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In the August 2018 update of its Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts Brent crude oil prices to average $73 per barrel (b) in the second half of 2018 and decline to an average of $71/b in 2019 (Figure 1). Competing upside and downside price risks are expected to play a large role in price formation during the forecast period. Upside price risks stem largely from the possibility of supply outages when both petroleum inventories and spare crude oil production capacity for members of the Organization of the Petroleum Exporting Countries (OPEC) are lower than average. Downside price risks stem largely from potentially reduced demand because economic growth and resulting crude oil demand could be lower than forecast. 


Daily and monthly average crude oil prices could vary significantly from annual average forecasts because global economic developments and geopolitical events in the coming months have the potential to push oil prices higher or lower than the current STEO price forecast.

EIA forecasts total global liquid fuels inventories to decrease by 0.3 million barrels per day (b/d) in 2018, followed by an increase of 0.3 million b/d in 2019 (Figure 2). Inventory changes of this magnitude should be considered mostly balanced, contributing to forecast Brent crude oil prices remaining between $70/b and $73/b from August 2018 through the end of 2019. However, the forecast for slight inventory increases in 2019 contributes to expectations of modest downward price pressure in 2019.


On the supply side, the combination of relatively low inventory and OPEC spare capacity levels elevates the risk of upward price movements if a supply disruption occurs or if forecast production growth does not materialize. 

Changes in global petroleum inventories data are not collected directly, but are estimated based on forecasts for global production and consumption. However, inventory data for the United States and other countries within the Organization for Economic Cooperation and Development (OECD) are available and may provide insight into global supply. In terms of days of supply, OECD inventories are expected to remain less than the monthly average for the previous five years, so any outages could have a significant effect on crude oil prices (Figure 3).


In 2018 and in 2019, EIA expects OPEC spare crude oil production capacity to decrease from 2017 levels (Figure 4). Although spare capacity in 2016 was lower than that forecast for 2018 and 2019, OECD inventories were higher in 2016, as seen in Figure 3. OPEC spare production capacity is forecast to average 1.6 million b/d in 2018 and to fall to 1.3 million b/d in 2019, down from 2.1 million b/d in 2017 and lower than the 10-year (2008–17) average of 2.3 million b/d. With little spare capacity, risks on the supply side (including greater-than-forecast disruptions in Iran, Venezuela, or Libya) may have significant price impacts.


EIA forecasts OPEC’s petroleum and other liquids production to decrease from the 2017 level of 39.5 million b/d to 39.1 million b/d in 2018 and to 39.0 million b/d in 2019. The small decline in 2019 reflects crude oil production increases from some producers that nearly offset anticipated declines from other OPEC members.

Brent spot prices averaged more than $74/b in June 2018, up $10/b from December 2017. Price increases in 2018 have been largely driven by unplanned supply disruptions and the expected loss of some Iranian crude oil production by the end of the year because of renewed sanctions. The August 2018 STEO reflects the U.S. withdrawal from the Joint Comprehensive Plan of Action (JCPOA) and the plan to reinstate sanctions on companies doing business with Iran. Sanctions will likely affect the Iranian oil sector, which would limit the country’s crude oil production and exports by the end of 2018. Uncertainty remains regarding the degree to which the U.S. sanctions will take Iranian crude oil off the market.

Future crude oil production in Venezuela and Libya and the magnitude of the production response from other OPEC members and Russia are also highly uncertain. Developments regarding these and other variables could influence prices in either direction.

Concerns about the pace of future economic and oil consumption growth have likely contributed to demand side uncertainty. The August STEO forecasts global demand growth for petroleum and other liquids to average 1.66 million b/d in 2018 and 1.57 million b/d in 2019, down from the July STEO forecast of 1.72 million b/d and 1.71 million b/d for 2018 and 2019, respectively.

U.S. average regular gasoline price increases, diesel price decreases

The U.S. average regular gasoline retail price increased less than one cent from last week to remain at $2.85 per gallon on August 6, 2018, up 47 cents from the same time last year. Rocky Mountain and East Coast prices each rose over a penny to $2.92 per gallon and $2.80 per gallon, respectively, and Midwest prices increased less than one cent to $2.77 per gallon. West Coast and Gulf Coast prices each decreased less than one cent to $3.34 per gallon and $2.59 per gallon, respectively.

