As Brazil works to extract its vast offshore oil and gas reserves found in pre-salt formations, one of the most challenging locations is the Santos Basin, where operators face a number of complex production and transportation conditions.  (NYSE: GE) has introduced innovative flexible pipes to help customers overcome these challenges by developing new materials for the pipes required to bring hydrocarbons to the surface.

During the past three years, the GE Oil & Gas team in Niterói has developed new flexible pipe technologies to meet the specific conditions of the Santos Basin oil. As a result, the company now is one of only two accredited providers of advanced flexible pipes to be used in this location.

GE's new flexible pipes feature important advances as each pipe layer is made with a specific material to ensure the safe and reliable transportation of oil and natural gas in the Santos Basin. Traditional flexible pipes are already highly engineered technologies that must be able to handle extreme pressures, temperatures and currents. The new pipes developed for the Santos Basin build on these characteristics by adding new materials specifically engineered to withstand the more acidic environment. Altogether, about 70 professionals worked on the flexible pipe technology project, which the GE team is continuing to enhance through more research and development.

GE's latest flexible pipe innovations build on the company's 2011 acquisition of Wellstream Holdings, which enabled GE Oil & Gas to further grow in the floating production, storage and offloading offshore segment that underpins deepwater oil and gas production activities in Brazil and around the world. The business specializes in the engineering and manufacturing of high-quality flexible risers and flowline products for oil and gas transportation in the subsea production industry.

To drive additional innovation, GE is establishing a new $250 million Global Research Center in Rio de Janeiro, which will host a subsea systems laboratory that will focus on developing more solutions for the pre-salt layer and ultra-deep water exploration.

Brazil is a key growth market for GE Oil & Gas, with the country expecting investments to reach about $320 billion by 2021, according to Energy Research Company. In addition to the future subsea systems laboratory, the company also has announced a total of $262 million in investments to expand its equipment production facilities in Niterói and Macaé—both in Rio de Janeiro—and Jandira in São Paulo.

As the economic fallout from the recent terrorist attack on Kenya's Westgate Mall by Somali militants is still unfolding, the country's petroleum industry will have to focus its attention toward security in order to keep its momentum, says an analyst with research and consulting firm GlobalData.

John McCormack, GlobalData's Lead Analyst covering Sub Saharan Africa, believes that while the Somali extremist group Al-Shabaab has not made a specific threat, Kenya's petroleum industry is of strategic importance to the country's economic future and is itself a feasible target for future attacks.

Although the attack on the Westgate Mall is likely to have a minimal impact on the overall pace of Kenya's oil and gas operations, most International Oil Companies (IOCs) will have to invest in security, especially with the relocation of high numbers of expatriates to Kenya. Additionally, there will also be a heightened risk of damage to oil and gas infrastructure, such as pipelines. These are particularly difficult to secure from Somali militants, McCormack says.

GlobalData forecasts the first oil production in Kenya to be achieved in 2016, from blocks 10BB/13T, once oil and gas legislative measures and infrastructure have been put in place. The Kenyan government is expected to receive revenues of $300m per year from oil produced from these blocks alone over the next 30 years.

According to McCormack, Kenya doesn'thave a safety and security master plan in place to protect its oil and gas infrastructure. However, Kenya Petroleum Refinery Company (KPRC) did tighten security around its Mombasa refinery facility, the only one in East Africa, following the attack.

Additionally, both security personnel and unarmed security guards are deployed at all onshore and offshore blocks where exploration operations are ongoing.
Furthermore, drilling rigs, especially those located close to the border of Kenya and Somalia in the Mandera, Anza and Lamu basins, are now on alert for militants after the Kenyan government showed no willingness to accede to the demands of Al-Shabaab.

The Kenyan government may lose some of its contract negotiating powers with the IOCs as a result of the deteriorating security conditions in the country. However, although the Westgate Mall attack will cause investors to consider the future ramifications of terrorism in Kenya, the opportunity-cost of turning down investment in the country is likely too high to justify not pushing forward, McCormack concludes.

