Brinx, Partners Complete Development Oil Well in Oklahoma

- Brinx, Partners Complete Development Oil Well in Oklahoma

Wednesday, September 07, 2011
Brinx Resources Ltd.

Brinx Resources and its partners have completed a new development oil well offsetting the highly successful 2008-3-5 well in southern Oklahoma. Completion of the new 2008-3-5A oil well took place on September 1, 2011.

The 2008-3-5A well immediately started flowing after it was perforated and began producing at a rate of 298 barrels of oil per day and an unmeasured quantity of natural gas. Since completion, the well has been producing at rates between 240 and 300 barrels of oil per day along with some natural gas. Electric log analysis indicates that several additional pay zones still exist above the completed section that will be tested at a later date.

The original 2008-3-5 well began production in May of 2009. As of June 1, 2011, that well had produced over 155,000 barrels of oil and 16.5 million cubic feet of natural gas from a single pay zone. The 2008-3-5 well continues to produce at a stabilized rate of over 100 barrels of oil per day. Engineers have estimated that the upper pay zones could contain over 180,000 additional barrels of oil to be recovered from the 2008-3-5A development well.

Brinx anticipates that it will take part in several additional development well drilling opportunities in Oklahoma in the near future. Also in Oklahoma, the Company expects to participate in a minimum of ten new exploration and development drill programs based on its recently completed 130 square mile 3-D seismic program.

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Petronas, Partners to Spend $5.05B to Develop Gas Offshore Malaysia

- Petronas, Partners to Spend $5.05B to Develop Gas Offshore Malaysia

Tuesday, August 23, 2011
Dow Jones Newswires
KUALA LUMPUR
by Ankur Relia

Malaysian state-owned oil and gas producer Petroliam Nasional Bhd. (Petronas) said Tuesday that it plans to spend MYR15 billion ($5.05 billion) with partners to develop marginal gas fields offshore Malaysia to meet growing demand in the country.

The project will likely encourage more investment in exploration activities that could lead to sizable discoveries offshore peninsular Malaysia, where subsidized prices have increased gas demand by 30% in recent years but have capped exploration and development.

"The development of the North Malay Basin project follows the recently introduced incentives by the government, particularly for the development of marginal fields, high [carbon dioxide] gas fields and fields located in high-pressure, high-temperature conditions," Petronas said in a statement.

It said a gradual revision of domestic gas prices also makes the project "more economically feasible."

The government said in May that it plans to raise the price of gas charged to the power sector by MYR3.00 per million British thermal units every six months, and expects the gas to be sold at market prices by 2016. It raised the price of gas for the power sector to MYR13.70 per mmbtu from MYR10.70 from June 1.

Demand for gas has increased by over 30% since prices were regulated in 1997 to keep them below market levels, Petronas said. However this has made investment less profitable, resulting in low levels of exploration and production activity, it said.

The North Malay Basin project comprises nine gas fields located within Blocks PM301 and PM302 and in the Bergading contract area about 300 kilometers off the coast, and includes a 200-kilometer pipeline from the fields to the state of Terengganu, the company said.

Petronas expects the first delivery of 100 million standard cubic feet of gas per day by early 2013, increasing production to 250 mmscf/d by 2015.

Petronas, Malaysia's only Fortune 500 company and the country's most profitable firm, didn't specify the partners it will be working with.

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

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SOCO, Partners Tame First Flow from Te Giac Trang Field

- SOCO, Partners Tame First Flow from Te Giac Trang Field

Monday, August 22, 2011
SOCO International plc

SOCO announced the first flow of crude oil and wet gas from the Te Giac Trang Field ('TGT'), which occurred at 0655 local time in Vietnam today. The block is operated on behalf of SOCO and its Partners, PetroVietnam and PTT Exploration and Production Public Company Limited, by the Hoang Long Joint Operating Company ('HLJOC'), which was established in 1999.

The TGT (White Rhineoceros) Field, discovered in August 2005, was approved for the initial development by the Government of Vietnam in September 2009. The development is comprised of a Floating, Production, Storage and Offloading vessel ('FPSO'), two Well Head Platforms (H1 and H4 areas), and a subsea pipeline system to transport hydrocarbons, gas export, gas lift and water for injection.