The U.S. average diesel fuel price decreased less than one cent from last week to $3.22 per gallon on August 6, 2018, 64 cents higher than year ago. Midwest prices fell nearly one cent to $3.15 per gallon, and West Coast, East Coast, and Gulf Coast prices each decreased less than a penny, remaining virtually unchanged at $3.72 per gallon, $3.22 per gallon, and $3.00 per gallon, respectively. Rocky Mountain prices were unchanged at $3.36 per gallon.

Propane/propylene inventories rise slightly

U.S. propane/propylene stocks increased by 0.1 million barrels last week to 66.4 million barrels as of August 3, 2018, 9.3 million barrels (12.2%) lower than the five-year (2013-2017) average inventory level for this same time of year. Gulf Coast inventories increased by 0.3 million barrels and Rocky Mountain/West Coast inventories rose slightly, remaining virtually unchanged. Midwest and East Coast inventories decreased by 0.2 million barrels and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 4.3% of total propane/propylene inventories.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.

Crude oil gasoline STEO (Short-Term Energy Outlook) Petroleum USA Iran Libya Venezuela OPEC OECD
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Your Weekly Update: 9 - 13 September 2019

Market Watch  

Headline crude prices for the week beginning 9 September 2019 – Brent: US$61/b; WTI: US$56/b

  • Hope reigns as the market banks on signs that the US and China could reach a trade deal would eliminate one of the largest risks to current oil prices: a full-blown global recession
  • However, this is merely the latest in a series of dashed hopes that has seen the trade war between the US and China – using tariffs as weapons – escalate dramatically over the year; new tariffs entered play September 1 and more could come, with both sides already feeling the pinch
  • But crude prices did get a lift from EIA data showing that US crude stockpiles fell far more than expected, down by 4.8 million barrels to its lowest level since October 2018 – an indication of strong demand, with US refinery utilisation at 94.8%
  • However, there are fissures appearing on the supply side that could trigger some risk premiums; in Venezuela, the upstream crisis continues with the latest blow being a Chinese contractor halting work over claims over non payment
  • More importantly, Saudi Oil Minister – or rather former Saudi Oil Minister Khalid al-Falih – was dismissed from the government; after initial reports suggested that al-Falih would focus on energy policy after the oil ministry was split, a royal decree issued days later confirmed his sacking
  • Saudi Arabia and its allies have been at pains to re-assure the market that the dismissal of al-Falih – who is respected around the world – will not impact Saudi production or the current OPEC+ supply pact
  • This will be confirmed at the upcoming OPEC+ meeting this week, which will be the first under Saudi Arabia’s new Energy Minister, one of the King’s sons Prince Abdulaziz bin Salman
  • Against this backdrop of turmoil, the active US rig count fell yet again; after two weeks of double-digit losses, US drillers lost four oil and two gas rigs, with losses seen once again in the Permian
  • Power moves within Saudi Arabia may have sent some tremors to the market, but it is likely that OPEC+ will stick to its commitments; with no signs that the US and China were doing anymore more than talking about talking, crude prices will remain rangebound – US$59-61/b for Brent and US$54-56/b for WTI

Headlines of the week

Upstream

  • Total has suspended plans for the US$3.5 billion crude export pipeline that would connect Ugandan oilfield to port facilities in Tanzania after a failure to buy a stake in Tullow Oil’s upstream assets in Uganda linked to tax negotiations; this will require a complete restart for the Uganda project
  • With other supermajors pulling out, Total remains committed to the North Sea, with CEO Patrick Pouyanne looking to invest up to US$10 billion over the next five years but cautions that Total maintain strict cost discipline
  • The Norwegian Petroleum Directorate (NPD) has consented to the startup of the giant Johan Sverdrup field, a potential 660,000 b/d resource that has been called the North Sea’s ‘last hurrah’
  • Permian-focused player Concho Resource has agreed to sell its assets in the New Mexico Shelf to Spur Energy Partners for US$925 million, continuing a wave of consolidation in the US shale arena
  • Shell has announced plans to start drilling in the offshore Saturno field in Brazil, becoming one of the first private players tapping the pre-salt Santos Basin

