New base 502 special 22 december 2014

Copyright © 2014 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced,

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NewBase 22 December 2014 - Issue No. 502 Khaled Al Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE

Iraq BP’s long game in Iraq is paying off Anthony McAuley The National + NewBase

BP’s business model in Iraq has proved to be highly profitable, even as progress has sometimes appeared to be slow and plans have had to be curtailed. The London-based company had attracted scepticism when it became the first of the big-oil majors to commit to the country after the 2003 war.

BP last week marked five years since signing its technical services contract to increase production from the “supergiant” Rumaila South oilfield, one of Iraq’s oldest and a large source of revenue. In that period, said BP, the field has produced 2 billion barrels, delivering US$180bn to the government.




“Now, we can’t claim all the credit for that because we inherited an existing oilfield,” said Michael Townshend, the head of BP Iraq and Middle East chief. “But what we can claim credit for is the amount of incremental production that we have delivered. So, over the last five years we can say we’ve delivered about $75bn of incremental revenue to the government and we’ve spent about $5bn to do it.”

BP estimates it can produce at least another 20 billion barrels from the field over its life. But that is something of a double-edged sword for Iraq, as the recent oil price slump has shown the country’s over-reliance on oil in general, and on the Rumaila field in particular.

With production running at an average of 1.3 million barrels per day at the field, total annual revenue at oil prices of $100 a barrel was just under $50bn a year, accounting for a large percentage of the federal budget.

If oil prices stay at $60 a barrel through next year, annual revenue from the field drops by about $20bn. That makes BP’s goal, under a new contract agreed in September, to increase production to an average of 1.4 million bpd next year crucial, even if it would only fill a relatively small $2bn of the budget hole.

The importance of Iraq to BP has also grown, as evinced by the frequency of visits by Bob Dudley, the chief executive.Under the terms of the new extended contract, BP and its partner PetroChina agreed to lower the field’s plateau production target from 2.85 million bpd, which was due to be hit in 2016. The new target is to raise production to 2.1 million bpd by 2024, and to lengthen the life of the field.

BP and PetroChina extended their deal by five years to run to 2034. They also negotiated higher shares of the operating company — they will raise their stakes by 9.5 per cent to 47.5 per cent and 46.5 per cent respectively, cutting the government’s share from 25 per cent to 6 per cent.

What is particularly interesting for BP is that the terms of the contract mean it doesn’t lose out if oil prices fall. The operating company gets paid $2 for every incremental barrel produced, after costs, and it takes this and its cost reimbursement as

physical oil in tankers lifted from Basra’s terminal. Furthermore, the incremental barrels are counted after taking into account a natural decline in the field of 17 per cent annually, so BP and PetroChina’s share of production has been on a rising trajectory since the contract began.

What happens when oil prices fall? “It means you need more ships,” said Mr Townshend. “If the oil price halves you need twice as many ships as before. It’s very simple.” BP won’t discuss the terms of its deal, but a simple calculation based on what BP has said about the field’s success suggests it has recovered its share of investment in the field of a little over $2.5bn and made a further $1.5bn on top of that over four years. That would tally with some analysts’ estimates of a return on capital of between 15 and 20 per cent a year.




How the company fares over the next few years depends on what terms it has agreed with the government about how to calculate the field’s natural rate of decline, as that determines what is considered “incremental” barrels for which the consortium gets paid. It is likely those terms remain favourable on the new higher equity percentage, as BP is raising its investment next year — by $1bn, to $3.5bn, Mr Townshend said.

In his presentation to BP investors this month, the company’s head of upstream, Lamar McKay, made only brief mention of the Middle East (passing references to Iraq and Oman). He instead concentrated on BP’s big projects in places such as offshore Angola, Azerbaijan, and the contiguous United States. But the Middle East prospects are showing growing potential and attractiveness, especially in a low oil price environment.

