China’s refining capacity growth set to slow to 1.5 mil b/d over 2015-2018
China will add a total 1.5 million b/d of primary crude refining capacity over 2015-2018, half the initial projection and indicating slower capacity growth, according to oil research and consulting company JBC Asia. “Instead of 3 million b/d coming online in China by 2018 or 2019, we only expect 1.5 million b/d,” JBC director Richard Gorry said at the Platts Refining Asia conference late last week.
The country is now grappling with overcapacity in its refining sector as oil demand growth in the last two years has failed to keep pace with supply following a decade of aggressive capacity expansions. Refiners have “finally realized they have brought out too much capacity too soon,” Gorry said.
This year, China is expected to bring onstream 600,000 b/d of new capacity, up from nearly 400,000 b/d that started up in 2013. The country has a total refining capacity of 10.7 million b/d as of end-2013, according to JBC Asia’s latest estimate. By slowing down the pace of new capacity expansions, Chinese refiners will be able to keep their utilization rates relatively high while simultaneously avoid flooding the regional Asian market with a glut of exports, Gorry said.
He said that while more exports of oil products from China are inevitable since there is already “oversupply building up” for some products in the domestic market, its refineries have little advantage against others in the region. China has to import more crude for its refining needs and there are currently very few government incentives to encourageoil product exports. And other than competition from major oil product exporters India and South Korea, Chinese refineries — together with Asia as a whole - will face more competition from the Middle East, where its rising exports will make better swing cargoes to demand centers in Europe and Africa.
The Middle East region will turn into a net exporter of virtually every oil product apart from gasoline after 2015, as it adds at least 2 million b/d of new refining capacity over the next 10 years, Gorry said. Given the Middle East’s competitive advantage in geography and in procuring cheap crude for feedstock, Gorry expects it to gradually displace Asia’s role in supplying transport fuels to Europe and Africa.
Overall oil demand growth in China meanwhile, is expected to remain steady in the short term, rising by 4-5% each year to 11 million b/d at the end of 2015, up from just under 10 million b/d in 2012, Wood Mackenzie’s Joel Chow, senior managing consultant for downstream, said at the same conference. The forecast average growth rate however, is slower than the 6% rise in 2011.
US crude output rises again in February; crude flows to Gulf Coast climb
US crude production continued higher in February, reaching 8.033 million b/d, up slightly from January, but significantly higher than the 5.244 million b/d produced five years ago in February 2009, US Energy Information Administration monthly data showed Tuesday.
Gains in US crude oil output has been driven by Texas, where output at 2.92 million b/d reached another record high in February, having more than doubled from just three years ago, and North Dakota. February output in North Dakota at 951,000 b/d was down from a record-high 976,000 b/d in November, as frigid temperatures have slowed growth.
At the same time, movements of crude oil, including tanker, pipeline and barges, between the Midwest and US Gulf Coast also jumped in February, reaching 23.4 million barrels, from 13.44 million barrelsin January. The rise in crude movements in February, up from about 11 million barrels in January 2013, was prompted by the start-up of TransCanada’s 590,000 b/d Cushing Marketlink pipeline — a 485-mile (780-km), crude line beginning at Cushing, Oklahoma, and extending south to Nederland, Texas.
The 400,000 b/d Seaway crude pipeline also runs from the Midcontinent to the Gulf Coast and in late May or June, is set for an expansion that will more than double its capacity to 850,000 b/d. The start-up of the Marketlink pipeline has worked to narrow the Brent-WTI futures spread.
The front-month spread had widened to more than $19/b in November 2013, but as the pipeline began to flow, the spread narrowed to closer to $6.15/b in late February. It was trading at $7.81/b on Tuesday.
Imports of crude into the US Atlantic Coast rose 74,000 b/d to 623,000 b/d in February from a month earlier. However, crude imports to that region have been on a steady decline since falling below the one million b/d mark in December 2011.
Nigerian imports to the USAC, which fell to an all-time low of 34,000 b/d in January were at 38,000 b/d in February. The bulk of the imports from Nigeria headed to Monroe Energy’s 185,000 b/d Trainer, Pennsylvania. The balance went to PBF Energy’s 190,000 b/d refinery in Delaware City, Delaware.
Angola imports to the USAC fell to 36,000 b/d from 58,000 b/d in January, while Canadian imports rose slightly to 290,000 b/d from 248,000 b/d in January.
