OIL OILGRAM NEWS - Baker McKenzie

Volume 92 / Number 41 / Thursday, February 27, 2014

[OIL ]

www.platts.com OILGRAM NEWS

Top stories

Asia Pacific

Asia prepares for Panama Canal delays 2

Singapore planning second LNG import terminal 2

Balai Cluster to start production in Q2 3

India’s refining throughput falls 4.5% in January 3

Japan’s policy stresses nuclear power 4

Sinopec plans news gasoil hydrotreater at Maoming 4

China’s piped gas imports rise 20% in January 4

Europe, Middle East & Africa

Russia eyes quotas for domestic fuel 5

Japan to lease more crude storage to Abu Dhabi 5

South Africa’s key energy bill faces delay 6

Karachaganak partners schedule expansion decision 6

Repsol eyes acquisitions after YPF deal 7

Iraq targets 3.4 million b/d crude exports in 2014 7

DONG eyes growth after Goldman crisis 8

South Sudan removes Upper Nile oil minister 8

The Americas

Ecopetrol’s production rises on year 9

Newfield expects to double Anadarko Basin output 9

Peru sells ethanol into Brazil after Europe price fall 10

Markets & Data

Gas is winner of global shale revolution 11

Crude futures settle higher as Cushing stocks fall 13

Oil industry questions Bakken crude testing orderWashington—The oil industry wants more clar-ity on the new US requirements to test Bakken crude-by-rail cargoes, the head of the American Petroleum Institute testified on Wednesday.

In an emergency order, the Department of Transportation said that effective immediately, shippers offering crude-by-rail services would be responsible for ensuring that their cargoes are properly tested and classified in order to better prevent spills and help emergency responders follow the correct hazardous mate-rials protocols in the event of an accident.

Violations of the order would result in a $175,000 fine per incident.

But at a hearing held by the House Trans-portation Committee, API President Jack Gerard said the emergency order is unclear on how often tests should be performed.

“Unfortunately, we don’t know what that means,” he said. “My guarantee is that there is a chilling effect to our industry that is trying to come up with the right answers.”

The emergency order was deliberately left vague, said Cynthia Quarterman, administra-

tor of the Pipelines and Hazardous Materials Safety Administration. She added that as long as shippers are properly labeling crude oil shipments according to federal regulations, the testing schedule would be up to them.

But inspections, under PHMSA’s so-called “Bakken Blitz,” that reveal incorrect labeling due to insufficient testing would result in fines, she said.

The PHMSA launched the “Bakken Blitz,” officially known as Operation Classification, last summer, making unannounced inspec-tions on crude shipments to ensure that highly volatile shale oil is properly labeled on rail manifests and other required documents. The agency has already fined three oil ship-pers for mislabeling their cargoes.

“We specifically left those terms [in the emergency order] to be determined by ship-pers based on their operations,” Quarterman said. “We did not want to say each and every instance before a shipment occurs that test-ing needs to occur. It may be that a shipper, if

(continued on page 10)

Sonangol to exit Iraq over security woesBaghdad clears delayed contracts for Eni’s Zubair project

Dubai—Security problems in Iraq have forced Angola’s state-owned Sonangol to pull out of the country, dropping plans to develop two oil fields, a source close to the company said Wednesday.

In 2009, Sonangol won the rights to oper-ate the Qayara and nearby Najmah oil fields in the Nineveh region, where Sunni Islamist insurgents remain active. Under the contracts, Sonangol was to produce 120,000 b/d from Qayara and 110,000 b/d from Najmah.

The source confirmed a report on Angola’s state news agency ANGOP, which quoted Sonangol board member Anabela Fonseca as saying the decision was taken after the com-pany was unable to develop the projects due to the security issues in the region.

Iraqi Deputy Prime Minister Hussain al-Shahristani said January 28 that terror-ist activity linked to Syria’s civil war has held back development of Iraq’s oil and gas resources in the west and northwest, includ-ing the Qayara and Najmah fields.

Former Iraqi oil minister Thamer Ghad-ban, now a senior adviser to Prime Minister

Nouri al-Maliki, sympathized with the “unfor-tunate” situation in which Sonangol had found itself.

“I wish they have not gone through such type of experience,” Ghadban told Platts on the sidelines of an industry conference in Dubai. “They were really willing and we want-ed them to work in Iraq. But unfortunately, the situation is unfortunate.” The problems facing Sonangol in the area intensified fol-lowing the December 2011 withdrawal of US troops from Iraq.

In January 2012, attackers bombed a facility belonging to Canada’s Terrasis, which had carrying out a seismic exploration survey for Sonangol on the Najmah oil field near Mosul, and the region has continued to remain unstable since then.

In a separate development, Iraq’s cabinet approved two contracts valued at a combined $1.7 billion for the giant Zubair oilfield in the south of the country, government officials con-firmed Wednesday.

The two approved engineering, procure-(continued on page 8)

2 Oilgram News / VOlume 92 / Number 41 / Thursday, February 27, 2014

ASIA PAcIfIc

Singapore planning second LNG import terminalSingapore—Singapore is planning to build a second LNG receiving terminal to further diversify its energy sources.

“We are studying a few potential sites in eastern Singapore,” Prime Minister Lee Hsien Loong said Tuesday, according to a copy of his speech given during the official opening ceremony of the country’s first LNG terminal, which started operations in May 2013.

“This will enhance our energy security by geographically diversifying our LNG import infrastructure,” Lee said.

In addition, the new project will support new industrial sites and power plants. More details will be released in due course by the Ministry of Trade and Industry, Lee said.

Singapore’s existing LNG import terminal, on Jurong Island, is owned and operated by Singapore LNG Corp. It has capacity of 6 mil-lion mt/year while a further expansion will bring this to 9 million mt/year by 2017.

SLNG said in a separate statement Tues-day that it has started the tender process to select a contractor and a final investment decision on the expansion is expected in the second quarter of this year.

However, while the current project can accommodate up to seven storage tanks with capacity of 15 million mt/year, expansion is limited due to land constraints, which is why the government decided to build a second LNG import terminal, Lee said.

SLNG said over 1.08 million mt of LNG has been delivered to the Jurong Island ter-minal to date. The cargoes came from UK BG Group’s portfolio, including Equatorial Guinea and Trinidad and Tobago, SLNG said. The UK company is the sole aggregator for LNG sup-

plies for the terminal and has a contract to bring in 3 million mt/year.

Lee said the government will launch a “competitive RFP [request for proposal] for the next tranche of LNG imports by June” this year.

The formal RFP process will open in the second quarter of 2014, as BG’s exclusive right to import the first 3 million mt/year of LNG into Singapore’s 6 million mt/year Jurong Island terminal nears its end, Singapore’s second minister for home affairs, trade and industry, Mr. S. Iswaran, said Tuesday.

After a process of evaluation—which would take into account price competitive-ness, security of supply and factors such as mechanisms to manage price volatility and indexation diversity—Singapore’s Energy Markets Authority will then appoint up to two importers, Iswaran said.

EMA outlined its intention to award con-tracts on a tranche-by-tranche basis, veering away from traditional long-term contracts, as more volumes are expected to hit the market over the next two years, potentially weighing on prices and creating some flexibility with regards to supply sources.

Although it did not face a natural gas shortage, Singapore decided to build an LNG import terminal to reduce its reliance on pipe-line gas supplies from neighboring Malaysia and Indonesia.

Over 90% of Singapore’s electricity is currently generated from natural gas, Lee said, pointing out that “with more gas avail-able, and new [power] generation capacity entering the market, electricity generation becomes more competitive, benefiting con-sumers”. — Song Yen Ling, Stephanie Wilson

Singapore—North Asian LPG buyers would like more certainty on the likely completion date of a delayed upgrade to the Panama Canal, which should translate to cheaper US car-goes, but are preparing for more hold-ups by seeking alternative supply sources.

Work on the Panama Canal upgrade restarted February 20 after a stoppage of more than two weeks prompted by a dispute over cost overruns.

Originally scheduled for completion this year, the Panama Canal Authority said earlier this month that the project would now not be finished until December 2015, six months later than the revised date of June 2015.

The upgrade, which will significantly widen and deepen the 80 km (50 mile) waterway, will allow many more very large LPG carriers, or VLGCs, to use the 100-year old canal.

But this month’s dispute between the contractors and the PCA has now likely pushed the completion date into 2016,

according to analysts.“The likelihood of the [upgraded] Panama

Canal opening before mid-2016 at the earliest seems very low,” said Erik Nikolai Stavseth, a shipping analyst at Norway’s Arctic Securities.

“Cost overruns and schedule delays are common on major projects. If history is any indication, the upgrade will likely not be com-pleted in 2015. I expect that the offtakers have priced in an alternative route among the variables for pricing cargoes destined for East of the Suez. How could they not have?,” said Natalie Regoli, a partner at Houston-based law firm Baker & McKenzie who specializes in gas.

The extent to which a delay in the open-ing of the project will impact US LPG exports to Asia depends on the arbitrage at the time between Middle East/African LPG and US LPG, Stavseth said.

“If the spread remains as wide, or is expected to remain as wide, as it has been during 2012/2013...there is ample incentive

for both exporters, shippers and importers to move cargo,” he said.

Stavseth estimated the increase in freight costs from the US to Asia around Africa, ver-sus from the Middle East, is currently in the $70-$75/mt range, equivalent to a day rate of $40,000.

“So if the spread were to narrow by $75/mt ... it would kill off some of the incentive [for Asian buyers] to buy [US] LPG exports,” he said.

Non-US optionsAlthough Japanese and Chinese LPG buy-

ers with term deals to import propane and butane from the US are sanguine on the lat-est delays, they are nonetheless looking into other sources of supply, such as West Africa, North Africa and Australia.

“We are not solely dependent on the US. We will continue to move forward our efforts to diversify our supply sources to avert region-al risks,” said an official with Japan’s top LPG supplier, Astomos Energy, noting efforts to procure LPG from Angola and Nigeria.

