GENERAL INTEREST — Quick Takes
Woodside makes takeover bid for Oil Search
Woodside Petroleum Ltd. has made a nonbinding indicative all-scrip takeover proposal for Papua New Guinea-based explorer and producer Oil Search Ltd. Woodside will offer 1 share of its own stock for every 4 shares of Oil Search stock. Based on trading before the bid, this values Oil Search at about $11.65 billion (Aus.) and is only a moderate premium. Oil Search is valued at $10.2 billion (Aus).
The Woodside proposal is a merger through a scheme of arrangement and is conditional on the granting of a mutually acceptable confidentiality agreement, an agreed period of exclusivity plus secure support from Oil Search’s main stakeholders. Specifically, Woodside wants to be satisfied that the transaction is likely to be supported by the Papua New Guinea government, which has a 10% shareholding in Oil Search.
Oil Search has given a cautious reply, saying that it would review the proposal without giving any guarantee that a binding agreement can be reached. Oil Search said it did not need Woodside given its high equity position (29%) in the world-class Papua New Guinea LNG project, operated by ExxonMobil Corp., plus attractive low-cost ongoing LNG development opportunities, reserves upside, and extensive high-quality exploration acreage.
Oil Search recently posted the highest half-year profit in its 86-year history with production up 50%. The company’s net profit after tax for the first 6 months of 2015 was $227.5 million (US) with revenue up 69% to $863.8 million driven by a marked increase in oil, condensate and LNG sales to 14.5 million boe from 4.7 million boe. The company’s share price has been robust.
In contrast, Woodside’s share price is close to a 52-week low and has been eroded recently by low LNG prices and its 19.9% gearing.
Shell, BG merger cleared by EU
The European Commission has unconditionally approved the planned $70-billion merger of Royal Dutch Shell PLC and BG Group PLC reported in April (OGJ Online, Apr. 8, 2015).
Including clearance in Brazil, two of the five preconditions to the combination have now been satisfied. In June, the US Federal Trade Commission granted early termination for the US antitrust waiting period (OGJ Online, June 16, 2015).
“The transaction is on track for completion in early 2016,” said Ben van Beurden, Shell chief executive officer. “The recommended combination with BG is a springboard to change Shell into a simpler and more profitable company, making Shell more resilient in a world where oil prices could remain low for some time.”
Phillips 66 to contribute assets to DCP Midstream
Phillips 66 and Spectra Energy have entered into a nonbinding letter of intent for contributing assets to strengthen their 50-50 joint venture DCP Midstream.
Spectra plans to contribute its ownership interest in both the Sand Hills and Southern Hills natural gas liquids pipelines. Phillips 66 plans to contribute $1.5 billion in cash, which is expected to be used to pay down a portion of the DCP revolving credit facility.
The companies say the transaction is expected to provide DCP with a stronger balance sheet and increased financial flexibility, and positions the JV to grow through commodity price cycles. DCP hopes to convert certain contracts from commodity price sensitive to fee-based.
The deal is expected to close in the fourth quarter, after which Phillips 66 and Spectra will remain 50-50 joint venture owners of DCP.
Earlier this year, Phillips 66 Partners LP acquired one-third equity interest in the limited liability companies that respectively own the Sand Hills and Southern Hills systems from Phillips 66 as part of a $1.01-billion deal (OGJ Online, Feb. 16, 2015).
Exploration & Development — Quick Takes
Noble, Israel continue gas field development talks
Noble Energy Inc., Houston, reiterated Sept. 3 that it is still in negotiations with the Israeli government regarding the development of Tamar and Leviathan natural gas fields in the eastern Mediterranean (OGJ Online, Jan. 19, 2009; Dec. 29, 2010).
Analysts said Noble’s statement was in response to concerns about the recent announcement by Italy’s Eni SPA that it made a “supergiant gas discovery” with its Zohr gas prospect drilled offshore Egypt (OGJ Online, Aug. 31, 2015). Eni believes Zohr could hold 30 tcf of lean gas in place in a 100-sq-km area .
Noble said it “continues to work diligently with the government of Israel to address matters necessary to facilitate the development of its world-class discoveries at Tamar and Leviathan and ensure a stable investment climate.”
Specifically, Noble restated that a regulatory framework for development was approved by the Israeli government and was presented to the Knesset. Also, Noble said the Egyptian government reiterated its support for gas imports from Israel for both domestic and LNG export purposes.
Tamar, discovered in early 2009, was the largest conventional gas discovery in the world during that year, the company said. Appraisal work, including drilling and core sample analysis, has determined gross mean resources of 10 tcf of gas, Noble said. Tamar production began in March 2013.
Leviathan, discovered in late 2010, was the largest exploration discovery in Noble’s history, the company said. With 19 tcf of gross gas mean resources, Leviathan is being evaluated by Noble and its partners for various monetization options including various LNG and pipeline export projects.
