newbase 632 special 23 june 2015

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,

or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this

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NewBase 23 June 2015 - Issue No. 632 Senior Editor Eng. Khaled Al Awadi

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

Oman: Phoenix Power makes MSM debut Oman observer

Phoenix Power Company was traded for the first time on Muscat Securities Market yesterday, and according to analysts performed on the expected lines. The shares surged by 33.36 per cent to close at 150 baisas. The shares touched a high of 155 baisas and a low of 145 baisas during the course of days transaction.

Joice Mathew, senior manager, United Securities, said, “Over 128 million shares were traded on the debut, generating about RO19.3 and amounting to 97 per cent of the total shares traded on the day. He added that the company is expected to perform on similar lines in the next few days and it may be noted that only 128 million shares of the 332.7 million allocated to retail investors were traded yesterday. He said there was a big demand from institutional buyers and pension funds, which had received 2.5 per cent allotment. The share was oversubscribed to the tune of 18 times, generating RO1 billion from investors against an issue size of RO 56.3 million. The company has allotted a minimum of 3,000 shares and 8.57 per cent of additional shares applied by retail investors. Phoenix Power is the largest power plant in Oman, with an installed




capacity of 2,000 MW. The contracted power capacity represents 27.8 per cent of Oman’s MIS total currently contracted capacity of approximately 7,197 MW based on OPWP’s seven-year statement (2014-2020). Close to 97 per cent of the total revenues of Phoenix Power in FY 2015 (excluding fuel revenue, which is virtually a pass-through) will be through capacity charges from OPWP for the contracted power capacity of the plant. These capacity charges are payable regardless of orders or output of the Plant. Phoenix Power’s capacity charges are calculated so that they cover its debt service and other fixed costs, such as operating and maintenance, insurance, taxes and capital returns. The project benefits from the proven contractual framework adopted by the Government, and leverages the strong track record of the country in tendering of IPPs and IWPPs. The output from Phoenix Power’s installed capacity is contracted with OPWP, through a single long-term PPA which expires on March 31, 2029. Beyond the PPA period, Phoenix Power shall either extend its PPA with OPWP or sell its output in a liberalized market in a power pool or to eligible customers. Its decision to do so will depend, amongst other factors, on the evolution of the market regulations set by the Authority for Electricity Regulation, Oman (AER). About Phoenix Power Vision

Phoenix Power draws its business strategy following our vision statement, as below: “To become a respected brand within the Oman’s power market by being the safest, most reliable, efficient, and environmentally conscious power provider, ensuring exceptional services and value to our offtaker, shareholders and other stakeholders.”

History

The ambitious journey of Phoenix Power started in 2011, with Oman Power and Water Procurement Company (OPWP) inviting proposals for the development of an Independent Power Project (IPP) at Sur. Following the competitive bidding process run by OPWP in 2011, the shareholders were awarded the contract to build the plant, which saw the incorporation of Phoenix Power Company.

The plant has been established under a Build, Own, Operate (BOO) scheme, which enables it to be operated beyond the Power Purchase Agreement (PPA) term of 15 years, either by extending the PPA (if agreed by OPWP), or by selling the power into an electricity pool which may exist at that time.

Shareholders

Axia Power Holdings B.V.

Chubu Electric Power Sur B.V.

Qatar Electricity & Water Company

Multitech LLC




Kuwait: Construction costs to delay s al-Zour oil refinery Reuters + NewBase

The start-up of Kuwait’s al-Zour crude oil refinery is expected to be delayed after rising construction costs forced state refiner Kuwait National Petroleum Co (KNPC) to seek more money to finance the plant, a KNPC spokesman said on Monday.

Officials had previously said start-up would occur by late 2018 or early 2019 and pegged the cost of the facility at 4 billion dinars ($13.3 billion). But KNPC spokesman told Reuters by telephone: “We are seeking additional funds to start awarding (contracts). We are already two months behind and we don’t know when we will get the funds.”

