IN THE PAST 24 HOURS, THE SAUDI 41-VESSEL FLEET "BAHRI" HAS ADDED ON 3 MILLION BARRELS OF CRUDE OIL. FLEET IS NOW 59% FULL.

@TankerTrackers  

Libya has the potential to upset the OPEC apple cart, and early expressions of high levels of compliance with the cuts agreed by OPEC and associated non-OPEC producers should be taken with a pinch of salt.

According to an interview with S&P Global Platts’ Eklavya Gupte January 24, chairman of Libya’s National Oil Company Mustafa Sanalla is targeting oil output of 1.25 million b/d by year’s end. This target comes with many caveats, including consistent funding from the country’s Central Bank. Given the volatility in Libyan oil output in recent years, it is not a target you would hang your hat on.

“We need some money for a quick restoration of our production,” he said. “The government has promised to give us money to have this amount of production.” He also said he was meeting officials from international oil companies in London with a focus on seeking investment and reconstruction in the country’s oil sector.

Progress has been slow, owing to continued political tensions between Libya’s UN-backed Government of National Accord and the Petroleum Facilities Guards, a militia which controls the bulk of the country’s oil terminals. “I press on my view to restructure and reorganize PFG and to be under NOC like it used to be,” he said. “Others [militias] should join the Libyan National Army. We have to have policies to be able to control them. I am making my uttermost efforts to ensure this,” he said.

Nonetheless, the current trend looks positive. Output has almost tripled since August last year when it was around 230,000 b/d. All the country’s major oil export terminals are currently open, although they are far from operating at full capacity as a result of damage caused after more than five years of civil year.

Libyan oil output was up 40,000 b/d in December on average at 620,000 b/d, according to secondary source estimates, and Sanalla said January production would not be far off NOC’s initial target of 719,000 b/d. Steady gains through the year to 1.25 million b/d would mean the addition of 630,000 b/d from December’s levels. Pre-conflict, Libyan crude oil production was as high as 1.6 million b/d.

The current deficit in the global market is between 700,000-900,000 b/d, which implies a stock drawdown this year of close to 300 million barrels. Large, but not that large when set against OECD commercial stocks that remain above the 3 billion barrel mark.

Based on the forecasts of the International Energy Agency, US Energy Information Administration and OPEC, oil demand growth in 2017 will be around 1.2-1.63 million b/d, but non-OPEC supply returns to growth of 200,000-410,000 b/d and OPEC’s Natural Gas Liquid output — which like Libyan and Nigerian production is not included in OPEC production targets — is expected to rise by 100-350,000 b/d. Increases in Libyan crude production could therefore go a long way to extending the stock overhang, particularly if the US shale rebound proves more extensive than expected.

This possibility makes compliance with the promised production cuts all the more important, both in terms of actual volumes and market sentiment. Although OPEC and its non-OPEC associates are talking the talk, it is still unclear whether they will walk the walk. Some of the minor commitments and early reports of reductions are not far off normal fluctuations in monthly output.

Natural decline, already factored into forecasts, may make up others. The focus should be on export volumes and refinery throughput, as much as total output because variations in Middle Eastern oil for power demand could have a substantial seasonal effect – January and February are on average the two coolest months of the year for Saudi Arabia, reducing air conditioning demand there and more broadly across the region.

http://blogs.platts.com/2017/01/26/libya-opec-wildcard/?hootPostID=decdbc285cafd267811d9c8765304abe

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The National Iranian Oil Company is keen to finalize high-priority oil and gas deals by the end of the current fiscal year in March, including Phase 11 of South Pars Gas Field and a plan to tender the giant South Azadegan Oilfield, NIOC's managing director said on Tuesday.

“The agreement to develop Phase 11 of South Pars Gas Field in the Persian Gulf will be finalized by March," Ali Kardor was quoted as saying by Shana.

NIOC signed a preliminary agreement, worth $4.8 billion, with Total S.A. and China National Petroleum Corporation in November to develop South Pars Phase 11, one of the least-developed phases of the joint field which has been plagued by years of procrastination.

Kardor said that Total and CNPC have conducted the technical studies on the phase and NIOC is close to preparing a final draft of the contract.

"Ninety percent of the work on drafting the contract with Total and CNPC is complete," he said.

