Halliburton: 'Phenomenal' Opportunities for Global Pressure Pumping Growth

- Halliburton: 'Phenomenal' Opportunities for Global Pressure Pumping Growth

Tuesday, September 06, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Halliburton Chief Executive David Lesar said Tuesday there are "fantastic and phenomenal opportunities" for oilfield service companies to expand shale drilling beyond North America, but that growth may come slowly.

"There is a lot to be excited about in the shale plays, but there are obstacles that need to be overcome and that's good because I don't think the industry today could serve a number of increasing shale plays outside the U.S.," Lesar told investors during a webcast presentation in New York.

Halliburton and other oilfield service companies have profited greatly in recent years as North American producers rush to unlock troves of oil and natural gas from deeply buried rock formations, called shales.

Demand for pressure pumping, which enables producers to crack open shales to release oil and gas, has outstripped Halliburton and its competitors' ability to provide the service, for example. In the last ten years pressure pumping has leap-frogged land drilling, offshore construction and offshore drilling to become the largest segment of the oilfield services industry, Lesar said.

While North America holds an estimated 15% of worldwide shale reserves, it has about 80% of global pressure pumping capacity.

"Even then we cannot keep up with the demand," Lesar said. "The challenge is going to be getting ramped up to address the shale opportunities outside the U.S."

Lesar said Australia, Poland and Argentina each have great potential for significant shale development, but that Australia is the only market that currently has the necessary geology, regulatory environment, pricing and infrastructure. Poland, he said, is lacking in oilfield infrastructure and in Argentina, where Halliburton recently completed South America's first shale well for Apache, government regulated natural gas prices are too low.

"Shale gas could develop very quickly in Argentina, but only at the right price and we're not there yet," Lesar said.

Global demand for natural gas should foster overseas shale development, though. Lesar said Halliburton expects worldwide demand for natural gas to rise 52% by 2030, three times the growth rate of oil demand.

Halliburton also forecasts increasing demand for deep-water drilling services. Lesar said the company is mobilizing for 31 jobs around the world, many in regions new to Halliburton, including Tanzania, Vietnam and Brunei.

Mobilizing for such jobs "doesn't come cheap," he said. "The up-front costs will weigh heavily on our margins and have weighed heavily on our Eastern Hemisphere margins, but I can tell you, this investment will pay off in the future."

Much of the work is being ordered by national oil companies, who are less likely than they have been in the past to share their resources with international oil companies, instead turning to service companies to help them extract their reserves, Lesar said. Four of Halliburton's top ten customers are now national oil companies, he said.

Lesar also said that Halliburton's pending purchase of Multi-Chem Group LLC., a deal that was announced earlier Tuesday, will give Halliburton the fourth largest production and completion chemical maker. Expected to close in the fourth quarter, the acquisition will also help Halliburton become less reliant on its peers' productions.

"It's been frustrating pumping competitors chemicals through our equipment," Lesar said.

Terms of the acquisition were not disclosed.

Copyright (c) 2011 Dow Jones & Company, Inc.

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AGR Notes New Drilling Technology and Growth Strategy

- AGR Notes New Drilling Technology and Growth Strategy

Thursday, September 01, 2011
AGR Group ASA

AGR Group is embarking on a new growth strategy that will allow it to maximize opportunities presented by today's market conditions. The strategy, announced by Skogen at Pareto, focuses on new technology and closer working relationships across divisions and markets.

AGR Group is launching a new technology which enables safer, cost-effective drilling of wells where reservoir conditions require more precise bottom-hole-pressure management. The EC-Drill® technology, which can be used off both fixed and floating rigs, is expected to enable further growth across the businesses.

Skogen's Pareto address signaled the official launch of this technology, "As a leading provider of technologies for demanding drilling and well operations, we are focused on developing new solutions which can enhance our customers' operations. With some reservoirs located a further 5,000 to 10,000 meters below the seabed, it is imperative that our equipment can handle very high pressures and temperatures."

Skogen also plans to bring the company's drilling technology and petroleum services divisions together to form 'AGR'. He continued, "In addition to EC-Drill® we have developed a range of established and market-leading technologies, including the Riserless Mud Recovery (RMR®) system.

"Previously, our drilling services division operated independently from our petroleum services division. We are now bringing them together to offer customers more choice and flexibility and to allow us to grow the company."

As Skogen turns his attention to growing 'AGR' he is seeking new opportunities for AGR's highly successful Field Operations business.

"Field Operations has grown significantly over the past few years and is today a substantial business. Going forward, we will consider how we can best further develop Field Operations. This is an attractive business and we see a range of interesting opportunities."

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Xodus Adds Director Duo to Support Global Growth

- Xodus Adds Director Duo to Support Global Growth

Wednesday, August 24, 2011
Xodus Group

Xodus Group has made two senior appointments to support its strategy for further international growth.

Nigel Ross joins as business development director from Wood Group GTS where he was global key account director. Maggie Leitch has been appointed global director for technical safety and risk (TSR) and joins from PSN where she was global head of safety & environmental engineering, managing a team she grew from 12 to 70.

Nigel brings more than 30 years' international industry experience and has helped to develop oil and gas businesses in key energy regions including West Africa, Middle East, the Caspian and Russia. He will sit on the board of the firm's XMOS joint venture in Nigeria and will help to expand the multi-disciplined global team.

A Russian speaker, Nigel is determined that his industry experience and contacts will be instrumental to Xodus achieving its bold growth targets in the coming years. He said, "Xodus is an ambitious, top flight consultancy on the cusp of further international expansion and I'm very keen to apply my global experience and structured business development and market entry skills to help the company achieve its growth target of 1,000 employees by 2015."

Nigel joins Xodus after 18 months at Wood Group where he worked as Global Key Account Director. Prior to this he worked at Petrotechnics Ltd as a business development manager overseeing a number of high-profile projects in the Middle East, West Africa and Brunei. Previously, Nigel worked in Shell International, SDPC Nigeria and Shell UK fronting up and downstream capital projects after starting his career with Scottish Enterprise where he spent 11 years developing export links with the former Soviet Union, on behalf of Scottish-based businesses.

Maggie Leitch joins Xodus with an extensive background within safety, loss prevention and risk management, boasting 22 years' industry experience.

Maggie worked at PSN as chief of safety and environmental engineering for over eight years. While there she was responsible for developing best practice and global policies for safety and environmental engineering groups, developing strategic plans for international growth and promoting personnel and industry development.

Further to this, Maggie set up her own internal consultancy which at peak boasted 22 technical specialists attracting its own external international clients. She previously worked at Atkins Process as the principal safety engineer building upon her past expertise at Total Fina Elf Exploration UK where Maggie spent the bulk of her early career.

Between 1989 and 2002 she performed various roles at TFEE UK ranging from process engineer to her peak position as the head of safety engineering and subsequently the senior project engineer on the £30 million Alwyn Systems Upgrade Project.

She said, "I'm looking forward to the challenge ahead and my aspiration is to help Xodus excel in the field of technical safety and risk. I want Xodus to be both the employer of choice for technical safety, value systems, risk and reliability engineers and the consultant of choice for clients."