KNPC said in a statement that a request for the new government money would be submitted to the Supreme Petroleum Council, a top oil policy body.

The company did not say when the request might be approved or how much extra money KNPC needed, but Kuwaiti daily al-Seyassah quoted the company’s chief executive Mohammed Ghazi al-Mutairi as saying the amount was estimated at 800 million dinars.

The 615,000 barrel per day oil refinery, originally planned more than a decade ago, would be the biggest in the Middle East, but the project has been repeatedly delayed by bureaucratic and political issues, including tensions between Kuwait’s parliament and the

cabinet.

KNPC said it had asked

companies which had bid for work on the project to extend the validity dates of their bids until it obtained the new funds. Bids for one of the

contracts, related to the tank farm, did not meet specifications

so the company is inviting fresh bids and set July 7 as the date for them

to be submitted. The refinery will make diesel, kerosene and naphtha for export and low-sulphur fuel oil for domestic power stations.




Saudi Aramco may shut Jeddah refinery in several years By Reuters + NewBase

State oil giant Saudi Aramco is considering whether to close its 90,000 barrel per day crude oil refinery in Jeddah after several years because of age and environmental concerns, industry sources said.

The refinery, which started operating in 1967, serves much of the country’s western region and its closure would increase demand at other Saudi facilities. It produces liquefied petroleum gas, gasoline, diesel, asphalt and jet fuel, and exports naphtha. Aramco was originally considering whether to close it in 2018 but now looks likely to postpone the closure to as late as 2022 because of growing domestic demand for oil products and since construction of a new refinery at Jizan, also on the Red Sea coast, has been delayed, said one source. Another said Jeddah’s growth had left the refinery in the middle of the city, which created environmental issues that contributed to a likely decision to close it. The sources declined to be named because they were not authorised to talk to media. In response to questions by Reuters, Aramco said on Sunday that it had no information to release at this time. Aramco has said it plans to bring the Jizan refinery online by 2018. However, industry sources said this was now expected to be delayed by at least two years for several reasons, including technical problems with building infrastructure in the sea.




A Singapore-based trader said Saudi Arabia’s new Jubail and Yanbu refineries, operated by Aramco, France’s Total and China’s Sinopec, would likely supply gasoline output lost by the eventual closure of the Jeddah facility. He said the impact on the international naphtha market would not be big as the refinery exported only about 40,000 tonnes per month. The United Arab Emirates’ Ruwais refinery is to raise yearly naphtha exports to over 10 million tonnes from the current 7.5 million tonnes, traders have said. IMPACT ON LUBEREF The Jeddah refinery is next to, and supplies feedstock and power to, a base oil refinery run by Luberef, a joint venture between Aramco and Jadwa Industrial Investment Group. Luberef makes a total of around 550,000 tonnes per year of oil lubricants from its two refineries at Jeddah and Yanbu. Luberef said it was now considering whether to shut the Jeddah facility eventually and expand Yanbu. “This is now in the planning phase and Luberef will be ready if Aramco’s Jeddah refinery closes, Luberef said in an emailed statement. One source familiar with the matter said the Luberef shutdown could happen in 2020. Companies based in Saudi Arabia have received a request from Luberef to express their interest for front-end engineering and design work, industry sources said. “They want to build a new vacuum distillation unit with a capacity of 26,000 bpd — they want to move some parts from the old plant,” said one. Luberef is already expanding its Yanbu plant by doubling capacity to produce a new, high-quality base oil. The company originally said it planned to start commercial production of this oil in the fourth quarter of 2015, but its statement to Reuters last week indicated the date would be later. “Production of the G-II expansion will commence by the second quarter of 2016 of which high quality G-II base oil will be introduced in (the) local and export market,” it said.




Norway: Tullow's Zumba exploration well in PL 591 in the Norwegian Sea disappoints… Source: Tullow Oil

Tullow Oil has announced that theZumba exploration well (6507/11-11) in licence

area PL 591 in the Norwegian Sea has not encountered hydrocarbons and will

now be plugged and abandoned.