Crude oil from the TGT Field is transported via a subsea pipeline system to the FPSO 'Armada TGT 1', which has a name plate processing capacity of 55,000 barrels of oil per day ('BOPD'), where it is processed, stored and exported via tankers to regional oil refineries. Gas will be transported through a pipeline to the nearby Bach Ho Facilities for processing and transportation to shore via the existing pipeline infrastructure for further distribution to meet domestic demand. TGT oil output is expected to plateau at approximately 55,000 BOPD and gas production will be approximately 30 million cubic feet per day.

The development of the TGT Field marks a successful investment co-operation milestone in the Vietnam oil and gas industry with the delivery of production within two years of approval.

In addition to starting first production from the TGT Field H1 area, HLJOC continues drilling production wells in the H4 area of the TGT Field and fabricating Platform Topsides in preparation for its petroleum production start-up in August 2012.

Ed Story, President and Chief Executive of SOCO, commented, "We are very pleased to announce first oil from the TGT Field in Vietnam, a key milestone for the Company demonstrating our ability to see our exploration successes through to the production stage. The project always had an ambitious delivery target and we are pleased to have achieved this.

"Our strong partnerships have allowed this significant event at the TGT Field to be realized and we now look forward to targeting further exploration and development success, both in Vietnam and in Africa."

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Enbridge Energy to Add Cryogenic Natural Gas Processing Plant

- Enbridge Energy to Add Cryogenic Natural Gas Processing Plant



Aug 8, 2011

Enbridge Energy Partners (NYSE:EEP) announced that it will construct a 150 million cubic feet per day cryogenic natural gas processing plant on its Anadarko gas gathering system near Wheeler, Texas.

The $230 million Ajax plant--strategically located to serve the rapidly Granite Wash play will add much-needed gas processing capacity to the Patnership's

Anadarko system is expected to be in-service by early 2013.

Enbridge Energy Partners (NYSE:EEP) has a potential upside of 25.8% based on a current price of $26.35 and an average consensus analyst price target of $33.14.

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Statoil, Partners Hit Significant Oil Pay in North Sea

- Statoil, Partners Hit Significant Oil Pay in North Sea

Monday, August 08, 2011
Statoil

Statoil and partners Petoro, Det norske and Lundin have made a high-impact oil discovery on the Aldous Major South prospect (PL 265) in the North Sea.

Well 16/2-8, drilled by the Transocean Leader drilling rig, has identified an approximately 65-meter oil column in Jurassic sandstone. The acquired data confirm that this is a reservoir of excellent quality.

Statoil has previously described the well as a high-impact well, and the result confirms Statoil's belief in the exploration potential on the Norwegian continental shelf in line with what was communicated at the Capital Markets Day event in New York in June.

Preliminary volumes are estimated to be between 200 and 400 million barrels of oil equivalent (boe) for this part of the structure in PL 265, and Statoil expects additional upside in the license both north and south of the discovery.

Aldous Major South is located west of Lundin's Avaldsnes discovery (license PL 501), where Statoil has a 40% stake, and some 35 kilometers south of the Statoil-operated Grane field.

Well 16/2-8 indicates the same oil-water contact as in the Avaldsnes discovery well, which suggests the likelihood of communication between the two structures. The Avaldsnes discovery encountered a 17-meter oil column. Statoil will update its total resource estimate for the area when the wells are completed and the data analyzed.

"Aldous Major South is a considerable oil discovery in one of Statoil's core areas. Together with the Avaldsnes discovery this may allow for a new stand-alone development in the North Sea. As the largest resource owner our priority is to find the optimal solution for the area, adding maximum value to all partners," said Gro G. Haatvedt, Statoil's senior vice president for Exploration on the Norwegian continental shelf.

After completing this well Transocean Leader will start drilling the Aldous Major North well. This well also has a considerable volume potential.

The partnership is planning two appraisal wells in PL 265 next year and Statoil has secured rig capacity for this.

The result of the ongoing drilling of the Lundin-operated well (well 16/2-7) in the Avaldsnes structure will help further clarify the area’s potential.

Aldous Major South is located in license 265. Statoil is the operator and has a 40% interest. The other partners are Petoro (30%), Det norske oljeselskap (20%) and Lundin (10%).

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BPMigas: ExxonMobil, Partners Need $1.3B to Develop Cepu Block

- BPMigas: ExxonMobil, Partners Need $1.3B to Develop Cepu Block

Friday, August 05, 2011
Dow Jones Newswires
JAKARTA
by Deden Sudrajat

ExxonMobil and its partners will need to invest around $1.3 billion to fully develop their oil production facility in the Cepu Block in Java, the head of the Indonesian oil and gas sector watchdog said Friday.