Japanese LPG importer Eneos Globe also expects its US LPG volumes to be delayed by the canal work disputes, but an official at the company pointed out that its term contract for 300,000 mt/year in 2015-16 with US Enterprise Products Partners will represent less than 10% of its annual LPG imports at that time. Eneos has not ruled out selling its US LPG cargoes outside Japan and continues to consider options to diversify its supply sources, the official said.

Similarly, developers of propane dehydro-genation plants in China with US term import deals are not too concerned by the prospect of more delays to the canal, said an LPG trad-er in Shanghai. The term contracts have fixed volumes and delivery dates, he said.

For example, the four-month-old Tian-jin Bohai Chemical PDH plant has a term contract with US Targa Resources for one propane cargo every two months over 2015-2020, a Beijing-based source said.

In any case, Chinese LPG importers still source the bulk of their supplies from the Middle East, which accounted for 80% of Chi-na’s LPG imports last year, while US volumes accounted for less than 3%.

And PDH plants obtain better margins from Middle Eastern propane due to its higher guar-anteed propane content and lower sulfur and metal contents, the Chinese sources said.

One medium-term alternative could be a new canal through Nicaragua. The central American country is reportedly close to break-ing ground on a rival project.

The Nicaraguan government last year awarded a $40 billion construction and man-agement contract to privately owned Hong Kong Nicaragua Canal Development Invest-ment Co. The company’s founder and CEO is Wang Jing, a Chinese telecoms entrepreneur. — Staff Reports

Asia prepares for Panama canal delaysNorth Asian LPG buyers look for alternative supply sources


ASIA PAcIfIc

India’s refining throughput falls 4.5% in JanuaryMumbai—Indian public and private-sector refiners processed around 18.74 million mt of crude, or an average of 4.43 million b/d in January, down 4.5% year on year, but 0.6% higher than December.

The average utilization rate of Indian refin-eries in January was 102.6% compared with 108.4% in January last year and 102.0% in December, provisional data released by the Ministry of Petroleum and Natural Gas on Fri-day showed.

State-owned Indian Oil Corp., the largest refiner, reported a 1.2% year-on-year fall in

crude throughput to 4.73 million mt.Throughput at IOC’s Mathura refinery

fell due to an extended shutdown at the fluid catalytic cracker, the ministry said. Meanwhile, throughput at the Panipat refin-ery was affected due to shift in a planned shutdown of the refinery’s hydrocracker and interruptions in crude supply due to a prob-lem in the SMPL (Salaya-Mathura Pipeline) crude pipeline, it added. The pipeline sup-plies crude from ports in Gujarat to IOC’s Koyali, Mathura and Panipat refineries. — M.C Vaijayanthi

Singapore—Australia’s Roc Oil expects to start commercial production from its Balai Cluster project in Malaysia in the second quarter of this year, making it the third project under the risk service contract format to enter production.

Malaysia’s state-owned oil and gas com-pany Petronas in 2011 awarded the Balai Cluster RSC to Roc Oil, Malaysia’s Dialog Group, and Petronas’ upstream subsidiary Petronas Carigali.

The Malaysian government together with Petronas in 2011 launched risk service contracts—a new fiscal regime to encourage investments in the country’s marginal fields.

Under the RSC arrangement, Petronas remains the project owner while the contrac-tors are service providers. Up-front capital investment is contributed by the contrac-tors, who start receiving payment from first

production and throughout the duration of the contract.

The other two projects under the RSC to have started production are the KBM cluster of fields and the Berantai fields offshore Pen-insular Malaysia.

Roc is the operator of the Balai Cluster project with a 48% stake, with Dialog holding 32%, and Petronas Carigali 20%.

The cluster consists of the Bentara, Balai, Spaoh and West Acis fields offshore Sarawak in east Malaysia.

Speaking at a webcast presentation on Wednesday, Roc’s CEO Alan Linn said the company submitted a field development plan for the Bentara field to Petronas in December last year and approval is expected very soon.

“Once that comes through, we can effec-tively move straight into production of the

field and start generating revenue,” he said.Production facilities have already been

installed and output will be via two wells.Reservoir sands at Bentara are “quite

good” and each well was previously tested to flow at between 2,000 b/d and 4,000 b/d, Linn said.

Roc had done appraisal work on four fields in the Balai cluster as part of the pre-development phase and first oil at the project had been achieved via the Mutiara Balai early production vessel which had been commis-sioned at the Balai field in November last year. This was part of the RSC area’s extend-ed well testing program.

However, more work needs to be done at Balai before the venture can go forward with production, Linn said. “The challenge with the Balai field is that it’s got a faulting system within the reservoir which may require addi-tional wells in order to fully recover reserves.”

Linn said there is more upstream poten-tial around Bentara. “It will be attractive but does require further technical work and appraisal,” he said, adding that more work is being discussed among the partners.

China projectsIn China, the offshore Beibu Gulf project

achieved a plateau production rate of 15,000 b/d in the third quarter of last year.

The project, in the southwestern part of the South China Sea in shallow water, started production in March last year from the Weizhou 6-12 field, while the Weizhou 12-8 West field started in October last year.

Roc operates it with a 19.6% stake, part-nering state-owned China National Offshore Oil Corp. (51%), Horizon Oil (26.95%) and Oil Australia (2.45%).

A feasibility study and development plan review is under way for a second phase devel-opment of the Weizhou 12-8 East prospect and this is expected to be concluded this year, Roc said.

Elsewhere in China, Roc’s net production from the Zhao Dong project in the Bohai Bay averaged 4,017 b/d last year, as a drilling program with 18 development wells was pro-gressed during the second half of last year. Roc is operator of the project and has stakes ranging between 11.7% and 39.2% in fields in the project.

The company said it started the Zhao Dong 2014 development drilling campaign last week, with another 15 to 18 wells expected this year. It has submitted an incremental development plan to its state-owned partner PetroChina for development at the project for another five years beyond the current production sharing contract, which expires in 2018, Roc said.

Roc said it has also completed 3-D seismic acquisition at the 09/05 exploration block, located 15 km north of Zhao Dong. The compa-ny expects to drill at least one exploration well this year in the 335 sq km block, with a second well dependent on weather. — Song Yen Ling

Balai cluster to start production in Q2Malaysia’s risk service contracts pay off with third project coming online

India’s Oil & Gas Production

Jan-14 Jan-13 % Change Dec-13 % Change

Crude ProductionOnshore 1676.53 1618.27 3.6% 1704.71 -1.7%Offshore 1584.07 1547.03 2.4% 1551.66 2.1%Total 3260.60 3165.30 3.0% 3256.37 0.1%

Natural Gas Production (million cu m)Onshore 800.07 744.79 7.4% 773.58 3.4%Offshore 2272.78 2496.40 -9.0% 2228.09 2.0%Total 3072.85 3241.20 -5.2% 3001.68 2.4%

India’s Refinery ThroughputIOC 4734.38 4790.35 -1.2% 4764.30 -0.6%BPCL 1903.73 2015.53 -5.5% 1655.10 15.0%HPCL 1448.98 1442.96 0.4% 1378.32 5.1%CPCL 880.44 949.26 -7.2% 770.22 14.3%MRPL 1222.61 1297.16 -5.7% 1367.32 -10.6%Essar Oil 1742.80 1753.03 -0.6% 1742.54 0.0%RIL (Jamnagar) 2191.79 2830.00 -22.6% 2210.22 -0.8%RIL (SEZ) 3186.90 3198.86 -0.4% 3186.90 0.0%BORL 321.03 504.66 -36.4% 564.95 -43.2%HMEL 867.24 601.33 44.2% 722.25 20.1%Total* 18739.06 19615.20 -4.5% 18630.74 0.6%Utilization Rate 102.6 108.4 -5.4% 102.0 0.6%

All figures are in ‘000 mt unless speficied otherwiseSource: Ministry of Petroleum and Natural Gas*Total includes Numaligarh & ONGC Tatipaka refinery


ASIA PAcIfIc

china’s piped gas imports rise 20% in JanuarySingapore—China imported 1.78 million mt of natural gas via pipelines in January, up 19.6% from a year earlier, but down 3.9% from December.

China’s General Administration of Cus-toms records natural gas trade data in metric tons, similar to LNG imports. The volume works out to about 2.46 billion cubic meters of pipeline gas imported in January.

Inflows from Turkmenistan in January rose 3.9% year on year and were largely stable from December 2013 at 1.49 million mt, the data released Wednesday showed.

Uzbekistan imports more than doubled from a year earlier to 137,275 mt.

Myanmar gas pipeline imports, which

commenced in August 2013, rose 17.5% from December 2013 to 120,356 mt in Janu-ary, while Kazakh imports rose 6% month on month to 29,553 mt.

Gas import volumes from Myanmar have steadily ramped up in recent months on the back of increased output at the deepwater Shwe gas project in the Bay of Bengal.

China’s current gas imports from Turkmeni-stan and Uzbekistan are transported via the Central Asia-China gas pipeline network that links with state-owned China National Petroleum Corp.’s Second West-East Pipeline in western Xinjiang province while Kazakh supplies currently flow through a pipeline operated by private com-pany Xinjiang Guanghui Energy.— Song Yen Ling

Tokyo—Japan in its latest energy policy plan has said that nuclear power should serve as the country’s key baseload power source along with coal, hydro and renewables for the next 20 years.

In the report, which was released Tuesday after a series of reviews, the government also said that nuclear reactors which meet the safe-ty standards set by the nuclear regulatory body should make progress on resuming operations.

Before its release, an energy policy commit-tee at the Ministry of Economy, Trade and Indus-try had released a draft plan in December say-ing nuclear power would continue to be Japan’s “key base power source” from the perspective of stable supplies and cost, drawing comments from the public as well as policy makers.

