to find cash.” Rix stressed that the key word “optionality” did not mean Repsol was mulling a sale. Rix also noted that Repsol had already disposed of 2 billion euros (US$2.24 billion) in non-core assets or about one-third of a total target of 6.2 billion euros (US$6.93 billion) set out in the latest strategic plan. “It’s all about delivery, and so far we’re delivering,” he said.n

Gas Natural “For us, booking these impairments and stepping-up cost savings is positive, but it is not a comprehensive solution, as they will have limited impact on Repsol’s very high

Ryan Stevenson, Editor, Europe Oil & Gas, NewsBase Ltd. Any questions? Please get in touch Email: ryans@newsbase.com

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Lundin cuts 2016 spending by 26% EUROPE LUNDIN Petroleum has slashed spending for this year by 26% compared to 2015, but still sees output rising owing to the launch of the Edvard Grieg oilfield in November. The Swedish independent said in a statement it intended to spend US$1.1 billion on development, appraisal, and exploration work in 2016, down from last year’s spend of US$1.49 billion. Lundin’s exploration and appraisal activity will be hardest hit, with spending set to fall by 64% from last year’s level to US$145 million. The company said it intended to drill five exploration wells and one appraisal well in the year, down from a total of 12 wells in 2015. In Norway, Lundin started drilling an exploration well at the Fosen prospect in licence PL544 this month. The company will spud another well at the Filicudi prospect in PL533 in the second half of the year and also plans to reenter the Neiden exploration well in the southern Barents Sea. Overall, the exploration programme in Norway is targeting 250 million barrels of oil equivalent in potential resources. Another two wells will be drilled in Malaysia. The first was completed earlier this month at the Bambazon prospect in licence SB307/308 and resulted in a minor oil discovery. Last week Lundin announced it had spudded a second well at the licence, this time targeting the Maligan prospect. Development spending in 2016 will be cut by 12% to US$935 million, with much of this going towards Phase 1 development of Johan Sverdrup and further drilling at Edvard Grieg. But despite cutbacks, Lundin said it saw average output rising to between 60,000-70,000 barrels of oil equivalent per day in 2016, owing to the recent ramp up at Edvard Grieg. This is around double the rate of

production the firm achieved in 2015. The Edvard Grieg oilfield is currently producing up to 85,000 boepd and is expected to reach a peak output of 100,000 boepd later this year. Lundin operates the project with a 50% stake. The company had 685 million boe in proved and probable reserves as of December 31, up 292% from a year earlier. This was largely because of the inclusion of Johan Sverdrup, due to come on line in 2019, as well as successful appraisal of Edvard Grieg and positive reserve revisions to the Volund field. Lundin is due to publish its 2015 financial results on February 3. Oslo-based Arctic Securities (AS) forecasts the Swedish firm to book a loss of US$739 million for the year, up from US$365 million for 2014. Its sales, meanwhile, are set to fall by 24% to US$596 million. Lundin’s overall debt will expand by 43% to US$3635 million, according to AS. Acquisition target This heavy debt burden, together with the company’s large reserve base, makes it an attractive target for acquisition. Norway’s Statoil announced it would buy an 11.9% stake in the firm earlier this month. In an effort to raise cash, Lundin announced this week it had entered farm-out agreements with Netherlandsbased Dyas for interests in three offshore Malaysian blocks. In return, the Dutch privately-owned player will pay an undisclosed sum and help fund Lundin’s exploration programme on SB307/308. Lundin also announced it had secured as much as US$5 billion in financing to pay for its share of costs at Johan Sverdrup. The funds were agreed under a sevenyear revolving credit facility with 23 lenders.n

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OMV books further writedowns EUROPE OMV said last week that low oil prices had forced it to take writedowns in its upstream and downstream businesses totalling 1.8 billion euros (US$1.99 billion). The news follows an earlier announcement in November of US$1.1 billion in upstream impairment charges. The Austrian energy group said it had booked around 1.5 billion euros (US$1.67 billion) in writedowns in its upstream business in the fourth quarter of 2015, and 300 million euros (US$335 million) downstream. Its total writedowns and charges for the year are now greater than the 2.2 billion euros (US$2.44 billion) in operating profit that it declared in 2014. In revealing the latest writedowns, the company explained that they were based on a downward revision of its expected 2016 average price forecast for Brent crude oil, from US$55 to US$40 per barrel. It added, however, that it anticipated the fall to be followed by a slow recovery in prices in the coming years. It foresees a level of US$55 per barrel next year, rising to US$65 in 2018, US$70 in 2019, and then US$75 from 2020 onwards. OMV’s CEO Rainer Seele told the Austrian news agency APA that no further writedowns would be

necessary, provided the envisaged US$40 scenario transpires. Low oil prices have already forced OMV to slash its investment programme for 2016, and it has put its 49% stake in the Gas Connect Austria gas hub up for sale in a bid to generate extra cash. The company has also abandoned its previously set production target for 2016 of 400,000 barrels of oil equivalent per day, and output has even stopped entirely at sites in conflict-affected Libya and Yemen that had accounted for 10% of its total output. A large part of OMV’s portfolio currently revolves around expensive assets in the UK and Norwegian North Sea waters that it bought from Statoil for US$2.65 billion in October 2013, and where production costs are relatively high. To counter this, Seele wants to expand the company’s business interests beyond Europe’s borders. It is already looking towards Russia for low-cost exploration, and is said to be interested in investing in oil and gas fields in Abu Dhabi and Iran. Seele is scheduled to unveil OMV’s new strategy in London on February 18, at which time its full-year results will also be released.n

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Russia suggests oil tax break rollback FSU RUSSIA’S Finance Ministry is reportedly pushing to reduce the scope of tax breaks for oil operators in a bid to increase budget revenues. Its efforts are likely to face opposition from the Energy Ministry, which backs industry executives’ contention that even more concessions are needed. According to Reuters, the Finance Ministry is seeking to reform the tax regime in ways that would effectively eliminate certain tax breaks. The changes would affect all of the greenfield projects that have been granted concessions, sources inside the Finance and Energy Ministries told the agency last week. The Russian government has awarded tax exemptions and concessions for a total of 198 brownfield and greenfield projects, the agency said, citing information from Vygon Consulting. The sources did not reveal full details of the Finance Ministry’s plan. Reuters noted, though, that the reforms were part of a wider effort to overhaul the current tax regime governing oil development. This drive calls for

emphasising profit taxes as a means of generating budget revenues. The existing system relies on mineral extraction tax (MET) and crude export duties. The proposals under discussion call for levying a 40% tax on oilfields once they begin to turn a profit, plus a profit-based tax equivalent to 70% of positive cash flow, said Sergei Yezhov, Vygon Consulting’s chief economist. The tax would apply to all oilfields, even those that were previously granted breaks, he told Reuters. Meanwhile, he added, greenfield projects would reap the benefit of being exempt from taxes in their earlier stages of development. Russia now applies a 10% tax to projects at this stage, he noted. Operators that have not won any tax concessions for their fields are now paying the equivalent of 42% of world oil prices in taxes – specifically in MET and export tariffs, he added. Russian President Vladimir Putin had said previously that his government would not raise taxes on any sector of the economy before 2018.n

