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Last Updated: August 26, 2017
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Kuala Lumpur, 25 August 2017 - PETRONAS today announced strong earnings for the first half of 2017, contributed by higher average realised prices, better margins and boosted by the on-going transformation initiatives to reduce cost and increase efficiency.

The Group's revenue grew to RM108.1 billion, up 15 per cent from RM93.7 billion in the first half of 2016, benefitting from the upward trend of key benchmark prices and foreign exchange rate, but was partially offset by lower sales volume.

Profit after tax (PAT) rose more than a 100 per cent to RM17.3 billion from RM6.4 billion in the corresponding period last year, notably due to higher average realised prices as well as lower net impairment on assets and well costs.

The increase however was partially offset by higher amortisation of oil and gas properties, tax expenses, net foreign exchange losses and costs related to the non-Final Investment Decision (FID) for the Pacific NorthWest LNG (PNW LNG) Project in Canada.

Earnings before interest, tax, depreciation and amortisation (EBITDA) was RM45.2 billion, a 35 per cent increase compared to RM33.6 billion recorded during the same period last year.

The Group's cash flows from operating activities also increased by 55 per cent to RM39.8 billion compared to RM25.6 billion in the same corresponding period in 2016.

Capital investments totalled at RM21.3 billion, mainly attributable to the Refinery and Petrochemical Integrated Development (RAPID) project in Pengerang, Johor.

Meanwhile year-to-date crude oil, condensate and natural gas entitlement volume was 1,778 thousand barrels of oil equivalent (BOE) per day while total production volume was 2,342 thousand BOE per day.

Total assets decreased to RM596.6 billion as at 30 June 2017 from RM603.4 billion as at 31 December 2016 primarily due to the impact of the strengthening of the Ringgit against the US Dollar.

Shareholders' equity of RM375.8 billion decreased by RM4.6 billion mainly due to the approved dividend of RM13.0 billion for the financial year ended 31 December 2016 and the foreign exchange rate impact, partially offset by profit generated during the period.

Gearing ratio decreased to 17.1 per cent as at 30 June 2017 from 17.4 per cent as at 31 December 2016.

Quarter on quarter, PETRONAS' performance for Q2 of 2017 also improved, largely driven by the upward trend of key benchmark prices and better margins.

PAT was registered at RM7.0 billion compared to RM1.7 billion in Q2 of 2016, a significant improvement mainly due to lower net impairment on assets and well costs, coupled with higher average realised prices recorded across all products. This was partially offset by higher net foreign exchange losses, amortisation of oil and gas properties and non-FID costs for PNW LNG in Canada.

The PAT was posted on the back of a RM 51.6 billion revenue, a 10 per cent increase from RM46.9 billion from the corresponding quarter last year as a result of higher average realised prices and foreign exchange rate impact.

EBITDA increased by 16 per cent to RM20.6 billion from RM17.8 billion in the corresponding quarter last year.

The Group's cash flows from operations also grew by 37 per cent to RM21.8 billion from RM15.9 billion in the corresponding quarter last year due to higher average realised prices.

Outlook

Despite higher prices compared to a year ago, the industry remains volatile tempering the company's optimism. PETRONAS continues to focus on internal transformation initiatives, effective cash management and cost optimisation.

The Board expects the overall year-end performance of PETRONAS Group to be fair.

Datuk Wan Zulkiflee Wan Ariffin, President and Group CEO PETRONAS

'We have closed out the first half of the year with stronger financials compared to the same period in 2016. While the price of oil was a significant factor, I also view this as tangible results of PETRONAS' transformation measures taken in response to the industry downturn. And I attribute this to the employees of PETRONAS. They continue to drive impactful changes, which create ripple effects that, as you can see, have positively improved the bottom-line.'

Operational Highlights

Upstream

• PETRONAS has made significant progress in re-basing its cost in the Upstream business. In 2017, PETRONAS expects further reduction in unit production cost to an average of US$6.8 per barrel through efficiency across its value chain.

• The total production volume for the first half of 2017 was 2,342 thousand BOE per day compared to 2,391 thousand BOE per day in the corresponding period last year. This was mainly due to lower Iraq production entitlement, lower activities in Canada and higher decline rate in the Malaysia-Thai Joint Development AREA and Egypt, partially offset by the increase in production in the MLNG supply system. Five new and infill projects were brought on-stream in the second quarter of 2017, contributing to 44,000 barrels equivalent per day of production. Total production entitlement improved to 1,778 thousand BOE from 1,731 thousand BOE in the corresponding period.