Midstream/Downstream

  • Sinopec’s new 160 kb/d Yangzi refinery has begun production of Europe-standard gasoline, providing an outlet for Chinese fuel products amid a domestic glut that has seen refiners look overseas for sales
  • Petrobras is extending the deadline for interested parties for its four refineries on sale from September 16 to September 27, citing high investor interest for the refining assets that represent 37% of Brazilian capacity
  • Saudi Aramco continues its downstream push in China, signing an MoU with the Zhejiang Free Trade Zone that could pave the way for further investments beyond current plans to acquire 9% of the Zhejiang Petrochemical refinery
  • Russia’s Sibur will be cutting back LPG exports to Europe to some 2 million tons from a typical 3.5-4 million tons per year, redirecting the LPG to be used as feedstock for its ZapSibNefteKhim petrochemicals plant in Western Siberia

Natural Gas/LNG

  • Months of uncertainty have been put to rest as the government of Papua New Guinea endorsed the US$13 billion Papua LNG project, following some new commitments by project leader Total – primarily on local content
  • Also in PNG, the government has approved Australian independent Twinza Oil’s Pasca gas/condensate project - the country’s first offshore gas project
  • ExxonMobil and its partners have sanctioned plans for the 6.2 mtpa Sakhalin 1 LNG plant on Sakhalin Island in Russia’s far east, with easy access to Japan
  • Argentina’s YPF is pushing ahead with plans to build a US$5 billion LNG export terminal – tapping into the Vaca Muerta shale basin – despite continued domestic political and financial chaos hanging over the project
  • Petronas has agreed to purchase natural gas that is set to produced from the Gorek, Larak and Bakong fields in the SK408 area in Sarawak, jointly operated by SapuraOMV Upstream, Petronas Carigali and Shell
  • Qatar Petroleum has booked 100% of regasification capacity at the Fluxys Zeebrugge LNG terminal until 2044, consolidating Qatar’s hold on one of Northwest Europe’s important gas entry nodes
  • Equinor has brought the Snefrid Nord gas field online, which is the first of several planned projects related to the Aasta Hansteen field to begin production, with an initial output of 4 mcm/d
September, 13 2019
Global gas and LNG outlook to 2035
Expansion in the gas and LNG markets continues, with LNG demand expected to increase 3.6 percent per year to 2035.

Detailed market research and continuous tracking of market developments—as well as deep, on-the-ground expertise across the globe—informs our outlook on global gas and liquefied natural gas (LNG). We forecast gas demand and then use our infrastructure and contract models to forecast supply-and-demand balances, corresponding gas flows, and pricing implications to 2035.

Executive summary

The past year saw the natural-gas market grow at its fastest rate in almost a decade, supported by booming domestic markets in China and the United States and an expanding global gas trade to serve Asian markets. While the pace of growth is set to slow, gas remains the fastest-growing fossil fuel and the only fossil fuel expected to grow beyond 2035.

Global gas: Demand expected to grow 0.9 percent per annum to 2035

While we expect coal demand to peak before 2025 and oil demand to peak around 2033, gas demand will continue to grow until 2035, albeit at a slower rate than seen previously. The power-generation and industrial sectors in Asia and North America and the residential and commercial sectors in Southeast Asia, including China, will drive the expected gas-demand growth. Strong growth from these regions will more than offset the demand declines from the mature gas markets of Europe and Northeast Asia.

Gas supply to meet this demand will come mainly from Africa, China, Russia, and the shale-gas-rich United States. China will double its conventional gas production from 2018 to 2035. Gas production in Europe will decline rapidly.

LNG: Demand expected to grow 3.6 percent per annum to 2035, with market rebalancing expected in 2027–28

We expect LNG demand to outpace overall gas demand as Asian markets rely on more distant supplies, Europe increases its gas-import dependence, and US producers seek overseas markets for their gas (both pipe and LNG). China will be a major driver of LNG-demand growth, as its domestic supply and pipeline flows will be insufficient to meet rising demand. Similarly, Bangladesh, Pakistan, and South Asia will rely on LNG to meet the growing demand to replace declining domestic supplies. We also expect Europe to increase LNG imports to help offset declining domestic supply.

Demand growth by the middle of next decade should balance the excess LNG capacity in the current market and planned capacity additions. We expect that further capacity growth of around 250 billion cubic meters will be necessary to meet demand to 2035.