JKX board ousted by Russian investor FSU THE board of London-listed JKX Oil and Gas was axed last week by the firm’s second largest shareholder, Russian investment fund Proxima Capital Group. It marks the latest offensive in a long-running battle for control over the Ukraine-focused explorer. A special shareholder meeting called by Proxima on January 28 lasted only 15 minutes, resulting in five of the company’s nine directors being removed. Days earlier two other directors had resigned over Proxima’s proposed coup, while two more stepped down immediately after the vote. Proxima is headed by Russian businessman Vladimir Tartarchuk and has a 19.9% stake in JKX. The Moscowbased firm said that a management shake-up was

necessary following a share price collapse of 91% since 2010 and the board’s failure to resolve a costly tax dispute with the Ukrainian authorities. “We do not believe that shareholders should be held to ransom any longer by a board that has presided over a massive destruction of shareholder value and yet still argues for the supposed need to retain their ‘extensive experience and corporate knowledge and memory,’” Proxima said in a statement ahead of the vote. On 26 January, the board blocked JKX’s largest shareholder Eclair Group and ally Glengary Overseas from the vote, claiming that the two stakeholders were collaborating with Proxima to seize control of the company. The Financial Times quoted sources close to

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the now-ousted board who accused the three investors of trying to take control of JKX without making a formal bid or paying a premium. Proxima denies colluding with Eclair and Glengary. Eclair and Glengary, which are controlled by Ukrainian billionaire Igor Kolomoisky and Russian oligarch Alexander Zhukov respectively, hold a combined 38% stake in JKX. The pair launched a failed attempt to topple JKX’s management in 2014, resulting in the board issuing another voting ban against them, which was later overturned in the UK courts. JKX is one of the largest independent oil and gas producers in Ukraine, with further assets in neighbouring Hungary, Russia and Slovakia. The company’s interim revenues for 2015 slumped by 40.2% on the year to US$44.4 million. This led to a net loss of US$13.8 million, down from a net gain of US$8.5 million for the same period of 2014. The board blamed the poor results on the challenging

oil price environment, deterioration in the Ukrainian investment climate and lower production from core upstream assets. Its output from assets in central Ukraine and southern Russia for the first six months of 2015 fell by nearly a fifth year on year to 8,611 barrels of oil equivalent per day. The new board of five directors said after the vote, during which around 70% of shareholders backed the reshuffle, it would update shareholders about future plans for JKX in the coming weeks. The April opening up of the market will allow users to choose their power suppliers. The retail market for large business users such as factories has already been liberalised.n Joseph Murphy, Editor, FSU Oil & Gas, NewsBase Ltd. Any questions? Please get in touch Email: josephm@newsbase.com

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Harbour Energy stalks Pacific E&P LATIN AMERICA STRUGGLING Canadian operator Pacific E&P has become the target of a hostile takeover by Harbour Energy. Pacific operates oil and gas assets across Latin America and was previously targeted by Harbour last year. Pacific’s share price has slumped and the company delayed bond payments this month, sparking default fears. Investment firm EIG Global Energy Partners, Harbour’s parent company, has made several bids in the past few weeks to buy Pacific’s debt and take over the company. The company made a bid on January 13 to buy Pacific’s outstanding notes. EIG’s assessment at the time was that “Pacific E&P is on the verge of insolvency and out of options.” The following day Pacific announced that it would be using the 30-day grace period to delay its bond payments. EIG then appealed to Pacific investors, saying in a statement on January 20 that the situation was set to “spiral downward ... in the face of a rapidly deteriorating market environment.” The company is offering a price of 17.5 cents on outstanding 2019, 2021, 2023 and 2025 bonds, which it said Pacific was unlikely to make payments on. Investors had until January 27 to submit tenders

at the 17.5 cent price. Tenders will remain open until February 10 at 12.5 cents. The tender requires that agreement be reached with 80% of creditors and 66.67% of investors on each series of bonds. Energy Finance Week approached Pacific E&P for comment on the possible default and takeover speculation, but the company did not respond. Pacific’s bondholders look likely to oppose the latest takeover attempt. Harbour’s previous bid for the company fell through after a group of shareholders led by Venezuelan businessman Orlando Alvarado thwarted the move. This time, UK-based investment firm Ashmore Group is one of eight bondholders that are pushing for an alternative to the EIG restructuring plan. Together the eight companies control 40% of the bonds EIG has bid for, meaning they could successfully block the tender offer. Ryan Stevenson, Editor, Latin American Oil & Gas, NewsBase Ltd. Any questions? Please get in touch Email: ryans@newsbase.com

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Iran eyes quick return to international bond market, with innovative structures MIDDLE EAST WITH international sanctions now rolled back, Iran is looking to secure up to US$550 billion in new capital required to bring the key sectors of its economy up to international standards as soon as possible. The Iranian Finance Ministry believes that it can count on around US$350 billion in readily available finance for projects development, most of which is geared towards the oil and gas sector. However, as much of this is going to be made in staggered payments over the next three years, Tehran is looking to raise at least US$150 billion additional new funding very quickly. Energy Finance Week can exclusively reveal that the solution has now been found in the form of a return to the international foreign currency-denominated sovereign bond market, with extremely innovative structures to boot. Looking for a way out Much like the rest of the Middle East’s domestic banking infrastructure, Iran’s banks are not now expected to shoulder any more of the burden of building out the country’s broad economic infrastructure than they have already done, Mehrdad Emadi, senior economist for risk analysis and energy derivatives markets consultancy Betamatrix, told Energy Finance Week. Official data shows that the ratio of non-performing loans to total loans was 13.4% as of the end of the first half of 2015, with the figure understood to have risen since then, and market estimates pointing to nearly double that figure with the equivalent of US$40 billion at the top end for non-performing loans. “The banks and other financial institutions had been directed by the government to make loans to quasi-state vehicles at extremely preferential rates so they have heavy debt burdens, and the upshot is that the stock market cannot fund the type of money needed for Iran’s plans, and a fresh new pool of capital is required,” Emadi said. Indeed, according to a statement last week from Constantinos Kypreos, senior analyst at ratings agency Moody’s Financial Institutions Group, in New York, the “biggest issues Iranian banks face is the high level of nonperforming loans and the low capital buffers.” He added that the Iranian banking sector remains undercapitalised, with a reported 2014 capital adequacy ratio of 6.8% compared with a regional average capital adequacy ratio

