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.
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.'
• 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.
• 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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The U.S. Energy Information Administration’s (EIA) latest Petroleum Supply Monthly shows the significant changes in petroleum markets that occurred in April, when most of the United States was under stay-at-home orders to limit the spread of coronavirus. In April, commercial crude oil inventories increased by 46.7 million barrels (10%)—the largest monthly increase in EIA data going back to 1920. U.S. refineries operated at 70% of their capacity, the lowest utilization rate in EIA’s monthly data series dating back to 1985. Demand for finished petroleum products fell to 11.7 million barrels per day (b/d), the lowest level since at least 1981.
April’s crude oil inventory increase is a result of refinery runs falling more quickly than crude oil supply, which is determined by domestic production and imports. U.S. crude oil production in April averaged 12.1 million b/d, a decrease of 669,000 b/d (5%) from March. This decrease represents the largest month-over-month decline since September 2008, when Hurricanes Ike and Gustav hit the U.S. Gulf Coast. U.S. crude oil imports fell by 776,000 b/d (12%) from March to April, further decreasing crude oil supply in the United States.
The combined drop in production and imports was smaller than the decline in gross inputs to refineries, resulting in record increases in crude oil inventories. Based on estimates in EIA’s Weekly Petroleum Status Report, commercial crude oil inventories reached a record high of 541 million barrels in the week ending June 19 and have fallen slightly in the weeks since then.
Source: U.S. Energy Information Administration, Petroleum Supply Monthly
Changes in travel patterns resulted in the lowest levels of U.S. demand for finished petroleum products (as measured by product supplied) in decades. Transportation fuels have been affected differently by changes in travel: demand for jet fuel and motor gasoline fell much more than distillate fuel, which is primarily consumed as diesel. From March to April, product supplied of finished motor gasoline decreased a record 1.9 million b/d (25%) to 5.9 million b/d, the lowest monthly value since the mid-1970s.
In the span of two months, U.S. demand for jet fuel fell by more than half, from 1.6 million b/d in February to 691,000 b/d in April. Before April, U.S. jet fuel demand had not been less than 700,000 b/d since the mid-1970s.
Distillate demand fell by 408,000 b/d, or about 10%, from March to April. Although the change in distillate demand was less drastic than the changes in motor gasoline and jet fuel demand, distillate consumption in April 2020 was the lowest in more than a decade.
Exports of natural gas to Mexico by pipeline are the largest component of U.S. natural gas trade, accounting for 40% of all U.S. gross natural gas exports in 2019. EIA expects these exports to increase with the completion of the southern-most segment of the Wahalajara system, the Villa de Reyes-Aguascalientes-Guadalajara (VAG) pipeline. VAG began operations in June 2020, connecting new demand markets in Mexico to U.S. natural gas pipeline exports.
The Wahalajara system is a group of new pipelines that connects the Waha hub in western Texas, a major supply hub for Permian Basin natural gas producers, to Guadalajara and other population centers in west-central Mexico. The Wahalajara system provides U.S. natural gas to meet growing demand from Mexico’s electric power and industrial sectors. With the 0.89 billion cubic feet per day (Bcf/d) VAG pipeline entering service, EIA expects utilization of the Wahalajara system to quickly ramp up, resulting in increased U.S. natural gas exports to Mexico out of western Texas and additional takeaway capacity out of the Permian Basin.
Since 2016, Mexico has been expanding its natural gas pipeline system, which has supported continual growth in U.S. natural gas exports. Most of this growth has been in U.S. natural gas exports from southern Texas after the existing U.S. pipeline infrastructure was expanded and the Los Ramones Phase II pipeline in central Mexico was completed.
Since the Sur de Texas-Tuxpan pipeline was completed in September 2019, U.S. natural gas exports to Mexico reached a record 5.5 Bcf/d in October 2019. U.S. natural gas exports from the border at Brownsville, Texas, to the southeastern state of Veracruz in Mexico averaged 0.6 Bcf/d during the last quarter of 2019, or about 20% of the pipeline’s capacity.
Overall, U.S. natural gas exports from this region have only increased by 0.2 Bcf/d from 2016 to 2019 because of delays in pipeline construction in Mexico. In particular, two regional pipelines were completed in 2017 but have not been used near their capacity:
Source: U.S. Energy Information Administration, Natural Gas Monthly
The Comanche Trail pipeline has been delivering an average of 0.1 Bcf/d of natural gas to Mexico since the San Isidro-Samalayuca pipeline entered service in June 2017. Pipeline operators do not expect flows to rise until the 0.47 Bcf/d Samalayuca-Sásabe pipeline is completed in either late 2020 or early 2021 in Mexico.
The Trans-Pecos pipeline, the U.S. segment of the Wahalajara system, did not transport significant volumes of natural gas until October 2018; it is currently only operating at 10% to 15% of its total capacity. Most of the demand centers are in southern Mexico, waiting to be connected to the VAG pipeline. Three of the project’s four pipelines in Mexico that are currently in-service include
Before the economic impacts and uncertainty associated with COVID-19 mitigation efforts and declining crude oil prices, S&P Global Platts expected U.S. natural gas exports to Mexico to increase immediately by 0.3 Bcf/d to 0.4 Bcf/d on the Wahalajara system. However, given the decreased demand for natural gas in Mexico in response to the economic impact of COVID-19 mitigation efforts, growth is likely to be slower than expected. Beyond these volumes, additional export volumes will be limited by how quickly customers in Mexico can be connected to the pipeline system.