USAC refiners have increasingly been railing in Bakken crude from North Dakota, displacing imported light sweet barrels, particularly from West Africa. In the USGC, crude imports declined 110,000 b/d from January to 3.549 million b/d in February.
Ecuadorean crude imports into US West Coast fall on strong competition
Imports of Ecuadorean crudes into the US West Coast — specifically California — fell to their lowest in more than two years in February, data published by the US Energy Information Administration showed Tuesday.
Deliveries from Ecuador totaled 3.703 million barrels in February, EIA said, lowest since 3.087 million barrels in January 2012. Strong competition from Canadian imports and Bakken crude railed from North Dakota has curtailed Ecuadorean imports to California, sources said, noting many of those barrels are now going to China and India.
“It is a sea change that has occurred in the market,” said one source. “Peru and Chile are the premium markets and a lot is going East, a lot is going to India at dramatically lower discounts.”
Ecuadorean crude imports to California hit a high of 8.092 million barrels in August 2013. Chinese state oil company PetroChina receives roughly 65% of Ecuador’s crude exports through a crude-for-financing agreement exports Oriente, a 24 API and 1.4% sulfur crude, and Napo (19 API, 2% sulfur), from the port of Esmeraldas to California refiners Chevron, Tesoro, Valero, ExxonMobil and Phillips 66. Prices for Napo have to be steeply discounted to compete in the US West Coast market, sources have said.
“There is more Middle Eastern and Canadian barrels going into the US West Coast,” said a second source. “Ecuadorian barrels are the last barrel in and the first barrels out of the region.” Chevron and Valero have recently imported VLCCs of Iraqi Basrah crude to their California refineries. Basrah has a gravity of 30.5 API and 2% sulfur.
Nigerian crudes begin to rise on increased activity
Nigerian crude differentials were beginning to rise amid strong Asian tender demand and increased spot activity, trading sources said Tuesday. Sources said spot trading was pretty slow last week on the Nigerian June program as traders were awaiting the results of the Asian tenders, and they were also awaiting the new NPPC term allocations.
But with most tenders awarded by now except for Pertamina, activity was gradually improving this week. “All activity was on hold as there were quite a few tenders: IOC, BPCL, HPCL and Pertamina. Now that’s over, cargoes have been offeredwhich they were not before as well as with new contract holders of the NNPC cargoes, it took some time before the NNPC cargoes were allocated and then shown to the market,” said a trader. “So instead of moving slowly, the activity was on hold and it all started to move at once so let’s see whether this strength holds,” the trader added.
Sources also said with improving refining margins, and with demand looking better as more refineries were coming back from maintenance, Nigerian crude differentials were beginning to rise steadily. Sources said Qua Iboe was being offered at Dated Brent plus 3.50/b while Bonny Light was being offered at Dated Brent plus $3.40/b. Sources also said that the rise in gasoline and middle distillate cracks were supporting the Nigerian light sweet crudes along with strong initial demand from India, Indonesia and Europe for grades like Qua Iboe and Bonny Light.
Qua Iboe was assessed at Dated Brent plus $2.60/barrel on Monday, a rise of $0.20/b from Friday last week, Platts data showed. Sources said so far six out of the seven Agbami stems were sold with four heard going toa Brazilian refiners.
Sources said the remaining Agbami stem was being offered as high as Dated Brent plus $1.95/b. The other grade that had sold out for June so far was Usan, with all four stems. “The market is strong on Nigerian grades after having been strong on Angolan grades. Usan is all done indeed and there is only Agbami left which is offered at Dated Brent plus $1.95/b. A stem of Abo and Brass River has sold,”
Eni says Libyan output still down more than 120,000 boe/d
Italy’s Eni still faces serious disruption to its operations in Libya as a result of ongoing unrest, with an impact on production of more than 120,000 barrels of oil equivalent/day, a senior executive said Tuesday.
“The situation is not very good. We are really losing a lot of production. We are losing more oil than gas,” Eni chief operating officer Claudio Descalzi told an analyst briefing. Descalzi said Eni’s Libyan production is currently 135,000 boe/d, compared with a peak in 2013 of 240,000 boe/d and potential output of as much as 280,000 boe/d.
The comments come despite Libyan authorities saying they are moving to end disruptions. State-owned National Oil Co. lifted a force majeure declaration at the port of Marsa Al-Hariga earlier in April and at the Zueitina export terminal Monday.