Colin Manson, CEO of Xodus Group welcomed the duo to the team. He said, "We are very pleased to be appointing two high-caliber industry specialists and these new positions will help to greatly strengthen our management team as we continue to expand in the UK and new markets overseas."

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Brazil's Pre-Salt Reserves to Boost Latin American Oil Production Growth

- Brazil's Pre-Salt Reserves to Boost Latin American Oil Production Growth

Friday, August 19, 2011
Rigzone Staff
by Karen Boman

Brazilian state energy company Petrobras' plans to develop its offshore pre-salt oil reserves will contribute in part to what Barclays Capital calls a "sizable upward shift" in hydrocarbons production through 2011 through 2020, according to Barclays' Global Energy Outlook. Brazil and Colombia are expected to experience increases hydrocarbons production during that time period, most concentrated in oil versus natural gas, Barclays noted.

Petrobras has unveiled plans to spend US $127.5 billion, or 57 percent of the resources under Petrobras' 2011-2015 Business Plan of US $224.7 billion, on exploration and production efforts. The company plans to increase total oil and gas output from 2.7 million boe/d in Brazil and abroad to 4 million in 2015 and 6.4 million in 2020.

Pre-salt output alone will add up to nearly 2 million boe/d in 2020, pushing the pre-salt's contribution to production from two percent today to 18 percent in 2015 and 40.5 percent by 2020. Petrobras will achieve this growth by setting up 30 extended well tests over the next five years, including 20 in the pre-salt cluster, and 10 in the post-salt area. Additionally, the company will spend US $1.3 billion per year on technology, which will include funding for efforts explore new frontiers, oil recovery and develop a new generation of offshore and undersea production systems.

Petrobras last month also confirmed the commercial potential of its Lula discovery in the pre-salt Santos Basin in water depths ranging from 6,890 feet to 7, 218 feet. Lula produced 28,436 b/d, according to Subsea IQ, and is the first well to produce from Brazil's high touted pre-salt offshore reserves. The well is interconnected to Cidade de Angra dos Reis FPSO and is the first of six production wells to be connected to the FPSO. Petrobras expects for the FPSO to produce around 100,000 b/d d throughout 2012.

Other companies are seeing significant potential in Brazil's pre-salt area. BG Group in June upgraded its estimate of its pre-salt Santos Basin interests to some 6 billion Boe net to BG Group with an upside potential of 8 billion BOE net. The new estimates results from the company's internal analysis of data gathered from drilling, appraisal and other data, including data collected from 29 wells drilled in BG's existing discoveries.

"Robust economics and solid progress with the fast-track development program will see gross installed production capacity rising steadily to reach more than 2.3 million boe per day by 2017," said BG Group Chief Executive Sir Frank Chapman.

Other companies active offshore Brazil include OGX, which has identified the presence of hydrocarbons in the Santonian section of well 1-OGX-47-RJS in the BM-S-59 block in the shallow waters of the Santos Basin, according to Subsea IQ. The operator found a hydrocarbon column of about 430 feet in sandstone reservoirs of the Santonian section with about 167 feet of net pay. The OGX-47 well, named Maceio, lies about 68 miles off the coast of Rio de Janeiro in a water depth of 607 feet. The Ocean Quest semisub drilled the well.

Chevron reported last month that it plans to drill a well later this year in the pre-salt section beneath its Frade field offshore Brazil. The company will drill the well using Transocean semisubmersible Sedco 706, according to RigLogix. "If successful, we'll be in a great position to take advantage of our existing production facilities," said George Kirkland, vice chairman and EVP of Global Upstream and Gas at Chevron.

Petrobras' ambitious drilling plans include constructing newbuild rigs within Brazil; these plans make it likely that service companies will beef up investments in Brazil to meet their customers' needs. National Oilwell Varco (NOV) this week signed contracts to supply drilling equipment packages for seven drillships to Estaleiro Atlantico Sul, including drilling riser and pressure control equipment. The value, over the term of the deliveries, is approximately $1.5 billion. Pete Miller, Chairman, President and CEO of National Oilwell Varco, said the company is investing heavily in Brazil to manufacture more of the products and technologies National Oilwell Varco provides to its oil and gas customers, and to service the rapidly growing installed base of NOV drilling equipment in the region.

Sedco 706

The significant distance at which pre-salt reserves lie offshore Brazil means that operators will likely continue to favor floating production systems as field development solutions. Brazilian waters will be the most active region for future floating production projects, with 50 potential floater projects in the planning cycle, according to a recent report by International Maritime Associates Inc. Of the 50 potential projects, 26 are planned for ultra-deepwater, or water depths greater than 4,921 feet; five are planned for deepwater, or water depths between 3,280 feet and 4,921 feet, and 19 for water depths less than 3,280 feet.

Keppel Shipyard is on track to complete the modification and upgrade of FPSO OSX-1, the first floating production storage and offloading FPSO unit for OSX Brazil S.A. Chartered to OGX Petroleo e Gas Participacoes S.A., the FPSO will be deployed in the Waimea field in the Campos Basin offshore Brazil. The FPSO is expected to leave Keppel in this year's third quarter; production is expected to begin in this year's last quarter at a rate of up to 20,000 b/d from the OGX-26 well.

OGX in June unveiled its business plan related to discoveries in the Campos and Parnaibas basins. Waimea and the Waikiki production is expected to begin in the fourth quarter of 2013. In 2013, the company expects to have three Floating Production Storage Offloading FPSOs (OSX-1, OSX-2 and OSX-3) and two Wellhead Platforms "WHPs" (WHP-1 and WHP-2) in place with a total of ten horizontal production wells onstream in these two projects. OGX expects to achieve 150,000 b/d of production from the Campos Basin in 2013 in these two production complexes from 10 horizontal wells producing an average of 15,000 b/d each.

The gas production ramp-up in the Parnaíba Basin is expected to begin in the second half of 2012. OGX has one project covering two accumulations in the PN-T-68 block, which is 46.7% owned by OGX, and is expected to achieve gross production of 5.7 million m3 of natural gas per day (approximately 200 MMcf/d), or approximately 36,000 BOE/d in 2013 (approximately 15,000 BOE/d net to OGX).

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Halliburton CEO: Demand for Services Outpacing Capacity Growth

- Halliburton CEO: Demand for Services Outpacing Capacity Growth

Monday, July 18, 2011
Dow Jones Newswires
by Ryan Dezember

Halliburton Co. (HAL) Chief Executive Dave Lesar said Monday that demand for oil field services in North America, such as hydraulic fracturing, continues to grow faster than companies like his can add equipment as producers rush to drill unconventional oil basins.

"Overall, growth in the demand for our service has outpaced capacity additions and we expect this imbalance to continue going forward," Lesar said on a conference call to discuss second-quarter results.

Halliburton reported a profit of $739 million, or 80 cents a share, up from $480 million, or 53 cents a share, a year earlier. The latest period included a penny in restructuring-related costs. Revenue climbed 35% to $5.94 billion, which set a new company record.

Analysts polled by Thomson Reuters most recently forecast earnings of 74 cents a share on revenue of $5.71 billion.