“We believe the large regional demand-including in Israel, Jordan, Egypt, and Turkey-is such that no single one of the region’s discoveries can fill it,” Noble said, adding, “And there is a significant export market to Europe as well.”
Karoon gets approval for Brazilian appraisal program
Karoon Gas Australia Ltd., Melbourne, has received approval from the Brazilian oil and gas regulator for its revised appraisal program for the company’s 65%-owned Santos basin blocks.
The forward work program includes the commencement of appraisal drilling on the Echidna light oil discovery during 2016. Karoon also expects to install an early production system (EPS) on the field, although this is contingent on the continued success of the appraisal drilling.
The EPS is likely to comprise two or more production wells that will provide important technical information about reservoir performance and form the basis of a full field development. In addition, the EPS would provide an analogue for understanding the nearby Kangaroo oil find and any similar discoveries in the company’s permits.
A 3D seismic survey also is planned to enable better risking and ranking of other prospects in the permits. Further discoveries would be tied back to a centrally located floating production, storage, and offloading vessel.
An added contingent work program is expected to start at the beginning of 2019 and comprise as many as four wells.
Drilling & Production — Quick Takes
Second well flows oil at South White Rose extension
Husky Energy Inc. has started oil production from a second well at the South White Rose extension offshore Newfoundland and Labrador.
The two wells are expected to produce a combined net peak production of 15,000 b/d (OGJ Online, June 29, 2015).
“This satellite extension aligns with our long-term strategy to extend the life of the main White Rose field through staged step-outs,” said Asim Ghosh, Husky chief executive officer.
Production from the South White Rose extension drill center is tied back to the SeaRose floating production, storage, and offloading vessel.
Operator Husky holds 72.5% interest in the main White Rose field and 68.875% interest in satellite fields North Amethyst, South White Rose, and West White Rose.
Husky said the West White Rose extension, subject to review and final approvals, is expected to begin production no earlier than 2020 (OGJ Online, July 28, 2015).
Smorbukk South ‘fishbone’ well flow starts
Statoil ASA has started production from the low-permeability Smorbukk South Extension of Asgard oil and gas field in the Norwegian Sea with what it claims to be the first use of “fishbone” multilateral technology offshore Norway (OGJ Online, Mar. 20, 2013).
Because of low permeability and porosity described as “ranging from bricks to tiles,” Statoil could not fracture the reservoir. It instead used a well with a long horizontal section from which 150 “bones,” each 10-12 m long, were drilled. The Odfjell Drilling Deepsea Bergen jack up handled drilling.
The technology achieved 5,200 m of reservoir exposure, Statoil said.
The company didn’t report the production rate. It estimates reserves at 16.5 million boe.
Discovered in 1985, the reservoir was long considered too tight to develop. Statoil said it might drill a gas-injection well.
NPD reports small oil discovery by Statoil
The Norwegian Petroleum Directorate reported a small oil discovery by Statoil Petroleum AS in the northern North Sea.
The 30/9-27 S in production license 104 encountered a 34-m oil column in sandstone with moderate to good reservoir quality. NPD cited preliminary estimates of 1-2 million cu m of recoverable oil equivalent.
The well was drilled by Songa Delta AS’s Songa Delta semisubmersible drilling rig about 7 km west of Oseberg Sor field. The well was drilled in 103 m of water to a measured depth of 3,989 m and a vertical depth of 3,353 m subsea, and terminated in the Ness formation.
The discovery will be developed with the Oseberg Delta 2 project (OGJ Online, Feb. 23, 2015). The Songa Delta will now drill a development well in PL 104.
Odfjell to drill six Maria wells off Norway
The Odfjell Drilling Deepsea Stavanger semisubmersible rig will drill at least six wells for Wintershall Holding GMBH’s subsea development of Maria oil and gas field in the Norwegian Sea (OGJ Online, May 8, 2015).
The $175 million contract provides options for additional wells. Beginning in April, 2017, Odfjell will drill three production wells each in the field’s two subsea templates in about 300 m of water 20 km east of Kristin field and 45 km south of Heidrun field.
Maria will be linked to platforms on those fields as well as the Asgard B platform. The Deepsea Stavanger is a dual-derrick, sixth generation deepwater rig.
PROCESSING — Quick Takes
Sibur-Gazprom Neft JV commission gas plant
A joint venture of Russian conglomerate PJSC Sibur Holding, Moscow, and PJSC Gazprom Neft, St. Petersburg, have commissioned the newly built Yuzhno-Priobskiy gas processing plant (Yuzhno-Priobskiy GPP) in Western Siberia’s Khanty-Mansi Autonomous Area.