Comment provided by John McCormack, GlobalData's Lead Analyst covering Sub Saharan Africa. John Sisa and Jamie Inkster, GlobalData's Analysts covering Oil & Gas, also contributed to this analysis.

Construction of the Keystone Gulf Coast Pipeline (KGCP) has advanced considerably, according to Genscape’s most recent flyovers on September 29^th and October 6^th. Genscape uses proprietary monitoring technology and aerial photography to monitor market moving pipeline flow disruptions and infrastructure projects to offer market participants a real-time look at the factors driving the U.S. and Canadian oil markets.

On October 2^nd TransCanada stated that major construction would be complete by the end of October and that the pipe would be ready for line filling shortly thereafter. Genscape is now monitoring power consumption at the Lufkin and Delta pumping stations and will be able to detect the power consumption to these pumping stations indicative of line fill activity. Delta is not expected to be necessary for the initial start-up capacity. Genscape’s analysts’ believe that late December to early January is a realistic estimate for the completion of the line fill, based on acceleration in construction progress from last month's flight. The bulk of work remaining on the project is centered on the origin Cushing pumping station.

At the Cushing terminal, all seven newly constructed tanks have hydrotested. Mixer installation appears complete, while tank pipeline connections require further work. Genscape believes that the associated connections are not necessary for initial KGCP fill, and that the tanks could potentially be bypassed. The terminal will have 2.25mn bbls of storage capacity.

Additionally, exposed pipe was observed near the Tupelo and Bryan facilities and crews were observed working on pipeline connectivity along the ROW at the Tupelo pumping station. The Cromwell, Bryan, Winnsboro, Lufkin and Liberty pumping stations each have four pumps installed. Hydrostatic testing looks to be complete at all pumping facilities except for the Bryan pumping station. After successful hydrostatic testing, final grading would take place at each pumping facility followed by the installation of a security fence, according to a TransCanada document. The Bryan pumping facility did not have a security fence installed as of Gencscape’s latest flight. The Tupelo, Delta, Lake Tyler and Corrigan stations do not have pumps installed at this time. Genscape believes these stations do not need pumps for the line to flow at its initial stated capacity of 700,000 bpd.

The 36-inch-diameter KGCP will flow 485 miles from Cushing, OK, to Nederland, TX. The line will have an initial capacity of 700,000 bpd with the option to expand to 830,000 bpd. Line fill for KGCP is approximately 3.2mn bbls. Genscape estimates it will take approximately 40-60 days to fill the line at near 54-81,000 bpd fill rate. The Keystone pipeline from Hardisty, AB, to Patoka, IL, took nearly 180 days to fill in 2010 at near 50,000 bpd fill rate. Line fill for Keystone to Patoka was approximately 9.2mn bbls. TransCanada estimated the line fill duration would be approximately 30 days. Sunoco Logistics Partners LP’s Nederland terminal will be the initial terminus of the KGCP pipeline, according to a Reuters report. Valero’s Lucas storage terminal would also receive crude from the line in Q1 2014 according to a September SEC filing.

TransCanada stated construction on the Houston lateral was slated to begin Q4 2013 and is estimated to be in service by Q4 2014. The lateral will be approximately 48 miles from the Liberty pumping station to Houston’s refining center. Click here to view the aerial photos that supplement this report.

Genscape’s Mid-Continent Pipeline clients receive ongoing notices of pipeline flows and infrastructure projects in advance of market reports. A free trial of the Mid-Continent Pipeline service, and all Genscape’s oil market services, is available by visiting info.genscape.com/keystone-october.

Noble Energy, Inc. (NYSE: NBL) announces that the A-2 appraisal well drilled on the Block 12 discovery offshore the Republic of Cyprus has successfully encountered approximately 120 feet of net natural gas pay within the targeted Miocene-aged sand intervals.  The Cyprus A-2 well, which is more than four miles northeast of the A-1 discovery location, was drilled to a total depth of 18,865 feet in 5,575 feet of water.

