Easwaran Kanason

Co - founder of PetroEdge
Last Updated: October 24, 2016
1 view
Business Trends
image

Last week in world oil:

All of Saudi Arabia’s bluster can’t hide the fact that the tenuous OPEC agreement to cut production had hit a number of obstacles, with the latest being that Iraq wants exemption from the cuts, just as Nigeria, Libya and Iran do. That was enough to send oil prices lower today, though they remain just above the US$50/b level.

Mexico has approved Italy’s Eni to go ahead with test drilling at the Amoca 2 well, a shallow water field in the Gulf of Mexico. It is only the second well to be drilled in Mexico since reforms to open up its energy sector dissolved Pemex’s upstream monopoly. The first well was Amoca 1, also by Eni, part of an acreage that is estimated to hold some 800 million barrels of oil and 480 bcf of associated gas. 

Announcements of asset sales by supermajors are common these days, particularly from Shell, seeking to pay for its acquisition of the BG Group. The latest involves some US$1.3 billion of non-core oil and gas properties in western Canada exchanging hands between Shell and Tourmaline Oil, including onshore land in the Gundy area of British Columbia and the Deep Basin area of Alberta that currently have a minor production output of 25 kb/d, with reasonable room for growth.

Higher prices spur more rigs, and the US operational oil rig count jumped by 11 last week, bringing the total to 443. Gas rigs also added 3 to their number, up to 108, as nimble onshore producers react to the positive price signals. The number of offshore rigs remains unchanged at 23.

There’s a problem looming in PDVSA and it threatens to spill over into the US Gulf. Beset with a huge amount of debt, the Venezuelan national oil company has been attempting to negotiate short-term measures to defer its debt, with the spectre of a default looming on the horizon. Already, Curacao appears to be abandoning PDVSA, seeking Chinese involvement in its refinery, while the woes are affecting PDVSA’s subsidiary Citgo in the USA and its Aruba refinery. A default would also wreck havoc with the US Gulf Coast refining system, dependent on Venezuela’s output that supplies a third of the crude processed along the Gulf Coast.

Qatargas has inked a deal with Petronas LNG UK to supply 1.1 million tons of LNG per year through 2023, extending a contract that was due to expire at the end of 2018. The deal is particularly important for Qatar, as it seeks to secure long-term supply agreements in the face of a looming global glut of gas supplies from Australia and the US, with Europe being a priority target. The LNG will be supplied from Qatargas 4, a joint venture between Qatar Petroleum and Shell, with the supplies delivered to the Dragon LNG terminal in Milford Haven in the UK. Qatargas is also looking at securing supply agreements in Rotterdam, which would be its gateway into western continental Europe.

The Chinese upstream sector is considered expensive, inefficient and now, declining. China’s crude output fell by 9.8% y-o-y in September, as low oil prices make imports cheaper while making the case that the country’s high-cost fields, like Daqing and Shengli, should be shut down. Crude output in August fell by 9.9%, the highest y-o-y decline on record, while September crude imports growth reached 18%.

Petrobras has finally reached a deal for its mothballed Nansei Seikyu refinery in Okinawa, agreeing to sell it to Japan’s Taiyo Oil for US$129.3 million as it continues on its asset sale spree to reduce its debt. The Okinawan refinery, an oddball choice that was acquired by Petrobras in 2007, has proven particularly difficult to sell, having its refining operations shut down last year due to the industry downturn. 

With the downstream oil market in doldrums but the petrochemical industry still holding strong, Saudi Arabia is aiming to capitalise on that by focusing on a giant crude-to-chemicals project. Saudi Aramco and SABIC have formed a joint management team, together with a unnamed third party, to assess the viability of such a project that would cut out the middle link in petrochemical production, bypassing gasoline and diesel to go straight into chemicals. A preliminary study is expected in 2017, and is in line with the Kingdom’s stated desire to diversify its economy away from crude petroleum sales.

After the US$15 billion Inpex/Shell plan to boost output at the Masela natural gas field by 2.5 mtpa utilising a floating LNG facility was rejected by the Indonesian government in March, a new plan has been proposed to build an onshore LNG plant on the islands of Aru or Saumlaki. The anticipated start date of the giant gas field has been pushed into the late 2020s, and to recoup investment, Inpex is proposing a near quadrupling of output, to between 7.5-9.5 mtpa in total now. A decision on the new proposal is expected from the Indonesian government within the month.