Descalzi said he hoped the Wafa gas and condensate field, which has been closed due to unrest and supplies most of its gas to the domestic market, will restart “in the next weeks”, reiterating an expectation the company has been voicing for several months.
He repeated earlier comments that Eni is optimistic about Libya in the medium- to long-term, saying: “We are in a transition process. I am sure in the future things will improve.”
Eni is still sending about 7 million cubic meters/day of its local gas production to the domestic market, Descalzi said. Eni was producing some 280,000 boe/d in Libya prior to the country’s February 2011 uprising, of which 115,000 b/d was oil and the rest gas.
U.S. Sanctions on Russia Put Western Oil Companies in Tricky Position
By Charles Kennedy | Tue, 29 April 2014 21:39 | 0
New U.S. sanctions on Russia that include asset freezes and travel bans on several top Russian officials, including Rosneft’s Igor Sechin, are raising the likelihood that Western companies with investments in Russia will be caught up in the economic feud.
BP, in particular, is significantly exposed. It used to be a major owner of TNK-BP, a joint oil venture in Russia, but agreed in 2013 to sell its holdings to Rosneft in exchange for a 19.75 percent stake in Rosneft itself.
Throughout the crisis in Ukraine, BP has maintained its commitment to Russia’s energy sector, and recently reaffirmed that position in response to U.S. sanctions. “We are committed to our investment in Rosneft and intend to remain a successful long-term investor in Russia,” BP said in a statement.
BP is not the only major oil company that stands to lose as a result of sanctions against Moscow. ExxonMobil is heavily invested in developing the Russian Arctic in cooperation with Rosneft. While exact figures haven’t been disclosed, some analysts believe that Russia accounts for 6 percent of ExxonMobil’s total oil production. ExxonMobil has not commented on the latest round of U.S. sanctions.
Standard and Poor’s cut the credit rating of Rosneft after it learned that CEO Sechin was on the list of Russian individuals who were sanctioned. The company’s rating was downgraded to “BBB-“ from “BBB.” The company also lost 2 percent of its value on Moscow’s MICEX index, despite a positive day for other Russian stocks.
By Charles Kennedy of OIlprice.com
by DR. KENT MOORS | published APRIL 29TH, 2014
The spread between WTI and Brent is tightening again.
What’s “the spread?”…
It’s the difference in price between what crude oil futures cost on the NYMEX in New York (the West Texas Intermediate rate) and the rate set in London (the Brent rate).
As of this morning, this spread stood at 7.2% of the WTI rate (the more accurate way to register its impact in the U.S. market).
It had been as low as 3.6% earlier this month, after hitting double-digit levels for most of 2013, when in some cases the spread jumped to over 20%.
Both of these represent oil that is sweeter (with less sulfur content) than 80% of the oil that is traded internationally on a daily basis.
These futures contracts are the principal “paper barrel” benchmarks against which the prices of the “wet barrels” (actual consignments of oil) are determined.
As this spread continues to narrow, it promises to create some direct consequences for investors.
Let me explain why this situation has suddenly changed…
The Battle Between WTI and Brent
Of course, it wasn’t always this way. Before August 2010, WTI would actually cost more than Brent since it was a better quality of crude.
But there were two things that changed this long-time relationship.
The first was that Brent became far more used as a benchmark in most regions of the world. The second was the growing situation at Cushing, Okla.
Cushing is where the WTI daily price is pegged. It is the single largest confluence of crude oil pipelines in the country. That presented a problem: There was consistent inability to move volume out of Cushing, creating a giant glut.
In turn, that glut depressed the price of WTI even more.
As a result, Brent priced at a premium to WTI for each daily session since August 16, 2010, except one.
Therefore, “the spread” for the past forty months has favored Brent and that has led to some rather direct consequences.
For one, it has actually improved the bottom lines of refineries. The rise in the relative cost of imported volume allowed processors to pass on increasing wholesale prices for oil products. The refiners were actually using more domestic production, as the increasing reserves of unconventional oil (tight and shale) came on stream. But given the integrated nature of the global market, the higher prices for Brent allowed for improved refining margins (and thereby profits) domestically.
For another, the upper hand given to Brent also tended to exacerbate its price volatility resulting from geopolitical events. The Arab Spring, Iran, Syria, Ukraine, unrest in Venezuela, and saber rattling from China all magnified Brent’s price given its closer connection to the broader markets.
