GENERAL INTEREST — Quick Takes
DNO to buy Marathon's Norway unit for $2.7 billion
DNO ASA has entered into a definitive agreement to acquire Marathon Oil Norge AS, a wholly owned subsidiary of Marathon Oil Corp., for $2.7 billion, effective Jan. 1. The deal, expected to close in the fourth quarter, includes the Marathon-operated Alvheim floating production, storage and offloading (FPSO) vessel, 10 company-operated licenses, and several nonoperated licenses in the Norwegian North Sea. In 2013, the company's net production in Norway averaged 80,000 boe/d.
This is the latest move executed by Marathon in a series of divestitures and acquisitions. The firm in September 2013 agreed to sell 10% interest in offshore Angola Block 32 for $590 million, and then reported plans to buy 4,800 net acres in the South Texas Eagle Ford shale for $97 million (OGJ Online, Sept. 10, 2013).
Last month, Marathon unit Speedway agreed to acquire Hess Retail Holdings LLC from Hess Corp. for $2.87 billion (OGJ Online, May 22, 2013).
"Since becoming an independent E&P company in 2011, Marathon Oil has executed $6.2 billion of strategic divestitures, repositioning the portfolio for future growth and profitability," said Marathon Oil Pres. and CEO Lee M. Tillman.
"Marathon Oil has a deep inventory across three high-quality US resource plays with expanding opportunities to further accelerate activity. Such organic growth will be our first priority for additional capital allocation," he added.
Entering the year, the company reported that more than $3.6 billion of its 2014 $5.9 billion capital, investment, and exploration budget would be allocated to resource plays as the company expects more than 30% growth from 2013 in production in the Eagle Ford, Bakken, and Oklahoma Woodford (OGJ Online, Dec. 11, 2013).
Marathon also has elected to retain its UK North Sea business after receiving "no acceptable offer."
Origin Energy to acquire Karoon's Poseidon permits
Origin Energy Ltd., Sydney, plans to buy 40% equity in the offshore Western Australian Browse basin permits WA-315-P and WA-398-P that contain the Poseidon gas fields from Karoon Gas Australia Ltd., Melbourne, for as much as $800 million.
The structured payment details within the conditional sale and purchase agreement include an up-front payment to Karoon of $600 million upon completion of the deal. There will also be a deferred cash payment of $75 million payable to Karoon on a final investment decision (FID) for development of the Poseidon fields plus a second deferred payment of $75 million payable on first production.
In addition Origin will pay $5 million for every 100 bcf of gas equivalent of independently certified 2P reserves exceeding 3.25 tcfe across the permits at the time of FID to a maximum of $50 million.
Origin will also be responsible for all proportional costs associated with the Pharos-1 exploration well currently being drilled in WA-398-P along with proportional costs associated with the ongoing Poseidon fields appraisal program.
The agreement is subject to joint venture pre-emptive rights and regulatory approval. ConocoPhillips holds 40% of both permits and is operator. PetroChina holds the remaining 20% in each permit.
Nevertheless, Karoon expects completion of the deal during the third quarter of this year.
Development of Poseidon may involve transportation of natural gas to an LNG plant in Darwin or to an FLNG facility at the field.
Karoon has retained its 90% interest in permit WA-314-P, which lies immediately to the north of WA-315-P.
The deal comes two weeks after Karoon's announcement of a $63 million farm-in to the company's offshore Carnarvon basin permits in WA to Apache Energy.
For Origin the Poseidon purchase extends its already considerable gas interests in Australia. The company has extensive stakes in the onshore Cooper basin of South Australia and Queensland, has recently farmed into permits in the Beetaloo basin in the Northern Territory, and is operator of the Australia Pacific CSG-LNG project feeding Surat-Bowen basin coal seam gas into an LNG plant being built on Curtis Island near Gladstone in Queensland.