• LNG sales recorded a two per cent increase in volume compared to the corresponding period last year, mainly attributable to the higher volume from Train 9 and Egyptian LNG. In addition, the PFLNG Satu has delivered two cargoes to India and Taiwan, respectively.

• Despite the decision not to proceed with the PNW LNG project, PETRONAS remains committed to monetise the natural gas resources in the North Montney area in Canada. At 22.3 trillion cubic feet of proven resources, Canada holds the second largest gas resources in PETRONAS' portfolio after Malaysia. To-date, Progress Energy Canada Ltd, a wholly owned subsidiary of PETRONAS, is producing around 540 million standard cubic feet of gas per day to the domestic market, generating revenue of CA$261 million (approximately RM861 million) for the first two quarters in 2017.

• As part of the company's portfolio high-grading efforts, PETRONAS has decided to divest its position in Algeria and not to proceed with the extension of the Block 1 and 2 Production Sharing Contract in Vietnam. In addition, PETRONAS has secured a third exploration block in Mexico, namely Block 6, in the recently concluded bid round. To-date, PETRONAS has accumulated a total of 5,491 sq kms of exploration acreages in the highly prospective Mexico offshore blocks.

Downstream

• For the first half of 2017, Downstream business recorded an increase in PAT attributable to better petrochemical product spreads as well as higher trading and marketing margins.

• Higher volume recorded from petrochemicals was 4.0 MMT for the first half of 2017 compared to 3.5 MMT in the corresponding period last year, following the commissioning of PETRONAS Chemical Fertiliser Sabah Sdn Bhd (also known as SAMUR) further supported Petrochemical business in capturing favourable products spreads.

• Healthy trading and marketing margin for Crude and Petroleum products mainly driven by focused trading strategies towards high-value activities.

• PETRONAS' key downstream project continues to progress well with the Pengerang Integrated Complex (PIC) project achieving 70 per cent completion at 30 June 2017 with seven per cent progress during the second quarter of 2017.

• PETRONAS, through its lubricants business unit, the PETRONAS Lubricants Marketing (Malaysia) Sdn Bhd has successfully secured a four-year Supply Contract Renewal from Mercedes Benz through Cycle and Carriage Bintang Berhad.

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Your Weekly Update: 17 - 21 February 2020

Market Watch   

Headline crude prices for the week beginning 17 February 2020 – Brent: US$53/b; WTI: US$49/b

  • As the Covid-19 pandemic seems to be coming increasingly under control, crude oil prices are recovering some ground as the market moves into speculative mode given the availability of cheap crude cargoes
  • Case in point, while the fear was of widespread demand destruction in China, a sudden buying spree by Chinese independent teapot refineries – attracted by cheap spot cargoes – surprised the market, being a sign that Chinese private refiners are anticipating a rebound in demand sooner rather than later
  • Despite this, the pandemic is still recalibrating Chinese energy demand in a dramatic way, with reports of four LNG tanker bound for northern China from Oman and Qatar diverted as CNOOC invoked force majeure on its contracts
  • China’s pain is also India’s gain, with so-called ‘distressed cargoes’ originally intended for China now offered to India at attractive terms from all over the world, including grades from the Caspian Sea to Latin America and West Africa
  • Based on the situation in China, the IEA is forecasting the first annual decline in quarterly global oil demand for the first time in over a decade, and dragging overall 2020 growth down by 30% to 825,000 b/d; the EIA followed suit as well, cutting its Brent price forecast for 2020 from US$64.83 to US$61.25
  • China and key Asian hubs impacted by the virus like Hong Kong and Singapore have pledged to provide extra fiscal stimulus to counteract the impact of the pandemic, possibly setting the stage for a rebound in Q2 2020
  • Saudi Arabia’s attempt to cajole the OPEC+ club into extending its supply cuts until June 2020 through an emergency February meeting has faded, with Russia being the main holdout
  • Amid the turmoil in the markets, the US active rig count remained unchanged for the week, adding two oil sites but losing gas and miscellaneous sites for a total of 790
  • Oil prices gained over the week as the Covid-19 pandemic looks to be contained; Brent should trade in a higher US$57-59/b range and WTI at US$43-55/b