of over 13/14%. This has a knock-on effect to broadening and deepening out the Tehran Stock Exchange, Emadi noted, in that it raises problems in companies raising capital, given the over-extension of the domestic banks. “Many of the most heavily weighted companies are quasigovernment institutions that came into existence to serve a specific government purpose, were heavily financed by the state, and now have large debt burdens with the banks,” he told Energy Finance Week. Going global Consequently, the favoured option currently reaching the end of the signing-off process is for Iran to re-enter the international bond markets, having first (in the next six months or so) tested the water with quasi-sovereign issues. “Quasi-sovereign in this context means local currency bonds issued by either of the big state hydrocarbons firms – the National Iranian Oil Co. (NIOC) or the National Iranian Gas Co. (NIGC) – which carry an implicit government guarantee, and this is likely to appeal both to those international oil companies (IOCs) who are eyeing bigger, direct investment into Iran’s oil and gas fields, and to those who want to take a more limited risk exposure to Iran in the early days of its post-sanctions recovery,” said Sam Barden, CEO of Middle Eastern fund manager SBI Markets. Speaking to Energy Finance Week, Ildar Davletshin, head of oil and gas research for Moscow-based Renaissance Capital, said: “Getting involved early on, as well, in whatever size, would also allow firms to judge how efficiently the resultant bond funds were utilised by the government towards their original intended purpose or whether they would wind up being frittered away on a range of non-oil and gas projects, like happened with [Venezuela’s] PDVSA.” He added that just as importantly, this would “afford participating firms preferred bidding status for future offers, be they in local currency- or foreign currency-denominated.” Novel approaches Although Iran’s lack of a sovereign debt credit rating over the past few years might appear to go against it in terms

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of launching any successful bond issues, the Iranians have been working on three strategies to ensure that any such landmark issues would meet with extraordinary investor demand, initially from the Far East and then from the major European Union (EU) countries. 1: The first of these strategies is to ensure that for issues denominated in rials the return is guaranteed at a suitably high coupon rate, over and above that which might be expected to be offered from a B/B+ rated sovereign body (which Iran was just prior to its ratings being removed because of sanctions), we understand from a number of sources close to the Iranian administration. “There is a lot of investable money both in Iran and with Iranians abroad [Dubai alone is home to around 500,000 Iranians who saw their bank accounts shut down under the sanctions regime] that for reasons mentioned earlier will not go into the stock market but is looking for better than deposit rate bank account returns,” said a source in Tehran. “It may be that these domestic currency bonds are issued by the NIOC or the NIGC but in effect they will be sovereign bonds but at a higher corporate bond rate yield level and this would allow Iran’s firms and banks to repair their balance sheets ahead of a growth push,” he added. 2. Energy Finance Week understands from a number of sources close to the Iranian administration that at a very advanced stage of completion is the issuing of bonds, also in rials, but – crucially for potential foreign buyers – carrying with them the option not only to be redeemed in rials but in any major currency (US dollars, Euros, Yen, British Sterling, and Swiss Francs) that a buyer prefers at the prevailing spot rate of the day the buyer decides to redeem the paper. “This would really be a cutting edge idea for bond issuance, but it would offer huge assurance to potential buyers that not only are the bonds liquid but also that any adverse currency risks [from effectively holding rials] does not arise,” said Christopher Cruden, CEO of hedge fund Insch Capital. 3. Finally, and perhaps even more astonishing than the multiple currency option idea is that one of the currencies on offer for redemption will be the Chinese renminbi. “There is a lot of money around that is looking for yield in a potentially very high-growth country now that China is slowing down, and down the line, not far from now, Iran could well be in the same bracket as China and India

were a few years back of being the exact best place to be,” Robert Savage, CEO of commodities-based hedge fund, CC Track, told Energy Finance Week. In addition, Iran has the advantage of not just being viewed as an oil play, in the same way as Saudi Arabia, but as a rounded economy. Indeed, Charles Robertson, chief economist for RenCap, said that quite aside from its massive hydrocarbons wealth, no other economy in the Middle East comes close to Iran’s in terms of its diversification. “It may surprise a lot of people but in reality Iran exports in every single category of the IMF’s ‘breakdown of exports’ list bar none, including – by the way – alcohol, albeit for industrial use,” he added. In this context, several major international bond issues are planned by Iran, with the Peoples Bank of China (PBOC) in Beijing acting as sole lead underwriter and principal distributor of the bonds. “The structure will be that the Iranian government, or state vehicle, will issue a bond through the PBOC, which will be backed by the Chinese central bank, either in renminbi or another currency pegged at a specific rate to the renminbi, and the PBOC will then distribute them simultaneously to the Central Bank of the Republic of China (Taiwan) in Taipei, and the Monetary Authority of Macao,” said the well-placed source in Tehran. On the one hand, the risk for the Chinese in this structure will be minimal, as all of the international sovereign issues will be fundamentally backed by some of the world’s largest hydrocarbons reserves, while, on the other hand, the upside is huge, as it will promote the use of the renminbi as one of the world’s truly international currencies, which China regards as befitting its standing on the world stage. “China has recently been included in the IMF’s Special Drawing Rights [SDRs, joining US dollars, Euros, Yen, and Sterling], so having a vast amount of bonds coming from one of the world’s top energy sources being denominated and traded in renminbi would be a very enticing prospect for international bond investors,” said Jeremy Stretch, head of markets strategy for CIBC. “It’s the sexiest prospect in frontier/emerging markets in the sexiest currency; what’s not to like?”n Ian Simm, Editor, Middle East Oil & Gas: Any questions? Please get in touch Email: ians@newsbase.com

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Kuwait’s pre-budget talk sets the stage for more realistic approach With governments in the Middle East suffering from low oil prices, Kuwait has taken the surprisingly conservative approach of basing its budget on an oil price of US$25. MIDDLE EAST STATEMENTS in advance of the official release of its 2016/17 budget suggest that Kuwait is showing a degree of realism regarding the oil pricing complex that would be welcome in many other major Middle Eastern oil producers. “Kuwait benefits from having a population of less than four million but even with this comparative advantage over places like Saudi Arabia, it is still looking to maintain essential spending on its oil sector and selected nonhydrocarbons businesses,” Richard Mallinson, senior geopolitical analyst for energy consultancy Energy Aspects, told Energy Finance Week. This comes “within the confines of a more realistic oil price assumption than many other states at the moment,” he added. Indeed, on January 26 Kuwaiti Finance Minister, Anas al-Saleh said that he expected the price of oil for the shortly-to-be-ratified end March 2016/beginning April 2017 budget to be set at around US$25 per barrel for the Emirate, which depends on oil export revenues for 90% of its overall government income. Although this price assumption is still slightly above the prices currently being paid for Kuwaiti oil, it is nonetheless a considerably more realistic price assumption than the US$45 per barrel for the budget that began on April 1, 2015 and runs to March of this year. It is also more accurate than the US$40 per barrel assumption that is thought to form the core of the new Saudi budget. Plugging the hole The projected deficit of Kuwait’s new draft budget would be 12.2 billion dinars (US$40.2 billion), nearly 50% higher than the previous year, according to the Finance Ministry, and there are a number of realistic options for this to be plugged. Sam Barden, CEO of consultancy and trading firm SBI Markets said: “A signal that the size and structure of the estimated deficit does not trouble the Kuwaitis is the fact that rather than utilise any part of the [the Kuwait Investment Authority’s (KIA)] ‘Reserve Fund for Future Generations’ to be drawn on in times of economic distress] they are actually going to contribute to it again this year