Energy XXI, EPL shareholders okay merger
Shareholders of Energy XXI (Bermuda) Ltd. and EPL Oil & Gas Inc. have approved the merger to which the companies agreed in March (OGJ Online, Mar. 12, 2014).
The deal involves Energy XXI; EPL; Energy XXI Gulf Coast Inc., an indirect wholly owned subsidiary of Energy XXI; and Clyde Merger Sub Inc., a wholly owned subsidiary of Energy XXI Gulf Coast.
On completion, Merger Sub would merge with EPL, making EPL an indirect wholly owned subsidiary of Energy XXI.
Exploration & Development — Quick Takes
Saratoga tests Rocky 3 well at 1,500 b/d of oil
Saratoga Resources Inc., Houston, has provided an update on its Rocky 3 horizontal development well in Breton Sound Block 32 field.
The SL 1227-29 Rocky 3 well in 14 ft of water was spud on May 3 using the Parker 72B barge rig, reaching a TMD of 7,178 ft (5,818 ft TVD) on May 15. The well was completed in the 5,800 ft sand with a lateral displacement of 750 ft. The Rocky 3 well tested on May 30 at a gross equivalent rate of 1,531 b/d of oil and 240 Mcfd on a 20/64-in. choke with flowing tubing pressure of 780 psi. Oil gravity is 39.8°.
Saratoga said its other horizontal wells in the same field, drilled in 2013, continue to perform well with the SL 1227-25 Rocky 1 well tested May 27 at a gross equivalent rate of 218 b/d of oil and 85 Mcfd on a 28/64-in. choke, and the SL 1227-26 Zeke well tested May 24 at a gross equivalent rate of 152 b/d of oil and 17 Mcfd on a 32/64-in. choke.
"The successful drilling and completion of the Rocky 3 development well in Breton Sound 32 supports our analysis that untapped development potential remains in the 5,800 ft sand in the eastern part of the field, and that the application of horizontal drilling technology is a viable means of tapping undeveloped potential in many of our fields," said Andrew C. Clifford, Saratoga president.
"Grand Bay field is another asset where we see a great potential for application of horizontal drilling technology. Horizontal wells make sense in areas with low structural dip, in fields with good well control and 3D seismic coverage and in fields with strong water drive, all attributes applicable to Breton Sound Block 32 and Grand Bay fields."
Saratoga intends to produce Rocky 3 at a rate of 650 b/d of oil due to current capacity limitations at Breton Sound Block 32 field.
Beach Energy JV makes two finds in Cooper basin
A joint venture of Beach Energy Ltd., Adelaide, and Drillsearch Energy Ltd. has added to its successful drilling campaign with two discoveries in the western flank of the Cooper basin in permit PEL 91 in South Australia (OGJ Online, Mar. 31, 2014).
The group's Stunsail-1 wildcat and Pennington-2 appraisal well have both hit multiple oil columns.
Stunsail, drilled in about the center of the permit, encountered a 6-m oil column in the primary Namur sandstone target plus an additional 4-m column in the mid-Namur section and shows within the Birkhead formation.
Beach, as operator, ran two drill stem tests. The best, across a 15-m Namur interval recovered 46 bbl of oil in a 4-hr operation equating to a rate in excess of 250 b/d.
Stunsail-1 has now been cased and suspended as a future oil producer. The field is likely to be developed in the 2014-15 financial year.
Beach estimates a gross reserve value of 1.6 million bbl and says a stand-alone development will cost $4 million (Aus.).
The Pennington-2 well lies 10 km south of Stunsail and 250 m southwest the Pennington-1 discovery. A 10-m net oil pay zone was intersected in the McKinlay and Namur reservoirs.
This was followed by Pennington North-1 about 600 m north of Pennington-1. The McKinlay and Namur were water-bearing, but strong oil shows were found in the Birkhead. A 4-hr DST flowed the 125 boe/d. This well was also cased and suspended as a future producer.
The results have boosted 2P estimated gross reserves for Pennington field to 2.7 million bbl from 1.7 million bbl.
