OGJ Newsletter

March 20, 2017
International news for oil and gas professionals


Barclays: E&P spending growth revised for 2017

Global exploration and production spending will rise 9% in 2017 compared with spending in 2016, according to the latest update of Barclays' E&P spending survey. This compares with 7% indicated in the January survey (OGJ Online, Jan. 9, 2017).

The upward revision reflects higher upstream spending budgets released or revised by companies over the last 2 months, especially an uptick in expectations for North America.

Barclays since January has revised estimates for 70 companies representing 88% of North America spend for 2016 from budget announcements mostly disclosed as part of yearend earnings. Collectively, those companies now expect North America upstream spending in 2017 to increase 32% year-over-year compared with the overall 27% increase expected 2 months ago.

US international oil companies are also expected to increase North America spending by 4% year-over-year vs. flat spending in January, driven primarily by increased spending from BP PLC and ExxonMobil Corp.

Since the beginning of the year, at least eight companies have announced acquisitions in the Permian basin totaling $16 billion. The largest of these was ExxonMobil's 250,000-acre acquisition from firms owned by the Bass family of Fort Worth, Tex., with an estimated 3.4 billion boe, doubling ExxonMobil's Permian basin resource to 6 billion boe.

However, near-term risk to the oil price, due to a combination of increasing US production, crude inventories continuing to build, and the big decisions facing the Organization of Petroleum Exporting Countries in May, adds downside risk to E&P budgets, which are a function of cash flow, Barclays noted.

"If oil prices stay below $50/bbl, E&Ps are likely to defer some growth by a quarter or two in North America, with little change to our international figures," Barclays said.

International spending is now expected to increase 3% in 2017 compared with the 2% rise expected in January's update.

Marathon Oil to buy Permian acreage for $1.1 billion

Marathon Oil Corp. has agreed to acquire 70,000 net surface acres in the Permian basin from BC Operating Inc., Midland, Tex., and other entities for $1.1 billion in cash.

The deal, effective Jan. 1 and expected to close in the second quarter, includes 51,500 acres in the northern Delaware basin of New Mexico and current production of 5,000 net boe/d.

Marathon will receive as many as 10 target benches within 5,000 ft of stacked pay and 900 million boe of total resource potential with 1,700 total upside locations from both tighter density and secondary targets.

Primary targets on the acreage are in Wolfcamp and Bone Spring areas. The leasehold has one operated rig drilling, and there are plans to add a second rig midyear. The firm also envisions further opportunities for growth from acquired acreage in the Northwest Shelf as well as further bolt-on acquisitions.

"The northern Delaware basin features outstanding well economics that compete at the top of our organic portfolio and is experiencing a positive rate of change in well performance unrivaled in US unconventional basins," commented Lee Tillman, Marathon Oil president and chief executive officer.

Marathon also reported Mar. 9 that it has agreed to sell its Canadian subsidiary, which includes its 20% nonoperated interest in the Athabasca Oil Sands Project (AOSP), to Royal Dutch Shell PLC and Canadian Natural Resources Ltd. for $2.5 billion in cash (OGJ Online, Mar. 9, 2017).

"Historically, our interest in the Canadian oil sands has represented about a third of our company's other operating and production expenses yet only about 12% of our production volumes," explained Tillman.

DOE announces awards from first sale of SPR crude

Seven companies have been awarded contracts for 10 million bbl of crude oil from the US Strategic Petroleum Reserve, the US Department of Energy announced on Mar. 10.

Atlantic Trading & Marketing Inc., BP Oil Supply Co., Marathon Petroleum Co., PetroChina International (America) Inc., Phillips 66, Shell Trading (US) Co., and Valero Marketing & Supply received the contract, DOE's Fossil Energy Office said.

