GENERAL INTEREST — Quick Takes
Saudi Arabia seeks to lower oil dependence
Reduced dependence by Saudi Arabia on revenue from oil is among targets of sweeping economic reform outlined Apr. 25 by Deputy Crown Prince Mohammad bin Salman.
In an interview with the Al-Arabiya news channel, Mohammad said the plan, which the cabinet has approved, envisions an initial public offering of 5% of state-owned Saudi Aramco.
Plans to sell part of Aramco had been reported earlier, but no indication had been made about the extent of privatization.
Mohammad said Aramco will become "a global industrial conglomerate," owned by the Public Investment Fund, which he said will become "the world's largest sovereign wealth fund."
The crown prince repeated plans to reduce consumption subsidies but said effects would be limited for low and middle-income earners. The plan calls for an increase in the share of nonoil revenue in Saudi gross domestic product to 50% in 2030 from 16% at present. It also pursues an increase in "localization of oil and gas sectors" to 75% from 40%.
Mohammad told the television station Saudi Arabia had developed "an oil addiction" that hampered development.
"I think by 2020, if oil stops we can survive," he said, according to press reports. "We need it, we need it. But I think in 2020 we can live without oil."
Swift emerges from bankruptcy, sells assets
Swift Energy Co. has completed financial restructuring and emerged from voluntary bankruptcy after completing the sale of 75% of its interests in South Bearhead Creek and Burr Ferry oil fields in central Louisiana (OGJ Online, Jan. 4, 2016).
The buyer of the Louisiana interests is Texegy LLC, formed in 2014 to acquire, operate, and develop producing, conventional oil and gas properties in Texas and Louisiana.
Swift's core assets are in the Eagle Ford shale play of Texas.
Swift and Texegy will form a joint venture, SV Energy Co. LLC, an affiliate of Texegy, to operate the Louisiana properties covered by the transaction.
Total records first-quarter net income of $1.61 billion
Total SA reported first-quarter net income of $1.61 billion, up from a $1.63-billion net loss in fourth-quarter 2015 but down from earnings of $2.66 billion in first-quarter 2015.
Adjusted net operating income from its upstream segment was $498 million compared with $748 million in fourth-quarter 2015 and $1.36 billion in first-quarter 2015.
Hydrocarbon production was 2.48 million boe/d, an increase of 5% from fourth-quarter 2015 and 4% year-over-year primarily due to new project startups and ramp-ups-notably Termokarstovoye, Laggan-Tormore, Surmont, Lianzi, Gladstone LNG, and Moho Phase 1b.
Total says second-quarter production will continue to benefit from the recent startups, but will be impacted by normal levels of seasonal maintenance. Production is expected to increase 4% in 2016, with startup of Angola LNG and Incahuasi expected by midyear and Kashagan by yearend.
The refining and chemicals segment took adjusted net operating income of $1.13 billion, up from $1 billion in fourth-quarter 2015 and $1.1 billion in first-quarter 2015.
Total refinery throughput was 2.11 million b/d compared with about 2.01 million b/d in both fourth-quarter 2015 and first-quarter 2015.
A utilization rate of 94% in the first quarter "was a significant achievement and refinery throughput increased by 5% compared to the first quarter 2015," the firm says.
The firm's organic investment of $4.6 billion during the first quarter is in line with its objective of limiting capex to less than $19 billion in 2016.
Statoil's first-quarter earnings down 71%
Reflecting lower prices for liquids and natural gas, Statoil ASA reported first-quarter earnings of $857 million, a decline of 71% compared with $2.945 billion in the same period in 2015.
Adjusted earnings after tax were $122 million compared with $902 million a year earlier. Equity production averaged 2.06 million boe/d, which was about the same level as a year earlier (OGJ Online, May 1, 2015). Underlying production growth was 2% after adjusting for divestments.
Production from the Norwegian continental shelf averaged 1.32 million boe/d while equity production outside Norway was 734,000 boe/d. Adjusted exploration expenses were $280 million, down from $351 million a year earlier.