Much of the quarter's success is attributed to activity in North America, where high crude prices, producers' healthy balance sheets and easy capital have fueled a rush to unlock unconventional onshore oil reserves, including shale formations.

Natural gas drilling in North America, though down 2% in the quarter, remained "relatively resilient, spurred by the increase demand for power generation due to the substitution of natural gas for coal and harsh summer temperatures in various regions," Lesar said. Though Halliburton remains "a bit cautious" on natural gas drilling, the company's move to reduce prices in order to keep customers drilling has been fruitful, he said.

Halliburton also cited an uptick in work in the U.S. Gulf, winning service contracts for eight of the 18 deepwater wells that have been permitted since U.S. regulators lifted a ban on such drilling in February. The ban was enacted in response to last year's Deepwater Horizon explosion, which killed 11 workers and touched off the worst offshore oil spill in U.S. history. Halliburton provided cementing services for the well the Deepwater Horizon was drilling for BP PLC (BP, BP.LN).

Lesar cautioned, however, that the pace of new drilling permits has slowed and once the current backlog of work is complete, the Gulf of Mexico recovery could stall in the second half of the year.

Internationally, where recovery from recession has come more slowly for service companies than in North America, margins improved slightly.

"We are now seeing evidence that the international pricing is stabilizing," Lesar said. "We believe that steady volume increases should be a precursor for overall international pricing to improve toward the end of the year."

Delays in Iraq weighed on results, though Lesar said he expects profitability in the Middle Eastern country by the fourth quarter.

"We believe that Iraq will be one of the fastest-growing countries internationally in the coming years and that we will benefit significantly as a result of a first-mover strategy," he said.

Lesar also said that while Halliburton is spending heavily in sub-Saharan Africa to establish operations in countries including Mozambique, Tanzania and Uganda, the efforts should "position us for many years of profitable operations going forward," Lesar said.

(Tess Stynes contributed to this article.)
Copyright (c) 2011 Dow Jones & Company, Inc.

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North America Delivers Strong Revenue Growth for Halliburton

- North America Delivers Strong Revenue Growth for Halliburton

Monday, July 18, 2011
Halliburton

Halliburton announced today that net income for the second quarter of 2011 was $747 million, or $0.81 per diluted share, excluding employee separation costs of $8 million, after-tax, or $0.01 per diluted share. Reported net income for the second quarter of 2011 was $739 million, or $0.80 per diluted share. This compares to net income for the first quarter of 2011 of $511 million, or $0.56 per diluted share. The first quarter of 2011 results were negatively impacted by $46 million, after-tax, or $0.05 per diluted share, related primarily to reserving certain assets as a result of political sanctions in Libya. Net income for the second quarter of 2010 was $480 million, or $0.53 per diluted share.

Halliburton’s consolidated revenue in the second quarter of 2011 was $5.9 billion, compared to $5.3 billion in the first quarter of 2011. Consolidated operating income was $1.2 billion in the second quarter of 2011, compared to $814 million in the first quarter of 2011. These increases were primarily attributed to improved pricing and equipment utilization in United States land, where nearly all product service lines have benefited from the shift to unconventional oil and liquids-rich basins. Consolidated revenue and operating income were $4.4 billion and $762 million, respectively, in the second quarter of 2010.

“I am extremely pleased with our second quarter results as total revenue set yet another company record. North America continues to deliver very strong growth in revenue and profitability, while international profit recovered modestly. As a whole, our level of operating margin was the highest it has been since 2008,” said Dave Lesar, chairman, president, and chief executive officer.

“North America revenue grew by 16% sequentially compared to United States rig activity growth of 6%, with incremental operating margins of greater than 50% for both divisions. This was driven by the execution of our North America growth strategy in liquids-rich basins, and our customers’ continued adoption of our integrated solutions.

“We have for some time expressed confidence in the strength of the North America cycle, and our results this quarter validate our positive view on the market. Strong crude prices, operators’ improved cash flows combined with their ability to access capital, and the increasingly liquids-rich nature of the United States land market, give us continued confidence in the strength of North America through 2012.

“International revenue grew 8% from the prior quarter, with 18% operating income growth, excluding the impact of Libya and employee separation costs. Strong sequential operating income improvement was driven by seasonal recovery in the North Sea and Russia as well as improved activity in Latin America and Asia. However, the shutdown in Libya, project delays in Iraq, mobilization costs in Sub-Saharan Africa, and the sluggish market in the United Kingdom and Algeria have impacted the pace of recovery for our international results. In Europe, despite the employee separation costs in the second quarter, increasing interest in shale development gives us confidence in business prospects longer term. We are now seeing some evidence that international pricing is stabilizing and we believe that volume increases will result in pricing improvements toward the end of the year.

“Robust growth in global energy demand supports the continuing need to develop new hydrocarbon resources and provides us with strong growth opportunities. We anticipate that the execution of our strategy and our focus on the high growth segments of deepwater, unconventional resources, and mature fields will result in margin expansion in both our North America and international business, and will support continued delivery of strong shareholder returns,” concluded Lesar.

2011 Second Quarter Results

Completion and Production

Completion and Production (C&P) revenue in the second quarter of 2011 was $3.6 billion, an increase of $446 million, or 14%, from the first quarter of 2011. Continued demand for production enhancement services in the United States accounted for the majority of this increase.

C&P operating income in the second quarter of 2011 was $918 million, an increase of $258 million, or 39%, over the first quarter of 2011. Excluding the second quarter impact of employee separation costs in the Eastern Hemisphere and the first quarter impact of the charge for Libya, C&P operating income improved $228 million, or 33%, from the first quarter of 2011. North America C&P operating income increased $213 million compared to the first quarter of 2011, primarily due to higher demand for production enhancement services in the United States land market. Latin America C&P operating income decreased $7 million, as higher costs across South America offset higher activity levels in Mexico and Brazil. Europe/Africa/CIS C&P operating income improved due to seasonal recovery in the North Sea. Middle East/Asia C&P operating income rose as higher activity across all product service lines in Saudi Arabia and Australia offset lower completion tools sales in Malaysia.

Drilling and Evaluation

Drilling and Evaluation (D&E) revenue in the second quarter of 2011 was $2.3 billion, an increase of $207 million, or 10%, from the first quarter of 2011, with all regions experiencing revenue growth.

D&E operating income in the second quarter of 2011 was $324 million, an increase of $94 million, or 41%, from the first quarter of 2011. Excluding the second quarter impact of employee separation costs in the Eastern Hemisphere and the first quarter impact of the charge for Libya, D&E operating income increased $76 million, or 30%, from the first quarter of 2011. North America D&E operating income increased $52 million compared to the first quarter of 2011, with higher United States drilling activity both onshore and in the Gulf of Mexico. Latin America D&E operating income increased $12 million, primarily due to higher activity in Brazil. Europe/Africa/CIS D&E operating income improved due to higher seasonal demand for drilling services in the North Sea and Russia which offset lower activity in Angola. Middle East/Asia D&E operating income was flat, as higher direct sales in China and Kuwait offset contract delays in Iraq.