"Improving the rate of recovery is the most important aspect of collaboration with Total and CNPC," Kardor said, noting that gas production from Phase 11 will exceed 50 million cubic meters per day in 20 years.

SP Phase 11 holds around 16 billion cubic meters of natural gas and some 834 million barrels of gas condensates, a type of ultra light crude. Oil Minister Bijan Namdar Zanganeh recently said that Total has pledged its long-term commitment to the South Pars project by using its advanced high-pressure boosters in the project.

Iran is developing the giant South Pars field in 24 phases. It is the world’s largest gas field shared by Iran and Qatar, covering an area of 3,700 square kilometers of Iran’s territorial waters in the Persian Gulf.

Azadegan Tender

Asked about NIOC's other priorities, Kardor said the South Azadegan Oilfield will be the first to be offered for tender under the new model of contracts – the Iran Petroleum Contract.

"The oilfield tender is scheduled for the near future," he said without elaboration.

Located 80 kilometers west of Ahvaz in Khuzestan Province, Azadegan holds an estimated 33 billion barrels of oil in place.

The Oil Ministry has issued a list of qualified companies to bid for its oil and gas tenders, but the list will be extended, Kardor said.

Tehran has strongly ruled out bias or favoritism, insisting that all foreign companies will compete for the major energy projects on an equal footing.

Early collaboration with several foreign companies, including with France's Total, Russia's Lukoil and Malaysia's state oil company Pertamina had fueled speculation that selected companies are given a head start in the oil/gas projects.

Pointing to the experience of energy giants such as Total S.A., Anglo-Dutch major Royal Dutch Shell and Japan's Inpex, Kardor said NIOC is making efforts to bring together the three majors to benefit from their capability to develop the Azadegan field.

http://tehrantelegram.com/story-z18135096

Despite near-term headwinds, the long-term future of global liquefied natural gas is positive for participants able to adapt to a more fragmented market, according to Deloitte’s new report “Navigating the new world of LNG.”

LNG players will have to adapt to new and different customer expectations and more short-term and flexible commercial arrangements.

“The transformation of global LNG markets is underway, and the future is expected to look very different from the past and present,” said Andrew Slaughter, managing director of the Deloitte Center for Energy Solutions, Deloitte Services.

In the near term, the industry expects to face headwinds of slowing demand growth, recent and imminent supply capacity expansions that could overtake the pace of demand growth and a lower price environment that challenges the economic viability of new developments, the report says.

“Long-term, strong underlying demand drivers and the opening of new markets could provide substantial opportunity for participants. However, the industry may need to adapt to a more complex market, moving away from high volume, long-term, point-to-point supply arrangements of the past toward more flexible physical supply and commercial arrangements,” according to Slaughter.

The report discusses how these evolving new external parameters will likely drive the emergence of new types of participants, such as financial intermediaries, traders, hub operators and more. These are expected to generate new business models to unlock profit down the value chain.

For the participants who can weather the near-term hurdles, the LNG outlook over the next two decades comprises a rich mix of growth, change, uncertainty, challenge and opportunity.

Natural gas is the fastest growing fossil fuel globally, the report says, benefiting from its flexibility of use in multiple demand segments, its competitive economics and its relatively lower emissions profile. LNG is well positioned to account for a substantial share of this growth, as many markets do not have indigenous or adjacent natural gas resources which can be delivered by pipeline. Increased action around the world to reduce the carbon intensity of economic activity provides additional support for the long-term prospects for LNG.

The report also notes that long-term growth prospects look positive as traditional markets expand, new markets emerge in more and more diverse destination countries, and new technologies and applications, such as in land and marine transport, power generation and others. Growth and diversity of markets could stimulate similar growth and diversity of supply sources, including more geographical variety and a range of liquefaction plant sizes and technologies.

The emergence of new suppliers, new markets, more flexible commercial arrangements and new technologies, all bring new options to participants right along the LNG value chain. From a period of historical development based on a limited number of suppliers, a limited number of large markets, fairly standard commercial arrangements and a small number of technologies, all these elements will likely change significantly over the next two decades.

With change, however, comes uncertainty, but when high-capital projects like large-scale LNG developments face heightened uncertainty, this often increases the risk profile of those investments. Sources of uncertainty include: the pace of recovery in demand growth; the price outlook for oil, which is still linked to a high proportion of global LNG trade; and what will be the impact of U.S. LNG, the new entrant into global markets?