These connections include new natural gas-fired combined-cycle generators and the scheduled 2020 completion of the 0.89 Bcf/d Tula-Villa de Reyes pipeline, which will deliver natural gas to central Mexico. Deliveries from the Wahalajara network are likely to partially displace higher-cost liquefied natural gas (LNG) imports into Mexico’s Manzanillo terminal, which serves markets in Guadalajara and Mexico City.
As U.S. natural gas exports on the Wahalajara system rise and crude oil prices remain low, EIA expects the price at the Waha hub in the Permian Basin, which had been steeply discounted to the Henry Hub national benchmark, to continue to strengthen.
Officially, we are past the half point of 2020 and with that the end of the second quarter. And what a quarter it has been. WTI prices plunged into negative territory (as low as -US$37/b) then recovered to US$40/b as OPEC+ moved from infighting to coordinating the largest crude production cut in history. In between, the Covid-19 pandemic wreaked havoc with the global economy, setting off a chain reaction within the oil world whose full impact is still unknown.
Opinions on a post-Covid oil world are divided. Some voices, the more optimistic ones, think that oil demand could recover to pre-Covid levels within a year or two. The more pessimistic ones think that this will never happen, that Covid-19 has hastened the trend away from fossil fuels to sustainable energy against the backdrop of climate change. Either way, this has thrown a spanner in the works of the giant, multi-billion oil and gas projects that were announced over the past two years as the energy world began to wake up from its post-2015 price crash investment hibernation. Those projects were made at a time when oil prices were at US$50-60/b. Since oil prices are now only at US$40/b, the current value and the future worth of these assets have now declined. Energy companies account for this by adjusting the value of their portfolios in accordance to the projected value of crude: an upward adjustment is known as a revaluation, and a negative one is known as an impairment.
This is a term that will crop up many times over 2020, as energy companies close their quarterly financial books and report their results to shareholders. The plunge in crude oil prices and the uncertain outlook for oil demand means that publicly-traded companies must account for this to their shareholders. Chevron was the first supermajor to book an impairment, in late 2019 when it took a US$10 billion hit to its oil and gas assets. It wasn’t the only one: firms all across the oil chain also reduced the value of their assets, from Repsol to Equinor.
Further impairments were made in April 2020 when the Q1 financial results were announced, mainly in response to the triggering of the OPEC+ price war (which saw crude prices halve from US$60/b to US$30/b) and the Covid-19 pandemic accelerating to a point where over half of the world’s population went into lockdown. But the major impact will come in Q2 2020, when the roil in the oil markets truly began to boil uncontrollably. BP has announced that it may take up to a US$17.5 billion impairment in its Q2 2020 financial results, while Shell has just admitted that it may have to shave US$22 billion from its asset value.
This has roots not just in the depressed demand for energy due to Covid-19, but also the ongoing conversation on climate change. Almost all supermajors have announced intentions to become carbon neutral by the 2050 timeframe. That may be good news for the planet, but it is bad news for the companies’ portfolio. Put simply, it means that some of the assets that they have invested billions in are now not only worth a lot less (due to Covid-19) but they may in fact be worth nothing at all, because climate change considerations mean that they will never be exploited. Challenging projects such as Total’s deepwater Brulpadda discovery in turbulent South African waters or Pertamina/ExxonMobil/Total/PTTEP’s beleaguered and complicated East Natuna sour gas asset in Indonesia may never be commercialised, either because of uneconomic prices or because they run counter to the goal of becoming carbon neutral. The Financial Times estimates that the amount of unviable or stranded hydrocarbon assets could reach as much as US$900 billion; that figure is pre-Covid, and could now become even higher.
There is one supermajor bucking the trend though. The biggest supermajor of all, in fact. Unlike its peers, ExxonMobil has not yet succumbed to impairments. If fact, it has not announced any negative revaluations at all over the past decade, even during the 2015 oil price crash. ExxonMobil claims that this is because it books the value of new assets ‘very conservatively’ and does not ‘adjust values to short-term price trends’, but critics say that it has an ongoing history of vastly overestimating its assets’ value. Along with Chevron, ExxonMobil does not disclose price assumptions in its financials. But unlike Chevron, ExxonMobil has not yielded to climate change through an official emissions target or asset revaluations.
On paper, that will make ExxonMobil look better than its supermajor brothers. But behind the scenes, this reluctance to admit that the future is less rosy than expected could be trouble waiting to be unleashed. Impairments are a necessary reality check: an admission by a company that things have changed and it is starting to adapt. Most have accepted that reality. ExxonMobil seems to be resisting. But even it is not immune. In pre-Q2 2020 results guidance that was just announced, ExxonMobil admitted that it expects to take a hit of some US$3.1 billion and slump to a second straight quarterly loss. In terms of Covid-19 impairments, that’s small. But it is, at least, a start.
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