Corporate and Other

During the second quarter of 2011, Halliburton invested an additional $12 million in strategic projects aimed at improving Halliburton’s operations and creating the opportunity for competitive advantage for the company. These include a lower cost service delivery model in North America and repositioning technology, supply chain, and manufacturing infrastructure to support projected international growth. Halliburton expects to continue funding this effort throughout 2011.

Significant Recent Events and Achievements

Halliburton was awarded a three-year contract by Chevron to provide integrated services for shale natural gas exploration in Poland. Under this contract, Halliburton will provide directional drilling, mud logging, cementing, coiled tubing, slickline, well testing, hydraulic fracturing, and completion equipment and services. Halliburton’s Consulting and Project Management team will support the project. Drilling is scheduled to begin in the fourth quarter of 2011.

Halliburton invests considerable time, energy, and resources in engineering solutions that set new standards for environmental safety – all while helping our customers do more by using less. The CleanSuite™ services are the latest in a long line of developments designed to reduce the environmental footprint of hydraulic fracturing operations. Recent achievements for CleanSuite™ technologies include the following:
Halliburton and El Paso Corporation announced that an El Paso-operated well in North Louisiana is the first natural gas producing well to be completed using all three Halliburton proprietary CleanSuite™ production enhancement technologies for both hydraulic fracturing and water treatment. More than four million gallons of CleanStim® hydraulic fracturing fluid, comprised of ingredients sourced from the food industry, were utilized to enhance the well and resulted in faster production of natural gas. Nearly 4.8 million gallons of water were treated through Halliburton’s CleanStream® process, which uses UV light instead of additives to control bacteria in water. Another one million gallons of produced water was recycled for use in the well through the CleanWave™ system, significantly reducing the need for freshwater.

Halliburton's CleanWave™ water treatment technology was recognized with the Spotlight on New Technology Award at the 2011 Offshore Technology Conference. The awards program is designed to showcase the latest and most advanced technologies that are leading the industry into the future. Year to date, we have treated over 47 million gallons of fracture flowback water or produced water with this technology.

Deepwater is the most challenging and expensive environment in which our customers operate. Recent technological developments by Halliburton that help improve our customers’ economics by providing more effective reservoir performance information include:
DynaLink® – Halliburton’s proven, two-way wireless acoustic telemetry system – now has the added capability to control downhole test tools from the surface during drillstem testing operations while transmitting real-time bottomhole pressure and temperature data.

This data, along with acoustic actuation of test tools, provides operators the benefit of changing the pre-defined well testing program based on reservoir response while testing. This technology was recently deployed successfully in deepwater wells in Mexico and Brazil.

The 4 Phase Vertical Test Separator is another step change improvement in deepwater well testing. First, the system eliminates the need for traditionally bulky and costly sand-handling equipment and the inherent operational difficulties associated with it. Second, it streamlines rig operations by eliminating costly rig time associated with the removal of produced solids. The Halliburton 4 Phase Vertical Test Separator recently demonstrated noteworthy time and cost savings for an operator in Brazil.

Realm Energy International Corporation has contracted Halliburton’s Consulting and Project Management team to work with Realm Energy to significantly expand the technical evaluation and ranking of the highest-potential shale deposits found in emerging prospective basins globally. Realm Energy and Halliburton’s Consulting and Project Management team began their collaboration in 2009 with an emphasis on European basins. During this initial effort 10 discrete sedimentary basins in four European countries were targeted for evaluation. The collaboration identified key prospect trends, and Realm has now successfully acquired 650,000 gross acres and has filed government applications for 4.4 million acres of contiguous tracts over significant shale resources.

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Premier Looks Ahead to Next Stage of Growth

- Premier Looks Ahead to Next Stage of Growth

Tuesday, July 12, 2011
Premier Oil plc

Premier provided a trading and operations update ahead of its 2011 Interim Results.

Simon Lockett, Chief Executive, commented, "With continuing good progress on our Asian development projects we expect to see a significant increase in production to around 60 kboepd by year end. Our development teams in the North Sea and Asia are already focused on delivering the next stage of Premier's growth. Our exploration program of around 20 wells over the next 12 months targets around 300 mmboe of unrisked prospective potential."

Production outlook

2011 to date has seen continuing good production performance from the Anoa field in Indonesia, while Pakistan's production has remained steady. This was offset by increased maintenance activity in the UK and a recent unplanned shutdown at Balmoral. As a result, estimated average group production for the first half of 2011 was 36.6 thousand barrels of oil equivalent (kboepd) (2010: 42.8 kboepd) and forecast full year production is now estimated at between 40 kboepd and 45 kboepd.

Near term developments in Asia (Chim Sao and Gajah Baru) are progressing well and 2011 year end run rate is expected to be around 60 kboepd as these projects ramp up. With the UK Huntington and Rochelle projects due on-stream next year, Premier is on target to reach a run rate of 75 kboepd in 2012. Our medium term target of 100 kboepd remains unchanged.

Singapore gas demand continues to grow for our gas exports from the Natuna Sea, with average gas sales under the West Natuna gas contract of 373 bbtud in the first half of 2011 compared to 357 bbtud in the second half of 2010. Block A's share of the contract amounted to 41 percent in the period (against a contractual share of 37 percent), though with a recovery in output from the other two PSC's participating in the contract, actual levels of production reduced from the prior period. Premier's production levels will rise in the second half of the year as the Gajah Baru development contributes from October.

In the UK, production was below expectations due to maintenance related downtime earlier in the year at the Balmoral and Wytch Farm facilities and a recent unplanned shutdown at Balmoral due to a subsea hydraulic leak. Production resumed at Balmoral on 4 July after a three week outage. Scott and Telford production has remained steady since April following earlier disruptions for gas compression maintenance.

As announced in June, Premier increased its stake in the Wytch Farm Assets by 17.715 percent. This is expected to add around 2.5 kboepd to Premier's UK production from year end 2011 when the transaction is targeted for completion. Following the shutdown in the first quarter, production at the Wytch Farm facilities has been rising in recent weeks to around 14 kboepd (gross).

Pakistan production is stable, with the natural decline in the fields offset by infill drilling and the completion of ongoing front-end compression projects. The successful K-18 sidetrack well on Kadanwari, which came on-stream in February 2011, continues to perform favorably. Delays in the front-end compression project at Zamzama are being resolved and increased production is anticipated imminently.

Current and future developments

Asia

In Vietnam, the Chim Sao project remains on schedule with first oil expected in August. On July 1, the FPSO moved from the Keppel yard to its offshore anchorage where deep water commissioning and trials were completed. The FPSO is now on tow to the Chim Sao field for the installation of the umbilicals that will connect it to the production wells.

The Gajah Baru project in Indonesia is progressing ahead of schedule. The Central Processing Platform topsides were installed on the jacket on July 6 and the bridge linking this to the wellhead platform was installed on July 7. Elsewhere on Block A, EPCI technical bids have been received and are under evaluation for the Anoa Phase 4 Development which will add additional compression capacity on the Anoa platform. In addition, the Front End Engineering and Design has been completed for the facilities and pipelines for the Pelikan and Naga fields. These projects are on target for sanction in the fourth quarter of 2011.