The recent wave of LNG supply capacity expansions, led by Australia and followed by the U.S. has resulted in a capacity overhang, often challenging the viability of existing and new projects, according to the report.

The duration of this period of overcapacity may be extremely challenging for operators and could put at risk the next phase of capacity expansions required early in the next decade.

“Technology marches on, opening up new applications on the demand side and new supply options. Our research suggests that LNG is expected to remain one of the most dynamic segments of the energy industry, as it transforms to take a key role in the 21st-century energy mix,” concluded Slaughter.

http://www.lngworldnews.com/deloitte-changing-lng-markets-suit-adaptive-companies/

European petrochemical end-users are reportedly switching away from maximizing the cracking of LPG as Northwest European propane cargoes reached a 22-month high and the gas becomes uncompetitive versus naphtha as a cracking feedstock.

The CIF NWE propane physical cargo rose $3/mt to a 22-month high of $459/mt Tuesday, while in the paper market the front-month CIF NWE propane swap edged to a 35-month high versus naphtha as it was assessed at 90.03% of the front-month CIF NWE naphtha swap, up from 89.67% the previous day.

The last time the front-month propane swap was assessed higher versus naphtha was February 3, 2014, when it was assessed at 90.97% of the front-month naphtha swap, S&P Global Platts data shows.

It is generally considered that propane stops being attractive as an alternative cracking feedstock when it reaches 90% of the value of naphtha.

Northwest Europe propane prices have been rallying since the end of December as a cold spell across the European continent boosted heating demand for the gas, and the spot propane arbitrage from the US to Europe became increasingly difficult to work.

According to trading sources, at least two petrochemical end-users have been re-selling propane in NWE, preferring to maximize the cracking of naphtha.

"We are starting to see signs of switching away from maximizing LPG," a naphtha trader said.

According to an end-user, finding propane is the main problem.

"Coasters have become too expensive, now [propane] is out of the cracking slate," he said.

Another end-user said that it was more profitable to send propane from the US to Asia than to Europe, and this has left Europe a bit short.

"When [the propane/naphtha spread] is minus $48/mt you can start to see reselling of propane and petchems get a different idea of what they want to crack as feedstock...we are reaching a kind of ceiling," he said.

The CIF NWE naphtha physical cargo gained $3.25/mt Tuesday to be assessed at a 18-month high of $508.75/mt, while the front-month CIF NWE naphtha crack swap strengthened 5 cents/barrel on the day to a nine-month high of 50 cents/b, according to Platts data.

http://www.platts.com/latest-news/petrochemicals/london/petrochemicals-turn-away-from-lpg-as-propane-26647204

Australia's plans for a huge increase in its production of liquefied natural gas are being dealt a big blow by a series of production delays, as energy companies struggle with technical problems and cost overruns.

The country is still likely to become the world's biggest LNG exporter, dispatching about 85 million tonnes a year by the end of the decade, up from 30.7 million tonnes in 2015 and 45.1 million tonnes last year. But the pace of growth is much slower than expected because of snafus and higher-than-expected costs that have delayed plans to start or increase LNG exports from four megaprojects, Gorgon, Ichthys, Prelude and Wheatstone, all along or off the coast of northwest Australia.

Now at least three of them, Shell’s Prelude floating LNG production vessel, Inpex’s Ichtys project, and the expansion of Chevron’s Gorgon operation, won’t begin exporting until 2018 or even later, rather than 2017 as previously planned, according to several sources with knowledge of the matter.

Chevron, Shell, and Inpex would not comment on potential delays.

It should all be a boon for other suppliers of LNG to Asian buyers, such as utilities in the region. These suppliers can also benefit from higher prices.

Traders said that the beneficiaries include U.S.-based Cheniere Energy with its facility at Sabine Pass in the Gulf of Mexico, and global energy giant Exxon Mobil with its production in Papua New Guinea.

Making matters even worse, the producers in Australia are having to go to their rivals to fulfill contracts.

"The Australian producers have supply commitments, so when there's production delays they have to buy these supplies from competitors in the spot market," said an LNG trader involved in such deals who was speaking on condition of anonymity.

"These guys will make a lot of money filling the gap of Australia's production delays," he said.