“Across the Middle East you tend to have contracts that are not oil-price sensitive, whether that’s Iraq, where it’s dollar-on-the-barrel; Oman, where it’s gas prices; [or] a recently signed deal in Kuwait that is oil-price independent,” said Mr Townshend. “On the other hand, each of the countries is very oil-price dependent, so budgets get squeezed. It’s good for the company but a very unique mix, an interesting dynamic.”

The challenges for BP at Rumaila are mainly logistical. The additional $1bn investment next year is constrained by what the company estimates is physically possible, given the particular impediments in Iraq that can slow projects down, such as moving equipment into the country, hiring and training staff, getting visas for specialised staff, etc.

The difficulties that have limited progress so far are clear from a visit to the field’s largest gathering point, Markesia, which is headed by Arkon Abdul Satter, an Iraqi petroleum engineer. “Much of the equipment here [is] dated from 1956, when the field started to produce,” said Mr Satter. “Everything was badly in need of upgrading in 2009.” Although there was a big jump from 900,000 bpd in 2009 to 1.2 million bpd the year after that, the next 100,000 bpd increase took more than three years.

That is because BP has had to make many incremental changes across a huge industrial site — 80 by 20 kilometres — while battling

against natural reservoir decline. Many of the refittings, refurbishments, and expansions take considerable time when trying to do them without disrupting existing flow. The work in the first four to five years focused mainly on drilling dozens of new wells and adding updated well pumps, removing bottlenecks, increasing the amount of gas that is used productively and not flared, and implementing better management operating plans.




The work of the next phase — which aims to get production to 1.8 million bpd by 2018 and plateau at 2.1 million bpd by 2024 — will be mostly about water.

Rumaila has hitherto produced “dry” oil — that is to say it came up with a low water cut that is still only 10 per cent. That percentage will grow substantially as water is used in coming years to increase pressure in the wells to pump up more crude. But that will require large-scale engineering projects to pump water into the well, to dehydrate and desalinate the oil at the gathering stations, and then pump the water back in an efficient way that does not harm the environment.

Getting the water engineering right would mean increasing the recovery rate of the well, and that goes straight to BP’s bottom line — every percentage point increase in the well’s recovery rate equates to about $200m for BP.

“A 40 per cent recovery rate for Rumaila would give you another 20 billion barrels. That’s realistic,” said Mr Townshend. “Will that view change in five years? Yes. It is dependent on being able to handle the water, getting pressure water in, recycling the water and pushing it back down again — 8 million barrels of water a day. These are massive challenges, and similar challenges exist in Abu Dhabi and Kuwait.”

But at least people are more focused on the engineering now, at least for the country’s south.

“When we first talked about Iraq five years ago virtually the only questions we got were, ‘well tell us about security’,” Mr Townshend recalled. “I think that’s changed now. I think perceptions have changed.”




Jordan Approves Gas Deal With Shell Jordan’s Petra News Agency + NewBase

Jordanian cabinet on Sunday approved a gas deal between the National Electric Power Company and Shell, reported Jordan’s Petra News Agency. The company was chosen after an international competitive tender, the news agency reported without providing details about the quantity of fuel the utility would be buying.

The cabinet had assigned the national power company, as buyer of natural gas, to negotiate with Shell the terms of the deal that would secure about 15 percent of Jordan s energy needs, Petra News Agency added. In September, Noble Energy announced the execution of a non-binding Letter of Intent (LOI) to supply natural gas from the Leviathan field, offshore Israel, to the National Electric Power Company Ltd. (NEPCO) of Jordan. Delivery of natural gas is expected to occur at a border location between Israel and Jordan, following the completion of related pipeline infrastructure. However, the deal has been facing stiff opposition as country’s main opposition party threatened Saturday to take legal action against anyone in the kingdom who signs the deal with Israel. Jordan’s House of Representatives also voted against a draft agreement that would have stipulated importing gas from Israel.

Al Aqabah Port , Jordan

Proposed for LNG terminal – Al Aqabah port




Oman: Musandam gas-fired power plant reaches EPC stage

The wholly state-owned Oman Oil Company (Oman Oil or OOC) and its partner LG International Corporation (LG) from South Korea made the final investment decision for their joint venture Musandam Power Company (MPC) independent power plant (IPP) to be built at Tibat-Wilayat Bukha in the Musandam Governorate of northern Oman.