Exploration & Development — Quick Takes
Thai coal company opts into Marcellus gas field
Thailand's Banpu PLC has acquired a 29.4% stake in Chaffee Corners joint exploration agreement for $112 million. The deal provides Banpu with a net interest equivalent 156 bcfd of gas. The agreement targets the net output of 21 MMcfd this year, Banpu said in a statement published on Thai stock exchange.
In an analyst presentation published Apr. 21, the acquisition adds 11,000 net acres to Banpu's position and is the first instance of a Thai company taking a stake in the US shale gas industry. Chaffee Corners JEA is 86% held by production with 62 producing wells, 14 wells waiting on completion, and 173 derisked well locations. The site lies in northeast Pennsylvania about 200 miles from New York City.
The field is currently owned by Talisman Energy Inc., which was purchased by Repsol SA for $13 billion, a deal that was finalized on May 8, 2015 (OGJ Online, Dec. 16, 2014). The company will continue to focus on its coal and power business, citing the Marcellus farmin as part of its emphasis to harness new technologies and lower impact fuel sources.
ONGC to explore India's unconventional gas basins
India's state-owned Oil & Natural Gas Corp. is seeking approval for 17 shale oil and gas exploration wells along the east and west coasts of the country, according to news agency Press Trust of India (PTI). Citing minutes of a recent meeting of the Expert Appraisal Committee (EAC) of Ministry of Environment and Forests, the operator wants to invest $105 million in exploring the countries unconventional resource potential.
According to PTI, ONGC sought permits on 11 wells in Cambay basin at Mehsana, Ahmedabad, and Bharuch districts of western Indian state of Gujarat, one well in Cauvery basin at Nagapattinam in the southern state of Tamil Nadu, and five wells in Krishna-Godovari basin in the East and West Godavari districts of Andhra Pradesh, a state on India's east coast.
If approved, this move would be largest push for shale exploration in the country but not the first. GAIL (India) Ltd. spudded its first of eight exploratory wells in the Cambay basin in western India in March (OGJ Online, Mar. 29, 2016). Drilling began Mar. 27, and target depth of 2,500 m was expected to be reached by mid-May. The well was targeting Cambay shale and Olpad formations on NELP-IX Block CB-ONN-2010/11.
In its 2013 assessment of global shale gas reserves, US Energy Information Agency estimates India has 96 tcf of technically recoverable shale gas reserves.
TE-6 exploration well spudded in Morocco
Moroccan national oil firm Office National des Hydrocarbures et des Mines (ONHYM) commenced drilling on its Tenerara Lakbir permit targeting Triassic sandstones at a total depth of 2,640 m. The Tendrara permit lies in the Oriental region's Figuig province in northeast Morocco, 120 km from Gazoduc Maghreb Europe (GME) pipeline that connects Algeria and Morocco to the Spanish-Portuguese gas grids.
The TE-6 well is in the High Plateau basin, near the town of Maatarka. The permit area is subdivided into eight blocks and covers 14,500 sq km. Seven wells have been drilled in the permit, five have been gas bearing and two have tested successfully. The SBK-1, drilled in 2000, had a peak rate of 5.5 MMcfd (OGJ Online, Aug. 30, 2000). The most recent well, TE-5, was drilled in 2007 and had flow rates of 1.5 MMcfd (OGJ Online, Mar. 30, 2007).
ONHYM's partners include Oil & Gas Investment Funds (OGIF) and Sound Energy Morocco (SEM). OGIF was granted the Tendrara Lakbir permit in April 2013, and has followed up with seismic interpretation and petroleum evaluation. In June 2015 SEM acquired 37.5% interest on Phase I of the license through a farmin agreement.
SEM will assume operatorship of the license and take 55% working interest in Phase II of the project, which will include two additional exploration wells. OGIF will retain 20% and ONHYM, 25%.
In addition, SEM entered into a field management agreement with Schlumberger Ltd. in December 2015, in which the service contractor agreed to fund a portion of the first three Tendrara wells and provide services, equipment, and personnel to SEM in exchange for a share of future production.