In North Sumatra, discussions with the shortlisted facilities EPCI bidders are under way. Technical bids are due in by September and final contract award is expected by year end. First gas on Block A Aceh remains on target for late 2013.

North Sea

The Huntington development in the UK is progressing, with work continuing on the Sevan Voyager FPSO upgrade project and sub-contracted modules. Timing for sail away (and therefore first oil) is likely to be impacted by the current financial situation of the FPSO supplier. Any material delay in the Huntington project will impact the average production for 2012 and the date at which a run-rate of 75 kboepd is achieved. In the meantime, key subsea equipment is on order and an installation contract has been signed. Development drilling commenced in April and is proceeding well.

An agreement for the Rochelle area has been executed with Premier acquiring a 15 percent equity in the unitised East and West Rochelle projects. First gas is anticipated for the fourth quarter of 2012. As previously announced, a Sale and Purchase Agreement for the Solan field was signed in May and Premier will become the development operator of the field at sanction with a 60 percent equity interest. Pre-sanction activities are progressing with final project approval targeted for later this year.

Development concept selection for Fyne is expected by year end, after the East Fyne appraisal well has been drilled. Discussions are ongoing with partners regarding potential development solutions for the Catcher Area. In Norway, development plans for the Froy field received Premier support for moving to the next phase. However, the operator has indicated that, due to limited resources and commitments elsewhere, they will not be proceeding with the project at this time. As a result, discussions with third party new entrants to the Froy project are underway. Dialogue also continues with the preferred contractor for the Bream field development regarding the timing of the FPSO availability.

Exploration and appraisal

Around 20 exploration and appraisal wells are planned during the next 12 months, with unrisked net prospective resource potential, on a P50 basis, of around 300 mmboe. Several of the planned wells for the first half of 2012 remain subject to partner approvals and government consents.

North Sea

As previously announced, the Grosbeak well in Norway was spudded in April 2011 and has now been sidetracked. The results of the sidetrack, which reached target depth on July 7, are anticipated later in July. Premier plans to drill its first operated well in Norway, the Gardrofa exploration well, in the third quarter of 2011.

Premier has signed a Heads of Agreement (HOA) with Antrim Energy to gain additional acreage in the Greater Fyne Area. Under the HOA, Premier will earn a 50 percent working interest in the acreage in return for funding a promoted share of the costs to drill a well on the Erne Prospect, which is planned for the third quarter. The Erne well will target an Eocene Tay Formation oil prospect located between the Fyne and Guillemot NW fields in the UK Central North Sea. A successful Erne exploration well will be taken into account for the Fyne development concept selection targeted for year end.

Separately the East Fyne appraisal well is now planned for the fourth quarter, using the Sedco 704 semi-submersible rig, the results of which - along with the results of the Erne exploration well - will feed into the Fyne development concept process. The Sedco 704 will then move to spud the Bluebell well, a prospect near to the Premier-operated Caledonia field and the Balmoral facility.

The Stingray well (Premier interest, 50 percent), which is scheduled for the first half of 2012, is targeting a Jurassic sandstone reservoir in UK Block 15/13b. In UK Block 28/9, the Joint Venture partners have decided to acquire 3D seismic data over the block in the second half of 2011. As a result, the Carnaby well will now be drilled in the first half of 2012.

Asia

In Indonesia, on the Tuna Block, Gajah Laut Utara was plugged and abandoned in June with oil and gas shows. The Ocean General Rig has now moved to Belut Laut, which spudded on 4 July. The Belut Laut prospect is in a separate sub-basin to that of Gajah Laut Utara and is an independent test of the petroleum system on the Tuna acreage. The results of Belut Laut are expected in August.

Elsewhere in Indonesia the Benteng-1 well on the Buton licence is expected to be drilled in the first quarter of 2012. The Matang-1 well on Block A Aceh is also scheduled to be drilled in the first quarter of 2012. The Antareja Resources land rig, Antareja-8, has been contracted for Matang-1.

Pakistan

As previously announced, the K-27 exploration well was successful and will be tied back to the production facility by the end of the third quarter, delivering around 30 MMscfd (gross). The K-29 and K-30 exploration wells, together with Badhra-6 Parh, are planned for late 2011.

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Faroe Clinches Credit Facilities for Future Growth Plans

- Faroe Clinches Credit Facilities for Future Growth Plans

Friday, July 08, 201
Faroe Petroleum plc

Faroe announced the signing of two new banking credit facilities, which provide substantial additional finance to underpin the Company's growth plans.

The two facilities are:

• NOK 1 billion (approx. £110 million) Norway Exploration Financing Facility, of which NOK 500 million (approx. £55 million) is initially committed by the participating banks, and a further NOK 500 million is available on an uncommitted "accordion" basis. Faroe Petroleum currently has approximately 20 exploration licenses offshore Norway and expects to drill 12 exploration and appraisal wells in Norway by the end of 2013. This facility is designed to have the capability of financing the majority of Faroe's exploration and appraisal costs on the Norwegian Continental Shelf. The facility will mature on 31 December 2014.
• US $250 million (approx. £156 million) Reserve Base Lending Facility, of which US $125 million (approx. £78 million) is initially committed by the banks, and a further US $125 million is available on an uncommitted "accordion'' basis. This facility is available to finance approved capital expenditure, operating costs and acquisitions. The facility will mature on June 30, 2016, with an amortizing repayment profile from June 2013.

Six participating banks have been selected and brought together as one group to provide the two facilities pro rata. The participating banks are BNP Paribas and Lloyds TSB Bank plc, as Mandated Lead Arrangers, together with Commonwealth Bank of Australia, DnB NOR Bank ASA, Royal Bank of Scotland plc and SEB. BNP Paribas are also acting as Facility Agent and Security Trustee under both facilities, with Lloyds TSB Bank plc acting as Technical and Modelling Bank under the Reserve Base Lending facility.

At 1 July 2011 the Group had cash balances of approximately £84.2m and, together with the cash flow from its existing producing assets, which now include the Blane oil field, and the forthcoming production income from the Brage, Njord, Ringhorne East and Jotun fields in Norway, the Group is well financed.

Commenting on the new facilities, Iain Lanaghan, Finance Director, said, "We are delighted to have concluded this financing exercise, and to have received such strong support from our banks, all of whom took part in a competitive process to participate in these facilities. The new facilities provide us with substantial new funding to support the growth of the Group."

"With an exciting drilling program ahead, of which the majority of wells will be drilled in Norway, the new Norway Exploration Financing Facility provides us with a powerful and efficient means of maximizing our equity participation for minimum cost. The combination of our new Reserve Base Lending facility and strong cash flow from our significantly enhanced portfolio of producing assets ensures that Faroe Petroleum is well funded for investment growth in our core areas."

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Husky Raises $1.2B to Boost Growth Strategy

- Husky Raises $1.2B to Boost Growth Strategy

Thursday, June 23, 2011
Husky Energy Inc.