Usually in the Sultanate of Oman the electrical power generation is financed, decided and operated by the Oman Power and Water Procurement Company (OPWP) under the govern of the Ministry of Finance Authority for Electricity Regulation and the Public Authority for Electricity and Water (PAEW).In order to support its economical development, Oman is planning to double its installed base of power generation in the period 2012 to 2019. In parallel to this expansion, Oman Oil is now able to develop its tight gas reserves as the most efficient source of supply for it petrochemical industry and electrical pow er generation.

With this new source of energy available in large quantity, Oman can not only envisage to build new gas-fired integrated water and power plants (IWPP) in industrial zones, but also to convert diesel-powered generation facilities into

clean gas for the more remote locations.

In that respect, Oman Oil made the final investment decision (FID) for the construction of the Musandam independent power plant (IPP) in the upper north of Oman, along the Strait of Hormuz. Scaled at 120 MW, this Musandam Power Company IPP project has been designed to run primarily with natural gas but also to accept diesel fuel as alternative in respect with its remote location from the gas fields.

Therefore instead of conventional gas turbines, Musandam IPP will be powered by reciprocating engines optimally designed to operate with gas and diesel.

Since Musandam electrical grid is independent from Oman national grid, the load capacity can range widely from 10MW to the nominal capacity of 120MW, the Musandam IPP will be equipped with 15 engines. In order to guaranty the performances of this dual-fuels

facility, Oman Oil has decided to award the engineering, procurement and construction contract (EPC) together with 15 years long-term service agreement (LTSA).

To secure the gas supply, Oman Oil and LG have decided to locate the Musandam IPP next door to the Musandam Gas Plant (MGP) currently under construction and to be operated by its upstream subsidiary Oman Oil Company Exploration and Production (OOCEP). With Musandam Gas Plant to come into commercial operation by end of 2015, Oman Oil is willing to build the Musandam IPP project on fast track so that it could start gas-fired power generation in 2016.




Pakistan: K-Electric turns to LNG to boost Karachi’s power supply LNG news + NewBase

Pakistan’s K-Electric Limited (formerly Karachi Electric Supply Company Limited) has signed two separate Memoranda of Understanding (MoU) with Engro with the objective of increasing power supply to the city of Karachi and it’s adjoining areas using LNG as fuel for new generation.

Introduction of LNG in the fuel mix is part of KE’s strategy to achieve fuel diversity and enhance power availability in its franchise area within shortest possible time.

According to details, K-Electric signed the first MoU with Elengy Terminal Pakistan Limited (ETPL), a wholly owned subsidiary of Engro Corporation Limited, which is currently developing the first LNG terminal in Pakistan.

Keeping in view the long term forecast of receding gas supply from indigenous sources, KE has shown keen interest in the development of LNG terminal by ETPL.

Press statement added that the second MoU is a tri-partite MoU signed between KE, Engro Powergen, and GE international for the development of a high efficiency 225 MW combined cycle LNG fired power plant at Port Qasim.

Engro Powergen, a subsidiary of Engro Corporation is the lead developer of the project and is expected to engage GE as the technology provider and investor in the project. KE will off-take power from the project under a long term PPA and has also shown interest to invest in the power company. The project is expected to be fast tracked and will be the first instance in Pakistan where an LNG fueled IPP shall be developed.




Indonesia: Lion Energy in agreement to explore highly prospective North Sumatran acreage. Source: Lion Energy

Lion Energy has joined forces with conventional PSC holders to explore highly prospective North Sumatran acreage Highlights

• Agreement signed with Bohorok conventional PSC holders to jointly evaluate unconventional acreage in Lion’s core Sumatra focus area

• Application for unconventional joint study to proceed incorporating conventional PSC parties

• Lion secures option to acquire a 15% interest in the conventional Bohorok PSC

• Seismic acquisition completed and well planned for 2015

Lion Energy has announced that it will join forces with conventional PSC holders Bukit Energy and New Zealand Oil & Gas to jointly explore an area within the prolific North Sumatra Basin. As part of the transaction Lion has an option to acquire a 15% interest in the conventional Bohorok PSC and the conventional PSC partners have the opportunity to acquire a 45% interest in Lion’s unconventional joint study application over a partially overlapping area.