Drilling & Production — Quick Takes
Production begins at Point Thomson on ANS
ExxonMobil Corp. has started production at its Point Thomson project on Alaska's North Slope near the Arctic National Wildlife Refuge (ANWR).
Central pad facilities are designed to initially produce about 5,000 b/d of condensate and 100 MMscfd of recycled gas. The recycled gas is reinjected for future recovery.
At full-rate, the facility is designed to produce as much as 10,000 b/d of gas-condensate and 200 MMcfd of recycled gas. It is expected to reach that level when the west pad well is online in a few months.
Point Thomson is on state acreage along the Beaufort Sea, 60 miles east of Prudhoe Bay and 60 miles west of the village of Kaktovik. ExxonMobil resumed drilling in the area last year after years of legal wrangling (OGJ Online, Mar. 12, 2015).
The firm says Point Thomson reservoir holds an estimated 8 tcf of gas and associated condensate, representing 25% of the known gas on the ANS. Potential future development will depend on a range of factors such as business considerations, investment climate, and the fiscal and regulatory environment.
ExxonMobil and the working-interest owners have invested $4 billion in the development of Point Thomson production facilities through 2015.
More wells planned for CD5 drill site in NPR-A
ConocoPhillips Alaska Inc. plans to drill additional wells and add associated on-pad infrastructure to boost production at its CD5 drill site in Alpine field in the National Petroleum Reserve-Alaska (NPR-A).
The additions, funding of which has been approved, will bring CD5 to its full design and permit capacity. Project work will begin this year, with the start of production from this next phase of drilling expected in third-quarter 2017. The new wells and infrastructure will be completed within the existing CD5 drill site footprint.
The CD5 pad is designed to accommodate 33 wells. The original development funding was for 15 wells, 10 of which have been completed. The cost of the project is estimated at $190 million, which includes construction, drilling, and well tie-ins. The company expects CD5 to meet its production target of 16,000 boe/d gross average for the year.
"The competitiveness of this next phase of CD5 drilling was improved due to the investment climate resulting from the passage of SB21," said Joe Marushack, ConocoPhillips Alaska president. "We want to continue to invest in production-adding projects like this."
The drill site, which began producing oil in October 2015, is the first commercial oil development on Alaska Native lands within the boundaries of the NPR-A (OGJ Online, Oct. 28, 2015).
The company says it's also advancing development of Greater Mooses Tooth No. 1 (GMT1) in the NPR-A (OGJ Online, Nov. 19, 2015). Production is expected to begin in late 2018 with an anticipated peak rate of 30,000 b/d gross of oil.
Long lead materials are being ordered and detailed engineering is under way. The firm also is pursuing permitting of another field in NPR-A, Greater Mooses Tooth No. 2, and is drilling three exploration wells this winter on the North Slope.
CD5 is part of the Colville River Unit operated by ConocoPhillips Alaska with 78% interest. A unit of Anadarko Petroleum Corp. holds the remaining 22%. The Greater Mooses Tooth Unit is also ConocoPhillips 78% and Anadarko 22%.
CNOOC starts oil production at Panyu 11-5 field
CNOOC Ltd. started oil production from Panyu 11-5 field in the Pearl River Mouth basin of the South China Sea.
A single well is producing 3,270 b/d in 110 m of water. The company expects peak production of 3,900 b/d later this year.
CNOOC said it is using facilities of Panyu 5-1 oil field and that three horizontal wells have been drilled.
CNOOC has 100% interest (OGJ Online, July 31, 2014).
Fitch: Depressed drillship price reported
Ocean Rig UDW Inc.'s recently announced acquisition of a deepwater drillship at less than 10% of its newbuild cost provides yet another signal of the dim market outlook for offshore drillers, Fitch Ratings said Apr. 27, saying the sale established a new offshore rig valuation low.
The drillship named Cerrado was sold at auction for $65 million, and it has no pending contract. Ocean Rig did not indicate its immediate plans for the drillship, which was built in 2011. The drillship will be renamed the Ocean Rig Paros upon delivery to Ocean Rig.