Husky will raise approximately $1.2 billion offering of common shares by way of a bought deal (the "Public Offering") and a concurrent private placement of common shares (the "Private Placement") to its principal shareholders, L.F. Investments (Barbados) Limited, and Hutchison Whampoa Luxembourg Holdings S.a.r.l.

The Company has entered into an agreement with a syndicate of underwriters, led by RBC Capital Markets, Goldman Sachs Canada Inc., HSBC Securities (Canada) Inc., and J.P. Morgan Securities Canada Inc. (the "Underwriters") under which the Underwriters have agreed to purchase for resale to the public, on a bought deal basis, 36,968,500 common shares in the capital of Husky (the "Common Shares"), at a price of $27.05 per Common Share resulting in aggregate gross proceeds of $1 billion. The Public Offering is made pursuant to a prospectus supplement to the Company's universal base shelf prospectus filed November 26, 2010 with the securities regulatory authorities in all provinces of Canada and to the Company's universal base shelf prospectus filed June 13, 2011, with the U.S. Securities and Exchange Commission ("SEC").

Pursuant to the Private Placement, the principal shareholders L.F. Investments (Barbados) Limited and Hutchison Whampoa Luxembourg Holdings S.a.r.l. will subscribe for a combined total of $200 million in Common Shares (a total of 7,393,714 Common Shares) on a private placement basis at the same price as the Public Offering.

The Company continues to execute on its strategic initiatives to accelerate near-term production and reserve growth. Husky expects production for 2011 to be towards the higher end of its previously announced guidance range.

The Public Offering and Private Placement is a key strategic element of the Company's proactive financing plan announced in November 2010 and will provide additional financial flexibility to advance its growth strategy. Proceeds will be used to accelerate exploration and development of the Company's emerging oil and gas resource portfolio and the continued development of its growth pillars in the Oil Sands, South East Asia and the Atlantic Region, including the Liwan Gas Project offshore China and Phase 2 of the Sunrise Energy Project in the oil sands of northern Alberta.

With the additional capital raised, the Company projects that production for the 2011 to 2015 time frame will be towards the high end of previous guidance of three to five percent average annual growth and is expected to be sustained at three to five percent average annual growth through to 2021. It is also anticipated an annual reserves replacement ratio of 140 percent will be achieved through the same period.

The Public Offering and Private Placement are expected to close on or around June 29, 2011 and are subject to customary closing conditions, including the approval for listing of the additional Common Shares on the TSX.

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Chevron CEO Highlights 2010 Performance, Future Growth

- Chevron CEO Highlights 2010 Performance, Future Growth

Wednesday, May 25, 2011
Chevron Corp.

Chevron highlighted the company's 2010 performance and discussed the company's future growth at the 2011 Annual Meeting of Stockholders.

"A combination of safe, reliable operations and superior execution helped make 2010 an outstanding year both operationally and financially," said John Watson, chairman and CEO. "As we look ahead to the next decade, we remain committed to safety and delivering profitable growth."

Watson discussed Chevron's strong 2010 financial and operational performance, which produced earnings of $19 billion. The company
increased the quarterly dividend by 5.9 percent in 2010, marking 23 consecutive years of annual dividend increases. During this period,
dividends grew at an average annual rate of 7 percent. Chevron announced another quarterly dividend increase in April 2011. Watson said that Chevron led its peers in total stockholder return over the past five years, besting the S&P 500 by more than 14 percentage points. The company maintained its leading position in total stockholder return through the first quarter of 2011.

Watson reinforced Chevron's long-standing commitment to safe, reliable operations. Chevron is an industry leader in safety and in 2010 achieved the best safety performance in the company's history. He also discussed the partnerships Chevron has formed to address health, education and economic development issues in the communities where the company operates. Over the past four years, Chevron's social investments around the world have more than doubled.

George Kirkland, Chevron vice chairman and executive vice president for Global Upstream and Gas, discussed Chevron's world-class queue of projects to meet the world's future energy needs. Chevron plans on investing $26 billion in 2011, with 87 percent of that amount expected to fund upstream activities.

Kirkland noted that since late 2009, Chevron has added 14 million acres to its portfolio, including the acquisition of Atlas Energy in the
northeast United States, and deepwater opportunities in Liberia and China. Kirkland also discussed Chevron's queue of major capital
projects, including Gorgon and Wheatstone in Australia. Over the next three years, 25 projects with a Chevron share of more than $250 million each are scheduled to start production, nine of which have a net Chevron share that exceeds $1 billion. Chevron has four major capital projects planned to start up in 2011. Additionally, over the next three years, the company expects to make final investment decisions on 13 more projects, each with a Chevron share in excess of $1 billion. Construction on the Gorgon project is nearly 25 percent complete, with startup expected in 2014, and Chevron remains on schedule to reach a final investment decision this year on the Wheatstone project, with startup planned for 2016.

Kirkland also discussed Chevron's Downstream and Chemicals business, which delivered improved earnings and competitive performance in 2010. After completing a restructuring, Downstream and Chemicals has a lower cost structure and a portfolio focused on core markets, including North America and Asia. Last year, Chevron had three key downstream project startups at plants in South Korea, in Qatar, and in Pascagoula, Mississippi. Kirkland also discussed Chevron's investments in projects that improve energy efficiency, flexibility and product diversity, including the 25,000-barrel-per-day base-oil plant in Pascagoula. When complete in 2013, Chevron will be one of the world's leading suppliers of premium base oil. In addition, Chevron plans to deliver $700 million in improvements to its refinery system by the end of 2012, through a combination of improved efficiency, and controllable margin and yield
improvement.

Stockholders voted on 11 proposals and supported the board's recommendation on each of the proposals. As of May 25, 2011, the
preliminary report of the Inspector of Election was as follows:

• Item 1: More than 1.2 billion shares, or approximately 90 percent of the votes cast, were voted for each of the 13 nominees for election to the board of directors.
• Item 2: More than 1.6 billion shares, or approximately 99 percent of the votes cast, were voted to ratify the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm.
• Item 3: Approximately 98 percent of the votes cast were voted to approve, on an advisory basis, the compensation for the company's executive officers.
• Item 4: Approximately 84 percent of the votes cast were voted to hold advisory votes on named executive officer compensation every year.
• Item 5: Approximately 25 percent of the votes cast were voted for the stockholder proposal regarding the appointment of an independent director with environmental expertise.
• Item 6: Approximately 3 percent of the outstanding shares of Chevron common stock were voted for the stockholder proposal to amend Chevron's bylaws regarding a human rights committee of the board.
• Item 7: Approximately 6 percent of the votes cast were voted for the stockholder proposal regarding a sustainability metric for executive compensation.
• Item 8: Approximately 24 percent of the votes cast were voted for the stockholder proposal regarding guidelines for country selection.
• Item 9: Approximately 8 percent of the votes cast were voted for the stockholder proposal regarding financial risks from climate change.
• Item 10: Approximately 41 percent of the votes cast were voted for the stockholder proposal regarding hydraulic fracturing.
• Item 11: Approximately 9 percent of the votes cast were voted for the stockholder proposal regarding offshore oil wells.