Production testing procedures were performed over a 39-foot section of the upper Miocene reservoir.  The test, limited by surface equipment, yielded a maximum flow rate of 56 million cubic feet per day (Mmcf/d) of natural gas.  Performance modeling indicates development wells in the reservoir should have capacity to deliver up to 250 Mmcf/d.  Evaluation of drilling data, wireline logs and reservoir performance information has resulted in an updated estimate of gross resources of the field ranging⁽¹⁾ from 3.6 trillion cubic feet (Tcf) of natural gas to 6 Tcf, with a mean of approximately 5 Tcf.  The Cyprus A structure represents the third largest field discovered to date within the Deepwater Levant Basin.

Keith Elliott, Noble Energy's Senior Vice President, Eastern Mediterranean, commented, "Results from the Cyprus A-2 well have confirmed substantial recoverable natural gas resources and high reservoir deliverability.  While the A-2 location has successfully defined the northern area of the discovery, we anticipate additional appraisal activities are necessary to further refine the ultimate recoverable resources and optimize field development planning.  In the meantime, we continue to identify and advance multiple development options.  In addition to the Cyprus A discovery, we are also encouraged about the further exploration potential in Block 12.  We have recently completed a 1,100 square mile 3D seismic acquisition, which will be interpreted over the next several months." 

Noble Energy operates Block 12 offshore the Republic of Cyprus with a 70 percent working interest.  Delek Drilling and Avner Oil Exploration each have 15 percent working interest. 

Noble Energy plans to move the Ensco 5006 drilling rig to Tamar SW, offshore Israel, at the completion of operations offshore Cyprus.  The Tamar SW well, testing an exploration prospect offsetting the main Tamar field, is expected to reach total depth by the end of 2013.  Noble Energy operates Tamar SW with a 36 percent working interest.   

(1)  Range of resource estimate based on 75^th and 25^th percentile probabilities

Petrobras, the operator for the BM-S-9 consortium, announces, together with its partners BG E&P Brasil and Repsol Sinopec Brasil, that the company's affiliate Guará BV has signed on its behalf a letter of intent to charter, through Modec Inc. and Schahin Petróleo e Gás S.A., an FPSO (floating production, storage and offloading unit) for use in production development of the pre-salt layer in the Carioca area, part of the Santos Basin's block BM-S-9.



The project provides for the initial connection of eight wells to the FPSO, four as producing wells and four for injection, with the possibility of subsequent additional wells. The Carioca area is expected to start producing in August 2016.



The platform will have a processing capacity of up to 100,000 barrels per day (bpd) of oil and 5 million m³/day of natural gas. The FPSO will be operated by the companies responsible for its construction and chartered to the BM-S-9 Consortium for a period of 20 years. The Carioca FPSO is scheduled to be delivered by June 2016.



The BM-S-9 Consortium is a partnership between Petrobras (the operator, with a 45% stake), BG E&P Brasil Ltda. (30%) and Repsol Sinopec Brasil S.A. (25%).

Technip was awarded by Qatar Petroleum an engineering, procurement, installation and commissioning contract for a strategically important* Offshore Project comprising a living quarter platform and an utility platform, with a bridge connecting the two platforms. The project location is within QP offshore facilities.

Technip will be responsible for the execution of the entire Project. The topsides for both platforms will be installed using the floatover technology, which Technip pioneered. This installation method enables large integrated topsides to be installed, thereby minimizing offshore hook-up and commissioning, without the use of large crane vessels.
Technip's operating center in Abu Dhabi, United Arab Emirates, with the support from the Group's operating centers in Paris, France and Doha, Qatar will execute the project.

Vaseem Khan, Senior Vice President of Technip in the Middle East, declared: "This contract reflects the growing interest for the floatover technology, by allowing a safe project execution in a time and cost-effective way while overcoming heavy-lift challenges. With this strategic project, we have the opportunity to further consolidate our presence in Qatar and to strengthen our relationship with Qatar Petroleum. It will also help us establish Technip as a leading Company in the region for executing offshore living quarter platform projects."

