The 10 OPEC members obligated to reduce oil output under the landmark agreement signed late last year achieved 91% of their required cuts in January, with their production falling 1.14 million b/d from October levels, according to an S&P Global Platts survey released Monday.

Those cuts were, however, offset partly by output gains in Libya and Nigeria, which are exempt from the accord, and Iran, which is allowed to increase its production slightly.

Related: Find more OPEC information in our news and analysis feature.

In all, OPEC's 13 members -- not including Indonesia, which suspended its membership at the group's last meeting -- produced 32.16 million b/d in January, a 690,000 b/d decline from December, the Platts survey showed.

With Indonesia, the organization's January production totaled 32.89 million b/d.

Under the agreement, OPEC pledged to cut 1.2 million b/d from its October output levels for six months starting from January 1 and freeze production at around 32.5 million b/d, including Indonesia.

Eleven non-OPEC countries led by Russia have also agreed to cut output by 558,000 b/d in the first half of 2017.

The survey shows that several OPEC countries covered by the agreement still need to make some progress in lowering output to their allocations, though the overcompliance of Saudi Arabia, Kuwait and Angola helps compensate.

Since the deal covers an average of January to June output, some month-to-month fluctuations are to be expected.

Saudi Arabia has backed up the strong words of its energy minister Khalid al-Falih, who played a key role in negotiating the agreement, with its January production falling to 9.98 million b/d, according to the Platts survey.

That is below its allocation of 10.06 million b/d under the deal, as crude exports declined by more than 500,000 b/d in the month, Platts shipping tracker cFlow showed. It is also the first month Saudi production has been below 10 million b/d since February 2015, according to the survey archives.

Falih in recent weeks had said that the kingdom would "strictly adhere to our commitment" and signaled that it would make deeper cuts in February.

Likewise, Kuwaiti oil minister Essam al-Marzouq, who chairs a five-country committee that will monitor and enforce the production agreement, has said that Kuwait would "lead by example."

Accordingly, Kuwait's production for January was under its quota of 2.71 million b/d, coming in at 2.7 million b/d, a 130,000 b/d drop from December, the survey showed.

Besides Kuwait, the monitoring committee comprises fellow OPEC members Algeria and Venezuela, along with non-OPEC Russia and Oman.

IRAQ HAS WORK TO DO

Algeria is slightly above its quota of 1.04 million b/d, with January production at 1.05 million b/d, while Venezuela also exceeds its allocation of 1.97 million b/d, producing 2.01 million b/d in the month, according to the survey.

Angola is below its allocation of 1.67 million b/d, with January output at 1.63 million b/d, as its crude loadings showed declines in the month.

Iraq, which had sought an exemption from the deal, has the most barrels to cut to reach its allocation, with January output at 4.48 million b/d, according to the survey, while its quota is 4.35 million b/d.

The January figure, however, was a decline of 150,000 b/d from December production, as exports from Iraq's southern terminals showed a significant decline from the previous month's record levels.

Iran, which is allowed to boost production to 3.80 million b/d under the deal, had January production of 3.72 million b/d, a 30,000 b/d increase from December.

Meanwhile, exempt Libya and Nigeria showed increases of 50,000 b/d and 210,000 b/d, respectively, as they continue to recover from militancy-related outages.

Libyan output had reached 715,000 b/d during the month, but frequent power shortages and a fire at the Sarir field caused production to fall towards the end of January, for a full-month average of 670,000 b/d, according to the survey.

Nigerian output saw good signs of recovery after recent attacks on infrastructure in the Niger Delta, as well as the return of key export grade Agbami from maintenance last month, averaging 1.65 million b/d in January.

The Platts estimates were obtained by surveying OPEC and oil industry officials, traders and analysts, as well as reviewing proprietary shipping data.

http://www.platts.com/latest-news/oil/london/opec-jan-crude-oil-output-3216-million-bd-down-26655512

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Frontline cash Dubai crude rose to its highest against the same-month Dubai swap in over three months Monday as demand for medium, heavy sour crudes was expected to remain supported on the prospect of the OPEC output cuts could be more apparent to Asian refiners in the second quarter.

