GENERAL INTEREST — Quick Takes
ExxonMobil’s second-quarter earnings fall 59%
ExxonMobil Corp. reported second-quarter earnings of $1.7 billion, down from $4.2 billion in second-quarter 2015 due to lower commodity prices and weaker refining margins. First-half earnings totaled $3.5 billion, a decline from $9.13 billion in first-half 2015. Upstream earnings in the quarter were $294 million, down $1.7 billion from second-quarter 2015. Lower liquids and gas realizations decreased earnings by $2.2 billion.
Production volumes were virtually unchanged at 4 million boe/d. Liquids production growth from recent start-ups more than offset the impact of field decline and downtime events, notably in Canada and Nigeria.
Liquids production during the quarter totaled 2.3 million b/d, up 39,000 b/d from a year earlier. Project ramp-up was partly offset by field decline and downtime mainly resulting from the Canadian wildfires. Natural gas production was 9.8 bcfd, down 366 MMcfd from second-quarter 2015 including field decline and divestment impacts.
US upstream quarterly earnings declined $467 million year-over-year to a loss of $514 million. Non-US upstream earnings were $808 million, down $1.3 billion vs. the prior year. Downstream earnings in the quarter were $825 million, down $681 million from second-quarter 2015. Weaker refining margins lowered earnings by $850 million while favorable volume and mix effects raised earnings by $130 million.
Chemical earnings in the quarter were $1.2 billion, reflecting continued benefits from gas and liquids cracking as well as growing product demand. The firm’s downstream segment earned $825 million in the quarter despite significantly lower global refining margins versus the prior year quarter.
Second-quarter capital and exploration expenses were reduced by 38% to $5.2 billion. First-half capital and exploration expenditures were $10.3 billion, down 36% from the 2015 total. ExxonMobil last month agreed to acquire all outstanding shares of Papua New Guinea gas producer InterOil Corp. for more than $2.5 billion (OGJ Online, July 21, 2016).
Statoil to buy interest off Brazil for $2.5 billion
Statoil ASA has agreed to buy the 66% operated interest in the BM-S-8 offshore license in Brazil’s Santos basin held by Petroleo Brasileiro SA (Petrobras) for $2.5 billion.
The license includes a substantial portion of the 2012 Carcara presalt oil discovery (OGJ Online, May 29, 2015).
Statoil said it is on the geological trend of the nearby Lula field and Libra area. It has 30° API oil and associated gas “in a thick reservoir with excellent properties.”
Carcara straddles BM-S-8 and open acreage to the north, which Statoil said is expected to be part of a license round in 2017. In addition to Carcara, the license “holds exploration upside.” The license is in its final exploration phase with one remaining exploration commitment well to be drilled by 2018. Statoil estimates the license has 1.3 billion boe in recoverable volumes.
Statoil said half of the purchase price will be paid after closing and the remainder paid when “certain milestones” have been met, including future unitization of Carcara.
Statoil and Petrobras are also in discussions focusing on long-term cooperation in the Campos and Espirito Santo basins, and new cooperation within gas and technology projects in the Santos basin.
Statoil said it has been in Brazil since 2001. The Statoil-operated Peregrino field marks 5 years of production this year.
Statoil cuts 2016 capex by $1 billion
Statoil ASA plans to cut its capital expenditure guidance for 2016 to $12 billion from $13 billion. That includes an exploration guidance reduction to $1.8 billion from $2 billion.
The state-owned firm’s production guidance remains unchanged, with expected organic production growth of 1%/year from 2014-17. Statoil recorded equity production of 1.96 million boe/d in the second quarter. Underlying production growth in the quarter, adjusting for divestments, was 6% compared with last year’s second quarter.
The firm took a second-quarter net loss of $307 million compared with a net profit of $861 million a year earlier. First-half organic capital expenditure was $5.3 billion.
Halcon Resources files Chapter 11
Halcon Resources Corp., Houston, has filed voluntary petitions under Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization in which the firm would eliminate $1.8 billion in long-term debt and reduce annual interest expense by more than $200 million.
If the plan is approved by a Delaware bankruptcy court, creditors would split ownership of the firm and third-lien noteholders would receive more than 75% of the equity. The firm holds $3.12 billion in debt and $2.85 billion in assets, according to the filing.
Halcon’s core operations are in the Bakken-Three Forks formations and Eagle Ford shale. Noncore assets include the Tuscaloosa Marine shale, Utica-Point Pleasant formations, and Austin Chalk formation.
Exploration & Development — Quick Takes
Cyprus blocks attract six applications
Cyprus has received six applications for three offshore blocks on offer in its third licensing round (OGJ Online, Mar. 28, 2016). A subsidiary of Eni SPA, part of the joint venture that discovered giant Zohr natural gas field offshore Egypt to the south, participated in bids for all three blocks.