Raden Priyono, the chairman of upstream oil and gas regulator BPMigas, estimated production at the Banyu Urip oil field can reach 165,000 barrels of crude a day at full capacity, compared with the current 20,000 barrels a day.

Exxon has picked a consortium of Samsung Engineering and PT Triparta as a partner for one of its five engineering, procurement and construction contracts in Banyu Urip. The $746.3 million contract was the biggest and the first to be signed. BPMigas' Priyono expects the remaining contracts to be signed later this year.

Mobil Cepu and Ampolex (Cepu) Pte. Ltd., both subsidiaries of Exxon Mobil, have a combined 45% stake in the block, while Pertamina EP Cepu owns 45% and the Cepu Block Cooperation Body, or BKS, holds the remaining 10%.

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

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El Paso Pipeline Partners Missed Q2 Estimates, Top Line Up 9%

- El Paso Pipeline Partners Missed Q2 Estimates, Top Line Up 9%



Aug 4, 2011

El Paso Pipeline Partners (NYSE:EPB) reported Q2 EPS of $0.50, missing consensus estimates of $0.54 per share. Revenues for the quarter rose 9.1% year-over-year to $358.0 million, missing consensus estimates of $360.8 million.

Jim Yardley, president and chief executive officer of El Paso Pipeline Partners said, "We continue to deliver superior results for our unitholders with another quarter of higher earnings and cash flow. Our portfolio of high-quality assets continues to grow through acquisitions and expansions. During the quarter, we completed the acquisition of additional interests in CIG and SNG, and now own 100 percent of SNG. We also placed into service additional expansion projects which brings our total to fourteen in less than three years. Our successful acquisitions and expansions have enabled us to deliver consistent distribution growth, as we have increased quarterly distributions every quarter since our IPO in 2007."

El Paso Pipeline Partners has a potential upside of 19.4% based on a current price of $35.29 and an average consensus analyst price target of $42.15.

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Earb South Discovery Disappoints Partners

- Earb South Discovery Disappoints Partners

Tuesday, August 02, 2011
Norwegian Petroleum Directorate

Marathon Oil Norge AS, operator of production license 505, has completed the drilling of wildcat well 25/10-11 testing the Earb South prospect in PL505.

The well was drilled about eight kilometers southwest of the previous discovery, 25/7-2, in the North Sea, about 40 kilometers south of the Heimdal field.

The primary exploration target for the well was to prove petroleum in Upper Jurassic reservoir rocks (Draupne and Heather formation). The secondary exploration target was reservoir rocks in the Middle Jurassic (Hugin formation).

Hydrocarbons were proven in a 95-meter interval with thin reservoir zones, in Middle/Upper Jurassic rocks. Hydrocarbons where also found in an intermediate 283 m gross interval, however, also in poorly developed reservoir rocks. A deeper zone had poorer reservoir properties, which was expected.

There were also hydrocarbons in the intermediate layer, but these were also in poorly developed reservoir rocks. The interval was production-tested, but did not achieve stable flow. Due to poor reservoir properties the well is not considered commercially interesting, but the licensees will consider further work in the production license.

The well is the first exploration well in production license 505, which was awarded in APA 2008.

The well was drilled to a vertical depth of 4534 meters below the sea surface, and was terminated in Middle Jurassic reservoir rocks. The water depth is 120 meters. The well will now be permanently plugged and abandoned.

Well 25/10-11 was drilled by Transocean Winner which will now proceed to production license 431 in the Norwegian Sea to drill wildcat well 6406/3-9, where Maersk Oil Norway AS is the operator.

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Lundin, Partners Submit Field Development Plan for Brynhild Field

- Lundin, Partners Submit Field Development Plan for Brynhild Field

Monday, August 01, 2011
Lundin Petroleum AB

Lundin as operator has, with its partners Noreco and Talisman, submitted a plan for development and operation (PDO) for the Brynhild field (formerly called Nemo) to the Norwegian Ministry of Petroleum and Energy. The Brynhild field is an oil field located in the Norwegian sector of the North Sea. First production from the Brynhild field in PL148 is expected in late 2013.