* For Technip, an "important" offshore contract is ranging from €100 to €250 million.

With Brazil’s  first exclusive pre-salt bidding round underway this month for a single block containing the Libra field, and massive potential identified within the country’s offshore pre-salt layer, bidding between several consortia is expected to push the state’s  take significantly higher than that which would result from a Concession Contract, says research and consulting firm GlobalData.

According to the company’s latest report*, Brazilian authorities consider the exploratory risk in pre-salt areas to be relatively low, and legislation was passed to govern upstream oil and gas activities within an area designated as the pre-salt polygon using Production Sharing Contracts (PSCs), instead of the traditional Concession Contract regime.

This form of contract ensures a higher government take from production projects and is being offered in the first bidding round for Libra, which is estimated to hold reserves of between eight and 10 bbl (billion barrels). State take from this and other fields within the area is now expected to be near 75%, which would represent a base state profit oil share of around 50%.

As well as the government receiving a share of production, higher royalties equal to the value of 15% of gross oil and tax production are payable, compared to a maximum of 10% under Concession Contracts. Meanwhile, a signature bonus for Libra, set at BRL15 ($6.3 billion), is also payable, but the Special Participation tax is not applicable.

Adrian Lara, GlobalData’s  Lead Analyst covering Upstream Oil & Gas, says: “While the effective production-sharing terms for the Libra block will not be known until the conclusion of the first pre-salt bidding round, the nature and caliber of companies taking part suggests to us that the competition will occur between three or four bidding consortia, despite the conspicuous absence of US oil giants.

However, beyond the initial pre-salt licensing rounds and into the medium-term, we are expecting further pre-salt licensing to progress at a relatively slow pace, with blocks only being offered once discoveries or prospects have been identified by Petrobras, Lara continues. “By clearly identifying potential before offering acreage, the risk for prospective investors will be lowered and the state will be able to secure a higher stake.”

In addition to the pre-salt bidding round taking place this month, November will also see the start of Brazil’s 12th Concession round, which will offer blocks in frontier and mature onshore basins. While some of these are estimated to hold significant shale gas potential, no major amendments have been made to the fiscal terms governing this round.

*Brazil Upstream Fiscal and Regulatory Report

TransMontaigne Partners L.P. (NYSE:TLP) has announced commercial operations are underway for phase one at the 185-acre Battleground Oil Specialty Terminal Company, LLC (BOSTCO) on the Houston Ship Channel. Approximately 20 of the 51 storage tanks being built during phase one construction are being placed into service this month, and the remaining tanks will come online during the next six months. A two-berth ship dock and 12 barge berths are also scheduled to be in service this month.



A joint venture of TLP (which owns a 42.5 percent interest in the facility) and Kinder Morgan Energy Partners, L.P. (NYSE: KMP), the approximately $485 million BOSTCO oil terminal at mile marker 43 on the Houston Ship Channel is fully subscribed for a total capacity of 7.1 million barrels and is able to handle ultra low sulfur diesel, residual fuels and other black oil terminal services.


Phase two of construction at BOSTCO is underway and involves the construction of an additional six, 150,000-barrel, ultra low sulfur diesel tanks, additional pipeline connectivity and high-speed loading at a rate of 25,000 barrels per hour. BOSTCO expects phase two to begin service in the fourth quarter of 2014.



"We are pleased to announce the commencement of operations of the BOSTCO facility, which provides the market with a unique, deepwater terminaling solution that provides high speed loading and improved barge and ship access to the Texas Gulf Coast for the export and import of various refined products," said Charles Dunlap, Chief Executive Officer of TLP’s general partner.



The BOSTCO project is employing approximately 750 local contractors during construction and has hired about 75 full-time employees to operate the facility.