Development plan for Gullfaks Rimfaks valley submitted Press Release Stat Oil .

Statoil and its partners have decided to develop the Rutil discovery located in the Gullfaks Rimfaks valley in the North Sea. Providing close to 80 million barrels of oil equivalent, the development will extend the lifetime of the Gullfaks A platform.

Ivar Aasheim, head of field development on the NCS, submitted the PDO for the Gullfaks Rimfaks valley development to Norway’s minister of petroleum and energy Tord Lien today, 16 December. (Photo: Ole Jørgen Bratland, Statoil)

The plan for development and operation (PDO) was submitted to the authorities today, 16 December. “We are pleased about the investment decision we have made that will extend the period of profitable production on the Gullfaks A platform. By using existing infrastructure and standardized solutions we are able to create great value for our owners,” says Ivar Aasheim, senior vice president for field development on the Norwegian continental shelf (NCS).

“Statoil is currently implementing a major improvement effort to reduce costs and increase profitability to secure longterm activity and value creation on the NCS. The Gullfaks Rimfaks valley is a good example of this work,” underlines Aasheim.

Gas and condensate will be transported in existing pipeline for processing in the gas processing facility at Kårstø north of Stavanger. The processed gas is transported to markets on the European continent.

“Production from the Gullfaks Rimfaks valley helps secure jobs and value creation from the Gullfaks field and throughout the whole value chain beyond 2030,” says Kjetil Hove, senior vice president for the operations west cluster in Development and Production Norway (DPN).

The investment costs of the Gullfaks Rimfaks valley development are estimated at 4.6 billion 2014 NOK.

The Gullfaks Rimfaks valley development will consist of a standard subsea template with two simple gas production wells, and possibilities of connecting two more wells. The well stream will be connected to the existing pipeline to the Gullfaks A platform.

The Gullfaks Rimfaks valley is one of Statoil’s fast track projects, aiming at realising resources quickly and cost-efficiently by for example using existing infrastructure while it is still available.

Production start is scheduled for the first quarter of 2017. The licence partners are Statoil (operator) (51%), Petoro (30%) and OMV (19%).




US: Wind power capacity additions expected to increase in Q4- 2014 Source: U.S. Energy Information Administration, Forms EIA860A and EIA860M On December 16, the Senate approved a bill (already passed by the House of Representatives on December 3) that retroactively extends the federal production tax credit (PTC) for wind plants, which had previously expired at the end of 2013. However, because of timing, this extension is unlikely to spur significant additional wind development activity beyond what installers had already planned. First introduced in 1992, the PTC allows eligible wind generators to take an inflation-adjusted tax credit per unit of generation (2.3 cents per kilowatthour in 2014) for the first ten years of operation.

Note: Data include facilities with a net summer capacity of 1 MW and above only. Data are reported as of November 25, 2014, covering through September of 2014. Data are based the

reported online dates of currently operational or planned wind generation facilities. The "<2005" category includes all currently operational projects added prior to 2005.

Previously, the PTC had been extended on an incremental, short-term basis and had been allowed to lapse or nearly lapse on several occasions. Before 2013, the tax credit legislation specified that projects must be in service by the end of the year. The 2013 and 2014 extensions were different, as they required that projects must have been under construction by the end of the year. Projects could meet the construction deadline by either starting physical work or through the safe harbor clause, which required them to spend at least 5% of the project cost prior to the end of 2013 and maintain continuous progress thereafter. Under the 2013 extension and subsequent IRS guidance, wind projects attempting to qualify for the PTC through this safe harbor provision had an incentive to enter service prior to the end of 2015 in order to ensure PTC eligibility.