And as it stands, Brent remains the standard for European usage, while the continent is far more dependent upon imports from precisely those same areas where unrest has been on the rise.
The Ongoing Effect of Swaps on Brent
Then there is the added element of contract swaps.
One noticeable change taking place in the global oil sector, especially over the past three years, has been the increasing use of swaps to facilitate export exposure without requiring the actual transport of oil.
The following example of an ongoing series of actual swaps provides a very good illustration of how this works. LUKoil (OTC:LUKOY), Russia’s largest independent producer/refiner had two needs.
The first was the need to supply a string of service stations acquired on the U.S. East Coast with oil product. The second was to expand elsewhere in the Western Hemisphere.
The initial demand for gasoline and other oil products resulted in short-term interim agreements with Exxon Mobil Corp. (NYSE:XOM) refineries to provide oil products since most of the retail locations they acquired were either Getty or Mobil branded outlets. But the Russian major also needed additional sourcing as it searched to acquire its own processing facilities in North America.
That was secured from Venezuelan state company PDVSA, who also happens to own the CITGO chain (and several refineries) in the states.
But the relationship developed much further into general ongoing contract swaps.
PDVSA was interested in securing end users in Europe, while LUKoil had the same interest in South America. Neither company, however, could absorb the cost of using tankers to move oil across the Atlantic.
Instead, the two companies swapped consignments.
LUKoil would agree to release oil from its storage terminal in the Netherlands to new PDVSA clients in Europe. Meanwhile, the Venezuelan company would release volume to new LUKoil customers in South America. So long as the grade of oil released in both locations was the same, the buyers could care less.
These swaps have been added to the types used normally by oil traders who are acquiring actual wet barrels in various parts of the world. As a result, the international market has become even more integrated, with prices impacted by exchanges taking place well beyond a particular region or domestic demand base.
This development also supported a higher Brent premium over WTI, since it is the benchmark more relied upon to set crude oil prices worldwide.
The End of the Brent Premium
However, we are now seeing a gradual end to the Brent premium, and with it some changes in the domestic market pricing in the US.
One reason for the contraction in this ongoing spread is the end of the Cushing glut.
New pipeline capacity is now online, transporting crude south to the petrochemical complexes on the Gulf Coast. That is beginning to remove the most apparent artificial depressant on WTI, thereby increasing its price.
Second, as I have previously noted, the emergence of U.S. refineries as the leading exporters of oil product internationally has placed a new stage in contract swaps. This involves crack spreads – the difference between WTI and Brent as applied to the differentials among crude and various oil product rates (primarily gasoline, diesel, and low sulfur heating fuel).
Only a few years ago, the expansion or contraction in the Brent-WTI spread would have been viewed as a primary indicator of raw material pricing only. But no longer.
As this spread tightens, it will affect both refinery profits and their competitive positioning for both servicing the rising domestic demand and expanding exports abroad.
I’ll be following this situation as it develops, since there will be some investment plays to make as a result. So stay tuned.
Ministry cites the company’s failure to fulfil its obligations
AFP
Tehran: Iran announced Tuesday that it was cancelling a $2.5 billion (Dh9.2 billion) contract with China National Petroleum Corp (CNPC), citing the company’s failure to fulfil its obligations.
The first phase of the deal was for CNPC to drill 185 wells at the giant South Azadegan field, which straddles the Iran-Iraq border.
But the oil ministry said on its website that only seven wells had been drilled so far under the contract, which was signed in late 2009.
“Due to non-compliance by the Chinese company CNPC, the termination of the contract will be issued,” said Rokneddin Javadi, managing director of the National Iranian Oil Company (NIOC).
China has become a bigger player in the Iranian oil market since Western governments imposed sanctions on Tehran as punishment for its controversial nuclear programme.
Under the South Azadegan agreement, CNPC was to target production of 600,000 barrels per day.
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However, Javadi said that one month after a 90-day ultimatum was issued in mid-February, the Chinese company had taken no action, leading to cancellation of the contract.
Under a separate $1.76 billion agreement signed in January 2009, CNPC and the NIOC are developing the North Azadegan field, aiming to produce 75,000 barrels per day.
The Azadegan field is one of the world’s biggest with reserves of about 42 billion barrels.
Another Chinese oil giant, Sinopec, is developing the Yadavaran field, which neighbours Azadegan.