Fitch estimated Ocean Rig could generate positive cash flow and earn an attractive return on capital, subject to any additional upgrade costs, with an anticipated day rate in the low-$200,000s if awarded a multiyear tender.
"This would be substantially below the $500,000-plus day rates these types of rigs previously fetched," Fitch added.
Fitch believes that creditors are likely to adopt a more conservative view of offshore rig values that will negatively influence prospective recovery in an offshore driller default scenario.
Fleet high-grading activity, even at these seemingly attractive levels, is likely to wait until a market recovery becomes more evident, Fitch said.
PROCESSING — Quick Takes
Plans advance for grassroots megarefinery in India
Public-sector refining firms Indian Oil Corp. Ltd. (IOC), Bharat Petroleum Corp. Ltd. (BPC), and Hindustan Petroleum Corp. Ltd. (HPC) are advancing a previously announced plan to jointly invest in construction of a grassroots 60 million-tonne/year integrated refining and petrochemical complex in India's Maharashtra state (OGJ Online, Jan. 29, 2016).
IOC, BPC, and HPC have enlisted fellow partner Engineers India Ltd. (EIL) to carry out a detailed feasibility study for the complex, with the site selection for the project already under way in consultation with the government of Maharashtra, India's Minister of Petroleum and Natural Gas (MPNG) Shri Dharmendra Pradhan said in an Apr. 25 notice to the Lok Sabha, the lower house of India's Parliament.
The project partners plan to make decisions regarding equity structure and financing for the project once site selection and the detailed feasibility study have been completed, Pradhan said. Implementation for the proposed project likely would be 7 years following acquisition of a land site, Pradhan added, without disclosing a firm timeframe.
To be built in two phases, the complex would produce gasoline, diesel, LPG, and jet fuel, as well as other feedstock for Maharashtra's petrochemical industry.
Phase 1 of the refinery would include a crude processing capacity of 40 million tpy, with an additional 20 million tpy of capacity to be commissioned following completion of Phase 2.
ADNOC opens Shah sour gas plant
Abu Dhabi National Oil Co. (ADNOC) subsidiary Abu Dhabi Gas Development Co. (Al Hosn Gas) and joint-venture partner Occidental Petroleum Corp. have formally commissioned the Al Hosn Sour Gas Development Project (SGDP) at Shah sour gas-condensate onshore field, southwest of Abu Dhabi City, UAE (OGJ Online, Jan. 30, 2015; July 9, 2008).
Officially inaugurated on Apr. 26, the Shah gas plant is the first project to produce and safely process more than 1 bcfd of ultra-sour gas from a single plant, ADNOC said.
Part of ADNOC's plan to maximize the value of Abu Dhabi's gas resources to help meet growing demand both within UAE and abroad, the $10 billion Al Hosn SGDP will produce 504 MMcfd of natural gas, 33,000 b/d of condensates, 4,400 tonnes/day of NGLs, and 9,900 tonnes/day of sulfur granules, the company said.
Comprised of two gas processing trains and four sulfur recovery units, the Shah gas plant initially reached its full 1-bcfd processing capacity in July 2015 to produce 500 MMcfd of sales gas, Saif Ahmed Alghfeli, chief executive officer of Al Hosn Gas, said in a September 2015 update on the project.
During 2015, the Shah plant produced 2 million tonnes of sulfur, which ADNOC said it expects will rise to 3.2 million tonnes for 2016.
Deal inked for sale of Hawaii downstream assets
Chevron Corp. subsidiary Chevron USA Inc. has entered a deal for the sale of its 54,000-b/d Kapolei, Ha., refinery on the island of Oahu and other associated Hawaiian downstream assets to Island Energy Services LLC, a subsidiary of One Rock Capital Partners LP, New York.
As part of the agreement, signed on Apr. 19, Island Energy Services will purchase the refinery as well as certain distribution and retail assets located in Hawaii, including Chevron's interests in a network of 58 retail service stations, four product distribution terminals (on Oahu, Maui, Kauai, and Hawaii Island, respectively), pipeline distribution systems, and other unidentified downstream assets in the state, One Rock said.