The policy will now be examined by the ruling Liberal Democratic Party before Cabi-net approval.

The plan did not include any numeric targets for Japan’s medium- to long-term energy mix.

Natural gas and LPG are positioned as intermediate-load to supplement energy from baseload sources. The report also said that Japan should not rely heavily on LNG, for which it currently pays a high price, and called for diversification of sourcing to cut costs.

As the world’s largest LNG importer, Japan has found itself increasingly exposed to high prices mainly because its LNG purchases are predominantly indexed to crude oil prices.

The plan also called for an end to destina-tion restrictions on FOB-based LNG contracts to introduce greater flexibility as part of efforts to enhance cooperation between buy-ers of LNG in Japan and abroad.

In addition, the government will promote exploration for methane hydrates off the coast of Japan. METI in December said that it has found substantial structures containing shal-low methane hydrate offshore Niigata and the Noto Peninsula in the Sea of Japan in the northwest of the country.

LNG to remain importantSeparately, an official with Japan Oil, Gas

and Metals National Corp. said Wednesday that the basic energy plan should be finalized within the next month.

“Whatever the outcome, demand for LNG will remain at a high level,” Jogmec Director General, Research and Analysis Department, Takashi Yoshida said at the Australian Domes-tic Gas Outlook conference.

In the short term, Japan’s LNG imports are expected to remain at 2012-2013 vol-umes, or around 90 million mt, Yoshida said. But in the medium and long term, imports will be dependent on how much nuclear power generation capacity needs to be replaced.

Japanese utilities are currently trying to reduce their LNG procurement costs via nego-tiations with their suppliers to review the crude oil-linked pricing mechanism, Yoshida said.

“Diversification of suppliers is one way [the Japanese companies] can strengthen their negotiating position in price reviews,” he added. “It is very important for Japanese firms to participate further up the value chain in LNG projects, in order to secure a stable and afford-able supply of LNG to Japan,” he said. — Eriko Amaha, with Christine Forster in Sydney

Japan’s policy stresses nuclear powerEnergy plan calls for greater flexibility in LNG contracts

Sinopec plans news gasoil hydrotreater at MaomingSingapore—China’s state-owned Sinopec is planning to add a 3 million mt/year gas-oil hydrotreater at its 23.5 million mt/year (470,000 b/d) refinery in the southern prov-ince of Guangdong this year.

Construction work started at the end of 2013 and the unit is scheduled to be ready by the end of this year, Sinopec said on its website Monday.

The refinery, which is operated by subsid-iary Sinopec Maoming Petrochemical, current-ly has two gasoil hydrotreaters with capacities of 2 million mt/year and 2.5 million mt/year.

Once the new 3 million mt/year gasoil hydrotreater comes online, the old 2 million mt/year gasoil hydrotreater will be permanent-ly shut, a source at the refinery told Platts.

“The 2 million mt/year gasoil hydrotreater is too old, and is even unable to produce gasoil that meets with the National Phase 3 emission standard,” the source said, adding that the new gasoil hydrotreater is designed to produce gasoil that meets with the Nation-al Phase 4 and Phase 5 emission standards.

The National Phase 5 emission stan-dard—broadly equivalent to the Euro 5 emis-sions standard—caps the maximum sulfur content in gasoline and gasoil at 10 ppm, while the National Phase 4 standard caps the sulfur content in both products at 50 ppm. Under the National Phase 3 standard, the sul-fur content of gasoline and gasoil are capped at 150 ppm and 350 ppm, respectively

China has set a deadline for the Phase 4 standard for gasoline to be adopted nation-wide from January this year, and that for gas-oil from January next year.

In order to meet the requirement, Sinopec Maoming refinery started up a 2 million mt/year gasoline S-Zorb unit at the end of last year, which has allowed the refinery to produce gaso-line that meets with the National Phase 4 emis-sion standard, according to the refinery source.

“We only produce Phase 4 emission stan-dard gasoline now,” the source added.

The refinery is currently producing about 280,000-290,000 mt/month of National Phase 4 standard gasoline and 80,000-90,000 mt/month of National Phase 4 standard gasoil. It is also producing about 80,000-90,000 mt/month of National Phase 3 standard gasoil and around 300,000 mt/month of National Phase 2 standard gasoil. — Staff Reports

china’s Piped Gas Imports in January

Country Jan-14 Jan-13 % Change Dec-13 % ChangeTurkmenistan 1,492,656 1,436,968 3.9 1,492,786 -0.01Uzbekistan 137,275 51,593 166.1 228,391 -39.9Myanmar 120,356 0 N/A 102,422 17.5Kazakhstan 29,553 0 N/A 27,873 6Total 1,779,840 1,488,561 19.6 1,851,472 -3.9

Unit: MtSource: General Administration of Customs, China


Japan to lease more crude storage to Abu DhabiTokyo—Japanese Prime Minister Shinzo Abe agreed on Wednesday with visiting Abu Dhabi Crown Prince Sheikh Mohammed bin Zayed al-Nayhan to increase the emirate’s leased crude storage capacity in Japan to 1 million kiloliters, or 6.29 million barrels, Japan and the UAE said in a joint statement.

Japan and the UAE emphasized their long-term partnership “regarding oil development cooperation, and welcomed that a mutually complementary relationship in oil develop-ment has advanced through such measures as technological collaboration, training pro-grams, financial cooperation and refining cooperation,” it added.

Under the agreement, Abu Dhabi’s leased crude storage capacity will jump 43% from the current storage level of around 700,000 kl, in place since November, according to a Japa-nese government source.

Abu Dhabi’s crude storage volume in Japan had already been increased in Novem-ber from around 600,000 kl previously, fol-lowing Abe’s proposal for an increase to the crown prince during his visit to the emirate in May, the source said.

Under the agreement, Abu Dhabi will be able to use Japanese crude storage tanks for commercial purposes in exchange for prioritiz-ing the supply of crude to Japan in an emer-gency, the Japanese government source said.

The agreement came ahead of the sched-uled June expiry of a two-year crude storage deal between the Ministry of Economy, Trade and Industry and Abu Dhabi’s Supreme Petro-

leum Council, following their original three-year deal in 2009.

Abu Dhabi National Oil Company originally signed the three-year contract in December 2009 with refiner Nippon Oil, which is now JX Nippon Oil & Energy, to store 620,000 kl of crude at the refiner’s terminal at Kiire in southwestern Japan.

Under the latest agreement between Tokyo and Abu Dhabi, both sides will work out details with a view to renewing the existing contract beyond June, said the source, add-ing that it remains unclear where Abu Dhabi’s crude will be stored under the prospective renewed contract.

Japan’s latest agreement with Abu Dhabi in the oil sector came just a month after the Abu Dhabi government decided to extend the con-cession for the offshore Upper Zakum oil field by more than 15 years to December 31, 2041, from its current expiry on March 9, 2026.

The Upper Zakum field is being jointly developed by Abu Dhabi National Oil Company (with 60%), ExxonMobil (28%) and an Inpex wholly-owned subsidiary Japan Oil Develop-ment Company (12%).

The Upper Zakum field, one of the largest oil fields in the world, is approximately 80 km (50 miles) offshore, northwest of Abu Dhabi city, and has an area of 1,150 square km (444 square miles).

Speaking to reporters in Abu Dhabi on January 20, METI Minister Toshimitsu Motegi said the 15-year-extension of the Upper Zakum oil concession was significant because it is one of main oil fields in the emirate. About 40% of Japan’s equity crude output is located in Abu Dhabi.

One of Japan’s top priorities has been to attempt to secure extensions to exist-ing concessions in Abu Dhabi that expire in 2018, as more than 60% of its concessions in the emirate are due to expire that year. — Takeo Kumagai

Moscow—Russia’s energy ministry is in dis-cussions with the country’s oil producers over the introduction of minimum quotas for sup-plies of gasoline and diesel to the domestic market, a spokeswoman for the ministry said.

“The energy ministry proposes introducing mandatory minimal gasoline and diesel sup-plies to the domestic market. The limits are still under discussion but will likely be close to the current gasoline and diesel supplies to the domestic market,” she said, adding that the requirements might come in force in the second quarter of this year.

In 2013, Russia produced 38.53 million mt of gasoline and 71.67 million mt of diesel, according to the energy ministry.

The 2013 exports of high-octane gasoline accounted for about 7% of the total produc-tion volume, while exports of diesel amounted to 54%, Russian daily Kommersant reported Wednesday, citing data from the Central Dis-patching Unit, part of the energy ministry.

The domestic supply requirements could be included in the four-party agreements between state officials and Russia’s oil producers, which were reached in 2011, she added.

Should the limits be introduced, this would ensure “balanced supplies to the domestic market,” the ministry spokeswoman said.

Analysts at Russia’s VTB Capital do not expect the requirements, if implemented, to have a visible effect on Russian oil produc-

ers’ finances.“We do not see any substantial volumes

of gasoline marketable on the Russian inter-nal market going abroad,” they said in their Wednesday morning review. “On the other hand, limiting oil companies’ operations is a negative, sentiment-wise.”

In January 2013, Russia introduced mini-mal levels for oil product trading on commod-ity exchanges, under which key oil producers have to sell no less than 10% of their monthly gasoline output, 10% of jet fuel, 5% of diesel and 2% of fuel oil.

This January, Russian gasoline exports increased and domestic prices surged on the back of a weakening ruble, fueling fears of a new domestic shortage similar to that the country experienced last summer.

At the time, the energy ministry dismissed the fears saying the domestic supply and demand were balanced.

“There is nothing to suggest any likely shortage of the product—refineries are work-ing normally and the average daily production of gasoline [is] in line with companies’ plans,” the ministry said at the time.

New pipelinesRussia’s Federal Antimonopoly Service

(FAS) has also proposed simplifying access to Russia’s crude and oil products pipeline networks for the country’s oil refineries, which some fear could result in an influx of low-quality products from small refineries entering the network.