AWAITING PRODUCTION VESSEL

Once completed the four projects will have a combined annual LNG capacity of 36.5 million tonnes. The development costs will total $130 billion.

Each one has had to hit the brakes. "All of Australia's recent wave of LNG projects have had cost and schedule overruns compared to expectations," said Saul Kavonic of energy consultancy Wood Mackenzie.

The projects being built In Australia are amongst the biggest and technically most challenging ever attempted in the industry. One problem the LNG project developers have pointed to in explaining production delays is that they struggle to find enough qualified and experienced staff.

"There aren't many experts and teams with relevant experience who can lead such huge developments. That's contributed to some of the delays," said on engineer who has worked on developing offshore oil and gas projects.

At the $35 billion Ichthys project, engineering firm CIMIC this week pulled out of its contract to build the facility's power station, citing cost overruns.

Ichthys, which includes a stationary rig and a floating production vessel, was due to start operations between July and September this year, but the power station problem will almost certainly cause more delays and costs.

"Any delays to the delivery of the project may have very serious implications for Inpex. Low oil prices have already impacted the financial position of the company," said Tom O'Sullivan, managing director of energy consultancy Mathyos Japan.

At Gorgon, which has cost $55 billion to develop and which started operations last year, there are problems in bringing expanded production online.

Two sources with knowledge of the matter said that crews working on the expansion phase had to be shifted to repair operational facilities, delaying full completion.

Chevron said it would not comment on daily operations.

Delays are also expected at Shell's Prelude. The production vessel, the world's biggest ship at half-a-kilometer in length, is currently being built in South Korea.

Scheduled to generate cash flow by 2018, one source with the shipyard and another with one of Prelude's LNG buyers said it was unlikely that Prelude would produce any gas before late 2018, maybe even 2019.

Potential delays and cost overruns are likely to have a big impact on returns on investment.

"On average, Australia's recent LNG projects were forecast to achieve an internal rate of return (IRR) of around 13 percent," Wood Mackenzie's Kavonic said. "They are now only forecast to realize below 8 percent,"

Neil Beveridge, oil and gas analyst at AB Bernstein in Hong Kong, said that "the returns of many of the projects are going to be low and probably lower than the cost of capital in the current oil price environment."

OTHERS MAKE THE MONEY

Beyond adding to already huge costs for its developers, the delays will have a strong market impact.

For 2017, they mean a tighter market than initially expected, and prices have already reacted. The Asian spot LNG price almost doubled between June last year and January 2017 to more than $9 per million British thermal units (mmBtu), its highest since 2014.

The delays are happening just as new supplies are coming on stream elsewhere. Seven U.S. export projects are currently approved, with a potential to reach 50 million tonnes a year by the early 2020s.

"Australian LNG projects will be competing with U.S. projects. Cost efficiency is going to be critical. And here, the Australians have to put in some serious effort," Kavonic said.

http://www.reuters.com/article/us-asia-lng-delays-idUSKBN15A24L

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Brazil's state-run oil company Petroleo Brasileiro SA announced on Thursday it is reducing diesel and gasoline prices at refineries, reflecting the fall in international petroleum products prices and the appreciation of the local currency against the dollar.

In a statement, Petrobras, as the company is known, said diesel prices will be reduced 5.1 percent at refineries, and gasoline prices will fall 1.4 percent. This may result in a reduction of up to 2.6 percent in diesel prices and 0.4 percent in gasoline prices to consumers, the company said.

http://www.reuters.com/article/petrobras-prices-idUSE6N14A048

Keppel Corp., the world’s biggest oil rig builder that eliminated more than 10,000 jobs last year, said even a doubling of crude prices is failing to offer relief to an industry slammed by overcapacity as it braced for a prolonged slowdown.

While OPEC’s recent decision to cut output renewed optimism, with spending by some oil majors expected to increase, a quick recovery isn’t in sight, Chief Executive Officer Loh Chin Hua said. The company, which reported a 65 percent drop in net income last quarter, said it is closing some yards and signaled additional job cuts as part of efforts to pare costs.

“We are happy that oil prices are starting to pick up, so that’s a good thing,” Loh said on a conference call after the market’s close Thursday. “But we are also realistic and it might take a while before it will flow down and it’s an overbuilt market.”