Subject to customary regulatory approvals, the deal is due to be completed sometime during this year's second half. Neither Chevron nor One Rock disclosed details regarding the proposed transaction's value.
Chevron's sale of the Hawaii refinery and related downstream assets comes as part of the company's strategy to optimize its portfolio by divesting noncore holdings, which during 2015, included its interest in Caltex Australia Ltd. and New Zealand Refining Co. downstream operations.
TRANSPORTATION — Quick Takes
US House committee approves pipeline safety bill
The US House Energy and Commerce Committee unanimously passed HR 5050, the pipeline safety reauthorization bill, on Apr. 27. The action followed the Transportation and Infrastructure Committee's approval of its own pipeline safety bill, HR 4937, a week earlier.
Chairman Fred Upton (R-Mich.) said the Energy and Commerce Committee's bill culminated months of bipartisan work to identify weaknesses in US pipeline safety laws. It contains targeted mandates for the US Pipeline and Hazardous Materials Safety Administration to increase transparency and accountability, complete overdue regulations, and improve pipeline safety, he indicated after the vote.
The legislation also tightens provisions allowing PHMSA to issue emergency orders, brings transparency and interagency reviews to the regulatory process, and increases inspections for some underwater oil pipelines, Upton added.
The Interstate Natural Gas Association of America welcomed the Energy and Commerce Committee's action. "We appreciate that HR 5050 is a 5-year reauthorization, starting at fiscal 2017, which was a suggestion INGAA made earlier this year," a spokeswoman said.
"We also appreciate that the committee made some critically important modifications to the emergency order authority section of the bill, so that it mirrors the provision contained in HR 4937 (the Transportation and Infrastructure version)," she said.
The US Senate previously approved its own federal pipeline safety bill, which would reauthorize PHMSA through fiscal 2019 while requiring the US Department of Transportation agency to finishing implementing mandates from the 2011 reauthorization law (OGJ Online, Mar. 4, 2016).
Husky to sell midstream assets in Lloydminster region
Husky Energy Inc., Calgary, is to sell 65% interest in certain midstream assets in the Lloydminster region of Alberta and Saskatchewan to Cheung Kong Infrastructure Holdings Ltd. and Power Assets Holdings Ltd. (PAH).
Cheung Kong is a global infrastructure company and PAH is a global investor in energy.
Husky will receive $1.7 billion (Can.) of gross cash proceeds and will remain operator with 35% interest in the assets.
The assets include 1,900 km of pipelines in the Lloydminster region and 4.1 million bbl of oil storage capacity at Hardisty and Lloydminster. A new limited partnership will be formed with Husky owning 35%, Cheung Kong, 16.25%, and PAH, 48.75%.
Husky CEO Asim Ghosh said the firm sought partners "who viewed these as top tier assets that provide considerable growth potential." Husky said the partners have the funding capacity to build midstream infrastructure associated with planned construction of additional thermal projects in the area (OGJ Online, Apr. 18, 2016).
Kinder Morgan cancels two pipeline projects
Kinder Morgan Inc. has cancelled both its Northeast Energy Direct (NED) natural gas and Palmetto liquids pipeline projects, citing insufficient contractual commitments for the former and unfavorable action by the Georgia legislature regarding eminent domain for the latter.
NED was to have extended between Wright, NY, and Dracut, Mass., using 30-in. OD pipe to provide 1.3-2.2 bcfd of incremental gas capacity to Kinder Morgan's existing Tennessee Gas Pipeline system (OGJ Online, July 17, 2015).
Palmetto was to have moved 167,000 b/d of gasoline, diesel, and ethanol from Louisiana and Mississippi to South Carolina, Georgia, and Florida. The project included expansion of the Plantation Pipeline between Baton Rouge, La., and Belton, SC, and 360 miles of newbuild line between Belton and Jacksonville, Fla.