Headlines of the week

Upstream

  • Saudi Arabia and Kuwait have officially restarted production from their shared Wafra field in the Neutral after five years of halted output
  • Despite being hampered by quarterly waivers that are subject to renewals by the US government, Chevron has ramped up production at its Petropiar crude upgrader plant in Venezuela to 130,000 b/d after being closed for most of 2019
  • Canada’s Alberta province’s plan to ease its crude glut through rail shipments has hit a snag, as protestors blocked train lines and the provincial government ordered trains to reduce speeds after a major derailment and fire
  • Tullow Oil reports that it has received approval from Ghana to flare gas ‘when necessary’ from its offshore fields, which should help the beleaguered company support production levels after a set of disappointing results for 2019
  • Somalia has passed a new petroleum bill into law, with the aim of setting up a regulatory framework to attract foreign upstream investment; Somalia currently does not produce any oil but estimates suggest significant reserves
  • As Uganda prepares to start producing oil for the first time, distribution and transport infrastructure remain an issue, with the state recently tapping a Chinese lender to build three roads to connect to its western oilfields
  • After a challenging few years of scandals and a subsequent refocusing on upstream, Petrobras has now hit a new upstream production record, with the ramp-up in pre-salt basins contributing to 3.025 mmboe/d in Q4 2019
  • CNOOC has commenced production at the offshore Bozhong 34-9 field in the Bohai Sea, with peak output expected at 22,500 b/d of crude by 2022

Midstream/Downstream

  • The Covid-19 Wuhan outbreak has claimed a few more refinery scalps, with ChemChina shutting down its 100 kb/d Zhenghe refinery in Shandong and reducing processing at its Changyi and Huaxing refineries by 10%; Hengli Petrochemical has cut utilisation rates at its new 400 kb/d Dalian refinery by some 17% as well, as petchem demand dries up
  • The 120,000 b/d Azzawiya Oil Refining Company refinery in Libya has been forced to halt all operations, as a prolonged conflict in the country has dried up the availability of crude for export or local refining
  • Egypt has given the go-ahead for a US$2.5 billion, 65 kb/d oil refinery in the Upper Egypt region, focusing on hydrocracking mazut – heavy, low quality fuel oil typically used for power generation – into high-value fuels
  • The Bangladesh Petroleum Corp has awarded a tender to supply some 1.06 million tons of gasoil, jet fuel, fuel oil and gasoline to Unipec and Vitol
  • Vietnam’s Nghi Son refining has offered a cargo of gasoil for export for the first time – an indication of slowing domestic demand from the Covid-19 outbreak that is hitting most major East and Southeast Asian economies

Natural Gas/LNG

  • NextDecade Corp’s US$15 billion, 26 million tons per annum Rio Grande LNG facility in Texas has been cleared for LNG exports by the US DoE
  • Portugal’s Sines port is being eyed by US energy companies as a strategic landing point for US LNG exports to Europe, as American LNG exporters race to lock down customers amid a supply glut that could last for years
  • Shell has acquired a 50% stake in Ecopetrol’s Fuerte Sur, Purple Angel and COL-5 gas blocks located in Colombia’s Caribbean deepwater region
February, 21 2020
This Week in Petroleum

Forecast growth in demand for U.S. petroleum and other liquids is not driven by transportation and not supplied by refineries

The U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO) forecasts that in 2021, U.S. consumption (as measured by product supplied) of total petroleum and other liquid fuels will average 20.71 million barrels per day (b/d), surpassing the 2007 pre-recession level of 20.68 million b/d. However, the drivers of this consumption growth have changed. Since the 2007–09 recession, U.S. consumption growth has shifted toward liquid fuels that are used primarily outside the transportation sector and are supplied mostly from non-refinery sources. Despite this shift away from domestic demand for refinery-produced fuels, U.S. refinery runs have increased, and the excess products have been exported, greatly contributing to the United States becoming a net exporter of petroleum in September 2019. EIA expects these trends to continue for at least the next 10 years.

Hydrocarbon gas liquids (HGL) have been the main driver of U.S. petroleum and other liquids demand growth since 2007 (Figure 1). U.S. production and consumption of HGLs—a group of products that include ethane, propane, normal butane and isobutane, natural gasoline, and refinery olefins—have risen with increased natural gas production and demand from an expanding petrochemical sector. As a result, EIA forecasts U.S. HGL consumption will be 1.27 million b/d more in 2021 than in 2007, and will average 3.45 million b/d.

Figure 1. Forecast change in U.S. consumption from 2007 to 2021

With the exception of jet fuel, EIA expects less U.S. consumption of refinery-produced products in 2021 than in 2007. Since 2007, increases in U.S. vehicle miles traveled, which normally increases total motor gasoline consumption, have been countered to some extent by increases in vehicle fuel efficiency. In addition, although U.S. total motor gasoline consumption exceeded 2007 levels for the first time in 2016, increased blending of ethanol into finished motor gasoline has displaced some of the petroleum-based, or refinery-produced, portion of gasoline consumption. Therefore, EIA forecasts 570,000 b/d less consumption of refinery-produced gasoline in the United States in 2021 than in 2007, while ethanol will be 0.5 million b/d higher. Ethanol is almost exclusively produced at non-petroleum refinery sites.