The primary objective of the well was to prove hydrocarbons in the Upper Jurassic

Rogn Formation with a secondary target in the Mid-Jurassic Garn Formation of the Fangst Group. The well found no reservoir development in the Rogn Formation and, while the Garn Formation had good reservoir quality, no hydrocarbons were present in either target.

The well was drilled by the Leiv Eiriksson rig in 270 metres of water to a Total Depth of 2875 metres. Tullow Oil Norge is the operator of PL 591 with 40%

equity. Lime Petroleum Norway (25%), Rocksource(20%*) and North Energy (15%) hold non-operated interests.




Madagascar: Madagascar Oil operations - updates Source: Madagascar Oil

Madagascar Oil has announced the appointment of Jefferies International as a strategic advisor to the Company and that a new, updated, company presentation is available on the Company's website. Updated Company Presentation:

The Company's CEO, Robert Estill, will be presenting at the Oil & Gas Council Africa Assembly in Paris on 23 June 2015 and a copy of the presentation to be made at that Assembly is now available on the Company's website. The Company Presentation includes the following items which are additional to the information previously reported by the Company and are therefore summarised below. The new information is based on the latest Company estimates and is consistent with the Company's plans as outlined in the approved Block 3104 Tsimiroro Development Plan (the 'TDP').

Tsimiroro Development Plan:

• Drilling costs for each development well are now estimated at US$150,000 per well based on latest data. It is expected that well completion, flowlines, tie-back and artificial lift costs will add a further US$140,000 cost for each development well. Both well cost components represent a reduction over existing TDP submission costings due to recent market price conditions.

• A new production profile up until 2045 has been highlighted which shows the latest estimated production growth forecasts under three newly defined stages as follows:

o Anchor Stage: the initial growth stage which shows gross production achieving between 7,000-10,000 barrels of oil per day ("bopd") from approximately 400 development wells in the period up to the end of 2018/early 2019. It is estimated that funds of between US$200-US$400 million will be required to fund this stage from a mix of equity, oil sales, farm-in, financial agreements with service companies or through other funding options. Jefferies will assist Madagascar Oil in determining the optimal funding route for this stage, including the identification and securing of a strategic partner(s), as referred to above. This stage was previously referred to by the Company as "Phase 1" of the TDP.




o Fast Track Stage: a further growth stage which envisages gross production reaching 50,000 bopd by 2021/2022. This stage would involve, amongst other things, the construction of a pipeline to the west coast of Madagascar and new coastal offtake facilities, increased drilling activities through a larger rig count and an additional central processing facility.

The latest Company estimates indicate that additional funds of between US$400-US$600 million will be required for this stage and it is envisaged that funding options may be available from a variety of avenues including debt, infrastructure funds, crude oil offtakers, equity, cashflows arising from crude oil sales and from other sources. The Company has already commenced discussions with third parties interested in funding elements of this stage and it is envisaged that discussions will continue as the Anchor Stage progresses. The Fast-Track Stage was previously referred to by the Company as "Phase 2" of the TDP.

o Enhanced Stage: this stage envisages gross production growing from 50,000 to

over -100,000 bopd through 2025 with the rate of growth being dependent on many factors, in particular the number of drilling rigs in operation at any one time and pace of development. Latest Company estimates indicate that this stage will be fully funded from project cashflows with no additional external funding being required.

Tsimiroro Development Value:

• The Company has run a range of commercial cases for the Tsimiroro Development based around varying oil prices, production profiles, oil recovery rates, capital spend and other cost assumptions. The Company's latest base case estimate (NPV10 value) is US$2.6 billion for the full contingent resource development, which is based on:

o the production profile arising from the three stages, referred to above;

o a late May 2015 forward oil curve price deck (US$62.50 per barrel rising to US$80 per barrel in 2018 onwards);

o capital and opex costs as included in the TDP; and

o estimated recovery factor of around 40% of the 1.7 billion barrels of contingent resources.