Under pressure gas player Santos has sold its offshore natural gas assets in Victoria to Australia’s Cooper Energy for US$62 million. The sale marks the exit of Santos from offshore Victoria following the sale of its Kipper field for US$520 million in March. The assets include interests in the Casino-Henry gas project, as well as control of the Sole field and Orbost gas plant in Gippsland Basin.

In another sign that petrochemicals are booming, India’s Reliance has beaten forecasts by posting an 18% y-o-y increase in its Q2 profit, buoyed by its petrochemicals business. Reliance’s petrochemicals margins for Q216 were 15%, the highest in nearly four years, while its refining margins fell sharply due to weak product prices. 

Meanwhile in the rig-making sector, Singapore’s Keppel Oil saw its quarterly profits fall by 38% on a weak offshore market. Cost-cutting measure and job cuts – more than 8,000 so far in 2016 – are continuing, and the company will also look at mothballing some facilities until 2020. 

Have a productive week ahead!

Read more:
oil and gas report. weekly oil report nrgedge nrgbuzz oil and gas commentary oil and gas oil markets
3
2 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

In 2018, the United States consumed more energy than ever before

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Primary energy consumption in the United States reached a record high of 101.3 quadrillion British thermal units (Btu) in 2018, up 4% from 2017 and 0.3% above the previous record set in 2007. The increase in 2018 was the largest increase in energy consumption, in both absolute and percentage terms, since 2010.

Consumption of fossil fuels—petroleum, natural gas, and coal—grew by 4% in 2018 and accounted for 80% of U.S. total energy consumption. Natural gas consumption reached a record high, rising by 10% from 2017. This increase in natural gas, along with relatively smaller increases in the consumption of petroleum fuels, renewable energy, and nuclear electric power, more than offset a 4% decline in coal consumption.

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Petroleum consumption in the United States increased to 20.5 million barrels per day (b/d), or 37 quadrillion Btu in 2018, up nearly 500,000 b/d from 2017 and the highest level since 2007. Growth was driven primarily by increased use in the industrial sector, which grew by about 200,000 b/d in 2018. The transportation sector grew by about 140,000 b/d in 2018 as a result of increased demand for fuels such as petroleum diesel and jet fuel.

Natural gas consumption in the United States reached a record high 83.1 billion cubic feet/day (Bcf/d), the equivalent of 31 quadrillion Btu, in 2018. Natural gas use rose across all sectors in 2018, primarily driven by weather-related factors that increased demand for space heating during the winter and for air conditioning during the summer. As more natural gas-fired power plants came online and existing natural gas-fired power plants were used more often, natural gas consumption in the electric power sector increased 15% from 2017 levels to 29.1 Bcf/d. Natural gas consumption also grew in the residential, commercial, and industrial sectors in 2018, increasing 13%, 10%, and 4% compared with 2017 levels, respectively.

Coal consumption in the United States fell to 688 million short tons (13 quadrillion Btu) in 2018, the fifth consecutive year of decline. Almost all of the reduction came from the electric power sector, which fell 4% from 2017 levels. Coal-fired power plants continued to be displaced by newer, more efficient natural gas and renewable power generation sources. In 2018, 12.9 gigawatts (GW) of coal-fired capacity were retired, while 14.6 GW of net natural gas-fired capacity were added.

U.S. fossil fuel energy consumption by sector

Source: U.S. Energy Information Administration, Monthly Energy Review

Renewable energy consumption in the United States reached a record high 11.5 quadrillion Btu in 2018, rising 3% from 2017, largely driven by the addition of new wind and solar power plants. Wind electricity consumption increased by 8% while solar consumption rose 22%. Biomass consumption, primarily in the form of transportation fuels such as fuel ethanol and biodiesel, accounted for 45% of all renewable consumption in 2018, up 1% from 2017 levels. Increases in wind, solar, and biomass consumption were partially offset by a 3% decrease in hydroelectricity consumption.

