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Last Updated: April 5, 2017
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Gas & LNG
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DOHA (Bloomberg) -- Qatar Petroleum plans to start a new development in the offshore North field, ending a 12-year ban on new projects that allowed the company to assess how its current rate of extraction affects the giant reservoir it shares with Iran.

The patch, in the southern section of the field, will have a capacity of 2 Bcfgd, or 400,000 boe, and should start production in five to seven years, CEO Saad Sherida Al Kaabi told reporters Monday at Qatar Petroleum’s headquarters in Doha.

Boosting natural gas production at home and searching for similar assets abroad signals Qatar Petroleum’s confidence in the longevity of gas demand, and its ability to remain a low-cost supplier in a market that has slumped amid a glut driven by output from U.S. shale and Australia. 

"Global demand for gas is expected to rise," Al Kaabi said. "There are no analysts who can say when demand for gas will wane. For oil, there are people who see peak demand in 2030, others in 2042, but for gas, demand is constantly growing."

Qatar Petroleum’s decision is a sign that it wants to increase its LNG market share, Giles Farrer, research director, global LNG, at Wood Mackenzie Ltd., said in an email. It’s "also a threat to other developers of new capacity worldwide, as Qatar can add new capacity at a lower cost than anybody else."

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Your Weekly Update: 19 - 23 August 2019

Market Watch 

Headline crude prices for the week beginning 19 August 2019 – Brent: US$58/b; WTI: US$55/b

  • Although oil prices are still depressed over concerns on long-term health and the global economy, the market received an uptick as the situation in the Middle East continues to remain tense
  • Oil and gas facilities in Shaybah, Saudi Arabia, were attacked by Yemeni rebels over the weekend; although no disruption to production was reported, the attack does illustrate how fragile the Middle East condition is right now, even if confrontations have simmered down
  • The crude tanker seized by British authorities in Gibraltar was released, but the US sought the block the release and has threatened sanctions on any country that aids the ship; Greece has said that it will refuse to help the tanker as it makes its way to the East Mediterranean, with Iran saying it could send a naval escort
  • In the ongoing US-China trade war, the US has delayed sanctions on China’s Huawei Technologies and new tariffs on Chinese imports to mid-December, a sign that the US expects some progress in current trade talks
  • But we have been here before, and the delays do not represent any concrete movement on diffusing the trade tensions between the world’s two largest economies; the trade situation remains volatile and subject to Trump’s whims
  • Also supporting prices are signs that the world’s major economies are moving to stave off the effects of a possible recession, with Germany reporting that it was preparing a package of fiscal stimulus measures
  • The US active rig count managed to finally snap six weeks of consecutive losses, gaining six new oil rigs but losing four gas rigs for a net gain of two; the current total active rigs in the US stand at 935, down 122 y-o-y
  • With the market relatively calm, crude prices will likely stay rangebound in the US$58-60/b space for Brent and US$54-56/b for WTI; the focus will still remain on the long-term health of global oil demand, but intermittent short-term supply issues could swing prices up or down


Headlines of the week

Upstream

  • After ExxonMobil and its series of blockbuster discoveries in Guyana, Tullow Oil joins the race as the Jethro-1 well in the Orinduik license confirms the presence of oil with estimates exceeding pre-drill forecasts
  • The US$7.7 billion Mariner field in the UK North Sea has produced its first oil, with operator Equinor expecting the field to produce over 300 million boe over 30 years, an initial output of 50,000 b/d and 70,000 b/d at peak production
  • Angola will launch a new licensing round, focused on 10 offshore blocks, including frontier areas in the Namibe and the Benguela basins
  • The Hibernia platform in Canada’s Newfoundland and Labrador has been granted permission to resume production after an oil spill in mid-July
  • Kenya has made its first-ever crude oil export as Tullow Oil sold a shipment to ChemChina UK; initial crude shipments are expected to be small-scale until a pipeline connecting Mombasa to the Turkana onshore fields is completed
  • Start-up of Petrobras’s Mero-2 pre-salt project in the Santos basin has fallen behind schedule, with first oil from the Sepetiba FPSO now expected in 2023
  • Joining the trend of other US upstream producers exiting the UK North Sea, ExxonMobil is reportedly considering a sale of its UKNS portfolio, which would be valued at some US$2 billion
  • Repsol has been granted permission by Norway to extend the life of the Rev field in the North Sea past April 2021, which started operations in 2009

Midstream/Downstream

  • After hosting its first-ever earning calls, Saudi Aramco reaffirms its desire to expand its downstream footprint further by taking a 20% stake in Reliance Industries for US$15 billion, which should secure regular sales of 500,000 b/d of Arabian crude to feed the Jamnagar refineries in India
  • First crude has been delivered from the Permian to Corpus Christi as Trafigura/Buckeye received a shipment through the Plains All American Cactus II pipeline that connects the Permian to the Gulf Coast
  • Malaysia is planning to develop the US$2 billion Bunker Island oil storage and ship refuelling site in Johor, which would provide competition to Singapore with capacity for 1.2 million cubic metres of fuel products
  • A group of American small fuel retailers is suing the US government over the move to lift the current ban on year-long E15 ethanol-gasoline sales, a move that was set to benefit the US farm lobby but place pressure on the oil lobby