With growing shale-gas production in the United States, the country is in a position to join Australia and Qatar as a top global LNG exporter. A number of competing US projects represent the long-run marginal LNG-supply capacity.

Key themes uncovered

Over the course of our analysis, we uncovered five key themes to watch for in the global gas market:

  1. Global LNG-price indicators have partially converged with the differentials among Asia, Europe, and the United States, falling to the smallest they have been in longer than a decade.
  2. Asia is leading a third wave of market liberalization after those in the United States and Europe, likely bringing fundamental changes to Asian markets.
  3. Long-term contract-pricing mechanisms are evolving in indexation and slope as gas and oil markets diverge, placing pressure on buyers to reshape their contract portfolios, with up to $15 billion per year at stake.
  4. Substantial new investment is necessary to deliver the infrastructure required to meet demand growth.
  5. Traditional, bilateral business models for LNG are being challenged today, and new business models with an increased focus on commercial and trading capabilities are emerging.
September, 13 2019
LNG – surfing the wave

Challenges in a growing market

Gas looks the best bet of fossil fuels through the energy transition. Coal demand has already peaked while oil has a decade or so of slowing growth before electric vehicles start to make real inroads in transportation. Gas, blessed with lower carbon intensity and ample resource, is set for steady growth through 2040 on our base case projections.

LNG is surfing that wave. The LNG market will more than double in size to over 1000 bcm by 2040, a growth rate eclipsed only by renewables. A niche market not long ago, shipped LNG volumes will exceed global pipeline exports within six years.

The bullish prospects will buoy spirits as industry leaders meet at Gastech, LNG’s annual gathering – held, appropriately and for the first time, in Houston – September 17-19.

Investors are scrambling to grab a piece of the action. We are witnessing a supply boom the scale of which the industry has never experienced before. Around US$240 billion will be spent between 2019 and 2025 on greenfield and brownfield LNG supply projects, backfill and finishing construction for those already underway.

50% to be added to global supply 

In total, these projects will bring another 182 mmtpa to market, adding 50% to global supply. Over 100 mmtpa is from the US alone, most of the rest from Qatar, Russia, Canada, and Mozambique. Still, more capital will be needed to meet demand growth beyond the mid-2020s. But the rapid growth also presents major challenges for sellers and buyers to adapt to changes in the market.

There is a risk of bottlenecks as this new supply arrives on the market. The industry will have to balance sizeable waves of fresh sales volumes with demand growing in fits and starts and across an array of disparate marketplaces – some mature, many fledglings, a good few in between.

Key LNG growth markets face teething problems

India has built three new re-gas terminals, but imports are actually down in 2019. The pipeline network to get the gas to regional consumers has yet to be completed. Pakistan has a gas distribution network serving its northern industrial centres. But the main LNG import terminals are in the south of the country, and the commitment to invest in additional transmission lines taking gas north is fraught with political uncertainty.

China is still wrestling with third-party access and regulation of the pipeline business that is PetroChina’s core asset. Any delay could dull the growth rate in Asia’s LNG hotspot. Europe is at the early stages of replacing its rapidly depleting sources of indigenous piped gas with huge volumes of LNG imports delivered to the coast. Will Europe’s gas market adapt seamlessly to a growing reliance on LNG – especially when tested at extreme winter peaks? Time will tell.

Established business models are changing

The point-to-point business model that has served sellers (and buyers) so well over the last 60 years will be tested by market access and other factors. Buyers facing mounting competition in their domestic market will increasingly demand flexibility on volume and price, and contracts that are diverse in duration and indexation. These traditional suppliers risk leaving value, perhaps a lot of value, on the table.

In the future, sellers need to be more sophisticated. The full toolkit will have a portfolio of LNG, a mixture of equity and third-party contracted gas; a trading capability to optimise on volume and price; and the requisite logistics – access to physical capacity of ships and re-gas terminals to shift LNG to where it’s wanted. Enlightened producers have begun to move to an integrated model, better equipped to meet these demands and capture value through the chain. Pure traders will muscle in too.

Some integrated players will think big picture, LNG becoming central to an energy transition strategy. As Big Oil morphs into Big Energy, LNG will sit alongside a renewables and gas-fired power generation portfolio feeding all the way through to gas and electricity customers.

LNG trumps pipe exports...


  

...as the big suppliers crank up volumes

September, 13 2019