Development is likely to cost $6 million (Aus.) and will take place during mid-2015.
Beach has 40% of PEL 91 while Drillsearch has 60%.
Regional seismic survey planned in Libya
Libya's National Oil Corp. signed an agreement with ION Geophysical Corp., Houston, in conjunction with North Africa Geophysical Exploration Co. for a regional seismic survey in Libya. To be shot in multiple phases, the survey will acquire 21,000 line-km of 2D data.
The first phase will acquire more than 7,700 line-km of long-offset data over the entire Libyan offshore.
Jason Robinson, vice-president EAME for ION's GeoVentures division, said the program "is designed to create a comprehensive picture of the Libyan geology, tying all of the major basins and providing the deep imaging essential to understanding new exploration plays."
Delivery of the data is planned for yearend.
Drilling & Production — Quick Takes
Horizon awarded Stanley gas project licenses
The Papua New Guinea government has formally awarded a production license (PDL 10) and pipeline license (PL 10) to Horizon Oil Ltd. for development of the Stanley gas project development in western PNG.
The grant of the licenses enables commencement of development activities including the drilling of the Stanley-3 and Stanley-5 development wells, site preparation, and facilities construction.
Stanley field is 40 km north of Kiunga in PNG's Western Province. It will be developed by the joint venture comprising Horizon, Talisman Energy Inc., Osaka Gas Co. Ltd., and Mitsubishi Corp.
The development envisages production of about 140 MMcfd from two wells, the recovery and sale of about 4,000 b/d of condensate from that gas flow and sale of some dry gas as fuel for regional power generation.
Remaining dry gas not required for immediate sale will be re-injected into the reservoir for enhancement of condensate recovery and retention for future sales that may include a combination of further regional domestic gas use and a near-shore LNG project.
The grant of the Stanley licenses was also the final condition precedent for Horizon's sale of 40% of its PNG petroleum interests to Osaka Gas. Under the terms of this agreement Horizon will receive its first payment of $78 million of the total $204 million sale price within 10 business days.
The completion of the Osaka Gas transaction, in turn, will satisfy a material condition precedent to Horizon's proposed merger with Roc Oil Co. Ltd. by way of a scheme of arrangement that was announced at the end of April this year.
Gazprom Neft starts oil production at Iraq's Badra field
JSC Gazprom Neft says it began oil production May 31 at the Badra field in eastern Iraq.
Testing of the central gathering station should be completed within 3 months. The field will then be ready to reach commercial production levels of 15,000 b/d. Production is expected to peak at 170,000 b/d in 2017 (OGJ Online, Mar. 13, 2014).
The gathering station's first line has been constructed with a capacity of 60,000 b/d.
Gazprom Neft, the operator, has 30%; Iraqi Oil Exploration Co. 25%; KOGAS 22.5%; Petronas 15%; and TPAO 7.5%.
The field is in Wasit Province. The development contract with the Iraqi government was signed in January 2010.
BP lets contract for Shah Deniz 2
BP Azerbaijan has let a £36 million call-off contract to Wood Group Kenny (WGK) covering engineering and project management services for the Shah Deniz 2 subsea execute phase.
WGK has worked with BP on the Shah Deniz project since 2008, providing engineering support through the appraise, select, and define phases. BP in March let a project management and construction contract to WGK for initial subsea and pipeline engineering and project management for Stage 2 (OGJ Online, Mar. 20, 2014).
BP also in December let a Stage 2 contract to KBR for engineering and procurement support services for an offshore complex consisting of two bridge-linked fixed jacket platforms as well as an onshore gas processing facility (OGJ Online, Dec. 30, 2013).
The contract with WGK is in addition to the subsea engineering work being carried out under the BP Global Agreement, covering engineering and project management services in the North Sea, Angola, and Gulf of Mexico.