FAS has not released full details of the proposed changes, but said that it has pre-pared a draft order, which “envisages remov-ing administrative barriers for connecting refineries to trunk crude and oil products pipelines,” a statement posted on the ser-vice’s website said.

Transneft, the state-owned operator of the pipeline network, is against the changes, a spokesman said Wednesday.

“FAS has informed us that if the draft is approved, it would mean that any refinery could access the pipeline network,” he said.

Transneft has long raised the alarm about smaller refineries, often referred to as tea-pots, which produce low-quality products and are “semi-criminal” enterprises.

“There are tens of these refineries, located along the routes of major pipelines,” Transneft’s spokesman said, when asked about the number of refineries currently off-grid that could gain access to the network if the changes are introduced.

Russia’s mini refineries generally cater to regional demand, process less than 1 million mt/year and typically produce naphtha, diesel and fuel oil.

A period of public consultation is now underway and is due to end March 11. If approved, the act introducing the amendments will become law 10 days after its publication, the FAS statement said. — Rosemary Griffin

Russia eyes quotas for domestic fuelPlan to extend pipeline access to more refineries

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Karachaganak partners schedule expansion decisionMoscow—Shareholders in Kazakhstan’s giant Karachaganak oil and gas field plan to take the final investment decision on a phase three expansion in 2017, with a view for com-pletion of the project in 2022, a senior official for PSA, the company that represents Kazakh-stan in the project, said Wednesday.

“In the middle of this year, we plan to approve the development plan for [expand-ing] Karachaganak, in 2015-16, prepare the design project, take the final investment deci-sion in 2017... and begin construction works in 2018. In 2022, the expansion project will be completed,” Kenzhebek Ibrashev, PSA CEO, said in an interview published on the website of Kazakhstan’s Prime Minister.

Under the plan currently discussed by Karachaganak shareholders, phase three is expected to increase the recoverable crude reserves of the project through gas re-injec-tion, Ibrashev said.

Crude oil production and gas sales within phase three is expected to remain at the cur-rent level, he said.

“It is important to keep the current liquids production level of 11 million mt/year and gas sales of 8-9 Bcm/year [at the expansion phase],” Ibrashev said.

Significant gas volumes will be re-inject-ed to support crude production volumes, which will allow an 100 million mt increase in recoverable liquid hydrocarbon reserves, he said.

“This is a significant [increase] consider-ing that Kazakhstan has seen no major hydro-carbon discoveries recently,” Ibrashev said.

In 2013, Karachaganak produced 373,400 boe/d of crude oil and condensate, up 2.3% year on year, and re-injected around 8.57 Bcm of sour gas, a volume equivalent to approxi-mately 49% of the total gas production.

The field has estimated gross reserves of over 2.4 billion barrels of condensate and 16 Tcf of gas.

Last April, then oil and gas minister Sauat Mynbayev said the Karachaganak consortium considered changing the design of phase

three: the shareholders mulled extending the crude production plateau rather than raising gas output from the field.

The third phase was expected to launch in 2008, but was delayed several times due to tax-related disputes between the project’s partners and Kazakh authorities. In late 2011, state-owned KazMunaiGaz received a 10% stake in the project after authorities agreed to drop the claims.

PSA termsBased on full-year 2014 results, Kazakh-

stan is set to receive 36% of the total hydro-carbon volumes produced at Karachaganak, compared with 20% now as the project has recovered its upfront investment costs, Ibra-shev said.

Last week, Kazakhstan’s oil and gas minis-ter Uzakbay Karabalin said Karachaganak has reached profitability and in line with the proj-ect’s production-sharing agreement, Kazakh-stan will start receiving 80% of the revenues.

Until a field developed under a production-sharing agreement reaches profitability, reve-nues from the operations are used to recover the investment of the consortium members.

Despite the changes, the Karachaganak consortium KPO will continue to export crude oil from the field mainly via the CPC and the Atyrau-Samara lines, both leading to Russia, while marketable gas volumes will be sent to Russia’s Orenburg gas processing facilities, Ibrashev said.

“Currently, the CPC line guarantees the best export netback levels. Currently, the CPC line ships some 9 million mt/year [of crude from Karachaganak], some 1 million mt/year goes via Atyrau-Samara and around 800,000-900,000 mt [of gas condensate] is sent to the Orenburg gas processing facility,” he said.

Gas supplies to the Orenburg plant reach 8-9 million mt/year, he added.

The final production-sharing agreement for Karachaganak, which has a 40-year term, was reached in 1997.— Dina Khrennikova

Cape Town—South Africa’s oil and gas opera-tors will have to wait a little longer for clarifi-cation to changes envisaged in mining and oil laws as parliament runs of out time to pass legislation before May 7 elections.

Law firm Webber Wentzel’s head of energy and mining, Peter Leon, said Wednesday it was unlikely the bill will be heard in the sec-ond house, the National Council of Provinces before Parliament is dissolved ahead of the general elections.

The delay in implementation of the Mineral and Petroleum Resources Development Amend-ment (MPRDA) Bill is likely to create regulatory uncertainty for industry players, who are already at odds over certain amendments, but could also have a positive outcome.

“Not passing the bill means uncertainty continues for the oil and gas companies but most seem to agree that rather a delay than a bill they can’t live with,” Democratic Alli-ance shadow minister of minerals resources, James Lorimer, said.

Leon said carrying over the bill to the next Parliament rather than passing it, was better than the lack of clarity that would be created by inadequately considered legislation. “I would rather have temporary uncertainty than permanent certainty,” he said.

While there is a need to get the legisla-tive backbone of the economically key South African minerals sector implemented properly and efficiently, stakeholders fear some of the changes proposed in the bill will, in fact, deter investors.

In a major departure from the current MPRDA, proposals in the new bill give the state a “free carried interest” in all new oil and gas exploration and production rights.

The bill proposes granting the state a 20% stake in new oil and gas ventures with the option for the state to up its stake to 50% by paying market-related rates for that additional 30% share. Under current offshore oil and gas rights, South Africa reserves 10% for the state during the exploration phase.

Investment climateGiving the government a share in profits

without having to contribute to capital develop-ment costs could have a damaging effect on exploration and production. This, say industry experts, also reflect the state’s plans to benefit from shale gas resources in the Karoo and the Western Cape’s offshore petroleum industry.

Although South Africa still awaits a large discovery, the sector has drawn interest from companies including Shell, Total, Sasol, Canadian Natural Resources, ExxonMobil and a number of independents with all of its off-shore hydrocarbon blocks now under license.

Another key concern among stakeholders is the division of opinion over the splitting of

oil and gas from minerals.During a recent meeting of parliament’s

mineral resources committee, chairwoman Faith Bikani proposed incorporating provisions covering oil and gas into a new law. Minerals Resource minister Susan Shabangu is against such a move.

Mining is a significant contributor to the South African economy, and despite a run of labor disputes in recent years, still accounts for 8% of GDP and 500,000 jobs in a country where unemployment is 25%.

“I think the ruling ANC is divided on the

bill, with Bikani reflecting the non-ideological view that the legislation should be split, and oil and gas should have its own law. That is certainly our position as the Democratic Alli-ance,” Lorimer said.

Oil and gas companies and the govern-ment have been in closed talks about the proposed bill and its impact on the sector. At a meeting of the committee last week, the South Africa Oil and Gas Alliance (SAOGA) said uncertainty in the regulatory environ-ment posed a major risk in South Africa, and warned investors would seek alternative emerging markets.

“South Africa needs to create an investment climate that continues to be favorable,” SAOGA CEO Ebrahim Takolia said. — Jacinta Moran

South Africa’s key energy bill faces delayOffshore, shale gas plays await rules on state share



Iraq targets 3.4 million b/d crude exports in 2014Dubai—Iraq aims to boost its oil exports by nearly 26% to 3.4 million b/d in 2014, a senior official said Wednesday.

“Exports reached more than 2.7 million b/d this month, and the rate [that] is planned for 2014, including exports from the Kurdistan Region of Iraq, [is] around 3.4 million b/d,” the Iraqi Prime Minister’s Advisory Council Chairman Thamir Ghadhban told delegates at the Iraq Energy Projects conference in Dubai.

Ghadhban said he hoped Baghdad and the Kurdistan Regional Government will resolve their protracted dispute over oil juris-diction and exports in the coming months.

Based on March nominations from the country’s State Oil Marketing Organization, Platts estimates that Iraq will export 2.415 million b/d in March, up from 2.228 million b/d of actual exports in January and an aver-age 2.39 million b/d in 2013.

The latest Platts survey of OPEC output puts Iraq’s crude production at 2.96 million b/d in January.

Regarding the Iraq National Energy Strat-egy, Ghadhban confirmed that the country’s medium-term target is to develop 9 mil-lion b/d of crude oil production capacity, although he also stressed that the strategy recommended taking a “dynamic approach, not to have one fixed scenario” with respect to oil development.

Under current government projections, Iraq would need 1.5 million b/d, or 16.7% of the target production capacity, as feedstock for its refineries to satisfy the country’s expand-ing domestic appetite for petroleum products, Ghadhban said. Demand is growing by 10% annually, he estimated.

“We are now still a net importer of oil

products,” Ghadhban said.Iraq hopes to have 1.5 million b/d of

refining capacity in place by 2020, enabling the country to stop fuel imports and improve fuel quality, he said.

Ghadhban also expressed optimism that Iraq would be able to eliminate the wasteful practice of flaring gas production associ-ated with its biggest gas fields as early as next year.

“We should be able by 2015 to capture most of the gas produced and have enough processing facilities to take up the increased production of gas,” he said.

In early February, the US and Iraq agreed to cooperate on developing strategies to reduce gas flaring at Iraq’s oil fields.

The US and Iraq also agreed to form a working group focused on combining mobile power generation technologies with reductions in gas flaring.