• The Company Presentation shows a range of sensitivities around the base case of US$2.6 billion using different oil price assumptions (ranging from US$40 per barrel to US$100 per barrel) and different stock tank oil initially in place ("STOOIP") volumes (ranging from 0.6 billion barrels STOOIP to 3.5 billion barrels STOOIP). The impact is shown on a chart in the Company Presentation (page 11).

• The latest NPV10 values are the Company's best estimate at this time and will inevitably change over time as new information emerges for the development.

Click here for Madagascar Oil Company Presentation June 2015




Netherlands: Output at Groningen gas field to be capped at 30 bcm Source: Reuters via Yahoo! Finance

Dutch Economy Minister Henk Kamp will propose a further tightening of production at Groningen, Europe's largest gas field, the Dutch news agency ANP reported on Monday, sending European gas prices higher. Output at the gas field, the world's 10th largest, will be capped at 13.5 billion cubic metres (bcm) in the second half of this year and at 30 billion bcm for the whole of 2015, ANP said.

In February Kamp had ordered production to be cut to an annualised rate of 33 bcm for the first half of the year, from 39.4 bcm previously, after the Safety Board said gas companies, regulators and the government had all failed to take the threat of earthquakes seriously enough.

The report of a production cut of 3 bcm in the second half of 2015 led to a tightening of liquidity on the Title Transfer Facility (TTF) gas hub and sent prices in Europe higher. A government spokeswoman declined comment on the figures. A formal decision was expected on Friday. A spokesman for the NAM Shell/Exxon Mobile joint venture, which exploits the Groningen field, was unavailable for comment.

Speculative buying by banks and traders drove gas prices higher on Monday, despite weak underlying fundamentals in regional gas markets, which are heavily oversupplied.

'There are no numbers to click on the TTF,' one trader said, referring to a trading platform that enables buying or selling of gas at the Dutch gas trading hub. It seems like every trader is waiting, nobody wants to offer, they are waiting to see which way the market will move.'

Dutch gas prices at the TTF hub were higher in early afternoon trade. The July contract was up 1.48 percent at 20.60 euros per megawatt hour, while the September contract gained 1.63 percent, also to 20.60 euros/MWh. The NBP Winter 2015 contract rose 1.9 percent to 48.65 pence per therm while the 3Q 15 contract climbed 2.7 percent to 43.50 pence per therm.

The ANP report, citing anonymous sources in The Hague, said the latest decision was based on a projection that temperatures will remain mild this year and that demand can be met by tapping 3 bcm in overcapacity at the Norg storage facility in Drenthe. In a conflicting report, local television channel RTV Noord said Kamp would propose a production cap of 33 bcm.




US:crude oil production growth helps reduce Gulf Coast imports Source: U.S. Energy Information Administration, Petroleum Supply Monthly

In recent years, higher domestic production of light, tight crude oil has led to a reduction in crude oil imports. Certain types of crude oil have been affected more than others; for example, the increased economic availability of domestic light, tight crude oil has virtually eliminated Gulf Coast imports of light crude oil. In the past year, Gulf Coast imports of medium crude oil have also fallen because of increased production from the Eagle Ford, Bakken, and Permian regions.

One of the key characteristics of crude oil is its density, measured by API gravity as established by the American Petroleum Institute. Less-dense liquids have higher API gravities. Crude oils with API gravities of 35 or above are considered light; 27 to 34 are medium; less than 27 are heavy.

From the first quarter of 2014 to the first quarter of 2015, medium-grade crude oil imports to Gulf Coast refineries decreased 45%, from 1.5 million barrels per day (b/d) to 0.8 million b/d. On the other hand, over that same period there was a 0.4 million b/d (22%) increase in imports to Gulf Coast refineries of heavy crude oil. Improved refining margins from processing additional volumes of heavy crude have resulted in a 3% increase in gross atmospheric distillation unit (ADU) throughput in the Gulf Coast region over this period, from 8.0 million b/d to 8.2 million b/d.