The Brynhild field is located adjacent to the Norwegian – United Kingdom (UK) international border. The PDO includes three wells and pipelines/umbilical tied back to the existing Shell operated Pierce field infrastructure in the UK sector of the North Sea. Brynhild holds 22 million barrels of oil (MMbo) in gross proved and probable reserves with a forecast gross peak production of approximately 12,000 barrels of oil per day (bopd). The oil will be processed and stored on the Pierce floating production, storage and offloading (FPSO) vessel before offshore loading to shuttle tankers.

Lundin Petroleum has a 50 percent working interest in the Brynhild field. Talisman and Noreco hold a 30 percent and a 20 percent interest, respectively.

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Caspian Energy, Partners Spud Kazakh Well

- Caspian Energy, Partners Spud Kazakh Well

Thursday, July 21, 2011
Caspian Energy Inc.

Caspian Energy and partners announced spudding of an exploration well between the two producing wells in the East Zhagabulak field of Kazakhstan.

The new well is the first step in a plan aimed at expanding the area held by the partners under a 25-year production licence, said Caspian Chairman and CEO William Ramsay. Ramsay said the well is one of six drilling targets approved July 8 by the Central Development Committee (CDC) of the Republic of Kazakhstan.

Well EZ #308 spud on July 16 and will take about 100 days to complete to about 4,700 meters, Ramsay said. It is targeting the same carboniferous structure of the Bashkirian layer from which the two earlier successful wells are currently producing about 400 barrels of oil per day.

All wells will be drilled under the direction of Aral Petroleum Capital, the operating entity in Kazakhstan, which is owned 40 per cent by Calgary-based Caspian and 60 per cent by Asia Sixth Energy of China.

Second target

At the same time that EZ #308 began drilling, a second rig was en route to a location southwest of the East Zhagabulak field, an area officially designated Zhagabulak II and III and locally known as Sakramabas. This rig is expected to commence drilling the CDC-approved Sakramabas #316 well before the end of July.

"Our seismic analysis indicates the potential for a high-porosity carbonate reef at the Sakramabas #316 site," Ramsay said. Neighbors have drilled successful wells on surrounding leases and our 3-D seismic indicates our well is on the same trend line as those producing wells and we have more advantageous geological conditions for oil and gas accumulation than our neighbors."

"It's a new direction for us and a potential new resource base, arising out of the success of our neighbors and a consequent re-examination of our seismic data.

"This is a deep well, targeting the same well know carboniferous structure of the Bashkirian layer at some 4,500 meters," he said. "Again we expect drilling to take about 100 days to reach total depth, with testing to follow.

"By drilling two separate exploration plays, we're offsetting risk and enhancing potential," Ramsay said. "We have good confidence in both prospects, but they are exploration wells and they entail some level of risk."

Next steps

Next steps in Aral's drilling plans will be governed by results at Sakramabas, Ramsay said. Success there may indicate the presence of a number of separate new oil and gas formations, from East Zhagabulak to Sakramabas. In the event of a good result at Sakramabas #316, the partners will complete the EZ #308 well and move that rig to a location northeast of Sakramabas, where it will test for oil between Sakramabas and East Zhagabulak. An additional drilling rig would then be contracted in October to pursue targets within East Zhagabulak.

Obtaining new geological data could prove regional distribution of oil and gas productive layers through all central parts of the Zhagabulak field and will enable Aral to apply for a production license on a greatly expanded area, Ramsay said.

"We would cross over into the new year with three rigs working full time to prove up the potential of the Zhagabulak field," he said.

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Lukoil, Partners Award Deal to Drill 23 Iraq Wells -Source

- Lukoil, Partners Award Deal to Drill 23 Iraq Wells -Source

Thursday, July 14, 2011
Dow Jones Newswires
LONDON
by Hassan Hafidh

Lukoil and its partners have awarded a deal to a "known" service company to drill some 23 new wells at Iraq's supergiant West Qurna Phase 2, a person familiar with the project said Thursday.

"The central contracts committee at the Iraqi Oil Ministry is studying the contract and we expect them to take a decision shortly," the person told Dow Jones Newswires.

Along with Norway's Statoil and Iraq's state South Oil Co., Lukoil is expected to award four other major deals in August to help develop the 12.9-billion-barrel field located in Basra governorate in southern Iraq.

The four contracts include a crude processing facility, a 126-megawatt power station, an export pipeline linking the field with a tank farm in Tuba near Iraq's southern export terminals, and six large storage tanks, the person said, adding the largest contract would be the crude processing facility.