The April cash Dubai was assessed at a discount of 6 cents/b to April Dubai swaps Monday, compared with a discount of 12 cents/b Friday, S&P Global Platts data showed.

The spread was last higher on October 31, 2016 when it was assessed at a premium of 9 cents/b.

During the Platts Market on Close assessment process Monday, Shell was seen bidding for April cash Dubai partials and it traded with Reliance Global at $55.29/b at the end of the MOC.

"Obviously medium and heavy sour is well supported, but light sour and sweet seems to be plenty around," a Singapore-based crude trader said.

Intermonth Dubai crude swaps spreads have also largely remained supported Monday after hitting multi-month and multi-year highs on Friday.

March Dubai crude swaps were assessed at parity to April crude swaps on Monday, while the spreads between April/May and May/June were both assessed in a contango of 2 cents/b, Platts data showed.

On Friday, the March/April crude swaps spread was assessed in a backwardation of 2 cents/b Friday -- the highest since September 30 last year when it was in a backwardation of 10 cents/b, the data showed.

The April/May and May/June crude swaps spreads were both assessed at a contango of 1 cent/b on Friday, the highest since August 31, 2016 and August 14, 2014 respectively.

Traders have said the stronger spreads reflected expectations that OPEC-related production cuts would be felt most acutely in the second quarter as producers look to comply by June 30.

Also reflecting support for the medium, heavy crude market, cash Oman crude was assessed at 56 cents/b above cash Dubai crude on Monday, the highest since December 30, 2016 when it was assessed at a 70 cents/b premium, Platts data showed.

The rise in Dubai crude has narrowed the crude's spread to benchmark Brent sweet crude, opening up options for end-users to seek competitively priced grades from outside the Middle East.

The second-month Brent/Dubai Exchange of Futures for Swaps -- which enables holders of ICE Brent futures to exchange a Brent futures position for a Dubai crude swap -- was assessed at $1.42/b Monday, down from $1.54/b last Friday.

The second-month EFS averaged $1.65/b in January, the lowest since September 2015 when it averaged at $1.54/b.

http://www.platts.com/latest-news/oil/singapore/dubai-crude-cash-spread-to-swap-at-three-month-26655378

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State-owned National Iranian Oil Co, or NIOC has started talks with international oil companies ahead of a new licensing round for Azadegan, one of its prized oil fields, a senior NIOC official said Saturday.

The new bid round will be held before the end of the Iranian year on March 20, NIOC managing director and deputy oil minister, Ali Kardor said in a statement released by the oil ministry.

Negotiations between NIOC and domestic and foreign companies are under way with a view to signing new-style oil contracts. This is after technical and commercial committee of oil contracts has prepared the necessary documents for putting Azadegan out to tender, Kardor said.

"The first list of international companies cleared to bid for oil projects has been announced, and given the request of some companies to completing their data, another list would be also drawn up," Kardor added.

Iran's oil ministry has qualified 29 international companies to bid for upstream oil and gas development contracts on its list. For South Azadegan, NIOC has signed about five memoranda of understanding with international companies to study the large onshore field with a view to bidding on development contracts.

Bid rounds for the development of West Karoun fields -- Yaran and Yadavaran -- will be held once Azadegan is tendered, Kardor said.

NATURAL GAS PRICE STALLS FARZAD-B DEVELOPMENT

Kardor also touched on negotiations with India's ONGC Videsh Limited for the development of the 18.75 Tcf Farzad-B gas field in the Persian Gulf.

"The technical model presented by the Indians is almost finalized, but we have yet to reach agreement on the financial framework because we are at odds over the gas price," he said.

He added that Farzad field would be developed under an engineering, procurement, construction and financing contract in case talks with India did not reach agreement.

OVL, the overseas arm of Indian state-owned explorer Oil and Natural Gas Corp., was prequalified along with 29 other oil companies to bid on the upcoming tenders. It discovered the Farzad-B gas field in 2008, but so far the field has not been developed.

Earlier this month, the company said it was in negotiations with Iran for the field's development rights and had submitted a development plan. India's oil ministry had been hopeful in December that OVL could reach an agreement on gas price formula and a master plan for the development before the end of the Iranian year on March 20.