The Ministry of Energy, Commerce, Industry and Tourism offered the licenses under a model exploration and production-sharing contract.
Eni Cyprus Ltd. operates a combine with Total E&P Cyprus BV in an application for Block 6.
The company bid solo for Block 8, which also received an application for a group operated by Capricorn Oil (Cairn Energy) and including Delek Drilling and Avner Oil Exploration. Delek Group is a partner in the Aphrodite discovery by Noble Energy Inc. off Cyprus, and it and Avner participated with Noble in the giant gas discoveries in Israeli waters nearby.
Block 10 received three applications: from an Eni-Total com-bine operated by Eni; from a combine operated by ExxonMobil Exploration & Production Cyprus (Offshore) Ltd. with Qatar Petroleum International Upstream OPC; and from Statoil Upsi-lon Netherlands BV bidding alone.
UK offers 1,261 blocks in 29th offshore round
UK’s Oil and Gas Authority (OGA) has launched the 29th offshore licensing round, making available 1,261 blocks for bid on the UK Continental Shelf (UKCS). Firms have until Oct. 26 to apply for blocks.
Some of the available areas were part of last year’s UK gov-ernment-funded, £20-million seismic campaign that acquired 8,896 km of full-fold seismic in the Rockall Trough area and 10,849 km of full-fold seismic in the Mid-North Sea High area.
The 29th Round marks the launch of the “innovate license” concept allowing licensees to work with OGA to design an optimal work program. OGA says the new concept enables more appropriate phasing of activity, rental fees, and competency tests; and implements a stage-gate process for better monitoring of progress than the previous licensing regime.
“We recognize that market conditions are currently very difficult but nevertheless we have a shared goal of making the basin as attractive as possible for exploration,” commented Andy Samuel, OGA chief executive. “We’ve listened to industry feedback and have introduced more flexibility in the licensing regime and opened up potential new areas for licensing.”
The 28th round in 2015 was one of the largest licensing rounds since offshore licensing began in 1964.
Seismic work slated for southeast Niger
Savannah Petroleum PLC has signed with BGP Niger SARL to acquire 800 line-km of 2D seismic data over part of the company’s R3 license area in southeast Niger. The company’s R1/R2 and R3/R4 permits are in the Agadem Rift basin, which contains 975 million bbl of 2P reserves with current production of 20,000 b/d, Savannah reported.
The seismic work is part of a call-off order through an unnamed Savannah subsidiary. The data acquisition will provide enhanced definition over 12 existing exploration targets identified on the operator’s existing 2D dataset. The targets incorporate stacked traps at multiple play levels including the Oligocene Upper Sokor, Eocene Sokor Alternances, and Upper Cretaceous Yogou formations.
The company is considering single exploration wells on some of these targets but provided no specific timeline for appraisal activity. In addition, seismic crews and equipment are expected “to commence shortly,” the company said.
A presentation released by Savannah says typical discoveries are 30° API gravity oil, and reservoirs in the Agadem area are normally pressured with porosity levels in the low-20% range. Average well costs are about $4 million.
China National Petroleum Corp. established Niger’s first hydrocarbon production in late 2011, with start of oil deliveries from Sokor and Goumeri fields. The country awarded nine production-sharing agreements to five exploration companies the following year (OGJ Online, Aug. 2, 2012).
Drilling & Production — Quick Takes
Total starts Incahuasi field in Bolivia
Total SA and partners have started production from Incahuasi natural gas and condensate field in Bolivia and are considering further development (OGJ Online, Sept. 25, 2013).
The first development phase has production capacity of 50,000 boe/d. It includes three wells drilled to below 5,600 m, a 230-MMcfd gas treatment plant, and 100 km of pipelines supporting exports to Argentina and Brazil. The field spans the Ipati and Aquio blocks in the Andean foothills 250 km south of Santa Cruz de la Sierra. A second development phase would involve three more wells and double the production rate.
Total, operator, holds 50% interest. Gazprom and Tecpetrol hold 20% each, and YPFB Chaco holds 10%.
Serica resumes production from Erskine field
Serica Energy PLC of London said Erskine field oil and gas production resumed July 27 following clearance of a blockage on a condensate pipeline and also on completion of scheduled maintenance on the Lomond platform.
Erskine, a high-pressure, high-temperature development, lies in 90 m of water in the UK North Sea.
The pipeline blockage happened earlier this year in the Lomond-to-Everest export line when a pig became lodged due to wax buildup. Crews used pressure pulsing from both ends of the pipeline as well as a wax solvent.
The field then remained shut for a planned 2-month maintenance program on the Lomond platform, which coincided with a planned 1-month shutdown for maintenance of export and processing equipment through which Erskine gas is exported.
Following a short period for final clean-up during the first week of August, production from Erskine is projected to build-up rapidly, Serica Energy said.