Shell, together with partners Japan’s Mitsubishi and Iraq’s state-owned South Gas Company, last May began operations on the Basrah gas project, which will capture and market gas currently being flared at the giant Rumaila, West Qurna 1 and Zubair oil fields in southern Iraq.

The project aims to produce 2 Bcf/d of gas when fully ramped up. — Staff reports

Madrid—Spain’s Repsol will consider selling the remaining 12% stake it holds in Argen-tina’s YPF as its looks to grow through poten-tial acquisitions following a key settlement with the South American country.

There are no legal constraints to keep-ing the remaining stake in YPF and the asset could be sold within two years for around $1.5 billion, CEO Antonio Brufau told analysts on a conference call Wednesday.

Under the settlement deal with Buenos Aires announced Tuesday, a further $5 billion would be obtained by cashing in the bonds that it accepted in return for the 51% stake seized by Argentina in 2012.

Brufau said proceeds from the YPF settle-ment in addition to the possible sale of its YPF stake and the disposal of its liquefied natural gas assets means the company will help fuel new growth, by acquiring new upstream assets.

Repsol is looking to invest more in upstream assets, he said, with further funds available from the sale of its LNG business to Shell at the start of the year for $4.1 billion and the possible sale of its 30% stake in gas company Gas Natural Fenosa.

Brufau said the company could consider buying a small or medium-sized company to expand its upstream footprint, with a focus on OECD countries.

Brufau said that the US and particularly Canada seemed to offer opportunities, with-out elaborating.

“We generally need to change the profile of our portfolio,” Brufau said, while also elimi-nating the possibility of re-investing in Argen-tina for the foreseeable future.

Production growthThe company on Tuesday said its fourth-

quarter 2013 production fell 7.5% year on year to 321,000 b/d of oil equivalent, as shortfalls in Libyan and Gulf of Mexico produc-tion offset increases from new startups.

Brufau said Repsol expects an annual pro-duction growth rate of 7% in 2014 due to new output in Brazil, Russia, the US and possible start-ups in Venezuela and Peru.

In Brazil, the company said it sees the net contribution of the Sapinhoa field rising to 15,000 b/d of oil equivalent in 2014 from 4,000 boe/d in 2013.

“The first well is behaving very promising-ly, producing more than expected. Last week we connected the second well and it is pro-ducing right now 33,000 boe/d,” Brufau said.

“The next two wells are expected to be connected in March and in May, with the first FPSO [floating production, storage and offloading vessel] reaching plateau by June,” he added.

Brufau said a second FPSO is already in

Brazil and will be producing and ramping up before year-end.

In Russia, the company said it sees higher average production from the SK field, while in the US, it sees greater output in 2014 from the Mississippi Lime field, without giving fur-ther details.

Otherwise, the company said it could see first production from Venezuela’s joint-venture with Italy’s Eni and state-owned PDVSA at the Perla field as well as possible production from Peru’s Kinteroni at the end of the year.

The Perla gas field in Venezuela, where it has a 32.5% stake could be producing 150,000 Mcf/d by the end of this year, Bru-fau said, rising to 450,000 Mcf/d next year.

Meanwhile, Brufau also hinted produc-tion from Kinteroni in Peru could start within this quarter as a stalled agreement with partners in the Camisea LNG plant could finally be signed.

Repsol would receive net production of 9,000 boe/d from the field, he added. How-ever, Brufau warned that the 7% growth target was also dependent on production from Libya, which was halted for more than 100 days dur-ing 2013 and already been intermittent so far this year.

So far in 2014, 15 days of production have already been lost, the company said.

The company has accounted for a number of possibilities for Libyan outages, Brufau said. If production from Libya were zero for the rest of the year, the upstream growth would be trimmed to a 4% or 5% increase, he said, but were Libya to produce fully all year, the rise in the company’s total output could be 11%.

In the downstream business, Brufau said he saw some recovery from a very weak 2013 as heavy-light spreads are set to widen and margins improve amid rising demand.

The company said that the LPG and trad-ing businesses had performed well, as had new conversion units at Cartagena and Bil-bao. — Gianluca Baratti

Repsol eyes acquisitions after YPf dealRemaining stake could be sold for $1.5 billion


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London—Denmark’s DONG Energy believes it is free to pursue its strategy of increasing oil and gas output as it looks to put its share-holder dispute with Goldman Sachs behind it.

DONG announced ambitious plans last year to more than double production to 150,000 b/d of oil equivalent by 2020, but the company’s future was thrown into doubt after Goldman Sachs and two Danish pension funds took a major stake in the company.

In protest, a party in Denmark’s ruling coalition left the government and public oppo-sition to the investment bank’s role in DONG remains fierce.

The company itself was shocked at the degree of opposition to the deal which came despite final parliamentary approval to allow the US bank to pay DKr8 billion ($1.5 billion) for an 18% stake in the company, according to DONG spokesman Karsten Anker Petersen.

But with the appointment last week of new Goldman Sachs director Martin Hintze, approval of the deal by shareholders and par-liament having earlier voted its support, the company could now put the public debate in Denmark behind it, the spokesman said.

“All the crucial decisions have been made now,” he said, adding that the uncertainties hanging over the group had now been removed.

“It’s not pleasant for an organization like ours to be in the middle of this political tur-moil. There’s been a lot of media coverage. The process took a little longer with more turmoil than everybody expected, but we can

now focus on the strategy we published last year,” Petersen said.

DONG says it is already well on its way to achieving its production growth targets.

In 2013, DONG produced 87,000 boe/d from its fields in the North Sea and interests in the Middle East, a 12% increase on the previous year.

The group says it is well-positioned to achieve a nearer-term production goal of 130,000 boe/d by 2016.

The Syd Arne field offshore Denmark pro-duced its first oil from the phase 3 develop-ment in November, while first production from the Laggan-Tormore gas fields in the UK West of Shetland area is expected in the second half of 2014.

DONG will also be boosted by a produc-tion start-up from the Hejre field in the Danish sector of the North Sea, expected in 2016.

Petersen said that Goldman Sachs was supportive of the production expansion.

“This is still one of our strategic goals,” he said.

“The strategy we presented last year spe-cifically mentioned the goal of 150,000 boe/d and Goldman Sachs clearly stated they are investing in the current strategy, so we are going forward and its still our goal to realize that production in 2020.”

Trouble ahead?But potential further turbulence lies ahead.Danish political experts said that, with the

Socialist Peoples’ Party having abandoned the government, the coalition could stagger on for

a while but fall before the next election.And even if it doesn’t, a new government

will almost certainly be installed when Den-mark goes to the polls—at the latest by Sep-tember next year.

The DONG shareholding furor hasn’t helped its standing among the Danish general public either.

A national poll in January found 68% of Danes were against the Goldman Sachs deal. There have been street protests and around 200,000 signed a petition against it going ahead.

Some of the Danes’ strong opposition to Goldman Sachs springs from ideological oppo-sition in tandem with fierce protective attitudes concerning their national oil and gas champion.

“It’s not been a good situation for the government because the general opinion of the people is that Goldman Sachs should not be involved in the Danish oil and gas [sector],” said the CEO of a major Danish energy asset holder who did not want to be named. “There are many misunderstandings of the situation.”

Most analysts agree that, even when the current government falls, the next one—almost certainly a center-right coalition—is highly unlike-ly to re-examine the deal or even reverse it.

“I would be very surprised because most of the politicians are in favor. There are only about 20% who are not in favor. A change in government won’t affect the deal,” said ana-lyst Thomas Storgaard at Nykredit.

Others broadly agree, but doubts remain.“It’s a done deal. But at the same time

no-one really wants to say that it is,” said SEB analyst Ebba Lindahl. “There are no obvious obstacles left, but politics is always politics.” — Patrick McLoughlin

DONG eyes growth after Goldman crisisDanish producer to refocus on output targets

South Sudan removes upper Nile oil ministerJuba—South Sudan’s President Salva Kiir has set aside the appointment of the Upper Nile state’s oil minister Francis Ayul, state-owned South Sudan Television, or SSTV, reported Wednesday.

The national broadcaster said Kiir issued “a republican order for cancellation of the Gubernatorial decree issued by the Governor of Upper Nile State appointing the state min-ister of petroleum and mining.”

Kiir did not give a reason for his action.Upper Nile, located on the border with

Sudan, is the only state pumping after pro-duction in neighboring Unity state ground to a halt after fighting began in South Sudan two months ago, forcing the government to cut production by about a fifth to 200,000 b/d.

A week ago, the Paris-based Sudan Tri-bune reported South Sudan’s oil minister Stephen Dhieu Dau warning that the current conflict between rebels and the government, which erupted on December 15, 2013, could hit oil production. — Moyiga Nduru

ment and construction contracts, both to South Korean companies, are an $894.4 million award to Samsung Engineering to be completed within a 30-month period, and an $818.2 million award to Hyundai Heavy Indus-tries for completion within 28 months.

They were respectively awarded under the North and Center DGS tenders, two out of three held in connection with plans by a consortium led by Italy’s Eni to develop the Zubair field.

The approval comes a day after Eni’s CEO Paolo Scaroni reportedly threatened to leave the Zubair project if contracts for the develop-ment continued to be held up by red tape. Earlier in the month, Scaroni said Eni’s invest-ment in the oil field project was suffering set-backs due to local bureaucracy that is among the ‘most complex on the planet’.

“This is for the Zubair field. It took more than six months to approve this,” the deputy director general of Iraq’s state-owned South Oil Company, Hayan Abdul Ghani, told report-

Sonangol to exit Iraq over security woes...from page 1


ers on the sidelines of the Iraq Energy Proj-ects Conference in Dubai.

The third contract required more work on the price, he added.

“These contracts include a new philoso-phy of extracting the oil and gathering and treating the oil. It is not a refurbishment of the existing facilities. It is degassing, some gas treatment and water injection as well. It is complex,” Abdul Ghani said.