OVL's $10 billion plan for development of the Farzad-B field includes an accompanying plant to liquefy the gas for transportation in ships. Kardor said Farzad's gas should feed LNG and petrochemical projects.

OIL PRODUCTION AND CONDENSATE EXPORTS RISE

Iran's oil production was 3.9 million b/d, while exports were 2.335 million b/d, Kardor said. Oil production is expected to reach 4 million b/d by March, with the addition of new production from the West Karoun area, adding 40,000 b/d, along with 15,000 b/d from the Azar field and 35,000 b/d from the oil layer of the South Pars gas field.

Condensate production now stood at 550,000 b/d, having been at 325,000 b/d, in 2013, he added.

Iran had been storing around 75 million barrels of condensates in vessels on the Persian Gulf, up until the signing of its nuclear agreement early last year.

"After the implementation of the JCPOA [the nuclear deal], 50 million barrels of gas condensate has been sold," he said. The remaining 25 million barrels is expected to be sold by April, at prices at around $40/b.

http://www.platts.com/latest-news/natural-gas/dubai/iran-to-finally-launch-azadegan-tender-in-march-26655395

Hydrocarbon production from the ‘Golden Triangle’ will peak in 2019 due to the lack of projects sanctioned in recent years, the energy intelligence group Douglas-Westwood said in its DW Monday report.

The Golden Triangle incorporates the deepwater (>500 m water depth) plays of Brazil, the U.S. Gulf of Mexico and West Africa.

According to the report, production data from Douglas-Westwood’s new online analysis tool, SECTORS, shows combined oil & gas production will reach its crux in two years’ time at some 7.1 million barrels of oil equivalent per day (mmboe/d) before declining into the 2020s. This is largely due to Petrobras’ continuing financial and tendering problems in addition to significant delays to large developments in West Africa – notably Bonga South-West (Shell) and Zabazaba (Eni), DW stated.

Outside the ‘Golden Triangle’, deepwater hydrocarbon production triples over the next seven years – rising from 1.3 mmboe/d this year to 3.9 mmboe/d. Of this 2.6 mmboe/d growth, 80% is natural gas. This reflects the increasing diversification of the deepwater sector as operators shift focus towards monetizing gas reserves discovered in recent frontier gas plays.

In the Gulf of Mexico, the larger discoveries in recent years have been in technically-challenging oil reservoirs with higher costs, like the Palaeogene. Operators have therefore focused more on the emerging gas provinces including LNG in East Africa and especially the eastern Mediterranean, where pipeline exports to local markets are possible.

Additionally, Asia – historically a shallow water-producing region – is now seeing an increase in deepwater projects, with CNOOC exploiting fields in the South China Sea and ONGC and Reliance Industries investing in deepwater gas fields in the Krishna Godavari basin, offshore eastern India.

DW said it expect operators worldwide to continue to shift away from the troubled waters of the traditional deepwater areas, seeing non-Golden Triangle output climb further from the mid-2020s. Countries within the ‘Golden Triangle’ will need to take steps to maintain production in the long-term by making the investment climate more attractive.

http://www.offshoreenergytoday.com/dw-og-operators-to-shift-away-from-troubled-deepwater-areas/

State-owned energy giant Qatar Petroleum aims to expand its liquefied natural gas (LNG) assets abroad, increasing its reserves and production capacity, chief executive Saad al-Kaabi said on Monday.

"You will see us going internationally with some of the partners we have in Qatar, this year and next year...We are in growth mode," Kaabi told reporters at the company's headquarters in Doha.

"We will continue to be in growth mode for a while. Some (growth) will be national but the majority will be international."

Kaabi also said supplies of LNG from the United States were not a threat to business and that his company was interested in exploring in the area of Cyprus.

http://www.reuters.com/article/us-qatar-petroleum-idUSKBN15L16M

UK-based energy giant and LNG player, BP reported a slight net profit for 2016, recovering from heavy losses the company logged the previous year.

BP posted a profit of $115 million, compared with the headline loss of $6.5 billion reported for 2015.