Keppel and peers including Hyundai Heavy Industries Co. have been slashing jobs and scaling back capacity as spending cuts by explorers crimped demand for offshore drilling rigs. The Singapore-based company had mothballed two overseas facilities earlier. Shares of the company declined Friday, after having rallied more than 30 percent in the past year on expectations the oil rebound will spur a revival.

“We remain bearish on Keppel’s O&M division earnings outlook for 2017 as we see little improvement in operating fundamentals,” despite market expectations for an industry turnaround helped by oil prices rebounding, Royston Tan, an analyst at Daiwa Capital Markets in Singapore, wrote in a note dated Jan. 26.

Keppel shares fell 2.2 percent to S$6.25 as of 9:03 a.m. in Singapore, the largest intraday decline since Dec. 15. The city’s Straits Times Index gained 0.3 percent.

Brent crude prices traded near $59 a barrel earlier this month, compared with less than $30 about a year earlier, according to data compiled by Bloomberg.

At its offshore and marine division, Keppel reduced its direct workforce by 2,620 in the quarter through December. For the whole of 2016, the unit shed about 10,600 workers, of which 3,800 were in Singapore.

“The painful but necessary measures to rightsize our O&M division must continue,” Loh said.

In October, Keppel said its senior managers and directors were taking a cut in their salaries.

Fourth-quarter earnings were dented by additional provisions for impairment of S$313 million, Keppel said.

“What we’re going through is a very long, harsh winter,” Loh said. “It’s not business as usual.” The decision to mothball yards was taken to make the division “stronger and more efficient,” he said.

https://www.bloomberg.com/news/articles/2017-01-26/keppel-s-profit-drops-65-on-provisions-as-job-cuts-continue

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Oilfield services provider Baker Hughes Inc said it expected revenue from its onshore business in North America to increase in the first half of the year as customers ramp up drilling activity and pricing improves.

The company, which is being acquired by General Electric Co, however, reported a bigger-than-expected fourth-quarter loss as prices for its services remained weak.

Improvement in pricing would remain limited as the market remained oversupplied, Baker said, joining bigger rivals Halliburton Co and Schlumberger NV in forecasting a decline in drilling activity and pricing pressure in markets outside North America.

In international markets, activity declines in its deepwater business are expected to be more severe, Baker said.

On an adjusted basis, the company reported a loss 30 cents per share, much bigger than the analysts' estimate of a 11 cents per share loss, according to Thomson Reuters I/B/E/S.

Net loss attributable to Baker Hughes was $417 million, or 98 cents per share, in the quarter ended Dec. 31, compared with a loss of $1.03 billion, or $2.35 per share, a year earlier.

The latest quarter includes after-tax charges of $291 million.

Baker Hughes' revenue fell about 29 percent to $2.41 billion, which beat analysts' expectations of $2.37 billion.

http://www.reuters.com/article/baker-hughes-results-idUSL4N1FG3HF

North American drillers could face a $43 billion cash shortfall this year even with oil prices on the rise, according to a new study.

U.S. shale drillers and Canadian producers would need oil prices to skyrocket to $80 a barrel oil to finance operations without borrowing more money or cutting spending by a whopping 40 percent, consultancy AlixPartners said in a study released Thursday.

The gap in the cash flow they need to keep operating in shale oil patches across the United States isn’t nearly as large as it was last year, when AlixPartners said the industry lacked $130 billion on much lower oil prices.

But oil companies that haven’t already gone through bankruptcy proceedings or fixed their balance sheet problems by other means are still at a stark disadvantage. These firms have on average $26,000 for each barrel of oil equivalent per day they produce, twice as much as rivals that have already restructured their balance sheets. More than 200 North American oil producers and energy services companies filed for bankruptcy over the past two years, according to Dallas law firm Haynes & Boone.

Despite the influx of optimism in the oil patch, drillers and service companies will likely continue to restructure their balance sheets or sell themselves in mergers and acquisition deals. AlixPartners said companies should behave as if crude prices are still around $45 a barrel, “to keep any surprises on the upside, not the downside.”

“For those companies that take requisite actions, at long last 2017 could be a year of rebuilding,” said Bill Ebanks, managing director of AlixPartners’ oil, gas and chemicals practice, in a written statement.