Natural Gas/LNG

  • The EIA forecasts that Australia will surpass Qatar as the world’s largest LNG exporter by 2020, as data confirms that Australia shipments exceeded Qatar’s in November 2018 and April 2019
  • Equinor has been granted permission by the Norwegian Petroleum Directorate to start production at the Utgard field in the North Sea, with production focused on condensate, natural gas and NGLs
  • Cheniere is on track to become the world’s second-largest LNG operator by capacity in 2020, with an expected installed capacity of 31 million tons per annum through five trains at Sabine Pass and two trains at Corpus Christi
  • Guangzhou Gas is still reportedly looking for LNG supplies after walking away from a potential deal to purchase 1 mtpa of LNG for Canada’s Woodfibre LNG
  • ExxonMobil is gearing up for high-profile natural gas drilling campaign in Australia’s Gippsland basin offshore Victoria
August, 26 2019
New PNG Government Reviews Past Oil Agreements

A lot of complications arise when a government changes. Particularly if the new government comes in on a mandate to reverse alleged deficiencies and corruption of previous governments. This is amplified when significant natural resources are involved. It has happened in the past – when Iran nationalised its oil industry by kicking out BP – and it could happen again in the future – in Guyana where the promise of oil riches in the hands of foreign firms has already caused grumbles. And it is also happening right now in Papua New Guinea, as the new government led by Prime Minister James Marape took aim at the Papua LNG deal.

Negotiated by the previous government of Peter O’Neill, the state’s new position that is the current gas deal is ‘disadvantageous’ to country. A complex set of manoeuvres – accusing O’Neill of multiple levels of corruption – led to a proposed vote of no confidence and an eventual resignation. With the departure of O’Neill, public opinion on the Papua LNG project (as well as the PNG LNG project) switched from being viewed as a boon to the economy to one of unequal terms that would not compensate the nation fairly for its resources.

So, despite a previous assurance in early August that the new government of Papua New Guinea would stand by the previous gas deal agreed with the Papua LNG stakeholders in April, Marape sent a team led by the Minister of Petroleum Kerenga Kua to Singapore to renegotiate with the project’s lead operator Total.

As the meeting was announced, suggestions pointed to a hardline position by Papua New Guinea… that they could ‘walk away from a new deal’ if the new terms were not acceptable. In a statement, Kua stated that the negotiations could ‘work out well or even disastrously’. From Total’s part, CEO Patrick Pouyanne said in July that he expected the government to respect the gas deal while Oil Search stated that it was seeking ‘further clarity on the state’s position’. The gas deal covers framework of the Papua LNG project, which was scheduled to enter FEED phase this year with FID expected in 2020, drawing gas from the giant onshore Elk-Antelope fields ahead of planned first LNG by 2024. So, the stakes are high.

With both sides locked into their positions, reports from Singapore suggested that the negotiations broke down into a ‘Mexican standoff’. No grand new deal was announced, and it can therefore be inferred that no progress was made. There is a possibility that PNG could abandon the deal altogether and seek new partners under more favourable terms, but to do so would be a colossal waste of time, given that Papua LNG is nearing a decade in development. Total and ExxonMobil have already raised the possibility of legal moves if the deal is aborted, with compensation running into billions – billions that the PNG government will not have unless the Papua LNG project goes ahead.

But the implications of the deal or no-deal are even wider. The PNG state has already stated that it will look at the planned expansion of the PNG LNG project (led by ExxonMobil and Santos) next, which draws from the P’nyang field. Renegotiation of the current gas deals in PNG may have populist appeal but have serious implications – alienating two of the largest oil and gas supermajors and two of PNG’s largest foreign investors could lead to a monetary gap and a mood of distrust that PNG may be unable to ever fill. Hardline positions are a good starting position, but eventual moderation is required to ever strike a deal.

Papua LNG Factsheet:

  • Ownership: Total (31.1%), ExxonMobil (28.3%), Oil Search (17.7%), state (22.5%)
  • Feed: Elk-Antelope onshore fields,
  • Capacity: 5.4 million tons per annum
  • Structure: 2 trains of 2.7 mtpa capacity each
August, 22 2019
This Week in Petroleum: 2018 OPEC net oil export revenues highest since 2013, but likely to decline

The U.S. Energy Information Administration (EIA) estimates that members of the Organization of the Petroleum Exporting Countries (OPEC) earned almost $711 billion in net oil export revenues in 2018 (Figure 1). The estimate is up 29% from 2017, but about 40% lower than the record high of almost $1,200 billion in 2012. The 2018 earnings increase is mainly a result of higher crude oil prices. The Brent spot price rose from an annual average of $54 per barrel (b) in 2017 to $71/b in 2018. However, EIA forecasts annual OPEC net oil export revenues will decline to $593 billion in 2019 and to $556 billion in 2020. Decreasing OPEC revenues are primarily a result of decreasing production among a number of OPEC producers.