Exploration acquisition adds to opportunities in Australia

Chevron Corporation (NYSE:CVX) announced on Tuesday, that its Australian subsidiary has acquired exploration interests in two offshore blocks located in the Bight Basin, a deepwater frontier basin.

Blocks S12-2 and S12-3 in the Bight Basin are similar in size to the Gulf of Mexico and contain significant exploration potential.

Blocks S12-2 and S12-3, which span more than 8 million acres (32,375 square kilometers), are located approximately 275 miles (443 kilometers) west of Port Lincoln off the South Australia coast. Chevron Australia is the operator with a 100 percent interest.

Melody Meyer, president of Chevron Asia Pacific Exploration and Production Company, said, "The acquisition of blocks S12-2 and S12-3 demonstrates Chevron's continued focus on pursuing high-impact exploration opportunities to expand its resource base and reinforces the importance of Australia to Chevron's global growth strategy."

Chevron Australia Managing Director Roy Krzywosinski added, "We are extremely pleased to be awarded the S12-2 and S12-3 offshore blocks located in the Bight Basin. The Bight Basin is similar in size to the Gulf of Mexico, and these two blocks contain significant exploration potential."

Baker Hughes Incorporated (NYSE: BHI) has announced that PETRONAS Carigali Sdn. Bhd. (PCSB) has entered into a long-term Oilfield Service Agreement (OFSA) with Baker Hughes to enhance the recoverable reserves and production of hydrocarbons in the Greater D18 fields, offshore Malaysia.

The 23-year agreement is the result of a collaborative, 2 1/2-year field development study, leveraging Baker Hughes' reservoir evaluation capabilities to analyze the geology and reservoir attributes of the mature and compartmentalized D18 field. Challenged with production declines, Baker Hughes successfully deployed two integrated production enhancement programs to revitalize production in target wells. Through further analysis, technical experts developed a comprehensive field development plan with fit-for-purpose technology solutions.

"We have utilized our best people to come up with solutions which are going to help PETRONAS Carigali Sdn. Bhd. [PCSB] achieve their goals of increased oil recovery from mature fields. The partnership between PCSB and Baker Hughes on this project represents a significant milestone in expanding our offering with reservoir development in addition to our traditional products and services portfolio," says Zvonimir Djerfi, President of Asia Pacific Region for Baker Hughes.

With the challenges surrounding this marginal, complex reservoir, Baker Hughes' field management strategy combines technical expertise and integrated solutions to enhance existing production by identifying new targets and efficiently constructing new wells to maximize production throughout the entire life cycle of the field.

Baker Hughes will participate in the redevelopment cost for the Greater D18 field in return for remuneration from the incremental production. The collaborative arrangement will extend the life of Greater D18 and will help sustain the area's economic strength. The company has successfully implemented a similar modeling strategy in other areas, including Asia Pacific, Mexico and the United States.

OPEC output dropped sharply in September, but non-OPEC supply growth is expected to approach record high in 2014

Global oil supplies declined by 625 000 barrels per day (650 kb/d) in September,  to 91.12 million barrels per day (mb/d), on steeply lower OPEC output, the IEA Oil Market Report for October told subscribers. But non‐OPEC supply growth for 2013 is forecast to average 1.1 mb/d, to 54.7 mb/d, rising to a near‐record 1.7 mb/d next year.

OPEC crude supplies slipped below 30 mb/d for the first time in almost two years, led by steep drops in Libya and Iraq. Output fell by 645 kb/d, to 29.99 mb/d, despite Saudi output exceeding 10 mb/d for a third month running. The "call on OPEC crude and stock change" was raised by 100 kb/d, to 29.6 mb/d, for the current quarter.

Recent demand strength has raised the 2013 forecast by 90 kb/d, to 91.0 mb/d. Demand growth for 2013 is projected at 1.0 mb/d (or 1.1%), ramping up to 1.1 mb/d in 2014 as the macroeconomic backdrop improves.