The change in eligibility requirements and the timing of the 2013 extension (the deadline wasn't extended past 2012 until the beginning of 2013) contributed to wind capacity additions falling from an all-time high of 13 gigawatts (GW) in 2012 to less than 1 GW in 2013. Capacity additions in the first three quarters of 2014 have totaled less than 2 GW, but project developers have reported to EIA an additional 3 GW of expected capacity additions for the fourth quarter. They have also reported to EIA an additional 11 GW of wind projects with expected completion dates in 2015, primarily in states such as Texas, Oklahoma, Illinois, Iowa, and Minnesota.

Source: U.S. Energy Information Administration, Forms EIA860A and EIA860M Note: Data include facilities with a net summer capacity of 1 MW and above only. Data are

reported as of November 25, 2014, covering through September of 2014. Data are based the reported online dates of currently operational or planned wind generation facilities.




US power sector employment declines, except for renewable electricity

generators .Source: Bureau of Labor Statistics (BLS) Quarterly Census of Employment and Wages

The electric power generation sector lost more than 5,800 jobs from January 2011 through June 2014 despite a gain of nearly 1,800 non-hydro renewable electricity generation jobs, according to the latest data available from the Bureau of Labor Statistics (BLS).

BLS data shown here only reflect jobs in electric power generation, not the jobs associated with electric transmission and distribution systems. Also, jobs involved in the construction of new facilities, processing or transportation of fuels, or behind-the-meter distributed generation installations and service (e.g., solar panel installers) are not counted by BLS as jobs in the electric power sector.

The overall decline in electric power generation jobs coincides with a period in which the United States has seendeclining year-over-year electricity sales, driven by energy efficiency improvements, and growth in distributed generation, such as behind-the-meter rooftop solar, among other factors. Additionally, the growth in some types of non-hydro renewable generation, particularly wind and solar, brings relatively few ongoing operations and maintenance jobs.

Fossil fuels. Recent coal plant closures, which were partially offset by new natural gas capacity additions, drove the net decline of 1,750 fossil fuel power generation jobs since 2011. While BLS does not break out the jobs category by fuel, the operations of the new natural gas power plants are less labor intensive than those of the older coal plants that are being displaced. Fossil fuel plants are more geographically dispersed across the country compared to other power generation categories, but the states that have the most fossil fuel jobs are: Texas, Michigan, Florida, Indiana, and Ohio. Fossil fuel jobs include employment at plants fueled by coal, natural gas, and petroleum.

Nuclear. Nuclear power facilities have shed more than 4,900 jobs since 2011. Most of the nuclear generation job losses occurred since January 2013, and are attributable to reactor closures at three locations: Southern California Edison's San Onofre Nuclear Generating Station, Dominion's Kewaunee plant near Green Bay, Wisconsin, and the Duke Energy's Crystal River




plant in Florida. Additionally, Entergy announced it will close operations at its Vermont Yankee plant at the end of 2014, which will result in further job losses. South Carolina, Pennsylvania, New York, Michigan, New Jersey, and Illinois are the states with the most nuclear plants.

Renewables . BLS first provided separate data series for renewable generation job categories in 2011. All four categories of non-hydro renewables have seen gains in power generation jobs since 2011. Solar has led the way, with the number of jobs related to the operation of solar generation installations in the electric power sector more than tripling in that timeframe. Although wind jobs have grown at a slower rate than solar since 2011, increasing 16%, there are still more than twice as many wind jobs as solar jobs in the electric power sector.

Renewables jobs are more geographically concentrated than fossil fuel jobs, corresponding to the location of renewable generation capacity. California is home to the most solar, geothermal, and biomass jobs, and the second-most wind jobs behind Texas. Employment at hydroelectric generators fell 6% over this time, but it was still more than double that of all other non-hydro renewable generation employment.




Oil Price Drop Special Coverage

Oil slide exposes weakness in shale drillers’ insurance Bloomberg + NewBase

Tumbling oil prices have exposed a weakness in the insurance that some US shale drillers bought to protect themselves against a crash.