Theses figures included a total of $4 billion non-operating charges taken through the year associated with resolution of the remaining legacy of the 2010 oil spill.

BP’s underlying replacement cost profit, the company’s definition of net income, was at $2.59 billion compared to #5.91 billion the year before.

The company said on Tuesday that the 2016 price environment was “challenging” as the average Brent oil price of $44 per barrel was the lowest for 12 years. The Henry Hub gas marker prices averaged $2.46 per million British thermal units and the refining marker margin was also the lowest since 2010, BP said.

In the fourth quarter of 2016, BP’s underlying replacement cost profit fell to $400 million, compared with $560 million expected by analysts but better than $196 million made a year earlier, according to Reuters.

BP said it will balance its books at an oil price of around $60 per barrel by the end of 2017 and expects organic capital expenditure to be in the range of $16-17 billion in 2017.

BP annual earnings dip to 10-year low, warns OPEC cut could affect 2017 production

Perhaps the worst is that BP now says it will need $60 a barrel to balance its books in 2017, up from the $50-$55 it has previously guided

http://www.lngworldnews.com/bp-turns-to-profit-in-2016/

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Norwegian energy giant and LNG operator Statoil reported a 58 percent drop in its adjusted operating profit for the year 2016.

Adjusted earning were at US$4 billion for 2016, down from $9.63 billion in the previous year.

The company’s adjusted earnings in the fourth quarter of 2016 were $1.66 billion, 6 percent down from $1.78 billion in the same period in 2015, attributing the dip to exploration well expenses and the lower European gas prices.

Statoil reported a net operating income of $80 million for the twelve months period, dropping 94 percent from the 1.37 billion the year before. It also reported a  loss of $1.90 billion in the fourth quarter compared to an income of $152 million in the same period of 2015.

The company said in its quarterly report that the result was impacted by $2.3 billion in net impairment charges mainly due to reduced long-term price assumptions.

Eldar Sætre, president and CEO of Statoil said the “result was impacted by the negative result from our international operations due to expensed exploration wells, high maintenance activity and impairment charges,” adding that the company achieved strong results in its improvement programme, saving $700 million above target of $2.5 billion.

Statoil delivered equity production of 2,095 mboe per day in the fourth quarter compared to 2,046 mboe per day in the same period in 2015.

The increase was primarily due to the ramp-up of new fields and strong operational performance. Excluding divestments, the underlying production growth was 2 percent compared to the fourth quarter last year.

Statoil updated its outlook for 2017-2020 period expecting a capital expenditure of around $11 billion for 2017. The company estimates a 4-5 percent production growth in 2017 from 2016, and an annual production growth of around 3 percent from 2016 to 2020.

http://www.lngworldnews.com/statoils-earnings-drop/

European gas traders are once again focusing on exports from its biggest supplier as freezing weather is set to return to the region.

Moscow-based Gazprom PJSC said on Wednesday that it reduced shipments through the Opal pipeline in Germany, which delivered about 15 percent of Russia’s gas exports outside the former Soviet Union last month, following a legal challenge led by Poland. The relatively minor cut rekindled memories of shutoffs during freezing weather eight years ago and helped to push prices to the highest in almost two years.

While the reductions along Opal are equal to just 5 percent of Russia’s overall supplies to the 28-nation European Union, they come as the region faces depleting inventories and the return of a winter cold snap. While Gazprom is able to boost deliveries through Ukraine, the cuts helped heating prices in Europe, according to analysts including BMI Research.

“People react jumpy to Gazprom reducing supplies all the time, often with a valid reason,” said Sijbren de Jong, a strategic analyst at The Hague Center for Strategic Studies. “But here it’s difficult to determine if something more is going on.”

Day-ahead gas on the Title Transfer Facility in the Netherlands, Europe’s biggest market for the fuel, rose 17 percent last week, the biggest gain since April, according to broker data compiled by Bloomberg. The close at 23 euros a megawatt-hour ($7.25 a million British thermal units) was the highest since April 2015.

Gazprom only increased flows through Opal in December after the European Commission eased some limits after years of disputes on the use of the pipeline, which is seen as a threat by transit nations including Poland and Ukraine because it can bypass their roles in transit to western Europe. Poland successfully challenged the commission’s decision and Gazprom returned to using about half of Opal’s capacity from Feb. 1.