Figure 1. OPEC net oil export revenues

EIA estimates net oil export revenues based on oil production—including crude oil, condensate, and natural gas plant liquids—and total petroleum consumption estimates, as well as crude oil prices forecast in the August 2019 Short-Term Energy Outlook (STEO). EIA’s net oil export revenues estimate assumes that exports are sold at prevailing spot prices and adjusts the prices for benchmark crude oils forecast in STEO (Brent, West Texas Intermediate, and the average imported refiner crude oil acquisition cost) with historical price differentials among spot prices for the different OPEC crude oil types. For countries that export several different varieties of oil, EIA assumes that the proportion of total net oil exports represented by each variety is the same as the proportion of the total domestic production represented by that variety. For example, if Arab Medium represents 20% of total oil production in Saudi Arabia, the estimate assumes that Arab Medium also represents 20% of total net oil exports from Saudi Arabia.

Although OPEC net export earnings include estimated Iranian revenues, they are not adjusted for possible price discounts that trade press reports indicatedIran may have offered its customers after the United States announced its withdrawal from the Joint Comprehensive Plan of Action in May 2018. The United States reinstated sanctions targeting Iranian oil exports in November 2018. Similarly, EIA does not adjust for Venezuelan crude oil exports to China or India for volumes that are sent for debt repayments to China and Russian energy company Rosneft, respectively, and thus do not generate cash revenue for Venezuela.

If the $711 billion in net oil export revenues by all of OPEC is divided by total population of its member countries and adjusted for inflation, then per capita net oil export revenues across OPEC totaled $1,416 in 2018, up 26% from 2017 (Figure 2). The increase in per capita revenues likely benefited member countries that rely heavily on oil sales to import goods, fund social programs, and otherwise support public services.

Figure 2. OPEC real net and per capita oil export revenues

In addition to benefiting from higher prices, some OPEC member countries have increased export revenues by reducing domestic consumption and consequently exporting more. For example, Saudi Arabia has significantly reduced the amount of crude oil burned for power generation. Limiting crude oil burn allowed Saudi Arabia to export more crude oil and to maximize revenues.

Others have been able to charge higher premiums based on the quality of their crude oil streams. As the global slate of crude oil has changed with more light crude oil production (with higher API gravity), OPEC members have benefited from a narrowing price discount for their heavy crude oils, which are typically priced lower than lighter crude oils because of quality differences. Smaller discounts for OPEC members’ heavier crude streams contributed to higher spot prices for the OPEC crude oil basket price, which incorporates spot prices for the major crude oil streams from all OPEC members (Figure 3).

Figure 3. Gasoline crack spreads (250-day moving average)

Despite the increase in annual average crude oil prices in 2018, OPEC revenues fell during the second half of 2018, mainly because of lower production and export volumes from Iran and Venezuela (Figure 4). EIA estimates that OPEC total petroleum liquids production decreased slightly in 2018 when increased production in Saudi Arabia, Iraq, and Libya could not offset significant declines in Iranian and Venezuelan production. Combined crude oil production in Iran and Venezuela fell by almost 800,000 barrels per day (b/d), or 14%, in 2018 and again by over 1.0 million b/d in the first seven months of 2019. Although Iranian net oil export revenues increased by 18% from 2017 to 2018, a year-to-date comparison indicates a significant decrease in revenues in 2019 (Figure 4). EIA estimates that from January to July 2018, Iran received about $40 billion in export revenues, compared with an estimated $17 billion from January to July 2019. Further decreases in OPEC members’ production beyond current EIA assumptions would further reduce EIA’s OPEC revenue estimates for 2019 and 2020.

Figure 4. Number of days Singapore had the highest and lowest gasoline crack spread among global refining centers

U.S. average regular gasoline and diesel prices fall

The U.S. average regular gasoline retail price fell nearly 3 cents from the previous week to $2.60 per gallon on August 19, 22 cents lower than the same time last year. The Gulf Coast price fell nearly 6 cents to $2.27 per gallon, the East Coast price fell nearly 4 cents to $2.52 per gallon, the West Coast and Rocky Mountain prices each fell nearly 2 cents to $3.24 per gallon and $2.67 per gallon, respectively, and the Midwest price fell nearly 1 cent, remaining at $2.52 per gallon.

The U.S. average diesel fuel price fell nearly 2 cents to $2.99 per gallon on August 19, 21 cents lower than a year ago. The Midwest price fell over 2 cents to $2.90 per gallon, the West Coast and East Coast prices each fell nearly 2 cents to $3.56 per gallon and $3.02 per gallon, respectively, the Gulf Coast price fell more than 1 cent to $2.75 per gallon, and the Rocky Mountain price fell less than 1 cent, remaining at $2.94 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 4.0 million barrels last week to 90.5 million barrels as of August 16, 2019, 10.2 million barrels (12.7%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast, East Coast, Midwest, and Rocky Mountain/West Coast inventories increased by 2.0 million barrels, 1.0 million barrels, 0.7 million barrels, and 0.4 million barrels, respectively. Propylene non-fuel-use inventories represented 4.4% of total propane/propylene inventories.

August, 22 2019