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EFC Reports US Order Growth

EFC Reports US Order Growth

Monday, May 09, 2011
EFC Group

Headquartered in Aberdeen, Scotland, EFC Group announced significant order growth for its Houston office and US-based manufacturing capabilities.

The Americas region of EFC Group, a leading designer and manufacturer of Handling, Control, Instrumentation, and Monitoring Systems for the global oil and gas industry, also announced several major new US contracts, taking its Hydraulic Controls Division over the $1 million USD [approx GBP600,000] mark in 2011 to date.

EFC Group general manager Americas, Mike Coady said: "Our Houston-based staff and contractor numbers have doubled in the last six months to meet local manufacturing demand.

"With the launch of EFC Group Hydraulic Control and Test Panel product line, the Americas team has recently secured contracts totaling over $1million USD. Most notably a contract award for six trailer mounted systems for a global pressure control company."

Ocean Rig has placed a further significant contract for its four ultra-deep waters high-specification drill ships, 12 hotline test panels have been procured, the first three have been delivered onboard the Ocean Corcovado.

Terry Wise, Ocean Rig Subsea Project Engineer commented "EFC quickly customized a neat solution providing the exact regulated lines for our testing needs. We will continue to work with EFC for future control and instrumentation systems."

EFC is predicting 60% international growth over the next two years, with a strong focus on the US market.

EFC showcased its latest hydraulic product launch, the high pressure 15Kpsi BOP Test unit during its OTC Open House. The BOP Test Unit answers the increasing industry need for frequent testing whilst reducing operational downtime.

Mike continues: "With North and South America and Gulf of Mexico sectors accounting for more than 30% of our international business, the US market is extremely important to us and is supported by our growing Houston team. We are continuing to develop our reputation as a specialist supplier of tailored mechnanical handling, well control, BOP control and marine instrumentation system solutions to the global oil and gas industry."

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Range Boosts Production in 1Q 2011

Range Boosts Production in 1Q 2011

Tuesday, April 19, 2011
Range Resources Corp.

Range provided an operations update. First quarter production volumes averaged 545.5 Mmcfe net per day, a 17% increase over the prior-year period and 1% higher than fourth quarter 2010. The record production marked the Company's 33rd consecutive quarter of sequential production growth. Production was 79% natural gas, 16% natural gas liquids (NGLs) and 5% crude oil. Targeted drilling to the liquids-rich portion of the Marcellus Shale play in Pennsylvania and the Midcontinent regions drove the production growth. First quarter 2011 production was 16% NGLs versus 12% for first quarter of 2010.

The Company also announced that its preliminary first quarter 2011 commodity price realizations (including the impact of cash-settled hedges and derivative settlements which would correspond to analysts' estimates) averaged $5.46 per mcfe. This represents a 2% decrease from the prior-year period, but a 2% increase as compared to the fourth quarter 2010. Preliminary first quarter production and realized prices by each commodity are: natural gas – 429.9 Mmcfe per day ($4.40), natural gas liquids – 14,338 barrels per day ($47.96) and crude oil – 4,924 barrels per day ($81.35).

Commenting on the announcement, John Pinkerton, Range's Chairman and CEO, said, "Despite the unusually cold weather conditions we incurred in the first quarter, we were able to reach the mid-point of our production guidance. Adjusting for the weather related downtime, we would have exceeded the high end of our guidance. Our operating teams did an outstanding job battling some of the most brutal weather conditions we have experienced in many years. Looking ahead, due to the terrific drilling results so far this year, combined with the progress of the infrastructure projects, we are well on track to reach our production growth target for the year. In addition, the Barnett sale is on schedule to close at the end of the month."

Marcellus Shale Division

We exited the first quarter at approximately 260 Mmcfe per day net from the Marcellus Shale, up from approximately 200 Mmcfe per day at year-end 2010. During the first quarter, the Marcellus Division brought online 26 horizontal wells in southwest Pennsylvania, 15 of which were located in the liquids-rich area of the play. The initial production rates of the 15 new wells averaged 7.4 (6.3 net) Mmcf per day of natural gas and 452 (384 net) barrels of NGLs and condensate per day or 10.1 (8.6 net) Mmcfe per day. An additional 16 wells were completed in southwest Pennsylvania during the first quarter that are awaiting connection to the gathering system. In northeast Pennsylvania, Range brought on its first five wells in Lycoming County at a combined initial production rate of 45 (39 net) Mmcf per day in mid-February.

Due to the outstanding performance of its existing wells combined with the initial performance of the newly connected wells, Range's Marcellus production has temporarily outgrown the existing infrastructure. In southwestern Pennsylvania, the third expansion of the gas processing facilities has been completed and is in the testing phase. This 200 Mmcf per day of additional processing capacity is expected to commence operation in May. With this expansion, Range's total processing capacity will expand to 350 Mmcf per day. Later in the third quarter, Range's processing capacity is scheduled to increase again to 390 Mmcf per day. In northeast Pennsylvania, the next expansion of the Lycoming County gathering system is scheduled to be completed late in the third quarter which will tie in an additional 20 wells.

Range has entered into two memorandums of understanding exploring options to sell ethane from the liquids-rich area in southwest Pennsylvania. Range plans to complete firm ethane sales agreements in the next 12 months covering a significant portion of its projected ethane production.

Midcontinent Division

First quarter activity for the Midcontinent Division focused on drilling operations in several key areas. One rig remains active in the Texas Panhandle, where two Granite Wash wells and one vertical St. Louis exploratory well are undergoing completion. Range's original horizontal St. Louis Lime well continues to perform above expectations. After 12 weeks of production, the well has produced more than 1.0 Bcfe with current rates still at 13.0 Mmcf of natural gas and over 900 barrels of liquids per day or 18.4 (5.6 net) Mmcfe per day. Activity in the Ardmore Basin Woodford play continues with four wells in various stages of completion. Production from these liquids-rich completions is expected to reach sales by the end of the second quarter. One operated rig is currently running in the play, along with additional non-operated activity. Drilling also continues in the Mississippian Lime play of northern Oklahoma with one operated rig and one non-operated rig in the Woodford "Cana" Shale play of the Anadarko Basin.

Appalachian Division

During the first quarter of 2011, the Appalachian Division continued to focus on tight gas sand and coal bed methane (CBM) drilling projects on its 350,000 (235,000 net) acres in Virginia. All of this acreage is either owned or held by production allowing for discretionary drilling with no lease expiration issues. In 2011, Range plans 50 tight gas sand wells, 15 CBM wells and 15 horizontal wells targeting the Huron Shale, Berea and Big Lime formations in Virginia. For the first quarter, the division drilled 5 (4.5 net) vertical tight gas sand wells and one CBM well in the Nora field. Also in the quarter, Range performed 8 recompletions of behind-pipe pays to continue to maximize production on existing wells.

Southwest Division

In the first quarter the Southwest Division drilled its first Penn Shale well in the Conger Field of West Texas where Range has approximately 91,000 net acres. The well has a lateral length of 4,000 feet and will be completed with a multi-stage fracture treatment later in the second quarter.