Some traders may face a cut in Gazprom supplies down to contractual volumes if they increased orders now, Russia’s Kommersant newspaper reported Thursday, citing people with knowledge of the matter it didn’t identify. The company’s press service declined to comment.

While there’s no substantial risk to Russian gas shipments, or European gas supply as a whole, prices “could rise more aggressively if the weather turns cold over February,” said Christopher Haines, head of oil and gas at BMI Research.

After the worst cold blast in a decade and a warmer than usual start to February, temperatures are expected to fall below the seasonal average throughout Europe. The northwest European average is forecast to be 0.4 degrees Celsius next week (33 Fahrenheit), compared with a 10-year mean of 3.3 degrees Celsius.

European gas storage levels have been drained below 5-year averages after January’s abnormally chilly temperatures. Meanwhile, there has been a dearth of liquefied natural gas imports, with the U.K., Netherlands and Belgium receiving just four cargoes in 2017 through Friday, compared with 13 in the same period last year.

“Higher prices on European benchmarks will pull in more LNG, particularly as Asian prices soften,” Haines said.

The Opal pipeline, which is co-owned by Gazprom and BASF SE’s Wintershall AG subsidiary, runs for 472 kilometers (293-mile) from the arrival point of the Nord Stream link on Germany’s Baltic coast toward the Czech Republic. It has a capacity of 36 billion cubic meters of gas a year, with actual supplies of 20 billion cubic meters in 2016
The EU and Dusseldorf courts handling Poland’s claims don’t disclose hearing schedules. While the procedures may drag on, there could be some interim solution that will allow Gazprom to use more capacity “in emergency situations,” said BMI’s Haines.

https://www.bloomberg.com/news/articles/2017-02-06/gazprom-supply-jitters-roil-gas-market-facing-return-of-freeze

North China's coal-rich Shanxi plans to increase coalbed methane (CBM) output to 20 billion cubic meters (bcm) by 2020, local media reported.

In 2017, Shanxi will accelerate system reform in CBM exploration and extraction, in response to the central government's supply-side reform, said Xu Dachun, director of the provincial Land and Resources Department.

In April last year, the Ministry of Land and Resources delegated part of CBM extraction approval rights to Shanxi. That was the first time the central government delegated CBM extraction approval rights to local government. So far, Shanxi has approved eight CBM exploration projects.

In 2015, Shanxi extracted 10.13 bcm of CBM, including 4.1 bcm from ground-based operations and 6.03 bcm from underground, accounting for 94% and 44.4% of the country's total.

By end-2015, Shanxi's CBM reserves stood at around 560 bcm, accounting for around 88% of the nation's total, official data showed.

http://www.sxcoal.com/news/4551965/info/en

Britain will not be able to inject additional supplies to its largest gas storage site after six of its wells failed tests, delaying a plan to have them back in service by the end of April, operator Centrica Storage Limited (CSL) said.

Concerns about integrity of wells at the Rough site, off England's east coast, prompted Centrica to impose limits last year on how much gas could be stored there as a safety precaution.

Following investigations, Centrica shut down the facility for injections and withdrawals of gas. Withdrawals resumed in December but injections were on hold until April.

"The return to injection operations in 2017 remains subject to successfully completing well testing on all wells and confirmation that Rough can be safely returned to service," it added.

Gas is injected usually in the summer months when demand and prices are low. Britain depends on stored gas reserves to help manage winter demand spikes and to ensure security of supply.

Rough usually provides more than 70 percent of Britain's gas storage capacity. The site is more than 30 years old and repeated outages have highlighted its vulnerability.

In a review by the Competition and Markets Authority last year, CSL said Rough was an ageing asset which had outlasted its original design life of 25 years and that its reliability was likely to worsen over time.

If there is reduced injection capacity over the summer months at Rough, other, smaller storage sites will have to be used.

There could be a risk of low levels of gas in storage for the winter 2017/18 season, traders said. Britain could have to pay for more liquefied natural gas deliveries and imports from Norway and the Netherlands.