Of the 10 million bbl, 3 million bbl will be sold from the SPR's Bryan Mound, Tex., site, 2.1 million bbl from the Big Hill, Tex., site, and 4.9 million bbl from the West Hackberry, La., site. Deliveries will take place in May and June, with early deliveries in April accommodated to the maximum extent possible, FEO said.

A continuing federal budget resolution, which became law on Dec. 10, 2016, included a provision to allow DOE to sell as much as $375.4 million in crude from the reserve as the first tranche of oil sales designed to fund operational improvements to ensure the long-term infrastructure integrity under the SPR Modernization program, it said upon announcing the sale.

Exploration & DevelopmentQuick Takes

Interior schedules region-wide US gulf lease sale

The US Department of the Interior will offer 73 million acres offshore Texas, Louisiana, Mississippi, Alabama, and Florida for oil and gas exploration and development in Lease Sale 249, scheduled for Aug. 16.

The proposed region-wide lease sale would include all available unleased areas in the western, central, and eastern planning areas of the Gulf of Mexico, covering 13,725 unleased blocks 3-230 miles offshore in 9-11,115 ft of water.

Proposed Lease Sale 249 will be the first offshore sale under the new Outer Continental Shelf Oil and Gas Leasing Program for 2017-22. Under the new 5-year program, 10 region-wide lease sales are scheduled for the gulf. Two gulf lease sales will be held each year and include all available blocks in the combined western, central, and eastern gulf planning areas.

The US Bureau of Ocean Energy Management estimates that the US OCS contains about 90 billion bbl of undiscovered technically recoverable oil and 327 tcf of undiscovered technically recoverable gas. The gulf OCS, covering about 160 million acres, has technically recoverable resources of 48.46 billion bbl of oil and 141.76 tcf of gas.

BOEM says production from all OCS leases provided 550 million bbl of oil and 1.25 tcf of natural gas in fiscal-year 2016, accounting for 72% of the oil and 27% of the natural gas produced on federal lands.

In the near term, central planning area Lease Sale 247 is scheduled for Mar. 22. The final gulf lease sale in the 2012-2017 5-Year program offers more than 48 million acres offshore Louisiana, Mississippi, and Alabama (OGJ Online, Dec. 22, 2016).

The final sale overall in that program is slated to be Lease Sale 244, which would offer 1.09 million acres in Cook Inlet off Alaska's south-central coast during a June auction. However, Cook Inlet lease sales in the recent past have been canceled by BOEM due to a lack of industry interest.

The 2012-2017 program has offered about 73 million acres, netted more than $3 billion in high bids, and awarded more than 2,000 leases.

Horseshoe discovery extends Alaska North Slope play

Two exploration wells drilled by Repsol SA and Armstrong Energy LLC—Horseshoe 1 and the 1A sidetrack—have extended the Nanushuk play more than 20 miles south of the existing discoveries in the same interval in Alaska North Slope's Pikka Unit (OGJ Online, June 5, 2015).

Repsol reported that the Horseshoe discovery qualifies as the largest US onshore conventional discovery in 30 years.

Drilled during the 2016-17 winter campaign, the Horseshoe 1 well reached 6,000 ft and encountered more than 150 ft of net oil pay in several reservoir zones in the Nanushuk section. The partners drilled the Horseshoe 1A sidetrack to a TD of 8,215 ft and encountered more than 100 ft of net oil pay also in the Nanushuk.

The companies estimate their blocks in the Nanushuk play could contain as much as 1.2 billion bbl of recoverable light oil. Repsol has not reported test results for the Horseshoe discovery, but previous wells—Qugruk 8 (Q-8) and Qugruk 301 (Q-301)—flowed 30° gravity crude at rates of as much as 2,160 bo/d and 4,600 bo/d, respectively.

Preliminary development concepts for Pikka anticipate start of production in 2021 with a potential rate approaching 120,000 bo/d.

Repsol holds a 25% working interest in the Horseshoe discovery and a 49% working interest in the Pikka Unit. Armstrong holds the remaining working interest and is currently the operator.