Designed by Sibur subsidiary NIPIgazpererabotka (Nipigaz), Moscow, the Yuzhno-Priobskiy GPP, which began construction in February 2014 based on the Yuzhno-Priobskaya compressor station, entered operation on Sept. 3, Sibur and Gazprom Neft said.
With a capacity to process 900 million cu m/year of associated petroleum gas (APG), the plant also will have a liquids-recovery rate that exceeds 95%, the companies said.
Sibur and Gazprom Neft said they expect processed APG from the plant to generate about 340,000 tonnes/year of NGLs and 750 million cu m/year of dry-stripped gas.
The Yuzhno-Priobskiy GPP comes as part of an initiative to develop a petrochemical cluster in Western Siberia under the Russian government’s gas and petrochemical industry development plan through 2030, the companies said.
Reconstruction of a pipeline for the supply of dry-stripped gas that connects to the Khanty-Mansiysk natural gas pipeline was executed concurrently with construction of the new processing plant to transport gas supplies to a gas-turbine power plant at the Yuzhno-Priobskoye field for power generation, as well as to the city of Khanty-Mansiysk and Khanty-Mansiysk District to meet domestic gas supply needs, Gazprom Neft said in an Apr. 27 release.
Infrastructure also was constructed to enable transportation of NGLs from Yuzhno-Priobskiy GPP to Sibur’s processing operations at Tobolsk in Western Siberia’s Tyumen region (OGJ Online, July 14, 2015; Feb. 20, 2015).
All supporting infrastructure was due to be in place before start-up of Yuzhno-Priobskiy GPP, Gazprom Neft said.
As part of the JV’s agreement, Gazprom Neft will supply APG from Yuzhno-Priobsky field to Yuzhno-Priobskiy GPP on a long-term basis, with Sibur to pay for half of the volume, the companies said in a late-December 2013 release.
The parties additionally agreed that SIBUR will its share of dry gas from APG processed at the new plant to Gazprom Neft and, in turn, purchase Gazprom Neft’s share of NGLs.
Formosa eyes Louisiana for ethylene project
Formosa Petrochemical Corp. (FPC), a member of Taiwan’s Formosa Group, is evaluating the possibility of building a $9.4-billion ethane cracking and petrochemical complex along the west bank of the Mississippi River in St. James Parish, La., according to the Louisiana Economic Development (LED).
In addition to ethylene, the complex, which FPC would develop in two phases, would include downstream plants for production of polyethylene as well as customized outputs of low and high-density polyethylene, ethylene glycol, polypropylene, and other derivatives, LED said.
Phase 1 of the project would involve construction of an ethylene cracker and associated plants followed by a doubling of those installations in Phase 2.
Details regarding planned production capacities at the complex were not disclosed.
Should FPC proceed with the project, construction and development on Phase 1 would begin next year, with plant recruitment to start in 2018.
Construction of the Phase-2 ethane cracker and downstream plants would follow completion of Phase 1 in 2022, LED said.
In an effort to secure the project, Louisiana has offered FPC a competitive incentive package to offset infrastructure costs that includes a $12-million performance-based grant to be paid in four equal annual installments beginning in 2018.
FPC is scheduled to take final investment decision on the proposed project by mid-2016. If approved, FPC’s project would be the second large-scale, grassroots ethylene production plant to be built in Louisiana by overseas operators.
Earlier in the year, Shintech Inc., the US subsidiary of Shin-Etsu Chemical Co. Ltd., Tokyo, confirmed its previously announced plan to invest $1.4 billion on construction of a 500,000 tonne/year ethylene plant on land the company already owns in Plaquemine, La. (OGJ Online, Apr. 23, 2015; Apr. 16, 2014).
Construction of the ethylene plant, the first ever to be built in the US by a Japanese operator, is due to be completed during first-half 2018, Shintech said.
As he did with Shintech, Louisiana Gov. Bobby Jindal laid the groundwork for FPC’s proposed complex during his 2014 economic development mission to Asia when he visited with company officials in Taiwan, LED said.
Thai operator lets second FEED for ethylene complex
PTT Global Chemical (PTTGC), Thailand’s integrated petrochemical and refining company, has let a contract to a consortium led by Bechtel Enterprises Holdings Inc. to perform front-end services related to construction of the company’s proposed petrochemical complex in Belmont County, Ohio (OGJ Online, Apr. 22, 2015).
Along with partners JGC America and Samsung Engineering America, Bechtel will deliver front-end engineering and design (FEED) for the proposed project, which will include an ethane cracker and derivatives units designed to process gas feedstock from nearby Utica and Marcellus shale region for production of ethylene, high-density polyethylene, high-purity ethylene oxide, and monoethylene glycol, Bechtel said.
The service provider disclosed neither the value nor duration of the contract.