Market reaction was muted. The Summer 2017 wholesale gas contract was down 0.55 pence at 45.95 pence per thermo.

CSL said it had completed calliper surveys on 20 out of 24 wells at the site and completed pressure testing on 12 of those 20 wells.

Eight of those 12 passed the tests but two will need further work and will not be able to return to service by April 30.

Four out of the 12 did not pass the tests and will not return to service by that date either, CSL said.

"All 6 wells that are not capable of returning to service by 30 April 2017 have been isolated from the reservoir," the firm said in a statement.

The firm said it is evaluating the consequences of the test results and will provide another market update as soon as it can. CSL is still testing remaining wells.

"The return to injection operations in 2017 remains subject to successfully completing well testing on all wells and confirmation that Rough can be safely returned to service," it added.

Withdrawal operations remain unaffected, CSL said.

http://www.reuters.com/article/britain-gas-rough-idUSL5N1FR17B

U.S. East Coast refineries, which have thrived for a few years on a boom of production from the Bakken shale play in North Dakota and eastern Montana, are increasingly looking abroad to supply their needs.

Last year through November, the region imported 884,000 barrels a day, which would be the highest full-year total since 2011, data from the U.S. Energy Information Administration show. Angola, Nigeria and Brazil have increased shipments to the East Coast this year. Rising supplies overseas made imported oil cheaper than domestic for the first time since 2013, data from the U.S. Energy Information Administration show. Canada is usually the leading importer to the region.

The price switch opened the doors for refineries like PBF Energy Inc., Philadelphia Energy Solutions and Phillips 66 to boost imports, says Andy Lipow, president of Lipow Oil Associates LLC in Houston. He said the new Dakota Access Pipeline, one of the energy projects supported by President Donald Trump, will make the East Coast even more reliant on imports.

The 1,172-mile line developed by Energy Transfer Partners LP may start moving crude June 1, according to a person familiar with the matter. It will connect the Bakken to Patoka, Illinois. Existing pipelines can take oil from Patoka to refineries in the Midwest and on the Gulf Coast, not to the East Coast. The East Coast relies mostly on rail to get Bakken oil.

“When the Dakota Access Pipeline starts, you will see less availability of Bakken in the East Coast and more imports coming,” Lipow said in a phone interview. “It will be more economical to ship Bakken oil to the Gulf Coast by pipeline than rail it to the East Coast.”

Brazilian Oil

Angola, Nigeria and Brazil produce the light to medium grades that make up the bulk of imports in the region, Gurpal Dosanjh, an analyst for Bloomberg Intelligence, says by phone from New York.

“Brazilian production has increased quite a lot because of offshore production,” he said. “We should see these supplies keep coming.”

Tankers carrying 2.5 million barrels of Brazilian oil are on their way for delivery to East Coast refineries, ship-tracking data show. This would be the most since at least 2002, according to data from the EIA. The vessels are set to deliver Sapinhoa, Ostra and Iracema grades into Philadelphia, where refiners including Philadelphia Energy Solutions and PBF Energy Inc. have bought Brazilian oil.

Philadelphia Energy Solutions and Phillips 66 declined to comment on their oil purchases. PBF didn’t return calls or e-mails seeking comment.

Front-month West Texas Intermediate closed at $53.01 a barrel Monday on the New York Mercantile Exchange, up 72 percent in the past year. Prices have held in the $50-$55 range this year since the Organization of Petroleum Exporting Countries and other producers like Russia agreed in November to cut production.

Those higher prices should spur rig counts and boost U.S. production, which may eventually prompt East Coast refineries to import less, John Auers, executive vice president at energy consultant Turner Mason & Co., said in a phone interview from Dallas. If the U.S. implements a border adjustment tax on imports from Mexico, for example, the East Coast refineries would look to domestic supplies again.

“Certainly if a BAT is enacted, that would magnify the decline,” he said. “With or without a BAT, I think the overall imported volume may fall with higher output in the Bakken.”

https://www.bloomberg.com/news/articles/2017-02-06/u-s-east-coast-appetite-for-foreign-oil-strong-as-bakken-dims