Some HGLs can be produced by both refineries and natural gas processing plants. Natural gas plant liquids (NGPLs)—a subset of HGLs that includes ethane, propane, normal butanes and isobutanes, and natural gasoline—can be extracted from natural gas production streams or produced at refineries that process crude oil. However, as U.S. natural gas production increased from 55.3 billion cubic feet per day (Bcf/d) in 2007 to 98.9 Bcf/d in 2019, the amount of HGLs extracted from natural gas production increased from 1.78 million b/d in 2007 to 4.83 million b/d in 2019. EIA expects HGL production from natural gas processing plants to continue to increase to 5.47 million b/d in 2021. Meanwhile, refinery HGL production has been flat at about 600,000 b/d (Figure 2).

Figure 2. U.S. hydrocarbon gas liquids production by source

Although HGLs have several different end uses, such as propane for space heating and normal butane for blending with motor gasoline, most of the growth in consumption stems from the use of HGLs as feedstock for petrochemical processes. The large increase in U.S. production of HGLs, and the resulting low prices, led to large investments in U.S. infrastructure to extract and transport HGLs to market, as well as investments in petrochemical facilities to consume it. Many of these facilities consume ethane, and to a lesser degree propane and normal butane, as feedstocks to produce intermediate building blocks for plastics, resins, and other materials with nonenergy uses. EIA forecasts that U.S. ethane consumption will reach 1.96 million b/d in 2021, up from 743,000 b/d in 2007, which represents 96% of the increase in U.S. HGL consumption between 2007 and 2021.

Removing HGL and ethanol consumption from the total demand for U.S. petroleum and other liquids indicates that EIA’s 2021 forecast U.S. demand for principally refinery-produced products is about 16.31 million b/d, on par with the 1997 level (Figure 3).

Figure 3. U.S. total petroleum and other liquids demand

Despite domestic demand shifting away from traditionally refinery-produced products, U.S. refinery capacity has increased 1.7 million b/d between 2007 and 2019. U.S. refineries have adapted to falling domestic demand for certain products, such as residual fuel, by investing in downstream coking capacity to upgrade it into more valuable products. More importantly, international demand for refinery-produced products has increased since 2007, allowing U.S. refineries to increase runs and utilization beyond what the domestic market demanded to supply products to export markets. As a result, the United States became a net exporter on an annual basis of distillate and residual fuel in 2008, of jet fuel in 2011, and of motor gasoline in 2016.

Similarly, demand for HGLs outside of the United States has increased and caused U.S exports of HGLs to increase from 70,000 b/d in 2007 to 2.07 million b/d in November 2019. Between 2013 and 2016, exports of HGLs were the largest contributor to the increase in U.S. exports of petroleum products. U.S. exports of HGLs are mostly of propane and ethane to markets in Asia and Europe, where they are also displacing refinery-produced naphtha as a petrochemical feedstock.

EIA projects that these trends of increasing U.S. production of HGLs, increasing domestic consumption of HGLs, and increasing exports of HGLs will continue beyond 2021. EIA’s Annual Energy Outlook 2020 (AEO2020), released in January, shows projections for further growth in HGL production at natural gas processing plants from 4.91 million b/d in 2019 to a peak of 6.58 million b/d in 2029 and then slowly decline to 6.17 million b/d by 2050. Domestic consumption of HGLs will also increase, driven by continued petrochemical demand for feedstock, which rises from about 3.14 million b/d in 2019 to more than 4.0 million b/d in 2029. Meanwhile, in the AEO2020 Reference case, U.S. consumption of motor gasoline declines until 2042, distillate consumption declines until 2040, and residual fuel consumption continues declining out to 2050.

U.S. average regular gasoline prices rise, diesel prices decline

The U.S. average regular gasoline retail price increased nearly 1 cent from the previous week to $2.43 per gallon on February 17, 11 cents higher than the same time last year. The Midwest price rose nearly 5 cents to $2.31 per gallon. The Rocky Mountain price fell more than 3 cents to $2.47 per gallon, the West Coast price fell 1 cent to $3.14 per gallon, the East Coast price fell nearly 1 cent to $2.36 per gallon, and the Gulf Coast price declined by less than 1 cent to $2.08 per gallon.

The U.S. average diesel fuel price fell 2 cents from the previous week to $2.89 per gallon on February 17, 12 cents lower than a year ago. The Rocky Mountain price fell nearly 4 cents to $2.86 per gallon, the East Coast price fell more than 2 cents to $2.94 per gallon, the Midwest and Gulf Coast prices each fell nearly 2 cents to $2.76 per gallon and $2.66 per gallon, respectively, and the West Coast price fell more than 1 cent to $3.47 per gallon.