Eni officials declined to comment.Eni’s partners in the Zubair technical

service contract are the US’ Occidental Petroleum, Korea Gas Corp. and Iraqi state-owned Missan Oil Company. Eni said on February 13 that is was pumping about 320,000 b/d of oil from the Zubair field and its on track to reach a target of 400,000 b/d by year end.

A July 2013 amendment to the original Zubair contract signed in 2010 has set target plateau output from Zubair at 850,000 b/d, down from 1.2 million b/d. — Staff reports


Newfield expects to double Anadarko Basin outputHouston—Big US onshore unconventional oil operator Newfield Exploration expects to double its production this year in the Anadarko Basin of Oklahoma, which the Houston-based company views as its fast-est-growing region.

“Well performance has been exceptional” in the basin’s assorted plays in recent months, Newfield Chief Operating Officer Gary Packer said during the company’s quarterly earnings conference call on Wednesday.

Houston-based Newfield’s net produc-tion from the Anadarko Basin totaled about 19,500 b/d of oil equivalent in 2013, and the company expects to produce more than 39,000 boe/d this year from the basin, where it has more than 225,000 net acres, it said in a late Tuesday statement.

Newfield has allotted $700 million of its $1.6 billion spending plan million this year in the Oklahoma basin where it operates eight rigs in its South Central Oklahoma Oil Province (SCOOP) and STACK plays. Its STACK acreage is located in western Oklahoma, in Canadian, Kingfisher and Blaine Counties, slightly northwest of SCOOP which is south of Oklahoma City. Both plays offer a series of “stacked,” or layered, geologic horizons.

For SCOOP, whose oil window is located at depths of 12,000-14,000 feet and the gas window at 14,000-16,000 feet, “ninety-day production rates are higher than 60-day rates,” Packer said, although typically wells show just the reverse performance with out-puts declining over time.

And in STACK, “30-, 60- and 90-day rates are very healthy,” he said. “We had eight wells under our belt at year-end and are early at optimizing our best well completion practices.”

Newfield unveiled STACK last November.“We know our returns will improve with

time and continue to drive efficiencies in our programs,” said Packer, adding current savings gained from well efficiencies have

been ploughed back into “more aggressive completion designs, resulting in better over-all well economics.”

At STACK, located at depths of 8,000–11,000 feet, the company has tested well spacing in the the Upper Meramec and Woodford Shales, and has plans to test the Lower Meramec in the second quarter as well as other prospective geologic zones on the acreage, he said.

“In the next two years, we will have a better handle on well spacing” in the basin, said Packer.

Another large operation for Newfield is located in Utah’s Uinta Basin, where the company will focus on an ongoing water-flood in the Greater Monument Buttes and assorted plays in the Central Basin. In the Central Basin, the second of a planned 14 super-extended lateral wells are drilling, the company said in its latest presentation. Super-extended laterals are extensions of a well’s horizontal leg that run to about 9,000-10,000 feet in length.

Meanwhile, since late 2013, Newfield has awaited completion of a large, third-party field gathering system upgrade in the SCOOP area. Recent completion of the system will permit Newfield to increase net sales by roughly 4,500 boe/d.

Current net production for Newfield in SCOOP and STACK is shortly anticipated at 31,000 boe/d.

While the upgrade was completed about six weeks late, the company said the delay should not negatively affect Newfield’s full-year guidance.

Newfield’s net production in the fourth quarter of 2013 was 142,000 b/d of equiva-lent oil, of which 24,500 boe/d was from international businesses that are classified as discontinued. In Q4 2012, Newfield’s pro-duction totaled nearly 131,000 boe/d, includ-ing international operations. — Starr Spencer

Bogota—Colombia’s state-controlled Eco-petrol reported Tuesday that production for the fourth quarter of 2013 averaged 779,400 b/d of oil equivalent, up 2.3% from 762,000 boe/d pumped over the same quarter a year ago.

But Q4 output was down 2.6% from the 800,400 boe/d the company produced in the previous quarter ended September 30.

Ecopetrol, which is 88.5% owned by the Colombian government, attributed the quarter-on-quarter fall to several factors including lower throughput on the main Ocensa crude oil pipeline, the end of a 11,300 b/d pur-chase agreement with Occidental Petroleum, and a drop in crude exports to Ecuador.

Like all oil companies operating in Colombia, Ecopetrol was also affected by an increase in attacks on drill crews, pipelines and engineering and construction personnel by leftist guerrillas. A total of 225 such inci-dents were reported in Colombia over 2013, an increase of 49% from the 151 attacks in 2012, according to Bogota-based security consultant Orlando Hernandez.

Over the year, 16 oil field workers were kidnapped, many of them working on the Bicentennial pipeline whose first 140,000 b/d phase opened last fall. Ecopetrol owns a majority stake in the line, which is designed to ease pipeline bottlenecks.

For the full year, Ecopetrol’s output aver-

aged 788,000 boe/d, a 4.5% increase from the 754,000 boe/d it produced in 2012.

The company also reported that proven hydrocarbon reserves as of December 31 stood at 1.972 billion boe, a 5.1% increase from the 1.877 billion boe at the end of 2012.

Slow growth in new crude and natural reserves booked by Ecopetrol and other companies exploring in Colombia has been a source of worry for government officials.

But on the bright side, Ecopetrol reported eight discoveries from its exploration program in 2013 and a 44% success rate in its explo-ration wells drilled.

Ecopetrol continued to focus on Asia, selling 44% of its total crude oil exports of 457,100 b/d to China and other Asian buyers, up from 28.7% of total exports of 456,500 b/d over the same quarter in 2012.

Crude sales to US Gulf Coast refineries on the other hand, continued to decline as a percentage of the whole, dropping to 33% over the quarter, down from 36% in Q4, 2012.

And out of Ecopetrol’s combined sales of 935,800 boe/d of crude oil, oil products and natural gas in Q4, exports accounted for 58%, with the rest to the domestic sector and coun-tries in the free trade zone.

Heavy crude as a percentage of the total basket of crudes sold also continued to rise, reaching 57% in Q4, up from 53% in the same quarter the previous year.

On the refining side, Ecopetrol expects to fully start up its 165,000 b/d Reficar refin-ery near Cartagena in 2015, which will be able to process some of the heavy crudes it now exports.

Construction on the $6.47 billion project has been delayed by labor problems. But par-tial start-up is now set for later this year, with the refinery expected to run at 97% capacity once it goes into full commercial operations.

Ecopetrol’s other major refinery at Barran-cabermeja meanwhile, operated at an average utilization rate of 74% in Q4, because of an ongoing modernization project at the refinery and partial turnaround.

Crude throughput at the 250,000 b/d Barrancabermeja refinery averaged 205,600 b/d in Q4, down 7.8% from 223,100 b/d in Q4, 2012.

A 42,000 b/d crude distillation unit under-went a 10-week maintenance shutdown, dur-ing which it was also revamped to be able to process heavier crudes. The unit restarted on November 29.

Ecopetrol reported a sharp drop in net income for Q4 to Colombian Peso 2.426 tril-lion ($1.2 billion) down 33% from a profit of Peso 3.62 trillion posted for the year-ago quarter. The company blamed part of the decline in profits to a $3/b fall in the sales price of its crude oil basket.

Total sales revenue totaled Peso 17.96 trillion for Q4, up 1.1% from Peso 17.76 tril-lion in the same quarter in 2012. — Chris Kraul

Ecopetrol’s production rises on yearCrude sales to Asia shoot higher, drop to the US

THE AMERIcAS


Peru sells ethanol into Brazil after Europe price fallMontreal—Anhydrous ethanol from Peru is soon to head to Brazil, several sources said on earlier in the week, including a 7,000 cubic meter cargo recently booked for March shipment into Itacoatiara port in Amazonas state in North Brazil.

Freight inquiries from Paita in Peru to Brazil were received for parcels ranging from 7,000 to 11,400 cu m loading in March to head to the ports of Itacoatiara (Amazonas) and Santos (Sao Paulo) by trading houses Bunge and Tricon, according to a report from Swiss ship broker Pole Shipping.

Traditionally, Peru exports almost all of its domestic production to Europe as it benefits from duty free access to the European mar-ket. In 2013, Peru exported 104,000 mt of ethanol, with 70% of it going to Europe.

However, the recent plunge in European ethanol prices triggered the interest of sellers of ethanol from Peru to look for other destina-tions, such as Brazil. “We started to receive offers from Peru last week, as European pric-es plummeted,” said a Brazil-base trader.

European ethanol hit a 45-month low of Eur442/cu m (US$608/cu m) FOB Rotterdam on February 19 as a combination of ample supply and limited seasonal demand sent prices 35% off their 2013 highs, according to Platts data.

Peruvian ethanol holds an advantage in Brazil over US material on the specifica-tion side, since it meets the EN spec, which meets maximum water requirements for Bra-

zil. Product from the US has to be produced at a tighter spec than usual and incurs a pre-mium over local prices.

In Brazil, soaring demand and increasing concerns with the 2014/15 sugarcane har-vest and a possible late start to the season are supporting higher domestic prices and prompting imports on fears of shortage.

On Monday, domestic ethanol prices in Cen-ter South Brazil hit their highest levels in almost three years, with hydrous reaching R$1,650/cu m (US$705.39/cu m) ex-mill Ribeirao Preto basis—the highest since April 21, 2011, when prices hit R$1,700/cu m. Meanwhile anhydrous ethanol surged to R$1,600/cu m, the highest since May 10, 2011.

Kingsman, a unit of Platts, estimates that Brazil’s stocks of ethanol by March 31 should be at 400 million liters of hydrous and 760 million liters of anhydrous, a tight scenario if the harvest does not start by April.

Domestic sales of hydrous in January totaled 1.27 billion liters, the highest since June 2011, when 1.3 billion liters were sold, according to the latest data from UNICA. Anhy-drous domestic sales were 844 million liters, the highest since August 2013, when 931 million liters were sold.