ATP Gets Go-Ahead to Complete Drilling at GOM Green Canyon Block

ATP Gets Go-Ahead to Complete Drilling at GOM Green Canyon Block

Friday, April 08, 2011

ATP O&G Corp.

ATP has received a permit to complete the previously drilled #2 well at Green Canyon (GC) Block 300 (Clipper) in the deepwater Gulf of Mexico.

"We are pleased that the BOEMRE is confident in ATP's commitment to safe and environmentally sound operations," stated T. Paul Bulmahn, ATP's Chairman and CEO. "The Gulf of Mexico is where we refined our deepwater expertise and we are looking forward to generating further production growth."

The GC 300 #2 well, located in 3,454 feet of water, was sidetracked and encountered a gas reservoir between 15,590 and 15,721 feet total vertical depth in 2006. ATP plans to commence well operations with Diamond Offshore's Ocean Victory in 2011. ATP operates GC 300 with a 55% working interest.

S. Korea Seeks Role in African Energy Development

S. Korea Seeks Role in African Energy Development

Friday, March 25, 2011
Asia Pulse Pte. Ltd

South Korea is seeking to take part in various energy development projects in Africa in an effort to boost mutual economic growth and make better use of natural resources, the government said Friday.

The Ministry of Knowledge Economy said a delegation led by Deputy Minister Kim Jung-gwan visited Angola and Ghana earlier in the month and discussed ways to expand cooperative tie-ups in liquefied natural gas (LNG), oil field development and oil refinery construction.

"Officials from both countries expressed a wish to forge a win-win partnership involving energy development, sharing of economic growth knowhow and fueling business investments," the ministry said.

The ministry added that Angola and Ghana have untapped natural resources and have considerable growth potential. Angola is the third-largest oil producing country in Africa, while Ghana started oil production last year and aims to build up its industrial infrastructure.

A memorandum of understanding on energy cooperation was signed with Ghana with views being exchanged on allowing South Korea companies to take part in a new oil refinery and gas pipeline building projects being pursued by the West African nation, it said.

SK Energy Co. and state-run Korea Gas Corp. have expressed interest in the two projects.

In Angola, the delegation discussed the possible purchase of LNG from a refinery that is expected to go on-line in 2012. Resource-poor South Korea is one of the largest importers of the fossil fuel resource in the world and has sought to diversify its imports to better insulate it from sudden price fluctuations.

The southwest African nation also said that it will welcome South Korean companies taking part in oil exploration efforts off its coast.

Budget fuel price call by Welsh Tories and Lib Dems

23 March 2011 Last updated at 06:44 GMT

Chancellor George Osborne has been urged to help Welsh motorists with fuel prices when he delivers his Budget.

Mr Osborne has hinted that he may scrap a fuel duty rise due next month.

Conservative assembly group leader Nick Bourne said he had "to do what's right by the country" and hoped he could act on fuel.

The Chancellor has faced calls for action after a sharp rise in petrol prices

Welsh Liberal Democrat leader Kirsty Williams said household budgets were under pressure and called for the fuel duty increase to be scrapped.

The Tories and Lib Dems said the UK government had laid the foundations for economic growth by dealing with the deficit.

But the Welsh Assembly Government said spending cuts were too deep and too fast.

On Sunday, Mr Osborne told the BBC's The Andrew Marr Show that he was "looking very carefully" at freezing the duty in Wednesday's Budget.

With uncertainty in the Middle East and Libya contributing to increased oil prices, the cost of petrol has risen sharply.

Motoring organisations have called on the government to scrap the planned rise in duty. It is due to take effect in April when it will go up by inflation plus 1p, making a total rise of about 4p per litre.

The Welsh Lib Dem leader said last year's Budget was "difficult... but it laid the foundations for the sustained economic recovery that Wales needs", she said.

"Fuel duty is now a real issue for so many families, particularly in rural Wales," she added.

The Wales Office has asked the Treasury to cut the cost of petrol by up to 5p a litre in rural Wales.

Minister David Jones recently revealed that he asked for a proposed fuel duty rebate scheme to be extended to the Welsh countryside

Growing the economy

But Welsh Assembly Government Finance Minister Jane Hutt said: "My main message to the chancellor is that the cuts are too fast and too deep and they are putting families, communities and businesses at risk in Wales."

She said the Budget needed to take action to stop the UK sliding back into recession, adding: "We need to see that there is a clear plan for growth and jobs."

Prime Minister David Cameron has rejected claims that Wales has been unfairly targeted by spending cuts.
Plaid Cymru said the Westminster coalition government should have concentrated on growing the economy instead of cutting spending in its first budget last year.

Plaid MP Jonathan Edwards said: "Quite simply, they got it the wrong way around."

Trade union Unison said its research showed last October's spending review could deprive the Welsh economic of £3.6bn and warned of 52,000 job losses, with half coming from the private sector.

Unison Cymru secretary Paul O'Shea said: "The view that the private sector is going to mop up the job losses being experienced in the public sector is merely wishful thinking."

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Increasing volume of legislation costs businesses £2bn

23 March 2011 Last updated at 06:33 GMT

By Eddie O'Gorman BBC NI business reporter

Businesses have lost out on more than £2bn in the last decade due to an increasing volume of legislation, according to business lobby group the CBI.

Nigel Smyth's comments come ahead of the Chancellor, George Osborne's first annual Budget statement on Wednesday.

Mr Smyth said additional support for growth and job creation, and less red tape, particularly relating to employment were the main preoccupations for Northern Ireland business.

Nigel Smyth of the CBI says businesses are having to deal with an increase in legislation

He said that business organisations had been lobbying hard to encourage government to reduce barriers to high-growth companies in order to create employment.

"This includes doing something to relieve the regulatory burden," he said.

"But they are also having to cope with increasing costs such as the carbon reduction commitment, which from being an incentive, has now turned into a carbon tax."

Mr Smyth said that Northern Ireland companies were competing in global markets now, and many of their competitors were not having to deal with the same level of regulation.

As a result they had a lower cost base than companies based in the UK, he said

He said: "The danger is that some of these highly successful, highly productive companies will simply move to locations where the cost base is not so high."

Dr Esmond Birnie, the chief economist for PricewaterhouseCoopers in Northern Ireland, believes that any tax increases in the Budget would have a serious effect on the local economy.

"February's unemployment is up 6.3% year-on-year," Dr Birnie said.

"That is the highest increase of all 12 UK regions, and we are forecasting that local economic growth will not exceed one per cent in 2011.

"It means that further tax increases could have a disproportionate impact on economic growth and business confidence."

On the bright side, it is thought that the 1p rise in fuel duty due on 1st April might be postponed because of the recent steep increase in oil prices, while personal tax allowances are set to go up by £1,000 to £7,475 for 2011/12.

It is estimated that this should reduce the tax liability of 23 million taxpayers by an average of £200 a year.
The Chancellor has already promised to increase personal allowances to £10,000 by 2015.

An announcement is also expected on the subject of corporation tax, or company profits.

Many economists and Northern Ireland business people have been arguing strongly that a reduction from the current rate of 28% closer to the rate of 12.5% which exists in the Republic, would do much to encourage inward investment.

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