At least six companies, including Pioneer Natural Resources Co and Noble Energy Inc, used a strategy known as a three-way collar that doesn’t guarantee a minimum price if crude falls below a certain level, according to company filings. While three-ways can be cheaper than other hedges,

they can leave drillers exposed to steep declines.

“Producers are inherently bullish,” said Mike Corley, the founder of Mercatus Energy Advisors, a Houston-based firm that advises companies on hedging strategies. “It’s just the nature of the business. You’re not going to go drill holes in the ground if you think prices are going down.”

The three-way hedges risk exacerbating a cash squeeze for companies trying to cope with the biggest plunge in oil

prices this decade. West Texas Intermediate crude, the US benchmark, dropped about 50% since June amid a worldwide glut. The Organisation of Petroleum Exporting Countries decided on November 27 to hold production steady as the 12-member group competes for market share against US shale drillers that have pushed domestic output to the highest since at least 1983.

Shares of oil companies are also dropping, with a 49% decline in the 76-member Bloomberg Intelligence North America E&P Valuation Peers index from this year’s peak in June. The drilling had been driven by high oil prices and low-cost financing. Companies spent $1.30 for every dollar earned selling oil and gas in the third quarter, according to data compiled by Bloomberg on 56 of the US-listed companies in the E&P index.

Financing costs are now rising as prices sink. The average borrowing cost for energy companies in the US high-yield debt market has almost doubled to 10.43% from an all-time low of 5.68% in June, Bank of America Merrill Lynch data show.

Locking in a minimum price for crude reassures investors that companies will have the cash to keep expanding and lenders that debt can be repaid. While several companies such as Anadarko Petroleum Corp, Bonanza Creek Energy Inc, Callon Petroleum Co, Carrizo Oil & Gas Inc and




Parsley Energy Inc, use three-way collars, Pioneer uses more than its competitors, company records show.

Scott Sheffield, Pioneer’s chairman and chief executive officer, said during a November 5 earnings call that his company has “probably the best hedges in place among the industry.” Having pumped 89,000 bpd in the third quarter, Pioneer is one of the biggest oil producers in US shale.

Pioneer used three-ways to cover 85% of its projected 2015 output, the company’s December investor presentation shows. The strategy capped the upside price at $99.36 a barrel and guaranteed a minimum, or floor, of $87.98. By themselves, those positions would ensure almost $34 a barrel more than yesterday’s price.

However, Pioneer added a third element by selling a put option, sometimes called a subfloor, at $73.54. That gives the buyer the right to sell oil at that price by a specific date.

Below that threshold, Pioneer is no longer entitled to the floor of $87.98, only the difference between the floor and the subfloor, or $14.44 on top of the market price. So at the price of $54.11, Pioneer would realise $68.55 a barrel.

David Leaverton, a spokesman for Irving, Texas-based Pioneer, declined to comment on the company’s hedging strategy. The company said in its December investor presentation that “three-way collars protect downside while providing better upside exposure than traditional collars or swaps.”

The company hedged 95,767 bpd next year using the three-ways. If Thursday’s prices persist through the first quarter, Pioneer would realise $1.86mn less every day than it would have using

the collar with the floor of $87.98. That would add up to more than $167mn in the first quarter, equal to about 14% of Pioneer’s third-quarter revenue.

The strategy ensures that the bulk of Pioneer’s production will earn more than Thursday’s market price. The three-ways will also prove valuable if oil rises above the subfloor.

“What they have is much better than nothing,” said Tim Revzan, an analyst with Sterne Agee Group Inc in New York. “But they left some money on the table that they could have locked in at a better price.”

Noble Energy used three-ways to hedge 33,000 bpd, according to third-quarter SEC filings. Assuming Thursday’s prices persist, Houston-based Noble will bring

in $50mn less in the first quarter than it would have by locking in the floor prices.