ExxonMobil to acquire interest in Mozambique Area 4

ExxonMobil Corp. and Eni SPA have signed a sale and purchase agreement to enable ExxonMobil to acquire from Eni a 25% indirect interest in the natural gas-rich Area 4 block offshore Mozambique.

Eni currently holds a 50% indirect share in the block through a 71.4% stake in Eni East Africa, which owns 70% of the Area 4 concession.

The agreed terms include a cash price of about $2.8 billion. The acquisition will be completed following satisfaction of a number of conditions precedent, including clearance from Mozambican and other regulatory authorities.

Eni will continue to lead the 3.3 million-tonne/year Coral floating LNG project as well as a 10 million-tpy onshore liquefaction joint venture in Area 4, while ExxonMobil will lead the construction and operation of natural gas liquefaction facilities onshore.

Following completion of the transaction, Eni East Africa SPA will be co-owned by Eni 35.7%, ExxonMobil 35.7%, and China National Petroleum Corp. 28.6%. The remaining interests in Area 4 are held by Empresa Nacional de Hidrocarbonetos de Mozambique EP, Korea Gas Corp., and Galp Energia, each with 10% interest.

Eni and Anadarko Petroleum Corp. signed a unitization and operating agreement in late 2015 that regulates the development of reserves straddling Anadarko's Area 1 and Eni's Area 4. They jointly proposed a two-train, 10 million-tpy onshore facility that will start up in 2022. Anadarko is developing a separate two-train, 12 million-tpy project that is expected to start up in 2021 for $15 billion, according to recent estimates.

The deepwater Area 4 block is believed to contains 85 tcf of gas.

Drilling & ProductionQuick Takes

Total brings Moho Nord field on stream

Total SA started production at Moho Nord field 75 km offshore Pointe-Noire, Congo (Brazzaville). The project was designed with a production capacity of 100,000 boe/d.

Moho Nord field was developed through 34 wells tied back to a tension-leg platform and to Likouf, a floating production unit. Oil is processed on Likouf and then transported by pipeline to the Djeno onshore terminal.

Total said there will be no routine flaring to minimize environmental impact. An all-electric design improves energy efficiency. All produced water will be reinjected into the reservoir.

Moho Phase 1b and Moho Nord are part of the Moho Bilondo license operated by Total E&P Congo (OGJ Online, Dec. 11, 2015). Total holds 53% interest, Chevron Corp. 31.5%, and Societe Nationale des Petroles du Congo 15%.

Buru to restart Ungani oil field onshore Australia

Buru Energy Ltd., Perth, has restarted production from Ungani oil field in the onshore Canning basin south of Broome in Western Australia.

Buru Energy says oil from the field will be trucked north to Wyndham Port where Cambridge Gulf Ltd. (CGL) will store it in its 80,000-bbl tank. From there, it will be exported by ship to nearby markets as well as South East Asia.

Earlier production from the field was stored in Wyndham in a smaller 30,000-bbl tank. Buru says the larger storage capacity brings significant economies of scale and commercial benefits through access to larger ships on spot charter rather than the previously used smaller time charter vessels.

Planned modifications to the larger tank also will help streamline the storage system and reduce operating costs.

Buru says the timing of the recommencement of production from Ungani will depend on CGL returning the storage tank from diesel service and the required modifications that entails, but the target is to bring the field back on stream by midyear.

Minor modifications at the field also will be undertaken prior to start-up. The field will be on natural flow initially at a target rate of 1,200 b/d. Electrical submersible pumps will be installed later this year to maintain and potentially increase production rates.

Noble to batch-drill two Leviathan wells

Noble Energy Mediterranean Ltd. and partners will batch-drill two production wells in the development of deepwater Leviathan gas field offshore Israel (OGJ Online, Mar. 2, 2017).

The partners had approved drilling of the Leviathan 5 appraisal well in December, stipulating that the well also could be a producer. They sanctioned development last month.