The Oil Market Report (OMR) is a monthly International Energy Agency publication which provides a view of the state of the international oil market and projections for oil supply and demand 12-18 months ahead. To subscribe, click here.

Shell and its partners have begun production from the second development phase of the Parque das Conchas (BC-10) project, located off Brazil’s south-east coast. The BC-10 project (Shell share 50%, Petrobras 35%, ONGC 15%) is comprised of several subsea fields which are tied back to a floating production, storage and offloading (FPSO) vessel, named the Espírito Santo.

In 2009 the first phase of the project began production, when the Abalone and Ostra fields were connected, along with the Argonauta B-West reservoir. The peak production of the first phase was more than 90,000 barrels of oil equivalent (boe) in 2010, and is currently producing some 35,000 boe per day.  Phase 2 connected a fourth reservoir to the vessel, the Argonauta O-North. At its peak, Phase 2 is expected to produce approximately 35,000 boe per day.



“Boosting production at BC-10 with the completion of phase two is another great example of our successful project development, delivery and execution capabilities,” said John Hollowell, Executive Vice President for Deep Water, Shell Upstream Americas. “It is a great day for Shell in Brazil.”



Building on what was already a successful proving ground for technology innovation, a 4-D Life of Field Seismic monitoring system was installed as part of Phase 2 subsea development. This technology, consisting of a network of seismic sensors installed throughout the field on the seabed, allows us to more effectively and efficiently monitor the reservoir. This is the deepest installation of its kind on a full-field scale in the world (approximately 1800m or 6000 feet).


Expecting to maximize the production life of BC-10 even further, Shell and its partners recently announced in July the decision to move forward with the project’s third development phase, which will include the installation of subsea-infrastructure at the Massa and Argonauta O-South reservoirs. Once online, Phase 3 of the BC-10 project is expected to reach a peak production of 28,000 boe.

A consortium of companies, including Royal Dutch Shell plc ("Shell"), Petrobras, Total, CNPC and CNOOC have won a 35-year production sharing contract to develop the giant Libra pre-salt oil discovery located in the Santos Basin, offshore Brazil.

The Brazilian regulator, Agência Nacional do Petróleo (ANP), estimates Libra's recoverable resources of between 8 to 12 billion barrels of oil.

"The Libra oil discovery in Brazil is one of the largest deep water oil accumulations in the world. We look forward to applying Shell's global deep water experience and technology, to support the profitable development of this exciting opportunity," said Peter Voser, Chief Executive Officer, Royal Dutch Shell.
Shell holds 20% in the consortium, with Petrobras 40% as operator, Total 20%, CNPC 10% and CNOOC 10%. The consortium will work together in an integrated fashion to support Petrobras, the most experienced operator in the Brazilian pre-salt, and will incorporate each company's deep water skills, people and technology for the success of the venture.

The production sharing contract is expected to be signed in November 2013. As part of the winning bid, Shell will pay its 20-percent share of the total signing bonus of USD $1.4 billion [3.0 billion reais], and fulfill the minimum work program no later than end 2017.
The ultra-deep water Libra accumulation is located in Santos Basin, approximately 170 kilometers (105 miles) off the coast of Rio de Janeiro. The block covers approximately 1,550 square kilometers in water depths of around 2,000 meters (6,500 feet). The reservoir depth is around 3,500 meters below the sea floor (11,500 feet). The ANP estimates that total gross peak oil production could reach 1.4 million barrels per day. Further appraisal is required to firm up this estimate, the development concept and a first oil date.

Shell is one of the industry's pioneers in deep water oil and gas with some 330,000 boe/d of production, world-wide, from deep water in 2012. Our commitment to technology and innovation continues to be at the core of our strategy. As energy projects become more complex and more technically demanding, we believe our engineering expertise will be a deciding factor in the growth of our businesses.