[700 million (US$2.3 billion) payment in over 2016/17],” he told Energy Finance Week. “There is a solid residual domestic and international interest in Kuwaiti assets, as evidenced by the fact that its benchmark stock index is trading at a [price to earnings (P/E)] ratio of over 14 times – notably higher than many of its regional counterparts, despite poor liquidity.” He added that this “implies that there are significant opportunities for it to roll out traditional and Islamic bond offerings in the coming weeks and months should it need to do so, in addition to IPO opportunities being there for its local firms.” These available pools of potential funding safety nets are quite separate from the near-US$600 billion in assets currently held by, the KIA, the world’s fifth biggest sovereign wealth fund. Spending sensibly On the expenditure side, although last week’s comments by Kuwait’s Emir, Sheikh Sabah al-Ahmed al-Sabah, calling for better management of spending and budget cuts to cope with declining revenues were interpreted as preparing the ground for cuts in energy and food price subsidies, major difficulties remain in effecting these policies. “The country still has a political structure that serves to stymie such effective rises in energy and food prices, so it is unlikely that we will see anything meaningful in this respect any time soon,” Mallinson noted. He added that the ruling Sabah family’s supremacy in the executive branch – including the right to form the government, which it has frequently invoked – shows no sign of being modified. Instead, it is more likely that even before looking to the capital markets for further funding, individual Kuwaiti firms will seek financing deals on an independent basis to fund key projects. A case in point, in fact, was the recent announcement by the CEO of state-run Kuwait Petroleum Corp. (KPC), Nizar al-Adsani, that as part of its planned expenditure of around US$100 billion over the next five years, it has just signed a memorandum of understanding (MoU) with K-sure and KOEXIM, the Korean credit agencies, for a total

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of US$11 billion to finance some upstream, downstream, petrochemical and transportation projects, in addition to sounding out international investors for potential interest in traditional and Islamic bond offerings from the firm. State of play This type of quasi-sovereign/high grade corporate funding initiative is likely to be the shape of things to come for Kuwait, underlined Barden, with its probable success likely to encourage other countries in the same position, notably Bahrain and Abu Dhabi. For Kuwait, with an eminently achievable target of increasing its oil production to 4 million bpd by 2020, up from the current 2.5-2.6 million bpd (3 million bpd by the end of this year), there is no interest in curtailing investment in what it regards as its key projects, following on the unprecedented 9.7 billion dinars (US$32.05 billion) worth of contracts awarded during 2015, 20% more than the year before. With more than half of these related to the oil and gas sector – even as oil and gas prices were plummeting – this year should see the award of a number of contracts to

overhaul its refineries in order to increase both the quality and quantity of its petroleum products. These projects include the long-delayed awarding of the 3.9 billion dinar (US$12.90 billion) new refinery contract at Al Zour in July and the development of the Lower Fars Heavy Oil production facility in the north of the country for 1.2 billion dinars (US$4 billion). This is likely to begin in earnest in April, with the contract for the LNG Import and Re-gasification Terminal, also in the Al-Zour area, valued at 1 billion dinars (US$3.3 billion), and the subsequent integration of a 2.12 billion dinar (US$7 billion) Olefins III plant into the refinery complex to proceed sometime in December. Upstream development of the north of the country is also set to continue apace, as is the Kuwait Oil Co.’s (KOC’s) tendering of three contracts, worth 1.7 billion dinars (US$5.62 billion) for the development of Jurassic non-associated gas reserves in four fields: West Raudhatain, East Raudhatain, Sabriyah, and Umm Niqa. These were originally scheduled for award in Q4 2015, but are now scheduled to occur in February and April of this year.n

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Week 01• 08 February • 2016

Iraq juggles funding sources to maintain spending MIDDLE EAST BAGHDAD is planning to launch the first local currency bonds for more than a decade this year to help fund the country’s huge projected budget deficit, Finance Minister Hoshyar Zebari announced in late January. Last year’s abandoned attempt to tap international markets is also to be revived, he added – but this time with World Bank guarantees in order to secure a more acceptable borrowing rate. Enabling payments to be made to the international oil companies (IOCs) operating Iraq’s crucial southern fields in order to encourage continued investment in maintaining production forms a key motivation for such fund-raising exercises, even as foreign firms are urged to scale back their development budgets to ease fiscal pressure. While institutions such as the World Bank would not directly assist such oilfield expansion projects, a longdelayed venture to monetise the associated gas produced at the major fields is set to receive funding out of a facility extended by the Washington-based institution targeted at energy efficiency schemes. Baghdad issued treasury bills worth several billion dollars to local banks in 2015, responding in part to a request in March to Zebari from Oil Minister Adil Abd al-Mahdi in the face of mounting arrears owed to IOCs – then put at around US$9 billion outstanding from 2014. In August, Al-Mahdi reported having cleared the previous year’s dues and professed to be working at paying in instalments the outstanding dues accrued that year of roughly the same amount. Despite well-publicised discussions to persuade the main IOC operators to reduce budgets for 2016 and to agree a revised contract model less onerous than the current fee-per-barrel arrangement, charges for this year are nevertheless set to be higher as a result of increased production levels from fields such as West Qurna 2 – the second stage of the supergiant West Qurna field – and Halfaya over the course of 2015. Exports averaged 2.5 million barrels per day in

January last year while they had climbed to 3.2 million bpd by last month – with production apparently up at around 4.1 million bpd, according to somewhat inconsistent data released by the Oil Ministry over the course of the month. Presenting the 2016 budget in October, Zebari indicated that a portion of the projected 105.8 trillion-dinar (US$74.6 billion) deficit would be met by a combination of local and international borrowing. In late January, he announced plans to issue three-year local-currency bonds, worth 5 trillion dinars (US$4.5 billion) and carrying an interest rate of 10%, this year. “Now we have to do it,” he told a press conference, in reference to the delayed plans for such issuance last year. “We don’t have a set date yet, but we have to do the sale this year.” Zebari and Central Bank of Iraq governor Ali al-Alak have both signalled the government’s intention to seek US$2 billion through an international bond issue, having cancelled a planned sale of the same value last October over the 11.5% yield apparently being demanded by investors. Citigroup, Deutsche Bank and JP Morgan have reportedly been retained to arrange the new roadshows – with investors this time to be offered the security of a World Bank guarantee, the central bank governor revealed in December. “It will be US$2 billion but [the World Bank] will guarantee maybe 40-50% of that,” he said. “That will open the market more … to attract more investors.” International rating agency Standard & Poor’s assigned the government a B- rating – six notches below investment grade – ahead of the last approach, which coincided with a further fall in oil prices compounding the obvious security, political and economic problems deterring buyers. Conditions now are even less propitious, with the government earning US$2.9 billion from oil sales in December, compared to US$3.9 billion in August before the last set of roadshows began. Baghdad has also mooted plans to seek further funds