Almost all medium-grade crude oil imports are from Middle Eastern countries. Gulf Coast imports of medium crude oil from Saudi Arabia decreased by 52% from the first quarter of 2014 to the first quarter of 2015, from 0.9 million b/d to 0.4 million b/d. Similarly, Gulf Coast imports of medium crude oil from Kuwait decreased by 46% over this period, from 0.4 million b/d to 0.2MBD.




US industrial natural gas usage falls unexpectedly Reuters

US manufacturers have not soaked up as much excess shale gas in the first half of 2015 as expected, but the shortfall may be an anomaly as a Gulf Coast manufacturing boom is poised to insulate the sector from seasonal demand fluctuations.

Average industrial demand for gas in 2015 was expected to increase nearly 4% over 2014, according to federal energy forecasts. But almost halfway through the year, it has eased about 1% to 21.7bn cubic feet per day from 22 bcfd a year earlier, according to Thomson Reuters Analytics. The primary reason for the decline was a milder winter this year than last year’s brutal cold in the heavily industrialised US Midwest and Gulf Coast. “The industrial sector has become more temperature-sensitive over the years, so it’s not surprising industrial demand was a little disappointing this winter,” said Kyle Cooper, managing director of research at energy consultancy IAF Advisors in Houston. Experts, however, expect the industrial sector to become less weather-sensitive as more manufacturing facilities enter service along the Gulf Coast, where heating is in less demand than in the Midwest.




Power generators and manufacturing companies will consume most of the gas in the US over the next 25 years, according to the US Energy Information Administration. So far this year, however, only the power sector had gobbled up its share of near-record output from shale fields. Power generators accounted for 33% of US gas consumption, burning on average 23.9 bcfd so far in 2015. That compared with 20.1 bcfd a year earlier and a 10-year average of 19.0 bcfd. With the retirement of dozens of US coal plants for economic and environmental reasons, power generators used near-record amounts of gas this year because the fuel was relatively cheap. Futures at the Henry Hub benchmark supply point in Louisiana averaged $2.77 per million British thermal units so far this year, the lowest since 2012. That compared with $4.66 per mmBtu for the same time in 2014. And the market expects prices to remain low for years as shale gas output grows, with futures trading below $4 through 2022. Plentiful and affordable gas supplies from shale plays have transformed the US from one of the world’s highest-cost producers 10 years ago to among the lowest-cost today. Chemical companies alone expect to spend more than $100bn to build or expand more than 200 US projects and create more than 300,000 jobs by 2023, according to the American Chemistry Council lobbying group. “The boom in industrial demand will not take off until 2017 to 2020, when many new manufacturing facilities, especially chemical plants, enter service,” said Gregory Shuttlesworth, executive director of natural gas at consultancy PIRA Energy Group in New York. Experts said they did not expect manufacturers to dominate the US gas market the way they once did, however. “The industrial sector will soon get back to the same volume of gas it used in 2000,” IAF Advisors’ Cooper said, “but I doubt we’ll ever see manufacturing back to the same percentage of total gas used 15 years ago.”

The EIA forecast gas used by

industrial companies would rise to about 22.5 bcfd in 2016, the first time it would top the 22.3 bcfd level set in 2000. In the mid 2000s, many gas-intensive US companies fled for lower cost markets after gas futures jumped

above $10 per mmBtu in 2000 and then to an all-time high past $15 in 2005 after Hurricanes Katrina and Rita devastated the Gulf Coast. The EIA said it expected US industrial companies to continue to consume about 30% of the nation’s gas over the next 25 years, compared with more than 35% 15 years ago.




Oil Price Drop Special Coverage

Oil prices fall on oversupply concerns, weak economic data REUTERS + NEWBASE

Oil prices fell on Tuesday on worries over a global glut, while surveys showing a contraction in manufacturing activity in China and Japan also dragged on market sentiment. An expected drawdown in U.S. crude stocks, however, put a floor under prices.

Brent crude was down 20 cents at $63.14 a barrel as of 0355 GMT (1155 EDT), after closing the previous session up 32 cents. U.S. crude for August delivery fell 34 cents to $60.04 a barrel. The July contract, which expired on Monday, closed up 7 cents at $59.68 a barrel.