So far this year, Brazil has already import-ed 38,000 cu m of US ethanol into Northeast Brazil in January, and Kingsman is tracking some 107,000 cu m set to enter Brazilian ports in February with the majority of it going to Center South Brazil. — Beatriz Pupo

they are producer, is producing from one play and that play is consistent and over time the testing results might be the same.”

Gerard said he hoped that regulators would work with API members who are devel-oping best practices on testing and classifica-tion procedures.

“Our companies know what they have. We’ve been testing this for years,” he said. “We need to sit down with the administrator and seek clarification on what they exactly would like us to do. I would hope it’s much more collaborative process.”

Rule delayAlso at the hearing, lawmakers pressed

rail regulators on why they are taking so long to issue new tank car standards that could make crude-by-rail shipments safer.

Though the US rail industry has since 2011 urged the DOT to adopt tank car standards that are more stringent than current regulations, the agency has yet to officially propose any new rules, leading to frustration among shippers that the cars they are buying now may not be compliant with future safety requirements.

“People need certainty on what to order, [or] people aren’t going to make the invest-ments in safer cars, and they’re going to keep running these crummy cars out there,” Representative Peter DeFazio, an Oregon Democrat, said.

PHMSA’s Quarterman said her staff is currently drafting a proposed rule, but she declined to commit to a specific deadline beyond “as soon as possible.”

“The staff of PHMSA and [the Federal Rail-road Administration] have been in sequestra-tion over the last several weeks drafting the terms of a notice of proposed rulemaking,” Quarterman testified. “We are very close in our drafting, but there are processes that fol-low our process. The final rule will depend on the comments we get back.”

In response to several crude-by-rail accidents over the last year, the PHMSA is currently weighing what safety measures to require in new tank cars that carry crude oil, as well as whether to require the phasing out or retrofitting of older, legacy DOT-111 cars.

Quarterman declined to elaborate on what the potential rule would contain. She explained that her agency has received more than 100,000 comments on tank car stan-dards that it is processing.

And she emphasized that the rule would cover more than just tank car standards.

“We need to prevent derailments,” Quar-terman said. “Getting a new tank car is not a silver bullet. Tank cars are designed for nor-mal operating conditions. They are not built to withstand 40-, 50-, 60-mile-per-hour derail-ments. This is one piece of the mitigative puzzle we need.”

Oil industry questions Bakken crude testing order...from page 1

THE AMERIcAS

The Association of American Railroads, which represents the US railroad industry, had developed in October 2011 its own voluntary tank car safety standards, dubbed CPC-1232, that trump the current DOT-111 regulations.

But AAR now thinks the CPC-1232 specifications are not sufficient, association President and CEO Ed Hamberger said at the hearing, likewise urging PHMSA to speed up its rulemaking.

“We believe it can be improved upon,” Hamberger said. “We believe it should have thicker steel shells, outer jackets, thermal wrapping, full-height head shields. We urge PHMSA to move quickly on its rulemaking. The existing legacy cars need to be retrofitted or phased out of service.”

Safety delaysThe AAR last week announced a series of

voluntary safety measures to prevent crude-by-rail accidents, including lower speed limits in urban areas and the use of rail traffic rout-ing technology.

The steps were unveiled under an agree-ment with the DOT, after Transportation Sec-retary Anthony Foxx had asked the railroad

and oil industries to develop safety recom-mendations to prevent derailments, spills and explosions of trains carrying crude, especially volatile Bakken oil.

In an interview on “Platts Energy Week” scheduled to air Sunday, Hamberger acknowl-edged that the measures could cause some initial delays in shipments.

“I don’t know about the cost, but it clearly will have some delay on the entire network,” he said. “Our members have been modeling that. But we think that trade off at this point is worth it. As we replace that fleet with new, robust tank cars, we believe we’ll be able to get the speeds back up to normal.”

“Platts Energy Week” airs on Sundays in Washington on WUSA, a CBS affiliate, and in Houston on KUHT, a PBS affiliate, as well as on other PBS stations in the US. The program is also available on the web at www.plattstv.com.

At the hearing, FRA Administrator Joseph Szabo said the DOT is also working with the American Short Line and Regional Railroad Association on similar voluntary measures. He said short line railroads have agreed to speed limits of 25 mph or lower when carrying crude, and some of the larger short lines are inter-ested in signing onto the AAR agreement.

The ASLRRA could not be reached for comment. — Herman Wang


DOE Weekly Stocks Summary

2/21/14 2/14/14 2/22/13

District 1

Crude 9.900 10.236 11.798Conventional Mogas 8.098 9.031 9.351Blend Components 53.111 53.981 50.445Kero Jet 9.293 9.022 9.312Dist >500 ppm 8.791 9.200 14.497Dist <15 ppm 18.091 17.572 20.633Dist >15<500 ppm 0.610 0.772 0.771Distillate 27.492 27.544 35.901Resid 7.066 6.992 8.085

District 2


District 3

Crude 177.667 176.120 174.582Conventional Mogas 11.529 12.226 17.074Blend Components 65.975 64.767 58.433Kero Jet 11.283 11.205 13.958Dist >500 ppm 5.584 5.503 4.573Dist <15 ppm 33.511 33.872 33.375Dist >15<500 1.753 1.260 2.383Distillate 40.848 40.635 40.331Resid 23.429 23.509 21.038

District 4


District 5


Total US


(numbers in million barrels)

Gas is winner of global shale revolutionAs shale oil augments global production, cheap gas is the prize

Houston—Shale oil is helping augment total global production, particularly in the US, but natural gas from shale is really the winner of the unconventional resources revolution in worldwide terms, a top oil analyst at invest-ment bank Credit Suisse said Tuesday.

“Shale is really a gas revolution,” Ed West-lake, the investment bank’s co-head of global oil and gas research, said during the latest of its periodic conference calls on the state of worldwide shale development.

“With shale oil we only increase the world’s reserves from 50 to 60 years,” West-lake said, citing figures from the US Depart-ment of Energy’s statistical arm, the Energy Information Administration. “With gas from shale, the world [reserves jump] from 60 years to 120 years. And, adding in things like hydrates, the world has several hundred years or more of gas.”

Oil markets, while benefiting from incre-mental oil released from shales, will “remain reliant on access to the Middle East,” he said.

“Cheap gas is really the prize energy con-sumers should focus on, and that will raise risks to things like LNG prices long-term,” said Westlake.

As a result of the ongoing shale revolution, which has been in progress for a dozen years now, onshore will continue as the area of fast-est capital expenditure growth, he added.

However, in US gas shale activity, “we’re surprised [that] we’re not hearing about much incremental drilling despite the improvement in gas prices,” Arun Jayaram, the investment bank’s research analyst for US exploration and production, said.

After gas prices largely stayed below $4/MMBtu the last couple of years, an early and brutally cold, snowy winter season in the US has pushed up NYMEX front-month gas prices as high as $6/MMBtu.

Even so, “only one producer thus far has increased activity,” Jayaram said, adding big unconventional resources producer Chesa-peake Energy has moved to nine rigs from seven in the gassy Haynesville Shale in North-west Louisiana, said to be one of the US’ largest gas fields. The company unveiled it as a commercial play in 2008.

And the “only company that expressed the potential to add rigs was...Southwestern Energy, [whose CEO is] contemplating add-ing one or two rigs in the Fayetteville Shale” in Northwest Arkansas, which it pioneered, he said.

In addition, several key themes emerged at Credit Suisse’s recent large annual energy conference in Vail, Colorado, Jayaram said.

First, a handful of core plays such as the Bakken Shale in North Dakota/Montana, the Eagle Ford Shale in South Texas, the Niobrara Shale in Colorado, the Permian Basin in West Texas (all predominantly oil plays right now, although they also produce varying amounts of gas), as well as the gassy Marcellus Shale in Pennsylvania and the liquids-rich Utica Shale in Ohio, remain key plays that offer the best returns, Jayaram said.

In addition, operators continue to show optimism over downspacing—that is, increas-ing the number of wells in a given acreage space, he said. That practice “could effective-ly increase the economic potential of a play by a factor of two or three,” he added.

Plays to watchBut among unconventional resource plays,

“the big handover we have to watch this year and next is the handover of production growth from the Bakken and Eagle Ford Shale to the Permian,” where production growth has been slow despite prolific drilling.

Even so, Permian-watchers say that cur-rent output of around 1.4 million b/d of oil is expected to start to climb at a more rapid pace in the near-term, with an expected flow of initial public offerings starting this year that will allow smaller companies more access to capital. This will allow them to drill the more expensive horizontal wells that eke out more production. Typically, smaller private companies have drilled less-produc-tive vertical wells because they are cheaper, but their outputs do not result in large pro-duction growth rates.

Besides the Permian, the “next genera-tion” plays to consider are the South Central Oklahoma Oil Province, or SCOOP, pioneered by Continental Resources and now attracting other large operators, and the STACK play, also in Oklahoma, unveiled late last year by Newfield Exploration, said Jayaram.

On the other hand, other Oklahoma plays may not be working as well as initially believed. Oklahoma City-based Devon Energy is pulling back in the Mississippi Lime play, for example, which also spans Kansas, “cit-ing more complex and varied geology,” said Jayaram. Fort Worth, Texas-based Range Resources, which pioneered the Marcellus Shale, is dropping down to a single rig in the play, he added. — Starr Spencer

MARKETS & DATA

Platts Podcast

North Sea crude dented by West African imports, less Asian demandPlatts’ crude oil team discusses the reasons behind the weak North Sea crude oil market, and look at the developing relationship between Brent crude futures and the physical market.

http://plts.co/1doitKQ


International cracking margins

ARA Brent Singapore DubaiItaly Urals-2

-1

0

1

2

3

4

3.33

0.26

2.492.13

-0.31

3.06

0.82

-0.56

3.48

-0.22

-1.58

3.11

Weekly Refinery Margins ($/b)

Refinery margins are derived from a weekly average of Platts daily spot assessments, and coking and cracking netbacks. For additional details, please contact Jeff Mower at [email protected].