PROCESSING — Quick Takes
Uganda advances plans for first refinery
Uganda's government has received proposals from four international companies bidding to build and construct the country's first refinery and related infrastructure in the Lake Albert region of Buseruka Subcounty, Hoima District, Uganda (OGJ Online, Dec. 2, 2013; Feb. 2, 2010).
An evaluation team comprised of government representatives as well as US-based Taylor DeJongh, transaction advisor for the project, will undertake a detailed, month-long evaluation of the proposals starting this month, after which the winning bidder will be announced, said Uganda's Ministry of Energy and Mineral Development (MEMD).
Negotiations are expected to be concluded by this year's fourth quarter, MEMD said.
The proposed 60,000-b/d refinery, which will be developed in two, 30,000-b/d phases, will include on-site crude oil and product storage as well as a 205-km product pipeline to a distribution terminal near Kampala, according to an October 2013 presentation from MEMD.
The Ugandan government will hold 40% equity in the project, while the winning bidder, as lead investor and operator, will hold the remaining 60%.
The refinery will be designed to process Uganda's waxy crude oil (23-33° API, 0.16 wt% sulfur) produced from the Albertine basin to serve petroleum product markets in Uganda, Congo (former Zaire), South Sudan, Rwanda, Burundi, Kenya, and Tanzania, MEMD said.
Companies submitting proposals include three consortia led by the China Petroleum Pipeline Bureau, South Korea's SK Group, and Russia's RT Global Resources, respectively, as well Japan's Marubeni Corp.
With financial close on the project scheduled for second-half 2015, the first phase of the refinery is slated to be commissioned sometime in 2017-18, MEMD said in October 2013.
More Pennsylvania Marcellus processing starts up
MarkWest Energy Partners LP, Denver, has begun operations at its 120-MMcfd Bluestone II cryogenic gas processing plant, its 20,000-b/d C2+ fractionator, and its 32-mile C2 pipeline connecting to Mariner West (OGJ Online, June 19, 2013).
The operations are part of the company's Keystone assets and increase available processing capacity in the Marcellus in northwest Pennsylvania to 210 MMcfd.
The Bluestone II plant mainly takes rich-gas production of Rex Energy Corp., which now has 190 MMcfd of dedicated processing capacity at MarkWest's Keystone facilities, consisting of 50 MMcfd of capacity at Bluestone I plant and 40 MMcfd of capacity at the Sarsen plant (OGJ, June 6, 2011, p. 88).
Repairs shut ethylene output at Stavrolen complex
Repair work at Lukoil's 350,000-tonne/year Stavrolen petrochemical complex in Budennovsk, Russia, following a February fire will shutter production of ethylene and propylene at the site for 6 months, the company said (OGJ Online, Feb. 27, 2014).
A completed investigation of the Feb. 26 incident determined the fire, which broke out in the plant's ethylene and propylene production unit No. 2, was caused by depressurization of the aluminum heat exchanger, Lukoil said.
The depressurization of the heat exchanger resulted from the fracture of a corrugated plate in the left heat-exchange section, the company said.
While repair and maintenance work at the site already is under way, Lukoil said it does not expect ethylene and propylene production capacities at the plant to resume until January 2015.
Polypropylene production from imported propylene feedstocks will resume this month, the company added.
Lukoil previously said it planned to commission of the first stage of a 2 billion cu m/year gas processing plant and modernization of existing ethylene and polyethylene units at the Stavrolen complex in 2015 (OGJ Online, Sept. 25, 2012).
TRANSPORTATION — Quick Takes
Dominion seeks FERC nod for NY, W.Va. gas projects
Dominion, Richmond, Va., reported that it's seeking approval from the US Federal Energy Regulatory Commission for its New Market project in upstate New York and Clarington project in West Virginia. The projects' combined cost is $235 million.
The New Market project would provide 112 MMcfd of firm transportation service. Just more than 33,000 hp of compression would be added in upstate New York to Dominion Transmission's existing system.