Partner Delek Group reports the group has decided to drill the Leviathan 7 appraisal and production well at the same time.

Drilling will begin after the Atwood Advantage drillship finishes work on the Tamar 8 production well in nearby Tamar gas field.

The rig will drill the Leviathan 7, about 120 km west of Haifa in 1,630 m of water, to 2,900 m below sea level (bsl). It then will move to the Leviathan 5 location about 130 km west of Haifa in 1,740 m of water.

After drilling Leviathan 5 to its target depth of 5,200 m bsl, the drillship will return to Leviathan 7 and drill to final depth of 5,100 m bsl.

Total drilling time is expected to be 7 months. Delek estimates drilling cost at $71 million.

The wells will be completed and connected to the production system later.


ExxonMobil marks $20 billion for USGC expansions

ExxonMobil Corp. will invest $20 billion over a 10-year period to expanding its chemical manufacturing capacity along the US Gulf Coast to support increased exports to overseas markets.

The Growing the Gulf expansion program will cover major chemical, refining, lubricant, and LNG projects at 11 proposed new and existing manufacturing sites in Texas and Louisiana, ExxonMobil said.

Most of the new chemical capacity that will come online as part of the program will target export markets in Asia and elsewhere, the company said.

"These projects are export machines, generating products that high-growth nations need to support larger populations with higher standards of living," said ExxonMobil Chairman and CEO Darren Woods. The investment decision is a result of growing US oil and natural gas production amid rising demand abroad, Woods said. "The supply is here; the demand is there," Woods said. "We want to keep connecting those dots."

ExxonMobil, which started the investment in 2013, said it expects to continue investing into the program at least through 2022.

Vietnam's first petrochemical complex project advances

Siam Cement Public Co. Ltd. (SCG) subsidiary Vina SCG Chemicals Co. Ltd. (VSCG) has entered a share purchase agreement with Qatar Petroleum International Ltd. (QPI) to acquire all of subsidiary QPI Vietnam Ltd.'s (QPIV) 25% equity stake in Long Son Petrochemical Co. Ltd.'s (LSP) long-delayed project to build Vietnam's first petrochemical complex on Long Son Island in Vung Tau City, Ba Ria Province, about 100 km southeast of Ho Chi Minh City (OGJ Online, Oct. 9, 2009).

Valued at $36.1 million, the equity transaction will increase SCG's total ownership interest in the LSP project to 71% from its previous 46% stake held through subsidiaries VSCG 28% and Thai Plastic & Chemicals Public Co. Ltd. (TPC) 18%.

The QPIV buyout follows QPI's 2015 notification to fellow LSP shareholders VSCG, TPC, and Vietnam's state-owned PetroVietnam and Vinachem 29% of Qatar's intention to withdraw from the project, according to a Nov. 13, 2015, release from SCG.

SCG said it plans to reach financial investment decision on the estimated $4.5-billion LSP project by the end of this year's first half, which if approved, will begin a 3-4-year construction period for a proposed startup date sometime in 2021.

As currently planned, LSP's complex would include a 1 million-tonne/year flexible-feed cracker capable of switching between ethane, propane, and naphtha feedstock to produce about 1.6 million tpy of ethylene depending on the feedstock mix, SCG said.

In a series of presentations during 2013-16, PetroVietnam told investors the new complex—which will be fully integrated with supporting infrastructure that includes a deep-sea port, jetty, storage installations, power plant, and other utilities—also would be equipped to produce 450,000-468,000 tpy of polypropylene, 450,000 tpy of high-density polyethylene, 500,000 tpy of linear low-density polyethylene, and 400 tpy of vinyl chloride monomer.