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from the IMF, which agreed to provide a US$1.2 billion loan under its rapid financing instrument to assist with “urgent balance of payments and budget needs” in July. In December, the fund announced approval of a Staff Monitoring Programme for the Iraqi authorities in order for Baghdad “to establish a track record of policy credibility to pave the way to a possible Fund financing arrangement”. During the same month, the World Bank agreed to provide US$1.2 billion to support reforms targeted at “longstanding challenges in the financial sector, public financial management and energy efficiency and security”. The energy efficiency component offers some hope to the IOCs involved in the long-delayed, hugelyambitious South Gas Utilisation Project to capture and

utilise associated gas – currently flared – to meet urgent local needs in the power and industrial sectors. Zebari confirmed in late January that he wished to assign US$300 million of the World Bank funds to Basra Gas Co. – the joint venture between state-owned Basra Oil Co., Royal Dutch Shell and Japan’s Mitsubishi Corp. implementing the flagship scheme – to enable progress. According to a breakdown published by the IMF at the end of last year, the main components of the government’s external financing plans for 2016 are the US$2 billion Eurobond issue, and concessionary loans of US$500 million from the Jeddah-based Islamic Development Bank and of US$502 million from Japan International Cooperation Agency.n

Syria’s oil sector losses reach US$60bn MIDDLE EAST SYRIAN Petroleum and Natural Resources Minister Suleiman Al Abbas announced last week that the civil war in his country has caused losses to the oil sector amounting to just over US$60 billion. Speaking to Iran’s Mehr News Agency (MNA), he highlighted that Syria’s oil and infrastructure has been seriously damaged by the ongoing conflict “particularly in the systems of pumping facilities and equipment.” Abbas said Syria had managed to maintain a degree of gas production that allowed it to provide sporadic electricity supply. Gas production is estimated at 523 million cubic feet (15 million cubic metres) per day, whereas prior to the war, gas output averaged slightly more than 1 billion cubic feet (28 mcm). At that point Syria was also producing an average of 387,000 barrels per day of oil, some of which was exported to Europe. Including that which is being pumped illegally by Daesh, the country’s oil production is thought to be around 50,000 bpd, with only around 10,000 bpd coming from legitimate operations. Reports have suggested that the Syrian government is purchasing oil and gas from Daesh, which controls large parts of the

country’s oil-producing region in the north-west. MNA blamed the US and Syria’s neighbours for the degradation of the country’s mid- and downstream sectors. The refinery at Homs has been seriously damaged during fighting with rebels but the Banias refinery on the Mediterranean coast is still operational, and has been processing Iranian crude. Iran has also been supplying the country with refined products. A US-led coalition carried out a number of airstrikes against oil facility targets in the Daesh-held areas of northern Syria over the weekend. According to Kurdish news agency ARA News, the airstrikes targeted Daesh tactical units as well as oilfields, and it added that one oil facility had been completely destroyed. Syria has complained to the United Nations about the US coalition airstrikes saying that the facilities being targeted are not part of Daesh’s smuggling operations. Meanwhile, Russian news agencies have quoted a spokesman for the Russian Ministry of Defence as saying that Russian aircraft have destroyed a stash of oil products belonging to Islamic group Jaish al-Islam in the Syrian province of Damascus.n

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Major shale drillers rein back capital spending Hess, Continental Resources and Noble Energy have been among the most prolific shale drillers so far to announce large cuts to capital budgets this year. NORTH AMERICA UNEXPECTEDLY large cutbacks in their 2016 capital expenditure plans by three major US shale oil drillers – Continental Resources, Hess and Noble Energy – illustrate how oil prices are hurting even the most successful producers, and more cuts are anticipated to follow among other shale drillers. The cuts announced on January 26 ranged from 40% to 66%, and came as oil and gas production from most of the US’ shale plays was forecast to fall again this month, according to January data from the US Energy Information Administration (EIA). Capex cuts The largest cut, announced by Continental, North Dakota’s second largest oil producer, was 66%. Continental said it planned to spend US$920 million this year, down from US$2.7 billion in 2015. Meanwhile Noble announced its 2016 capex budget would be US$1.5 billion, 50% down on 2015, and Hess said it planned to spend US$2.4 billion this year, down 40% from capex of US$4 billion last year. The announcements marked the second straight year of budget cuts by companies generally considered to be among the most resilient group of shale oil producers. As a result, the moves indicate that capex budgets among others will also be cut further than previously anticipated in 2016. For instance, Bernstein Research had previously forecast an average 38% cut for the shale industry this year. The Hess budget was roughly 20% below preliminary 2016 guidance of US$2.9-3.1 billion provided in October 2015, and included a US$470 million allocation for shale resources, mainly to operate two rigs and bring around 80 new wells on line in the Bakken play in North Dakota. “In response to the current low oil price environment, we have significantly decreased our 2016 capital and exploratory expenditures and we plan to reduce activity at all of our producing assets,” said Hess’ president and chief operating officer, Greg Hill. “Moreover, we will continue to pursue further cost reductions and efficiency gains across our portfolio.” Hess’ announcement followed its biggest loss in the last 13 years in 2015. Last year, Hess also exited the Malang shale oil block

in China, as well as pulling back in the Utica so that it could concentrate its unconventional activity on the Bakken. Continental was also affected by its decision in the autumn of 2014 to scrap its hedges, leaving it fully exposed to the swing in crude prices at a moment when other producers had locked into higher prices. Those that did so got some breathing space as the oil price began to fall even further. Meanwhile, Noble has also cut its quarterly dividend by 44% to US$0.10 as it attempts to save cash. The company saw its debt increase last year following its July 2015 acquisition of Rosetta Resources for about US$2 billion, which was the first significant deal among US shale oil producers following the collapse in oil prices. Noble announced a US$283 million loss in the third quarter, having already pulled all rigs out of the Marcellus shale gas earlier in 2015. It said in November that it would cut jobs and capex and curtail exploration activity until the oil market rebounded enough to support increased spending. What next? The downward trend in the shale industry shows no short-term signs of reversing. The number of active rigs in the Bakken has fallen to its lowest level since at least 2011. In 2015, many operators managed to boost output as they devised new ways to maximise shale oil production from their most prolific assets, but now there is speculation that the limits of performance optimisation may have been reached. Noble, Continental and Hess all said they would cut the number of rigs drilling new wells in US shale oil plays. Continental has projected that it will produce about 10% less oil this year and will not be profitable until oil prices return to above US$37 per barrel. The company is aiming to spend most of its 2016 budget in the Bakken. The South Central Oklahoma Oil Province (SCOOP) formation will receive Continental’s second largest budgetary allocation. Reduced output will be reported by many other shale players this year. The EIA projects that total US crude output will drop to around 8.7 million bpd this year. In