Shell was the first International Oil Company to produce on a commercial scale in Brazil and has more than 100 years of history within the country, with circa 65,000 boe/d of operated production in 2012. Shell is currently operating two Floating, Production, Storage and Offloading (FPSO) vessels in Brazil's offshore – the Espírito Santo at Parque das Conchas and the Fluminense at the Bijupirá/Salema fields - and has recently announced projects to expand production at both fields.
Shell also operates and owns an 80% interest in the BM-S-54 block, where the Gato do Mato discovery is being appraised. Shell has also other interests in Brazil, particularly our Lubricants business and our joint venture Raízen, the leading sugar cane ethanol producer and fuels retailer.

As fast-growing energy use in Southeast Asia leads to a sharp rise in the region’s dependence on oil imports and a reduction in its surplus of natural gas and coal for export, the International Energy Agency (IEA) has urged countries in the region to take serious action to improve energy efficiency.

“Southeast Asia is, along with China and India, shifting the center of gravity of the global energy system to Asia,” IEA Executive Director Maria van der Hoeven said at the launch of a World Energy Outlook Special Report, Southeast Asia Energy Outlook, which provides a comprehensive picture of the region’s energy future. Joining Ms. Van der Hoeven at the launch in Bangkok were Thai Minister of Energy H.E. Pongsak Ruktapongpisal and Hidetoshi Nishimura, Executive Director of the Economic Research Institute for ASEAN and East Asia.

The report projects Southeast Asia’s energy demand to increase by more than 80% in the period to 2035, a rise equivalent to current demand in Japan. Currently the region’s per-capita energy use is still very low, in part because 134 million people, or over one-fifth of the population, lack access to electricity.

Increasing reliance on oil imports will impose high costs on Southeast Asian economies and leave them more vulnerable to potential disruptions. The report projects that by 2035, the region’s oil imports will rise to just over 5 million barrels per day, making it the world’s fourth-largest oil importer after China, India and the European Union and doubling its dependency (to 75% of demand). Southeast Asia’s annual spending on oil imports is seen rising to $240 billion in 2035, equivalent to almost 4% of its GDP. Thailand’s and Indonesia’s oil import bills are projected to be the highest in the region, tripling to nearly $70 billion each in 2035.

According to the report, Southeast Asia will see a reduction in the surplus of natural gas and coal for export, as production is increasingly diverted to domestic markets. Its net gas exports are cut by more than three-quarters to 14 billion cubic meters in 2035. The region’s net coal exports also decline after 2020 as regional demand surges and demand in the wider Asia-Pacific market slackens. Indonesia’s coal production rises by almost 90% as it remains, by a very large margin, the world’s top exporter of steam coal.

The WEO Special Report highlights that the power sector is fundamental to the energy outlook for Southeast Asia, and that within it, coal is emerging as the fuel of choice because of its relative abundance and affordability in the region. Electricity generation is projected to increase by more than the current power output of India, with coal accounting for almost 60% of the growth. “The rising share of coal in power generation underscores the urgent need to deploy more efficient coal-fired power plants,” Ms. Van der Hoeven said. Currently the average efficiency of these facilities is very low, at just 34%, owing to the almost exclusive use of subcritical technologies.

Developing policies to attract investment is vital for enhancing energy security, affordability and sustainability in Southeast Asia. Around $1.7 trillion of investment in energy-supply infrastructure is required in the period to 2035. The report notes underdeveloped energy transport networks, the need for greater stability and consistency in the application of energy-related policies and subsidized energy prices as key challenges that must be overcome to mobilize this level of investment. The IEA noted the detrimental effects that fossil fuel subsidies have on energy markets, finding that in Southeast Asia they amounted to $51 billion in 2012.

The report includes an Efficient ASEAN Scenario that highlights the gains possible in Southeast Asia simply by adopting energy efficiency measures that make economic sense. Doing so would cut projected energy demand by almost 15% in 2035, an amount that exceeds Thailand’s current energy demand. Net oil imports would fall by around 700 kb/d, comparable with Malaysia’s current production. And regional GDP would rise by about 2% in 2035, as reduced spending on energy increases disposable income and stimulates economic activity.