AlixPartners also said it estimates oil field service companies that operate on land have seen profitability fall 68 percent over the past three years, even as they cut 250,000 jobs around the world. Don’t expect a full recovery this year, but more of a transition to higher demand in 2018, the consultancy said.

http://fuelfix.com/blog/2017/01/26/drillers-face-43-billion-cash-shortfall-in-2017-study-says/

Alaska Gasline Development Corp, the state-owned gas corporation, is in discussions about purchasing ConocoPhillips' mothballed Kenai LNG plant at Nikiski, south of Anchorage, officials told state legislators Wednesday.

The idea is at an early stage. "We haven't signed a confidentiality agreement yet," said Frank Richards, AGDC's engineering vice president. The state-owned corporation is briefing legislators in Juneau on the Alaska LNG Project this week.

Fritz Krusen, AGDC's vice president for LNG, said owning the plant, which exported Cook Inlet gas and is not now operating, would help the state corporation in its current bid to build a much larger LNG export project using North Slope gas.

"It could allow us to present an early production scenario to buyers," Krusen said, where the smaller ConocoPhillips plant, which is capable of liquefying up to 1.5 million mt/year, could begin exports before a 20 million mt/year project is constructed.

The three-train liquefaction plant planned as a part of the Alaska LNG Project would be on a 600-acre tract of land near the site of the current ConocoPhillips plant. There are many ways AGDC's acquisition of the plant would benefit the larger project, Krusen said. "For example, it would give up control of much more waterfront acreage," on Cook Inlet, he said.

Owning the plant would also allow AGDC to tap into a long history of reliable operations and relationships with customers, Krusen said.

State Senator Bill Wielechowski asked Krusen about the status of discussions with ConocoPhillips during a briefing of the Resources Committee of the state Senate.

"If I answered that, I'm afraid I would breach confidentiality," he replied.

ConocoPhillips has operated the plant since 1969, but ceased regular shipments to Japan in early 2012. The company put the facility up for sale last fall.

Company spokeswoman Amy Jennings Burnett did not confirm talks were underway with AGDC, but said discussions are being held with a wide range of possible buyers.

"We are in the early stages of marketing the plant. ConocoPhillips is following a standard marketing process for the Kenai LNG plant. A virtual data room, which opened on January 10, provides critical information to help potential buyers assess the asset and determine if they are interested in submitting a formal bid," Burnett said in an e-mail.

"Interested parties are currently reviewing the data room material and we anticipate receiving bids later this year. At that point, ConocoPhillips will evaluate the bids and determine a path forward. We are not in negotiations with any party at this time," she said.

Phillips Petroleum built the plant in 1969 to ship LNG made from Cook Inlet gas, then in surplus, to Japan. At the time, it was the first long-distance shipment of LNG, and demonstrated the viability of the business.

Much larger shipments of LNG to Japan from southeast Asia developed in following years.

The Kenai plant made regular shipments until 2012, when long-term contracts with Tokyo Gas and Tokyo Electric expired. ConocoPhillips made periodic shipments following spot sales in 2014 and 2015, but made no shipments in 2016.

The company recently sold the North Cook Inlet gas field, which had supplied gas to the plant, to Hilcorp Energy, which operates other Cook Inlet oil and gas properties.

AGDC recently assumed control of the Alaska LNG Project from a consortium of three North Slope producers and itself, as one of four partners in pre-engineering work.

Given the state of Pacific LNG markets, the three producers -- BP, ConocoPhillips and ExxonMobil -- have stepped back from the project for now, but are supporting the AGDC in continuing to work on, and pursue innovative commercial terms, like tax-exempt status, that would be available only to a state-owned project.

If built, Alaska LNG would tap 35 Tcf of confirmed gas reserves on the North Slope with an 800-mile pipeline from north to south across Alaska, and also build the large LNG plant near Kenai and a gas treatment plant on the North Slope.

The companies, and the state, have spent about $600 million to date on pre-engineering, environmental and regulatory work. AGDC is working to raise about another $1.5 billion to carry out the final engineering work and is seeking investors and gas purchasers. The three large producers may still participate in the project, they say.

Overall project cost is now estimated at $45 billion. If built according to AGDC's current schedule, Alaska LNG could be operating by 2025.

http://www.platts.com/latest-news/natural-gas/anchorage/alaska-state-gas-corporation-in-kenai-lng-plant-21708650