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terms of capex, one of the exceptions to the rule that shale drillers are cutting back is likely to be Pioneer Natural Resources, which stated recently that it aimed to spend US$2.4-2.6 billion this year, up from US$2.2 billion in 2015. Hess’ oil and gas production for the whole year is anticipated to fall to 330,000-350,000 barrels of oil equivalent per day, compared with 368,000 boepd in 2015. Hess has noted improving returns on its Bakken activity, where its net production is forecast to average 95,000-105,000 boepd in 2016. Hess has also said that it has no significant financial stress on its balance sheet, and that it possesses the cash to fully fund its 2016 programme. In a market where crude prices will have to rise again significantly to buoy confidence, many companies’ output stands to fall. While this development would help ease oversupply in the global oil market, much of this production could come back on line fairly easily when prices rebound. Meanwhile, growing debt is weighing ever more heavily on banks, amid concerns that they will increasingly be forced to call in their worst-performing loans. One concern for some shale players in the months ahead will be the stance taken by such lenders. In their second semi-annual 2015 review of producer loans,

undertaken in the autumn of 2015, banks generally gave the US shale industry more time to cut costs and raise cash. While there is speculation that the next round of redeterminations will be tougher on shale producers, there are incentives for lenders to help drillers stay afloat in order to stand the best chance of having their loans eventually repaid.n Anna Kachkova, Editor, North America Oil & Gas, NewsBase Ltd. Any questions? Please get in touch Email: annak@newsbase.com

US producers expected to post US$15 billion in losses NORTH AMERICA INDEPENDENT US oil and gas producers are expected to report annual losses of over US$15 billion for 2015 by the end of the first week of February as a result of the oil price crash, Bloomberg has reported. Hess, Murphy Oil and Anadarko Petroleum were among those to have already reported net losses in the last week. Occidental Petroleum and ConocoPhillips followed in reporting losses this week. Last week, Hess reported a net loss of US$1.82 billion for the fourth quarter of 2015 and US$3.06 billion for the year. This was the firm’s first annual loss since 2002. The New York-based producer cut its 2016 drilling budget by 40% to US$2.4 billion. The firm also reduced its estimate of proven oil and gas reserves by 24%, citing low crude prices and the reduction in its drilling plan. Murphy, meanwhile, posted a net loss of US$2.27 billion for 2015. The firm also cut its capital spending for 2016, which at US$825 million is 62% lower than last

year. Murphy also said that it had cut its workforce by around a fifth last year. Anadarko said on February 1 that it expected to reduce its capital spending by about 50% this year. The Houston-based company reported a net loss of US$1.25 billion for the fourth quarter of 2015. On February 4, Occidental reported a fourth-quarter loss of US$5.18 billion, worse than had been expected. This was the company’s largest loss in over 25 years. The company said it expected its 2016 capital programme to be no more than US$3 billion, with production growth of 2-4% from ongoing operations. ConocoPhillips posted a US$3.5 billion loss for the fourth quarter of 2015. The company also lowered its capital spending guidance for 2016 from US$7.7 billion to US$6.4 billion Producers have also cut back their workforces and restructured debt – in some cases in an effort to avoid insolvency. However the number of bankruptcies among

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smaller US drillers has been rising. US-based ratings agency Standard & Poor’s cut the credit ratings of some leading US oil and gas companies this week, in a move that illustrated the severity of the crisis affecting the oil sector. Chevron and Apache were among the companies to see their ratings cut, with super-majors also not proving immune to the slump. Indeed, Chevron posted its first loss since 2002 last week, despite analyst expectations of a profit. The company posted a fourth-quarter net loss of

US$588 million, compared with a net profit of US$3.47 billion a year ago. In addition, three shale oil and gas producers – Continental Resources, Hunt Oil and Southwestern Energy – were downgraded from investment grade to junk status by Standard & Poor’s. ExxonMobil, the largest US-based oil company, was also put on watch for possible downgrade of its AAA rating. It is currently only one of three firms in the US to have an AAA status.n

Penn West cuts 2016 capital budget by 90% NORTH AMERICA PENN West Petroleum announced last week that its board of directors approved a capital expenditure budget of C$50 million (US$36 million) for this year, down 90% from its 2015 capex, in response to the low oil price environment. “Our 2016 capital budget is consistent with the strategy announced on September 1, 2015, which limits our total expenditures to funds flow from operations, while driving down our cost structure,” the company said in a statement released on January 28. The company, which focuses on conventional oil and gas, added that it planned to shut in 4,000 barrels of oil equivalent per day of production that is currently considered uneconomic in the first three months of 2016. “Given the present state of the commodity price environment, our 2016 capital budget reflects the reality of living within our means at current price levels and managing the business on a week-to-week basis,” said Penn West’s president and CEO, Dave Roberts. “In 2016, we will be prudent in limiting our capital expenditures to protect our balance sheet and we will continue our focus on the economics of every dollar we spend even at the expense of maintaining our production levels. We intend

to only proceed on opportunities with near-term payout at current price levels.” This latest reductions followed several cuts that Penn West made to its 2015 capex, bringing it down to C$480 million (US$348 million) by the end of the year from C$840 million (US$609 million) projected in late 2014. In addition to the budget cuts, Penn West was forced to let go of 400 full-time employees and contractors in 2015, which represented roughly a third of its staff. Penn West produced over 77,000 boepd in 2015. The company expects production this year to fall to 60,000-64,000 boepd.n

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Brass LNG on course Nigeria seeks US$3.5 for FID billion in loans AFRICA

NIGERIA’S government is in talks for concessionary loans worth US$3.5 billion from the World Bank and African Development Bank (AfDB) to help finance a planned record budget this year, Finance Minister Kemi Adeosun said. While discussions are going on, a formal request has not yet been made, Adeosun said by telephone on January 31. The government plans to tie the funds to specific capital projects, she said. A request for assistance has not been made to the International Monetary Fund. President Muhammadu Buhari’s government is seeking to spend its way out of an economic crisis triggered by a collapse in oil prices. Nigeria is Africa’s biggest oil producer and relies on crude for almost all its exports and two-thirds of government revenue. Buhari has proposed boosting this year’s budget to a record 6.1 trillion naira (US$30.7 billion). Adeosun said on January 31 that authorities will borrow about US$5 billion in external debt from multilateral agencies and the Eurobond market to plug record budget gap of 3 trillion naira. Lawmakers in Nigeria’s parliament will begin deliberations this week on the 2016 spending plan, Adeosun said on January 31. Authorities will begin nondeal roadshow meetings with investors to sound out a potential sale of US$1 billion of Eurobonds in February, she said. Nigeria has issued dollar bonds twice, most recently in 2013. Crude oil prices have dropped about 46% since June last year and were trading as low as US$35.14 per barrel in London on January 25. The West African nation’s economy probably grew 3.2% last year, the slowest pace since 1999, according to a Bloomberg survey of economists. BLOOMBERG, January 31, 2016