The person said that Lukoil has shortlisted five oil services companies for this plant--Saipem, SNC-Lavalin Group, Punj Lloyd, Globalstroy-Engineering and South Korea's Samsung Engineering.

For the power station the Russian supermajor has received offers from a number of companies such as Petrofac and Greece's ENKA, the person said.

The contracts are part of an initial development plan to start production from the untapped oil field, set by Lukoil and Statoil and approved by Iraq's Oil Ministry last year. They are expected to help production at the field hit 150,000 barrels of oil a day in 2013, the person said.

Lukoil and Statoil were awarded a 20-year service contract for West Qurna Phase 2 in Iraq's second licensing round held in December 2009. The companies promised to get the southern field pumping at a rate of 1.8 million barrels a day for payment of $1.15 a barrel.

The development project is one of several that Iraq awarded last year with the ambitious objective of expanding its oil production capacity to 12 million barrels a day by 2017. But Iraq's oil minister said last month that Baghdad was considering scaling down this goal and could renegotiate deals.

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

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EnCore, Partners Acquire North Sea License

- EnCore, Partners Acquire North Sea License

Friday, July 01, 2011
EnCore Oil plc

EnCore Oil and its P1655 (Block 15/21g) partners, Nautical Petroleum and Serica (the P1655 group), have agreed terms to acquire a 70 percent interest in a part of adjoining License P218 (Block 15/21a). P218 is currently operated by DEO Petroleum with co-venturers, Faroe Petroleum plc, Maersk Oil UK Ltd and Atlantic Petroleum (the P218 group). The area in P218 to be acquired includes the 15/21a-38z Spaniards/Gamma discovery well, drilled in 1989 by Amerada Hess, which flowed 2,600 bbls/day of 26 API oil on test. In consideration, the P1655 group have agreed to assign the P218 group a 30 percent interest in P1655, and have agreed to fund the cost of the first well to appraise the Spaniards/Gamma discovery. It has also been agreed that a subsequent appraisal well, if deemed necessary and approved by the partnership, would be funded on promoted terms by the current P218 partners as shown in the table below, after which funding for any further wells would be by equity share.

The first well, is expected to commence drilling in Q2 2012, subject to suitable rig availability and receipt of the necessary permitting and site survey approvals.
Blocks 15/21d (P1870), 13/28b (P1866), 22/5 (P1876)

EnCore has also, subject to necessary DECC approvals, acquired a 50 percent interest in the above mentioned 26th Round Promote licenses under the terms of a pre-existing option agreement between EnCore and Echo Exploration Limited for a nominal sum. Echo Exploration is a 100 percent owned subsidiary of North Sea Energy Inc..

Block 15/21d contains the 15/21-50 Beehive discovery well, drilled by Amerada Hess in 1993 which flowed 5,700 bbls/day of 28 API oil on test.

Alan Booth, Chief Executive of EnCore commented, "We are especially pleased to have reached agreement with the P218 group to progress the further evaluation of the Spaniards/Gamma discovery. Although not without risk, if successfully appraised, Spaniards/Gamma has significant upside potential but also a relatively low commerciality threshold, given both the proximity of the Scott Field and the potential for synergies with the prospective development of the nearby Perth Field. Block 15/21 is a prolific block, containing a number of previously developed fields and having had 56 exploration and appraisal wells drilled in it to date, the last well, 15/21-56, being drilled some 14 years ago. We believe that the time is now right for further evaluation of these undeveloped discoveries."

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Repsol, Partners Make Discovery Offshore Brazil

- Repsol, Partners Make Discovery Offshore Brazil

Tuesday, June 28, 2011
Repsol YPF

Repsol Sinopec and its partners Statoil and Petrobras have made a discovery of good quality oil in the 1-REPF-11A-RJS well, informally known as Gávea. The find in Gávea is the most significant made in the pre-salt area of the Campos Basin.

The well, located 190 kilometers off the coast of Rio de Janeiro, was drilled with the latest-generation Stena DrillMAX drillship in a water depth of 2,708 meters (8,885 feet), reaching a final depth of 6,851 meters (22,477 feet).

The consortium is currently analyzing the results of the well before continuing with exploration and evaluation work in the area.

Repsol Sinopec, with a 35% stake, is the operator of the exploration consortium, in partnership with Statoil (35%) and Petrobras (30%).