U.S. energy consumption of selected fuels

Source: U.S. Energy Information Administration, Monthly Energy Review

Nuclear consumption in the United States increased less than 1% compared with 2017 levels but still set a record for electricity generation in 2018. The number of total operable nuclear generating units decreased to 98 in September 2018 when the Oyster Creek Nuclear Generating Station in New Jersey was retired. Annual average nuclear capacity factors, which reflect the use of power plants, were slightly higher at 92.6% in 2018 compared with 92.2% in 2017.

More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

April, 17 2019
Casing design course
Candidates :Drilling engineers/ drilling supervisors- Venue: Istanbul/Turkey- Duration: 5 days- For more information contact me at: Tel: +905364320900- [email protected] [email protected]
April, 17 2019
A New Frontier for LNG Pricing and Contracts

How’s this for a first? As the world’s demand for LNG continues to grow, the world’s largest LNG supplier (Shell) has inked an innovative new deal with one of the world’s largest LNG buyers (Tokyo Gas), including a coal pricing formula link for the first time in a large-scale LNG contract. It’s a notable change in an industry that has long depended on pricing gas off crude, but could this be a sign of new things to come?

Both parties have named the deal an ‘innovative solution’, with Tokyo Gas hailing it as a ‘further diversification of price indexation’ and Shell calling it a ‘tailored solutions including flexible contract terms under a variety of pricing indices.’ Beneath the rhetoric, the actual nuts and bolts is slightly more mundane. The pricing formula link to coal indexation will only be used for part of the supply, with the remainder priced off the conventional oil & gas-linked indexation ie. Brent and Henry Hub pricing. This makes sense, since Tokyo Gas will be sourcing LNG from Shell’s global portfolio – which includes upcoming projects in Canada and the US Gulf Coast. Neither party provided the split of volumes under each pricing method, meaning that the coal-linked portion could be small, acting as a hedge.

However, it is likely that the push for this came from Tokyo Gas. As one of the world’s largest LNG buyers, Tokyo Gas has been at the forefront of redefining the strict traditions of LNG contracts. Reading between the lines, this deal most likely does not include any destination restriction clauses, a change that Tokyo Gas has been particularly pushing for. With the trajectory for Brent crude prices uncertain – owing to a difficult-to-predict balance between OPEC+ and US shale – creating a third link in the pricing formula might be a good move. Particularly since in Japan, LNG faces off directly with coal in power generation. With the general retreat from nuclear power in the country, the coal-LNG battle will intensify.

What does this mean for the rest of the industry? Could coal-linked contracts become the norm? The industry has been discussing new innovations in LNG contracts at the recent LNG2019 conference in Shanghai, while the influx of new American LNG players hungry to seal deals has unleashed a new sense of flexibility. But will there be takers?

I am not a pricing expert but the answer is maybe. While Tokyo Gas predominantly uses natural gas as its power generation fuel (hence the name), it is competing with other players using cheaper coal-based generation. So in Japan, LNG and coal are direct competitors. This is also true in South Korea and much of Southeast Asia. In the two rising Asian LNG powerhouses, however, the situation is different. In China – on track to become the world’s largest LNG buyer in the next two decades – LNG is rarely used in power generation, consumed instead by residential heating. In India – where LNG imports are also rising sharply – LNG is primarily aimed at petrochemicals and fertiliser. LNG based power generation in China and India could see a surge, of course, but that will take plenty of infrastructure, and time, to build. It is far more likely that their contracts will be based off existing LNG or natural gas benchmarks, several of which are being developed in Asia alone.

If it takes off  the coal-link LNG formula is likely to remain a Asian-based development. But with the huge volumes demanded by countries in this region, that’s still a very big niche. Enough perhaps for the innovation to slowly gain traction elsewhere, next stop -  Europe?

The Shell-Tokyo Gas Deal:

Contract – April 2020-March 2030 (10 Years)

Volume – 500,000 metric tons per year

Source – Shell global portfolio

Pricing – Formula based on coal and oil & gas-linked indexes

Learn more about LNG business, technology, markets and contracts
LNG Fundamentals - May, 27 – 29, Singapore
LNG Markets, Pricing, Trading & Risk Management - May, 27 – 29, Singapore
LNG Terminal Operations - June19 – 21, Singapore
Gas & LNG Contract Negotiations - August, 21 – 23, Kuala Lumpur
LNG Fundamentals – October, 22 – 24, Singapore
visit https://www.petroedgeasia.net/oil-and-gas-training-course

April, 15 2019