Residential heating oil prices increase, propane prices decrease

As of February 17, 2020, residential heating oil prices averaged more than $2.91 per gallon, almost 1 cent per gallon above last week’s price but more than 31 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged $1.80 per gallon, more than 5 cents per gallon above last week’s price but 34 cents per gallon lower than a year ago.

Residential propane prices averaged more than $1.98 per gallon, less than 1 cent per gallon below last week’s price and nearly 45 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.56 per gallon, more than 1 cent per gallon higher than last week’s price but almost 27 cents per gallon below last year’s price.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 3.0 million barrels last week to 74.3 million barrels as of February 14, 2020, 18.4 million barrels (32.9%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories decreased by 1.1 million barrels, 1.0 million barrels, 0.6 million barrels, and 0.4 million barrels, respectively. Propylene non-fuel-use inventories represented 7.5% of total propane/propylene inventories.

February, 21 2020
EIA expects natural gas production and exports to continue increasing in most scenarios

According to projections published in the U.S. Energy Information Administration’s (EIA) Annual Energy Outlook 2020 (AEO2020), total dry natural gas production in the United States will continue to increase until 2050 in most of the AEO2020 cases, primarily to support growing U.S. exports of natural gas to global markets. The United States began exporting more natural gas than it imports on an annual basis in 2017, driven by increased liquefied natural gas (LNG) exports, increased pipeline exports to Mexico, and reduced imports from Canada. In most of the AEO2020 cases, net natural gas exports continue to increase through 2050, and most of the increase is in the near term.

The AEO2020 Reference case represents EIA’s best assessment of how U.S. and world energy markets will operate through 2050, assuming no significant changes in energy policy occur. Side cases show the effects of changing model assumptions: the High and Low Oil Price cases simulate international conditions that could drive crude oil prices higher or lower, and the High and Low Oil and Gas Supply cases vary production costs and resource recoverability within the United States.

U.S. dry natural gas production, AEO2020 reference case

Source: U.S. Energy Information Administration, Annual Energy Outlook 2020

EIA expects dry natural gas production to total 34 trillion cubic feet (Tcf) in 2019 once the final data is in. In the AEO2020 Reference case, EIA projects that U.S. dry natural gas production will reach 45 Tcf by 2050. Production growth results largely from continued development of tight and shale resources in the East, Gulf Coast, and Southwest regions, which more than offsets production declines in other regions. Dry natural gas production from these three regions accounted for 68% of total U.S. dry natural gas production in 2019 and, in the Reference case, 78% of dry natural gas production in 2050.

Most of the increase in dry natural gas production is coming from natural gas formations such as the Marcellus and Utica in the East region and the Haynesville in the Gulf Coast region. A smaller but still significant portion of the growth is from natural gas production in oil formations (also known as associated gas), especially in the Permian Basin in the Southwest region.

U.S. natural gas trade, aeo2020 reference case

Source: U.S. Energy Information Administration, Annual Energy Outlook 2020

In the Reference case, both U.S. natural gas exports by pipeline and U.S. LNG exports continue to grow through 2030. LNG exports account for most of the export growth because more LNG export facilities are becoming operational and more projects are under construction. In the Reference case, EIA projects that LNG exports will almost triple, from 1.7 Tcf in 2019 to 5.8 Tcf in 2030, the equivalent of nearly 16 billion cubic feet per day (Bcf/d). LNG exports remain at this level through 2050 as U.S.-sourced LNG becomes less competitive in world markets and as more countries become global LNG suppliers.

U.S. LNG exports are more competitive when oil prices are high (as in the High Oil Price case) and U.S. natural gas prices are low (as in the High Oil and Gas Supply case) because of pricing structures that link Brent crude oil prices to LNG prices in many world markets. In the High Oil Price case, U.S. natural gas net exports reach nearly 13 Tcf by the late 2030s, most of which is LNG. Conversely, in the Low Oil Price case and Low Oil and Gas Supply case, U.S. LNG is less competitive globally and remains lower than 5 Tcf per year through 2050.

By comparison, pipeline trade of U.S. natural gas is less sensitive to changes in assumptions about domestic natural gas supply and world oil prices. Pipeline trade of natural gas is highest in the High Oil and Gas Supply case because low domestic natural gas prices reduce U.S. natural gas imports from Canada.

U.S. natural gas net trade

Source: U.S. Energy Information Administration, Annual Energy Outlook 2020

February, 20 2020