Bonanza Creek, based in Denver, Colorado, set up three-ways with a floor of $84.32 and a subfloor of $68.08, SEC records show. If prices stay where they are, the company will realise $8.1mn less in the first quarter than it would have by just using the floor.

Ryan Zorn, Bonanza Creek’s senior vice president of finance, said that the comparison doesn’t take into account the advantages of the strategy. The proceeds from selling the $68.08 puts helped pay for the protection at $84.32, without which Bonanza Creek would likely have purchased cheaper options with a lower floor.

“The other comparison is if we’d done nothing,” Zorn said. “I view it as being much better than being unhedged.”

Representatives for Anadarko, Noble, Carrizo and Parsley didn’t return e-mails and phone calls seeking comment.

“Because we’ve had high energy prices for so long, it could have given them a false sense of confidence,” said Ray Carbone, president of Paramount Options Inc in New York. “They picked a price they thought it wouldn’t go below. It has turned out to be very expensive.”

Callon’s first-quarter three-ways cover 158,000 barrels with a floor of $90 and a subfloor of $75, company filings show. Callon, based in Natchez, Mississippi, will get $3.3mn less that it would have realized by using the $90 floor, assuming prices stay where they are.

“Certainly, if we’d had the foresight to know prices were going to crater, you’d want to be in the swap instead of the three-way,” said Eric Williams, a spokesman for Callon. “Swaps make more sense if you knew prices were going to go down the way they did, but a few months ago everyone was bullish.”

Russia will not get a second miracle out of this oil slump Robin Mills The National + NewBase

Russia seems to experience an oil-triggered economic crisis every decade or so. The 1986 price slump led to the fall of the USSR, US$10 per barrel oil in 1998 derailed the tentative post-Soviet recovery and brought the unknown Vladimir Putin to prominence, while Russia scraped through the short price slump following the 2008-9 recession.




This year, both the oil price and the rouble have beaten Mr Putin to 63 – his birthday is next October, while Brent crude was $60.70 per barrel on Friday and the rouble touched lows of 77 to the dollar on December 16.

It is worth recalling what happened after 1998. The Russian economy rebounded surprisingly quickly. Elected president in 2000, Mr Putin initially followed a prudent and orthodox macroeconomic policy, improved tax collection and accumulated “rainy day” savings. Helped by rising oil prices and lower domestic costs because of the weaker rouble, the oil industry revived and grew strongly up to 2004. Apart from 2008’s economic crisis, production has increased every year since 1999.

It is those higher oil prices that have underpinned Mr Putin’s rule: social benefits and cheap imports for ordinary Russians; freedom for enrichment for a circle of insiders. He has re-nationalised most of the Russian petroleum industry, allowed foreign investment only on stringent and usually unfavourable terms, and employed oil and gas projects as strategic, political tools.

Things may not be so favourable this time. Oil prices could remain relatively low for an extended period. The weaker rouble will help Russian oil producers cut costs and bring the national budget closer to balance – but at the cost of stoking inflation, while sharply higher interest rates choke off economic growth.

As Anders Åslund, an expert on the Russian economy, has observed, Russia has $100 billion of external debt repayments due in both 2015 and 2016, which it can neither refinance – because of sanctions – nor pay off, because of the plunging oil price.

The oil industry will not be able to stage a repeat of the “West Siberian miracle” that followed 1998. It has exhausted the backlog of cheap, under-exploited fields – new reserves are in remote parts of East Siberia, or in Arctic waters or shale, which require sanctioned western technology to develop.

Russia has never been able to devise a system that taxes oil production efficiently while still keeping marginal fields commercial. Rather than squeezing more from the sector, if anything tax rates will have to fall, further stressing the budget.

The recent major gas deal with China, concluded on very good terms for the Chinese, was presented – misleadingly – as a blow against Europe. Such a tendency to politicise energy exports is not profitable and scares customers; China is obviously a major and growing market, but Russia does not want to become Beijing’s resource colony. The conflict in Ukraine needs a face-saving settlement for the Kremlin that lifts sanctions.