Anadarko to keep six rigs in Delaware basin
Anadarko Petroleum Corp. plans to keep six rigs working in the Delaware basin, citing improved efficiencies and lower drilling costs. Previously, Anadarko executives had said they likely would cut the Delaware rig number from six to four this year.
“We’ve continued to significantly reduce our cost structure throughout the year,” said Al Walker, Anadarko chairman, president, and chief executive officer, during a second-quarter earnings and operational update conference call on July 27.
Anadarko achieved record production from certain Gulf of Mexico operations, and onshore in the Delaware basin in West Texas and in the Denver-Julesburg basin in Colorado. Executives cited record sales volumes were reported from the Lucius and Caesar-Tonga offshore fields.
“Should the commodity-price outlook continue to improve, we will evaluate redeploying some of the additional cash generated via operations and asset sales toward our highest-quality US onshore opportunities,” Walker said.
He said he expects light, sweet crude oil futures to return to $60/bbl on a sustained basis in 2017. Walker expects total US oil production will “bottom” at 8 million b/d possibly in this year’s fourth quarter.
Anadarko’s second-quarter sales volumes of natural gas, oil, and natural gas liquids totaled 72 million boe for an average of 792,000 boe/d.
In the Delaware basin, Anadarko continues its delineation program, running six rigs to enhance its understanding of both the vertical and horizontal potential across its 600,000-gross-acre holdings.
In the Gulf of Mexico, Anadarko said the Lucius platform achieved a 24-hr gross production record and averaged sales volumes above the platform’s 80,000 b/d nameplate capacity. The Constitution spar reached 65,000 b/d while Anadarko’s K2 complex reached an 8-year-high production rate of 28,000 b/d.
During the quarter, Anadarko continued to advance its understanding of the Shenandoah discovery in the gulf. Anadarko encountered more than 1,040 net ft of oil pay in the Shenandoah-5 appraisal well, expanding the eastern extent of the field.
Additionally, the company increased its working interest in Shenandoah to 33% and added several new exploration opportunities by participating in a preferential-right process.
PROCESSING — Quick Takes
Phillips 66 finds buyer for Whitegate refinery
Canada’s privately held Irving Oil Ltd., Saint John, NB, has agreed to acquire the 71,000-b/d Whitegate refinery—Ireland’s only—from current owner Phillips 66 Co., Houston.
The companies, which signed an agreement on Aug. 3, plan to conclude the transaction by the end of the third quarter, at which time Irving Oil will take full ownership and continue full operation of the refinery, including maintaining its existing workforce, Irving Oil said.
As part of the agreement, Irving Oil also will acquire Phil-lips 66’s associated wholesale marketing business in Ireland, Phillips 66 spokesman Dennis Nuss told OGJ.
Phillips 66 will continue to operate the business as usual until the transaction closes, Nuss said.
Located in Cork, the Whitegate refinery processes light, low-sulfur crude oil sourced mostly from the North Sea and West Africa to primarily produce gasoline, diesel, and kerosine for distribution mostly in Ireland, with some exports to customers in the UK and elsewhere in Europe.
Phillips 66 first announced plans to sell its business in Ireland in 2013, which at the time was to include the refinery and associated wholesale marketing business, as well as a crude oil and refined products storage terminal in Bantry Bay (OGJ, Dec. 2, 2013, p. 34).
The company’s local management informed Ireland’s Department of Communications, Energy, and Natural Resources (formerly Communications, Climate Action, and Environment) of its intention to put the refinery and marketing business up for sale in October 2015, DCENR said.
Tupras commissions unit at Izmit refinery
Turkish Petroleum Refineries Corp. (Tupras) has let a contract to Honeywell UOP LLC, a unit of Honeywell International Inc., for a hydrocracking unit designed to boost diesel production at its 11 million-tonne/year Izmit refinery in Turkey’s northwestern province of Kocaeli.
As part of the contract, Honeywell UOP has provided the refinery technology licensing and equipment for its proprietary Unicracking enhanced two-stage processing unit, which produces 75,000 b/sd of middle-distillate products, including Jet A-1 aviation and Euro 5-quality diesel fuels.
Already installed and in operation, the Unicracking unit is integrated with the Izmit refinery’s Honeywell UOP-licensed coker naphtha and distillate Unionfining units in a system that uses a common fractionation section and collectively processes feedstocks of straight-run diesel, coker gas oil, and vacuum gas oils. Along with boosting the site’s diesel production by as much as 7% to help Tupras meet rising demand for transporta-tion fuel, the unit also will contribute to reductions in the refinery’s energy and hydrogen consumption, Honeywell UOP said.
LyondellBasell approves HDPE plant at US Gulf Coast
LyondellBasell has reached final investment decision to build a grassroots high-density polyethylene (HDPE) plant at the US Gulf Coast. Scheduled for startup in 2019, the proposed 1.1 billion-lb/year HDPE plant will be the first ever to use LyondellBasell’s proprietary Hyperzone PE technology, a cascadegas phase process based on the company’s existing Multizone circulating-reactor technology, the operator said.