Repsol Sinopec and the consortium informed the Brazilian authorities of the existence of traces of hydrocarbons in the Gávea exploratory well in March 2011 for the first level and April for the second one.

Repsol Sinopec is the largest foreign owner of exploration rights in the Santos, Campos and Espírito Santo basins, participating in 16 blocks of which it operates 6.

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Statoil, Partners Aim to Boost Recovery Rate at Njord License

- Statoil, Partners Aim to Boost Recovery Rate at Njord License

Wednesday, June 22, 2011
Statoil

Statoil and its partners in the Njord license in the Norwegian Sea have decided to invest in low-pressure field production. This, combined with other measures, will prolong the lifetime of the field until 2020.

Reservoir pressure on Njord is falling and the field has entered tail-end production. By lowering the pressure on the first and second stage separators it will be possible to increase production from individual wells and maintain production in each for an extended period.

"Owing to the complexity of the Njord reservoir the recovery rate of proven resources is currently roughly 23%. The aim is to increase the recovery rate to 30%. This type of measure is important with a view to maintaining production on the Norwegian continental shelf (NCS)," stated Ivar Aasheim, head of NCS field development.

There is currently a great deal of activity in the Njord area. The Njord northwest flank project six kilometers northwest of the Njord platform is now being carried out. It consists of two new long-distance wells drilled directly from Njord and tied back to the platform.

Several wells will be drilled in coming years. In addition, Hyme fast-track is being processed via Njord.

"In combination with the low-pressure production project these measures will prolong the lifetime of Njord until 2020," explained Njord production head Arve Rennemo.

The low-pressure production project on Njord will boost volumes by roughly 18.5 million barrels of oil equivalents alone and extend the field's working life by two to three years.

Investments in low-pressure production amount to roughly NOK 500 million.

The contracts for Njord low-pressure production modification and the Hyme topside has been awarded to Reinertsen. The contract for compressor procurement and installation was awarded in March of this year to GE Oil & Gas.

Project execution will take place in the autumn of 2012 and the start-up of low pressure production on Njord is scheduled for the fourth quarter of 2012.

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Det norske, Partners Sign Agreement for Block in Barents Sea

- Det norske, Partners Sign Agreement for Block in Barents Sea

Friday, June 10, 2011
Det norske oljeselskap ASA

Det norske and partners DONG and Edison have signed agreements for production license 613 at the Ministry of Petroleum and Energy.

Production license 613 was awarded in the 21st licensing round. The license is located in the northern part of Loppa High in the Barents Sea. The license covers blocks 7322/10 and 11.

The work program that the companies have now committed themselves to, includes acquisition of 3D seismic over the area. The decision to drill an exploration well must be taken within three years. Acquisition of seismic is planned to start already this year, and the first partner meeting will take place as early as next week.

Work with this license will be placed at Det norske's office in Harstad.

Licensees in PL 613:

• Dong E&P Norge (operator) 40 percent
• Det norske oljeselskap 35 percent
• Edison International Norway 25 percent

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Enterprise Products Partners Reports Strong Q1, Revenue Up 19% YoY

Enterprise Products Partners Reports Strong Q1, Revenue Up 19% YoY



May 10, 2011

Enterprise Products Partners L.P. (NYSE:EPD) reported Q1 EPS of $0.49 today, beating the consensus estimate for $0.44 per share. Revenues for the quarter were up 19% year-over-year to $10.18 billion, easily topping the consensus estimate for $8.86 billion.

Michael A. Creel, president and CEO of Enterprise stated, "Enterprise had a record first quarter to begin 2011. Our 50,000-mile system of natural gas, NGL, refined products, crude oil and petrochemical pipelines continues to operate at record or near record volumes. We are continuing to benefit from production growth in the shale regions as well as increased demand for NGLs by the U.S. petrochemical industry and international markets. With few exceptions, the partnership's diversified mix of businesses had another strong quarter."

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Buckeye Partners Reported In Line Q1 Results, Top Line Surged 71%

Buckeye Partners Reported In Line Q1 Results, Top Line Surged 71%



May 6, 2011

Buckeye Partners (NYSE:BPL) reported Q1 EPS of $0.79, in line with consensus estimates. Revenues for the quarter rose 71.3% year-over-year to $1.25 billion, ahead of consensus estimates of $860.0 million.

The company announced that its general partner declared a cash dividend of $1.00 per limited partner unit for the quarter ended March 31, 2011.