Dangote lets contract for Nigerian refining complex

Dangote Oil Refining Co. (DORC), a division of Nigerian conglomerate Dangote Industries Ltd. (DIL), has let a contract to MAN Diesel & Turbo SE (MDT), Augsburg, Germany, to provide equipment and associated technology services for its grassroots integrated refining complex now under construction in southwestern Nigeria's Lekki Free Trade Zone, near the capital of Lagos (OGJ Online, Nov. 25, 2013).

MDT will build and deliver two axial compressor trains driven by 30-Mw turbines to support operations at the refinery's fluid catalytic cracking plant, as well as provide a comprehensive auxiliary service package, including equipment commissioning services, MDT said.

While a precise cost of the contract was not revealed, the service provider valued the order in the double-digit million dollars.

MDT said it expects to deliver the equipment sometime in 2018, ahead of DORC's planned startup of the entire $12-billion refining and petrochemical complex in 2019.

According to social media posts from the state government of Lagos as well as details of a previous contracts awarded for the former $11-billion project, the integrated complex will include a 650,000-b/d crude distillation unit and 3.6 million-tonne/year polypropylene plant, as well as units for the following major processes: residual FCC; diesel hydrotreating; continuous catalyst regeneration; and alkylation.

While Nigeria holds the second-largest amount of proved oil reserves in Africa—more than 37 billion bbl—the country currently imports most of its refined product requirements due to lack of domestic refining capacity.

Once completed, however, DORC's refinery will be able to satisfy 100% of Nigeria's fuel demand, said Alhaji Aliko Dangote, DIL's president and chief executive.

Additional planned capacity of the refinery comes alongside a series of efforts under way by the Nigerian government to modernize and expand capacities of refineries operated by state-owned Nigerian National Petroleum Corp. beginning this year as part of a strategy to meet Nigeria's domestic demand for refined products and reduce its reliance on foreign imports.


Canada okays NGTL's Towerbirch expansion project

Nova Gas Transmission Ltd. (NGTL) has received approval from the Canadian government for the Towerbirch Expansion Project in northwest Alberta and northeast British Columbia.

NGTL, a subsidiary of TransCanada Corp., said the $439-million (Can.) project includes 55 km of 36-in. pipeline that will parallel the existing NGTL Groundbirch mainline and a 32-km Tower Lake section of 30-in. line that will parallel existing third-party pipelines.

The project also includes four receipt meter stations and expansion of an existing meter station. Facilities are expected to be in-service in the fourth quarter (OGJ Online, Nov. 17, 2015).

Jim Carr, Canada's minister of natural resources, said the project will create as many as 750 jobs during construction, address the need for increased natural gas transmission capacity along the existing NGTL system, and support economic growth. About 82% of the project will parallel existing rights-of-way or "existing disturbances." The approval includes 24 binding conditions.

Carr said the government took into consideration the National Energy Board's recommendation report on the project, Environment and Climate Change Canada's assessment of upstream greenhouse gas emissions, the views of Canadians gathered through an online questionnaire, and consultations with indigenous peoples.

MPC completes $2-billion midstream dropdown

Marathon Petroleum Corp. has closed on a deal to contribute certain terminal, pipeline, and storage assets to MPLX LP for $2.015 billion.

The assets include 62 light-product terminals with 24 million bbl of storage capacity; 11 pipeline systems consisting of 604 miles of pipeline; 73 tanks with 7.8 million bbl of storage capacity; a crude oil truck unloading facility at MPC's refinery in Canton, Ohio; and eight NGL storage caverns in Woodhaven, Mich., with 1.8 million bbl of capacity.

"This drop-down of additional high-quality logistics assets to MPLX represents the first of several drops expected to occur in 2017," said Gary R. Heminger, MPC chairman, president, and chief executive officer.

MPC will receive an issuance of $504 million in MPLX equity and $1.511 billion in cash. The equity to be issued in the deal consists of MPLX common units and general partner units to maintain MPC's 2% general partner interest in MPLX. The units will be valued based on the 10-day volume weighted average price of MPLX common units prior to the closing.