Despite its US Gulf Coast location, the plant will be equipped to produce a range of high-performance, multimodal HDPE products for export to markets across the globe, the firm said.
While LyondellBasell disclosed no further details regarding the precise location or cost of the project, the company told investors in June that, alongside its planned investment of $1.9 billion in 2016 on a maintenance and growth program designed to further increase reliability, efficiency, and production at existing manufacturing sites, it also was evaluating a total investment of $3-4 billion over the next 5 years on other growth projects (OGJ Online, June 3, 2016).
Announcement of this latest HDPE project follows a series of completed and ongoing projects LyondellBasell has undertaken as part of its long-term strategy to take advantage of increased North American shale gas production.
Alongside completing ethylene expansions of 800 million lb/year at its LaPorte, Tex., plant and 250 million-lb/year at the Channelview, Tex., plant in 2014 and 2015, respectively, the company currently is wrapping up an 800 million-lb/year expansion at its production complex in Corpus Christi, Tex. (OGJ Online, May 2, 2014).
The Corpus Christi ethylene plant expansion is due to be completed by the end of this year’s third quarter, said Bob Pa-tel, LyondellBasell’s chief executive officer.
The company also is moving forward with plans to build the world’s largest propylene oxide (PO) and tertiary butyl alcohol plant at its Channelview complex, which when completed in 2020, will be equipped to produce about 1 billion lb/year of PO and 29,000 b/d of oxyfuels.
TRANSPORTATION — Quick Takes
Deal reopens three Libyan oil terminals
Three Libyan oil terminals are reported to have reopened after being blockaded since December 2014.
The Ras Lanuf, Es Sidra, and Zuetina terminals opened under a deal between the presidency council brokered by the United Nations and Ibrahim Jidran, branch leader of the Petroleum Facilities Guard (PFG).
The group said its blockades of Libyan ports responded to corruption and illicit oil sales.
In a statement welcoming the terminal deal, the National Oil Corp. said the only payments to the PFG were of overdue sala-ries. Rival groups threatened to attack tankers approaching the terminals. Terminal problems are among reasons Libyan production last year averaged slightly more than 400,000 b/d, down from 1.6 million b/d in 2010 before the start of civil war.
EIA: US crude-oil shipments by rail on decline
Movements of crude oil by rail in the US averaged 443,000 b/d in the first 5 months of 2016, down 45% from the same period last year, according to the US Energy Information Administration’s energy-by-rail data methodology report. Fewer shipments of crude oil by rail from the Midwest (PADD 2) to the East Coast (PADD 1) account for about half of the decline.
The decrease in crude oil shipments by rail since last summer has been mainly attributable to narrowing price differences between US and imported crude oil, the opening of crude-oil pipelines, and declining production in the Midwest and Gulf Coast onshore regions.
“The economics of crude-by-rail transportation depend largely on the relationship between the prices of domestic and inter-national crude oils. Domestic crude oils priced in the Mid-west and West Texas are no longer heavily discounted relative to imported crude oils priced in the North Sea. The narrower the spread between domestic and imported crude oils, the more likely coastal refiners will choose to run imported crudes rather than domestic supplies shipped by rail,” EIA said.
Crude oil carried by rail from the Midwest to the East Coast remains the country’s largest crude-by-rail movement at 176,000 b/d, or 45% of the total crude oil moved by rail in the US in May. Crude oil imports processed by East Coast refineries have generally increased since early 2015, averaging 760,000 b/d in May, up from 666,000 b/d in May 2015.
Mexican storage, transportation system proposed
TransCanada Corp., Sierra Oil & Gas, and Grupo TMM have proposed to jointly develop an $800-million refined product storage and transportation system to serve rising demand for gasoline, diesel, and jet fuel in central Mexico and surrounding markets. The project—being touted by the partners as the largest single investment in refined products since the establishment of the Mexico energy reform—will include construction of a marine terminal near Tuxpan, Veracruz, a 100,000-b/d, 265-km product pipeline, and an inland storage and distribution hub in central Mexico.
The marine terminal, with a draft of 14 m, will include four docking positions. The terminal will be pipeline-connected to regional distribution centers and will offer racks for truck loading and barge access to service other Gulf Coast ports. The pipeline will parallel TransCanada’s recently awarded Tuxpan-Tula natural gas pipeline project (OGJ Online, Nov. 11, 2015). The inland distribution hub in central Mexico will provide connectivity to much of the Mexico Valley with access to major highways and distribution centers.
The project’s planned in-service date will be based on discussions with shippers. TransCanada will hold a 50% interest, with Sierra holding 40% and Grupo TMM holding 10%.