This crisis may spur Russia to do what it should have done long ago: tackle the institutionalised corruption that has become the system and improve the security of investments, both to reduce domestic capital flight and attract international investment. The oil industry can still drive growth – as it does today in the United States – but needs to be diverse, efficient and technologically advanced. With its great territory and human resources, Russia does not have to be a one-trick economy.

Moscow has fruitlessly discussed the falling oil price with Riyadh, but will never choose to cut its own




production significantly. The Arabian Gulf countries, already on the opposing side over the Syrian civil war, should be wary of retaliation against their energy industries. And Russia’s struggles carry a warning to all petroleum exporters – the memories of the good times are not much comfort when the decade’s oil slump rolls around.

Energy shares still risky despite recent slump Reuters + NewBase

Bargain hunters may have to think twice before scooping up shares of beaten-down oil services companies, as a slump in crude prices raises questions about their ability to pay back debt.

The damage from the drop in crude, down by nearly half in six months, is pummeling the bonds of energy companies and sending shock waves through the high-yield credit market as investors reassess the firms’ balance sheets.

Spreads on the bonds of energy companies have widened by 148 basis points to 841 basis points over US. Treasuries in the last two weeks, according to Bank of America Merrill Lynch data. That has led to a number of deals being pulled — and effectively shut the primary market for a time as contagion fears rippled across the markets, according to IFR.

With depressed oil prices, the default rate on high yield bonds in the US energy sector — about a fifth of the entire US high yield market — could rise to 10 per cent, according to UBS analysts.

“People are just starting to dump these bonds given the trajectory of oil prices,” Saxo Bank Chief Investment Officer Steen Jakobsen said. “When the flight out of the sector accelerates it’s going to be ugly.” In JPMorgan’s ‘worst-case scenario’ where oil would remain around $65 for the next three years, the cumulative default rates in the energy sector could rise to as high as 25 to 40 per cent.

“We’re reaching a point where there’s a risk of seeing corporate and sovereign defaults in energy-producing countries, which could revive global systemic risks,” said Christophe Donay, head of strategy at Pictet, which has $441 billion in assets under management and custody.

The MSCI World energy sector index has tumbled 30 per cent since June, wiping out about $1 trillion in the market value of oil and gas shares, roughly the size of the combined annual GDP of Saudi Arabia and Qatar, according to Thomson Reuters Datastream data.




Corporate bonds in oil-producing Russia — where the rouble has tumbled against the dollar have been particularly hard hit, with JPMorgan’s CEMBI benchmark Russian corporate debt index showing yield spreads have more than doubled this year to above 1,000 basis points. Dividends scrapped

The energy sector’s first line of defence against falling cash flows has been to scrap dividend payments, drawing the ire of investors used to rich payouts. Offshore oil driller Seadrill, seismic data firm CGG and marine services and engineering group Fugro

have already scrapped payouts. Seismic survey specialist PGS warned on Friday it was likely to do so. More drastic measures, such as capital increases, may be required. Goldman Sachs analysts, downgrading their rating on Seadrill to “sell”, wrote on Friday that the firm would be in breach of its debt covenant in 2016 if Brent hovers in the $70 a barrel region, warning that this could trigger an equity issue.

Goldman also flagged ‘balance sheet risks’ at PGS and CGG. “Some companies with a significant level of debt will have to think whether they can continue to keep paying dividends, or even more drastically, if they will be able to repay their debt,” said Edouard Vecchioli, co-manager of hedge fund Parus Finance, which has short selling positions on a number of energy stocks.





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Khaled Malallah Al Awadi, Energy Consultant MSc. & BSc. Mechanical Engineering (HON), USA ASME member since 1995 Emarat member since 1990

Mobile : +97150-4822502 [email protected] [email protected]

Khaled Al Awadi is a UAE National with a total of 25 years of experience in the Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed great

experiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted internationally , via GCC leading satellite Channels.

NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE

NewBase 22 December 2014 K. Al Awadi

New base 502 special 22 december 2014

Economy & Finance

Transcript of New base 502 special 22 december 2014