To download the Southeast Asia Energy Outlook, please click here.

To see the slides presented at the report’s launch, please click here

 Huisman,a worldwide specialist in lifting, drilling and subsea solutions, has secured a new contract from Helix Energy Solutions Group, Inc. for the delivery of a Well Intervention System onboard Helix’s new build Semi submersible “Q7000”. The system, which is based on Huisman’s proven Multi Purpose Tower (MPT) design, will be built by the Huisman production facility in China.

The fully integrated 800mt Well Intervention System will be capable of handling the Intervention stack, the high pressure riser and other components. The Huisman Multi Purpose Tower has the same functionality as a normal derrick but offers improved accessibility to the well center, which allows for new improved handling procedures that increase efficiency and safety. The superior accessibility to the well center and the small footprint of the MPT are ideally suited for well intervention and subsea installation services. Subsea equipment can be skidded into the well center from three sides, offering enhanced flexibility.

The active heave compensation hoist system of the MPT provides excellent means for safe landing of equipment at the seabed while the passive heave compensation system provides a safe and redundant means to supply top tension to the risers. A guide trolley, travelling the entire length of the tower, guides the subsea modules during lifting operations. The system also features multiple transfer hatches that can be used to move equipment into the well center, and a skiddable work floor covering the moonpool flush with main deck.

The skiddable work floor allows large subsea modules to be deployed, without the need for a raised work floor. When large objects need to pass the moonpool the work floor can be skidded aside. In closed position, the work floor is flush with the main deck, which significantly reduces HSE risks and improves equipment handling on deck.

In addition to the Well Intervention System Huisman will also supply a 150mt Knuckle Boom Crane and a 160mt Pedestal Mounted Crane. Previous orders from Helix, amongst others, the Multi Purpose Tower onboard the “Q4000”, “Well Enhancer” as well as the cranes for the “Q4000” and “Q5000”.

Chevron Corporation (NYSE: CVX) has announced that its Australian subsidiaries have signed binding long-term Sales and Purchase Agreements (SPAs) with Tohoku Electric Power Company, Inc. (Tohoku) to supply liquefied natural gas (LNG) from the Chevron-operated Wheatstone Project in Western Australia.

Under the agreements, Chevron subsidiaries, together with subsidiaries of Apache Energy and Kuwait Foreign Petroleum Exploration Company, will supply Tohoku with 0.9 million tons per annum of LNG for up to 20 years.

Joe Geagea, president, Chevron Gas and Midstream, said, "These agreements with Tohoku create a new partnership between our companies and demonstrate the benefits of buyers and sellers working together to ensure supply is brought to the market to meet growing LNG demand."

Roy Krzywosinski, managing director, Chevron Australia, said, "We welcome the agreements with Tohoku, which mean that 85 percent of Chevron's equity LNG from Wheatstone is now committed to customers in Asia on a long-term basis.  These agreements, combined with our ongoing exploration success, demonstrate that our Wheatstone and Gorgon projects in Australian are well-placed to meet the growing demand for natural gas in the Asia-Pacific region."

The Wheatstone Project is located at Ashburton North, 7.5 miles (12 kilometers) west of Onslow in Western Australia. The project will consist of two LNG trains with a combined capacity of 8.9 million tons per annum and a domestic gas plant.

The Wheatstone Project is a joint venture between Australian subsidiaries of Chevron (64.14 percent), Apache Energy (13 percent), Kuwait Foreign Petroleum Exploration Company (7 percent), Shell (6.4 per cent), and Kyushu Electric Power Company, Inc. (1.46 percent), together with PE Wheatstone Pty Ltd. (8 percent).

Chevron also holds an 80.17 percent equity interest in the Wheatstone and Iago fields that provide 80 percent of the feed gas to the Wheatstone Project. The participants in the fields are PE Wheatstone Pty Ltd. (10 percent) as well as Australian subsidiaries of Shell (8 percent) and Kyushu Electric Power Company, Inc. (1.83 percent).