"I think the Japan and China PMI figures are weighing on the market," said Jonathan Barratt, chief investment officer at Sydney's Ayers Alliance. China and Japan are Asia's two biggest oil importers.

The HSBC/Markit Flash China Manufacturing Purchasing Managers' Index (PMI) edged up to 49.6 in June, a three-month high, from 49.2 in May, but remained below the 50 mark, which separates contraction from expansion. Japanese manufacturing activity contracted slightly in June with the Markit/JMMA flash Japan Manufacturing PMI falling to a seasonally adjusted 49.9 in June from a final 50.9 in May.

"Although China’s figures picked up slightly, we continue to believe that growth remains weak as PMI figures are not moving past 50. We expect no change to crude demand from Japan and China in the near future with manufacturing PMI figures being weak," Phillip Futures said.

Growth in U.S. gasoline stocks, which increased by almost 500,000 barrels in the week to June 12, high U.S. crude output of about 9.6 million barrels per day and 2 million barrels per day of excess capacity by oil producers cartel OPEC added to oversupply concerns, Barratt said.

But analysts expect U.S. commercial crude oil stocks to have dropped by an average of 1.8 million barrels to around 466 million barrels last week.




Saudi & UAE keep growing despite cheap oil SG/Agencies + NewBase

Saudi Arabia and the UAE continue to witness growth despite lower oil prices, a report by Crédit Agricole Private Banking said Monday, noting that the UAE even recorded high levels of job creation during May, while Saudi Arabia’s output and new orders expanded.

Commenting on the financial institution’s research report “Macro Comment – Mena Update”, Dr Paul Wetterwald, chief economist at Crédit Agricole Private Banking, said “interestingly in the UAE, once again new orders and new export orders components reflected strong growth, while job creation hit a three-month high. This is reflected in the

UAE’s non-oil private sector PMI which did not decline significantly in May (56.4) compared to 56.8 in April. On the other hand, input costs rose contrasting with a slight decline of the output prices charged by companies.” Dr Wetterwald added “in this background, it is too early to infer from this latest change that a downward trend in the CPI indices has started. We can see that the UAE’s CPI was +4.2 percent year-on-year in April, which is the same as in Dubai where inflation can be an issue. Nevertheless, we can say that the UAE is yet to fully feel the pinch of the lower oil price across its relatively diversified economy in comparison to GCC peers.” “Similarly in Saudi Arabia, output and new orders expanded but the rate of growth and pace of job creation eased somewhat during the month. It was interesting to note that the Kingdom’s headline PMI last month (57.0) was at its lowest level since May 2014. While the most recent data in the PMI series still depicts a growing non-oil private sector economy, our estimate of growth in Saudi Arabia is more conservative,” he said. “For example, based inter alia on the latest Saudi Arabia Monetary Authority statistics, we get a Q1 2015 nominal GDP growth estimate which is only slightly positive.” Dr Wetterwald noted that with regards to food inflation, the recent softening of world food prices should bring significant benefits to GCC consumers. “This is indicated by the FAO food price index in May 2015, which was down 20.7 percent year-over-year and 1.4 percent month-on-month. Given the large weightage on food items in consumers’ baskets, this lower food price scenario will be positive for consumers in the GCC countries where most of the food requirements are imported from other places,” he said. “This situation will prevail provided no strong El Niño episode occurs. El Niño is a natural phenomenon which is a key factor worldwide for the agricultural sector, as it contributes to extreme weather. A strong El Niño would put the crops of some agricultural commodities at risk, leading to higher food prices during and after its occurrence,” Dr Wetterwald added.




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Khaled Malallah Al Awadi, Energy Consultant MS & BS Mechanical Engineering (HON), USA Emarat member since 1990 ASME member since 1995 Hawk Energy member 2010

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 23 June 2015 K. Al Awadi

newbase 632 special 23 june 2015

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