PTTGC previously awarded a contract to a consortium of Flour Corp., Technip SA, and SK Engineering & Construction Co., to provide FEED work on the planned petrochemical complex (OGJ Online, Sept. 4, 2015).
The Fluor-led team said it will complete FEED activities for the project in 2016.
On Sept. 3, Ohio Gov. John R. Kasich said PTTGC intended to invest $100 million to conduct detailed engineering design for the proposed project, which would be built in Belmont County, on the west bank of the Ohio River.
PTTGC also has signed an option agreement for key properties in Ohio’s Mead Township, where the complex would be built, said Supattanapong Punmeechaow, PTTGC’s president and chief executive.
The company plans take up to the next 12 months to determine evaluate the project’s feasibility.
If approved, construction on the project would take 3-4 years, Kasich said. Final investment decision on the project is due sometime in 2016-17.
TRANSPORTATION — Quick Takes
Inpex submits revised plan for Abadi LNG project
Inpex Corp., Tokyo, has submitted a revised plan of development to the Indonesian government for the Abadi LNG project in the Arafura Sea. It envisions a floating LNG (FLNG) plant with a processing capacity of 7.5 million tonnes/year.
The revision stems from confirmation of a greater volume of natural gas reserves in Abadi field’s Masela block.
Operator Inpex Masela Ltd. sent the revised plan to the Indonesian Special Task Force for Upstream Oil and Gas Business Activities (SKK Migas).
The initial plan was based on developing Abadi field in stages, with the first stage having an LNG processing capacity of 2.5 million tpy (OGJ Online, Dec. 27, 2010). Between November 2012 and November 2014, Inpex conducted front-end engineering and design work.
Based on evaluations of three appraisal wells drilled between June 2013 and April 2014, Inpex confirmed the presence of a greater volume of Abadi gas reserves, which was confirmed by Indonesian authorities. Inpex said it conducted studies “to assess the optimal development scenario.”
Inpex expects the field to contain sufficient reserves to support LNG production of 7.5 million tpy for more than 20 years, and 24,000 b/d of condensate.
Masela block lies in 400-800 m of water covering 3,221 sq km about 150 km off Saumlaki, Maluku Province.
Inpex Masela has 65%, and Shell Upstream Overseas Services Ltd. 35% (OGJ Online, May 28, 2013). The block is based on a production-sharing contract under the supervision and control of SKK Migas. Inpex acquired the block in 1998 and the discovered Abadi in 2000.
Second segment of Aegis pipeline complete
Enterprise Products Partners LP (EPP) has completed construction of the Aegis pipeline segment connecting Beaumont, Tex., with Lake Charles, La.
The 48-mile segment, along with the initial 60-mile segment currently in service (OGJ Online, Sept. 30, 2014), supplies ethane to petrochemical facilities between Mont Belvieu, Tex., and Lake Charles.
The final leg of the 270-mile Aegis system, expected to be completed by yearend, will extend the pipeline from Lake Charles to the Mississippi River.
EPP’s Mont Belvieu complex is the terminus for more than 3 million b/d of natural gas liquids supply pipeline capacity, and is connected to more than 2 million b/d of industry NGL fractionation capacity and more than 110 million bbl of EPP-owned salt dome storage capacity.
Combined with EPP’s existing South Texas system, Aegis will provide shippers with access to a 500-mile ethane header system between Corpus Christi, Tex., and the Mississippi River in Louisiana.
The Aegis pipeline is supported by customer commitments of more than 300,000 b/d that ramp up over the next 4 years. The pipeline’s capacity can be expanded to 400,000 b/d with additional pumps.
Origin plans Otway gas pipeline
Origin Energy Ltd., Sydney, has submitted plans for environmental approval of its proposed natural gas pipeline associated with development of nearshore Halladale and Speculant fields in the offshore Otway basin of western Victoria.
Plans are for the 200-mm, 33-km line to be co-located with a 50-mm, 33-km mono-ethylene glycol (MEG) pipeline that will transport MEG to the offshore wells.
The intention is to reuse an old in-situ pipeline for the 24-km central section between onshore Croft field well and the site of the former Heytesbury gas plant.
A 1.6-km line will link Speculant and Halladale wells to the Croft site and a 7-km pipeline will link the Heytesbury and Otway gas plant sites. Construction is slated to begin before yearend with the pipeline brought on stream in a year’s time.
Speculant and Halladale fields are expected to produce at 20-30 petajoules/day averaged over 10-15 years with a maximum early flow of 65 petajoules/day.
The new offshore pipelines will be buried in a common trench. They will be directionally tunnelled to cross the coast under the heritage listed Great Ocean Road.
Halladale and nearby Black Watch fields lie just 5 km offshore. Origin purchased control from Woodside Petroleum Ltd. in 2008. Origin discovered Speculant field in 2014.