Source: Platts; Turner, Mason & Company

($/b)

US cracking margins

MidwestWTI

USGCLLS

USACBonny Light

USWCANS

7-Feb31-Jan 14-Feb

0

5

10

15

20

16.5

13.0912.2

6.16

13.76 14.16

8.89

6.77

13.8313.02

11.66

7.18

13.1314.28

5.497.16

US coking margins

MidwestWTS

USGCMars

USACCabinda

USWCANS

0

5

10

15

20

2523.39

7.75

10.51 10.96

17.69

7.78 7

11.49

16.82

7.16

9.3911.3

16.47

9.06

2.13

10.41

21-Feb

($/b)

($/b)

7-Feb31-Jan 14-Feb 21-Feb

7-Feb31-Jan 14-Feb 21-Feb

Platts pricescore

Week ending Feb 21 Feb 14

Crude oil ($/b):Dated Brent ($/b) 109.47 109.20Dubai (First month) ($/b) 106.57 105.07WTI (Cushing)(First month) ($/b) 102.97 100.20ANS (California) ($/b) 107.57 104.60Mars (MOC) ($/b) 104.12 102.69

Products:

NWE (CIF cargoes)Naphtha (physical) ($/MT) 918.10 908.50Diesel 10PPM NWE ($/MT) 955.40 941.05Diesel 10ppm UK ($/MT) 957.40 943.05Fuel Oil 3.5% ($/MT) 579.65 571.10Jet Kerosene ($/MT) 994.95 983.55

Singapore (FOB cargoes)Kerosene(physical) ($/b) 124.12 122.88Kerosene (paper) ($/b) 123.72 122.27Gasoil 0.5% ($/b) 125.09 123.58HSFO 180cst ($/MT) 617.20 611.84LSWRmixed/cracked ($/b) 105.88 104.40*C&F JapanNaphtha (physical) ($/MT) 933.75 927.48

US Atlantic Coast (Barge)RBOB 87 (cts/gal) 283.47 275.71No. 2 (cts/gal) 308.29 300.25No. 6 1.0%(Cargo) ($/b) 105.10 102.65Ethanol**

US Gulf (Pipeline)Unleaded 87 (cts/gal) 273.02 270.90No. 2 (cts/gal) 292.34 285.58

US Gulf (Waterborne)No. 6 3.0% ($/b) 91.55 90.17

Average settlement prices:

NY Mercantile ExchangeLight Sweet Crude ($/b) 102.53 100.11No. 2 oil (cts/gal) 312.87 302.88RBOB (cts/gal) 282.76 276.03Natural Gas ($/MMBtu) 59.13 49.16

IntercontinentalExchangeGasoil ($/MT) 932.90 921.30Brent ($/b) 109.82 108.80

The averages in this table are the mean of Platts low and high daily quotations, or exchange settlements, calculated on a 5-day week basis, Monday through Friday. Saturdays and Sundays are excluded; *LSWR assessment is FOB Indonesia.**Effective February 21, 2013 the Platts ethanol assessment may be found in the new Platts Biofuelscan.

MARKETS & DATA


To reach PlattsE-mail:[email protected] AmericaTel:800-PLATTS-8 (toll-free) +1-212-904-3070 (direct)Latin AmericaTel:+54-11-4121-4810Europe & Middle EastTel:+44-20-7176-6111Asia PacificTel:+65-6530-6430

Vice President, EditorialDan Tanz

Platts PresidentLarry Neal

Chief Editor: Gary Gentile, [email protected] Editor: Benjamin Morse, [email protected] Oil News: Beth EvansEurope & Africa Oil News: Stuart ElliottAsia Pacific Oil News: James BourneEditorial Director, Global Oil News: Richard SwannGlobal Director, Oil: Dave ErnsbergerEditor Emeritus: Onnic MarashianRegional offices:New York—Janet McGurty; Washington—Herman Wang; Houston—Starr Spencer, Bridget Hunsucker; London—Margaret McQuaile, Robert Perkins; Cape Town—Jacinta Moran; Dubai—Tamsin Carlisle; Moscow—Nadia Rodova, Dina Khrennikova, Rosemary Griffin; Singapore—Mriganka Jaipuriyar, Song Yen Ling; Sydney—Christine Forster; Tokyo—Takeo Kumagai

Vol 92 / No 41 / Thursday, February 27, 2014

AdvertisingTel : +1-720-264-6631

0163-1284ISSN#

Oilgram News is published every business day in New York and Houston by Platts, a division of McGraw Hill Financial, registered office: Two Penn Plaza, 25th Floor, New York, N.Y. 10121-2298.Officers of the Corporation: Harold McGraw III, Chairman; Doug Peterson, President and Chief Executive Officer; Kenneth Vittor, Executive Vice President and General Counsel; Jack F. Callahan Jr., Executive Vice President and Chief Financial Officer; Elizabeth O’Melia, Senior Vice President, Treasury Operations.Platts makes no warranties, express or implied, as to the accuracy, adequacy or completeness of the data and other information set forth in this publication (‘data’) or as to the merchantability or fitness for a particular use of the data. Platts assumes no liability in connection with any party’s use of the data. Corporate policy prohibits editorial personnel from holding any financial interest in companies they cover and from disclosing information prior to the publication date of an issue.Copyright © 2014 by Platts, McGraw Hill FinancialPermission is granted for those registered with the Copyright Clearance Center (CCC) to

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New York—NYMEX April crude settled 76 cents higher at $102.59/b Wednesday, nar-rowing its discount to ICE Brent to a five-month low after US government data showed stocks at the Cushing, Oklahoma, delivery hub fell again last week.

ICE April Brent settled 1 cent higher at $109.52/b. The front-month Brent-WTI spread fell to $6.75/b during the session—its lowest level since October 9, 2013. The spread then settled at $6.93/b.

The spread has been narrowing as stocks leave Cushing through TransCanada’s south-

ern Keystone pipeline link, a 485-mile (780 km) crude line beginning at Cushing and extending south to Nederland, Texas, which began moving oil last month.

US Energy Information Administration data released Wednesday for the reporting week ended February 21 showed Cushing crude stocks fell for the fourth consecutive week, down 1.08 million barrels to 34.79 million barrels. The draw puts stocks at the hub at a 7.16% deficit to the EIA five year average.

Overall, moves in the US crude stockpile were fairly muted last week, with inventories rising just 100,000 barrels to 362.4 million barrels, as imports dropped and refiners upped run rates.

Harry Tchilinguirian, global head of com-modity markets strategy at BNP Paribas, said that the previously-ample stocks at Cushing are predominately being moved to, rather than being consumed on, the Gulf Coast, with consequently limited impact on overall crude stocks.

Indeed, the Cushing draw was somewhat tempered by a 1.6 million-barrel build in stocks in the US Gulf Coast.

“Given upcoming seasonal refinery mainte-nance in March and April and further increases in Lower 48 crude oil production, the recent rate of stock declines at Cushing are unlikely to be sustained and US crude stocks overall may continue to build,” Tchilinguirian said.

Analysts polled by Platts were anticipating a 1.5 million-barrel build in crude stocks for the reporting week ended February 21.

The slight build in total stocks puts crude at a 3.1% surplus to the EIA five-year average, down from 3.6% surplus the week prior. The surplus has narrowed since reaching 13.3% on November 22, 2013.

While analysts were expecting a further drop in refinery utilization rates on continued maintenance, rates actually rose 1.2 percent-age points to 88% of capacity last week.

During that time, maintenance continued at Tesoro’s 166,000 b/d Golden Eagle refin-ery in Martinez, California, after a gasoline unit was shut the week prior, Platts has reported. But Shell had started up an unspec-ified unit at its own, 165,000 b/d refinery in Martinez on February 19. Shell had previous shut an unspecified unit January 25, though it remained unclear whether the two incidents were related.

Marathon Petroleum was also said to have completed planned maintenance at its 522,000 b/d Garyville, Louisiana, refinery, according to an analyst report.

At the same time, imports of crude fell 384,000 b/d to 7.04 million b/d last week and were off by more than 920,000 b/d from year-ago levels, EIA data showed.

A drop in crude imports from Kuwait by 357,000 b/d to 482,000 b/d accounted for the bulk of the total decline. Mexican imports declined 219,000 b/d to 655,000 b/d last week, EIA data showed.

Import levels were expected to have been hampered after vessel boardings in the Hous-ton Ship Channel were suspended for much of last week due to fog.

On February 17, a total of 75 vessels, 53 inbound and 22 outbound, were affected by the suspension. Early Wednesday, how-ever, vessel boardings resumed for inbound and outbound vessels after rain helped to lift the fog.

Imports to the Gulf Coast region fell 150,000 b/d to 3.43 million b/d, while Mid-west imports shrank to 1.82 million b/d from 1.97 million b/d a week earlier.

In products, NYMEX March ULSD settled 2.38 cents higher at $3.1281/gal and March RBOB ended 11 points higher at $2.7992/gal.

EIA data showed that US distillate stocks rose for the first time in seven weeks, up 300,000 barrels to 113.1 million barrels, but remain at a more than 20% deficit to the EIA five-year average. — Alison Ciaccio

crude futures settle higher as cushing stocks fall

MARKETS & DATA

NYMEX crude settle, �rst month

NYMEX natural gas settle, �rst month

($/bbl)

($/MMBtu)

101

102

103

104

102.92

102.2

102.82

101.83

102.59

26-Feb25-Feb24-Feb21-Feb20-Feb

February 26 settle: $102.59, up $0.76

4.5

5.0

5.5

6.0

6.5

6.064 6.135

5.4455.096

4.855

26-Feb25-Feb24-Feb21-Feb20-Feb

February 26 settle: $4.855, down $0.241

What crude & natural gas markets are doing...

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