The project includes two 11,000-hp compressor stations in Madison County, NY, and Chemung County, NY; 11,000 hp of additional compression at Dominion's current Brookmans Corners Station in Montgomery County, NY; and upgrades at the existing Borger, Utica, and Brookmans Corners stations.
The project is designed to improve access to gas to serve two National Grid subsidiaries: Niagara Mohawk and Brooklyn Union. If approved and the FERC issues the certificate in April 2015, construction would begin in late summer 2015 and the project would be placed into service by November 2016, Dominion said.
The Clarington project would provide 250 MMcfd of firm transportation service. It would add 16,000 hp of compression at existing stations in West Virginia and Ohio, and provide incremental firm transportation services and increased access for production in the Appalachian region.
If approved and the FERC issues the certificate in May 2015, construction would begin in October 2015 and the project would be placed into service by November 2016, Dominion said.
The project includes two 10,000-hp compressors at the existing Mullett Compressor Station in Monroe County, Ohio; additional 6,000 hp of compression at existing Burch Ridge Compressor Station in Marshall County, W.Va.; and an interconnection with CNX Gas Co. near Lightburn, W.Va., to receive Appalachian gas and deliver it to Texas Eastern Transmission and Rockies Express Pipeline in Monroe County, Ohio.
NGTL to build Merrick pipeline supplying Kitimat LNG
Nova Gas Transmission Ltd. (NGTL), a TransCanada Corp. wholly owned subsidiary, will build the Merrick Mainline pipeline to supply natural gas to future liquefaction plants on the British Columbia coast.
TransCanada signed agreements with Chevron Canada Ltd. and an Apache Canada Ltd. wholly owned and controlled partnership (APA) for 1.9 bcfd of firm gas transportation to underpin development the extension of its NGTL system.
Merrick will transport gas sourced through the NGTL system to the inlet of Chevron and Apache's proposed Pacific Trail Pipeline, delivering to the Kitimat LNG terminal at Bish Cove near Kitimat, BC. Chevron acquired its 50% interest in Kitimat, LNG, Pacific Trail, and 644,000 acres in the Horn River and Laird basins last year.
The proposed 161-mile, 48-in. OD pipeline will be an extension from the existing Groundbirch Mainline section of the NGTL system running from near Dawson Creek, BC, to near Summit Lake, BC. Progress Energy Canada Ltd. last year signed a transportation agreement with NGTL underpinning development of its North Montney Mainline expansion project, also originating at Groundbirch (OGJ Online, Aug. 7, 2013).
TransCanada is conducting field studies, community engagement, engineering and design work, and pipeline route evaluation to support applications for regulatory approvals and finalize project requirements. The company anticipates filing with Canada's National Energy Board (NEB) in the fourth quarter. Pending approval, TransCanada expects Merrick to enter service first-quarter 2020.
Under the commercial arrangements with Chevron and Apache, delivery volumes will ramp up between 2020 and 2022 to the aggregate 1.9 bcfd. NGTL is also in discussions with other parties that have expressed interest in transporting gas on Merrick. Merrick will cost $1.9 billion, part of TransCanada's declared $38 billion capital growth plan between now and 2020.
Line C of Central Asia-China Gas Pipeline operational
China National Petroleum Corp. says Line C of the Central Asia-China Gas Pipeline became operational May 31 with the turn of a valve in Uzbekistan to receive gas from Turkmenistan.
The 1,830-km line runs parallel with Line A and Line B. It enters China at Horgos, Xinjiang, to link with the Third West-East Gas Pipeline.
Construction of Line C began in September 2012. CNPC said Line C will reach its designed annual deliverability of 25 billion cu m (bcm) upon completion of all its supporting facilities by the end of 2015.
By then, the overall delivery capacity of the Central Asia-China Gas Pipeline will reach 55 bcm/year. CNPC said that would equal 20% of China's natural gas consumption.
A construction management agreement for Line D was signed Mar. 4 (OGJ Online, Mar. 11, 2014).