Forrest E. Wylie, Chairman and CEO stated, "Buckeye's overall operating results for the first quarter of 2011 were strong,. Adjusted EBITDA, our primary measure of performance, increased by 36.6 percent year over year. Although the primary driver of the increase is attributable to recent acquisitions, we saw a 7.9 percent year over year increase in the Adjusted EBITDA of our Pipelines & Terminals segment, which largely represents organic growth."

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Duncan Energy Increases Quarterly Cash Distribution

Duncan Energy Increases Quarterly Cash Distribution



Apr 14, 2011

Duncan Energy Partners (NYSE:DEP) announced its board of directors had declared an increase in the quarterly cash distribution rate paid to partners to $0.4575 per common unit, or $1.83 per unit on an annualized basis.

The quarterly distribution will be paid on Friday, May 6, 2011, to unit holders of record at the close of business on Friday, April 29, 2011.

The distribution is 2.2% increase from Q1 of 2010 and is the 10th consecutive quarterly distribution increase.

The stock is up 22.62% over the last 3 months.

Statoil, Partners Sign $1.5B EPC Contract with Petrofac

Statoil, Partners Sign $1.5B EPC Contract with Petrofac

Tuesday, April 12, 2011
Statoil

Statoil, BP and Sonatrach have signed a USD 1.15 billion engineering, procurement and construction (EPC) contract with Petrofac International (UAE) LLC in Algiers for the execution of the In Salah Southern Fields development project.

The EPC contract is part of the phase two development of the In Salah license. For Development and Production International the project marks an important step towards maturing barrels for profitable production.

The three gas fields – Krechba, Teg and Reg – located in the northern part of the license, were initially developed in phase one, with the objective of delivering a production profile of nine billion cubic meters of gas annually. This phase started in late 2001, and first commercial gas was delivered in July 2004.

Based on the expected decline of gas production from these three fields, phase two of the development has now implemented to maintain the production plateau and sustain long-term gas sales commitments. It consists of four gas fields – Garet El Bifna, Gour Mahmoud, In Salah and Hassi Moumene – in the southern part of the license.

Under the EPC contract Petrofac will build a number of facilities – including well pads, manifolds, flowlines, and a new central processing facility (CPF) with a gas processing capacity of 17 million cubic meters per day. The CPF will be constructed north of In Salah town and tied back to the existing producing facilities located in Reg for further transport of the gas to Krechba CPF for carbon dioxide removal and gas export.

In his speech, Victor Sneberg, Statoil's country president in Algeria, stated his expectation to Petrofac to deliver on time, cost and schedule.

First gas from the Southern Fields development project is expected for the first half of 2014. Gas produced from In Salah is marketed by joint marketing company "In Salah Gas Limited" – an association between Sonatrach, BP and Statoil. The three partners in the In Salah license have investment shares of 35% (Sonatrach), 33.15% (BP) and 31.85% (Statoil), respectively.

OMV, Partners Get MED Nod for Seismic Acquisition at GSB

OMV, Partners Get MED Nod for Seismic Acquisition at GSB

Friday, April 08, 2011

OMV NZ Ltd.

OMV New Zealand and its Joint Venture partners have confirmed that applications to modify the current work commitments to include the acquisition of 3D seismic data and/or drilling in their Great South Basin exploration permits were approved by MED on March 25, 2011.
The number of commitments in each permit remains the same, as does the decision date for confirmation of the commitments.

"Allowing for either drilling and/or 3D seismic acquisition during the next phase of work gives us greater flexibility as we work through our next steps," Managing Director for OMV New Zealand, Dr Wayne Kirk explained.

"It’s important to note that very little was known about the Great South Basin geology when OMV and its Joint Venture partners were awarded the permits in July 2007."
Since then, the Joint Venture has acquired 16,000 km of 2D seismic data in 2008, plus an additional 2,600 km of 2D seismic data in 2010.

"We’ve now evaluated this data and believe that there are a number of prospective areas which may benefit from 3D seismic definition prior to drilling."

Dr Kirk reiterated that the Joint Venture continues working towards the July 10th decision date, but no final decisions over drilling, 3D seismic or individual license continuations have been made.

If the decision is made to commit to further work, the activity must occur by July 10th 2012.
The Great South Basin permits 50119, 50120 and 50121 are held by OMV NZ Ltd (Operator, 36%), PTTEP NZ Ltd (36%) and Mitsui E & P Australia Pty Ltd (28%).