BRASS LNG chairman Dr Jackson Gaius-Obaseki has expressed confidence that the Final Investment Decision (FID) for the project would be taken in the next couple of months. This is because the management has stepped up efforts to ensure that the project receives the necessary support from all the key stakeholders. Speaking at the 11th Annual General Meeting of the company in Abuja, Gaius-Obaseki commended the shareholders and stakeholders for their steadfastness and doggedness in supporting the Brass LNG project despite the challenges it had faced. According to him, 2015 was an eventful one for Brass LNG, especially as it continued to forge tirelessly towards attaining FID on the project. Listing some of the major milestones recorded in 2015, Gaius-Obaseki disclosed that the company was able to successfully achieve cost optimisation. According to him, this was attained through the renegotiation of contract rates, commercial terms, scope of works and reclassification of contracts and purchase orders from dollars to naira denominations in compliance with the Central Bank of Nigeria, CBN’s directive. He noted that this had allowed for significant cost savings in respect of the approved budget of the project, without giving further details. He said that the Pre-Front End Engineering Design, PreFEED Concept Evaluation Study, PFCES, had been completed as well as the feed gas sensitivity scenarios, and the final reports submitted to the company. Gaius-Obaseki also disclosed that the project site security contract for pre-FID had been awarded, while the Enterprise Resource Planning, ERP, a robust tool that will automate and create seamless processes within the company has been completed. He insisted that the Brass LNG project was still very feasible and on course, despite the low price of crude oil in

the international market. VANGUARD (NIGERIA), February 4, 2016

Zambia’s energy sector to benefit from AfDB loan ZAMBIA will greatly benefit from the US$12 billion that the African Development Bank (AfDB) has appointed to the energy sector in Africa, special assistant to the president for press and public relations Amos Chanda has said. This came to light when President Edgar Lungu met AfDB president, Akinwumi Adesina on the sidelines of the just ended 26th African Union (AU) summit in Addis Ababa. Chanda told journalists after the closed door meeting that US$12 billion had been set aside for investment in the energy sector in Africa over a five-year period. “During the bilateral meeting, the AfDB announced that they are putting huge investments in the energy sector, agriculture and women empowerment, but particularly in the energy sector. The bank has a US$12 billion initiative for the next five years that is at continental level and a significant amount of that money will come to Zambia because the AfDB president says there is huge potential for hydro, solar and thermal power”, he said. TIMES OF ZAMBIA (ZAMBIA), February 1, 2016

ASIA

Snags hit Iran-China oil debts deal IRAN’S petrochemical chief Abbas Sheri Moqaddam says China needs to improve a mechanism it has offered to settle oil debts to Iran through funding the Iranian petrochemical projects. Indications

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are growing in Iran that the country has come across problems with China over a mechanism to receive at least 20 billion euros in overdue debts from past sales of oil to the country through investments in the Iranian petrochemical projects. Sheri Moqaddam, the managing director of Iran’s National Petrochemical Company (NPC), has been quoted by the domestic media as saying that China needs to modify its offered mechanism and come up with a better version that would take into account Iran’s post-sanctions business environment. “Iran’s conditions have changed after the removal of the sanctions against the country and that China cannot dictate its own plans on Iran,” Iran’s official news agency IRNA has quoted Sheri Moqaddam as saying. “By considering the removal of the sanctions, the foreign companies need to present more efficient business offers for co-operation with Iran over its petrochemical industry.” The official, who is also a deputy oil minister, made the comments in response to an IRNA question on whether the Iranian petrochemical companies have refused to receive loans from China as proposed in an industrial finance mechanism to settle oil money debts with Iran. “We cannot put China aside,” Sheri Moqaddam said. “China has good companies, but it should remember that the conditions they had considered for working with us during the sanctions era should be changed in the postsanctions era.” PRESS TV (IRAN), January 29, 2016

Shell to sell refining stake to Malaysia Hengyuan International SHELL has reached a conditional agreement with Malaysia Hengyuan International Limited (MHIL) for the

sale of its 51% shareholding in the Shell Refining Company (SRC) in Malaysia for US$66.3 million. It is MHIL’s intention for SRC to invest in the upgrades needed to meet the Euro 4M and Euro 5 requirements. The transaction is expected to complete in 2016, subject to obtaining regulatory approval. Shell Malaysia Trading will ensure security of supply to its retail and commercial customers in Malaysia and honour other existing commitments through an existing comprehensive supply strategy that includes a long term offtake from Shell Refining Company. The sale is consistent with Shell’s strategy to concentrate its global downstream footprint and businesses where it can be most competitive. Malaysia continues to be an important country for Shell. Shell is the leading retail fuels and lubricants provider and continues to invest in growing these businesses in the country. Other recent downstream divestments include the sale of downstream businesses in Australia and Italy; a number of retail sites in the UK; and the initial public offering of, and further drop downs to, Shell Midstream Partners LP. Shell has also agreed the sale of its marketing business in Denmark and Norway, its LPG businesses in France and a 33.24% shareholding in Showa Shell Sekiyu KK. NEWSBASE, February 1, 2016

Meralco sales grew 5.4% in 2015 MANILA Electric has registered a 5.4% growth in power sales last year compared to the previous year, mainly on account of stronger power demand across all market segments. “The 2015 growth stood at 5.4%, equivalent to 36,615 GWh,” Meralco senior vice-president Alfredo Panlilio said. The growth is historically higher compared to the average growth over the past years, which has been a low of 3%. The Meralco official

said growth was attributed to a stronger demand across all segments, particularly from its residential customers, “due to lower generation charges; low inflation; El Nino, which meant higher temperatures; a stable supply; and a lot of our customer programmes.” In 2014, the company’s sales volume grew by 3.2% to 35,160 GWh over 2013, due largely to the combined commercial and industrial volumes of Meralco and Clark Electric Distribution Corp. Meralco President Oscar Reyes had said stronger sales would help achieve Meralco’s core-profit guidance of 18.5 billion Philippine pesos for 2015. The number, if attained, is slightly higher than the company’s 18.1 billion peso actual core net income in 2014. BUSINESSMIRROR (PHILIPPINES), February 1, 2016

EUROPE

EU must turn a blind eye to Hungary “hijacking” energy efficiency funds HUNGARY’S Environmental and Energy Efficiency Operational Programme (EEEOP), which was accepted by the European Commission in February 2015, clearly states that above 50,000 households are expected to benefit from the scheme by 2013, while the EC has no legal tool to force member states to implement all the measures outlined in the programme, reveals a letter written by European Commissioner for Regional Policy Corina Cretu to Hungarian MEP Benedek Javor. Cretu has practically acknowledged that although Brussels frowns upon the fact that Hungary has launched programmes targeting only public buildings and funds would

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be available for the improvement of the private building stock, it has no means to force the country to reach the target it had committed to. Contrary to what local daily newspaper Nepszabadsag reported, this would not lead to an obligation to repay the EU funds. EEEOP, which was accepted by the commission in February 2015, clearly states the need for energy efficiency grants for both publicly and privately owned buildings. Yet, Janos Lazar, the prime minister’s cabinet chief, has fastidiously maintained for the past three months that the EU funds (some US$41.5 million) earmarked for environmental and energy efficiency were never intended for distribution to private households but rather for public institutional use. PORTFOLIO.HU (HUNGARY), January 29, 2016

Boralex closes financing for French wind farms CANADIAN renewables developer Boralex has closed 63 million euros (US$68 million) in financing for wind farms in France. The amount is funded by Credit Industriel et Commercial (Group Credit Mutuel) in collaboration with Desjardins. The Canadian company agreed 20.6 million euros in long-term financing for the 13.8 MW Touvent wind farm, which amounts to nearly 85% of the total investment. Drawdown on the facility is subject to certain customary conditions which are expected to be lifted shortly. Amortised over a 15-year period, the loan will bear interest at a rate of approximately 2.5% for the full term of the loan, 90% of which will be covered by a forward rate agreement. Construction on the Touvent wind farm has begun and commissioning is slated for the second quarter of 2016. Boralex has also arranged long-term refinancing for the 34.5 MW St-Patrick

wind farm to the tune of 42.4 million euros. The financing will be used in part to repay the balance of the loan currently in place for the St Patrick facility, which is 28.4 million euros. As a result, Boralex will be in a position to reinvest some 10.5 million euros, net of unwinding costs and other fees, in new equity in its projects under development and support its growth initiatives. SEENEWS (UK), February 1, 2016

New GBP 12 million oil industry jobs fund being set up A new GBP 12 million (US$17.5 million) fund to help people who face losing their jobs in oil and gas to gain new skills and find new work is being set up by the Scottish government. First Minister Nicola Sturgeon said the Transition Training Fund should help keep expertise in the energy sector, or in related roles in manufacturing. She said job losses were “distressing”. The fund will offer grants for individuals to acquire specialised skills or further training. “It is absolutely crucial that we take every possible action to retain the expertise that the industry has built up over decades so that it remains flexible enough to capitalise on exploration investment and future oil price rises,” She said. Also announced was GBP 12.5 million of Scottish Enterprise funding aimed at helping oil and gas firms sustain growth and compete internationally by developing new innovative technologies. The announcements, and plans for a GBP 20 million Aberdeen International Airport revamp, came just days after a GBP 504 million package was announced earlier by the UK and Scottish governments to improve infrastructure in Aberdeen and Aberdeenshire, and to attract new jobs. North East Scotland Labour MSP Lewis Macdonald said: “The Scottish government’s offer of extra money to

train those made redundant by the oil and gas industry is a step in the right direction but a year later than it should have been. “This is the kind of initiative which should have been put in place when the North Sea saw the first signs of a crisis, not after an estimated 65,000 people have already lost their jobs.” North East Scotland Lib Dem MSP Alison McInnes welcomed the support. “What we now need to know is how exactly this fund will be distributed, who can apply and clear details as they come in of how many people are actually benefiting,” she said. BBC NEWS (UK), February 1, 2016

L AT I N A M E R I C A

Mexican economic reforms forge ahead MEXICO has raised taxes to levels close to OECD averages as part of a move to reduce its dependency on oil proceeds and help it to weather financial storms. Mexico’s currency, the peso, is vulnerable to oil price fluctuation, which exposes the whole economy to the vagaries of the energy market. Mexican Finance Minister Luis Videgaray said that in the three years since he became finance minister in December 2012, Mexico had reduced its budget dependence on oil from 39.2% to 19.6%, portraying it as due to financial discipline. A part of this decline has come from oil prices, however, which averaged US$101.96 per barrel in 2012 and US$43.29 per barrel in 2015, according to Energy Ministry data. Mexico received 922 billion pesos (US$50.1 billion) from various Pemex sources in the first 11 months of 2015, some 25% of national income when taxes on fuel are included, 19.6% if this tax is ignored. Due to the energy reform that began in December 2012, Mexico reduced its direct taxes on Pemex, which lost its monopoly in August 2014 but is

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the only active producer. Its special hydrocarbons right, which raked off 70% of oil sales income, was replaced by a lower percentage and passed to a Bank of Mexico-managed fund that disburses to the government after a delay. NEWSBASE, January 29, 2016

Gazprombank ready to boost co-operation with PDVSA ON February 2, Venezuela’s Minister of Petroleum and President of PDVSA, Eulogio Del Pino, held a meeting with vice-president of Gazprombank Boris Ivanov in Moscow as part of Del Pino’s tour of OPEC and nonOPEC countries organised in an effort to promote a balance of oil prices. “Gazprombank confirmed its willingness to continue strengthening the alliance with the Venezuelan state oil company,” the PDVSA statement read. RIA NOVOSTI (RUSSIA), February 3, 2016

MIDDLE EAST

IMF says Bahrain should cut deficits as oil prices fall THE International Monetary Fund has urged Bahrain to take “sizable” steps to reduce its growing budget deficit as slumping oil prices have sharply reduced exports and government revenues. The warning following the IMF’s annual consultation with the island Gulf state comes as another struggling oil producer, Azerbaijan,

is seeking as much as US$3 billion in IMF financing aid and a US$1billion World Bank loan, according to a source familiar with the matter. An IMF team is currently meeting with Azeri officials in Baku on a factfinding mission, discussing technical assistance and assessing possible financing needs. The steep drop in oil and commodity prices in the past year amid strong global production and lower Chinese demand has sparked concerns about the economic stability of a number of oil and commodity exporters, including Venezuela, Nigeria and Brazil, now mired in its worst recession in decades. In Bahrain, the IMF said it forecasts gross domestic product growth to fall to 2.2% in 2016 from 3.2% in 2015 and 4.5% in 2014. The country’s budget deficit will remain elevated at 15% of GDP, causing debt to increase substantially. “With the oil price decline expected to persist over the medium term, external and fiscal vulnerabilities have intensified, and consumer and investor sentiment has weakened,” the IMF said in its review. A sizable fiscal adjustment is urgently needed to restore fiscal sustainability, reduce vulnerabilities, and boost investor and consumer confidence,” the Fund added. Near-term fiscal measures could include the implementation of a previously agreed value added tax, reducing spending on social transfers and freezing public-sector wages, it said. Fiscal consolidation will help support Bahrain’s dollar peg, the IMF said, adding that Bahraini banks’ strong capitalisation and liquidity will help them weather a slowdown in growth.

Oman to call bids for US$6 billion refinery by June OMAN intends to ask companies to submit bids before June to build the US$6 billion Duqm oil refinery and petrochemical complex, a report said. Winning bidders will be named by the end of the year, Oil and Gas Minister Mohammed Al Rumhi was quoted as saying in the Muscat Daily report. He added that negotiations on a US$1 billion natural gas pipeline from Iran were still in progress. TRADE ARABIA (BAHRAIN), February 2, 2016

NORTH AMERICA

NGP commits US$200 million to PCORE Exploration & Production II PCORE Exploration & Production II announces it has raised US$200 million of equity commitments from Natural Gas Partners through NGP Natural Resources XI, the most recent NGP private equity fund focused on natural resources, and the PCORE II management team. Based in Dallas, Texas, PCORE II is an exploration and production company driven by subsurface understanding and engineering execution and is focused on developing core unconventional oil prospects in North America. PCORE II (US), February 1, 2016

REUTERS, January 29, 2016

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