Russia and Saudi Arabia were coming around to the idea Friday that they need to ease the OPEC/non-OPEC production cuts, which have gone overboard in recent months, removing much more than the 1.72 million b/d of supply they had pledged to curb under the November 2016 agreement.
There was no formal statement by the time we closed this report Friday evening in Asia, but there was talk of putting 1 million b/d more into the market to cool overheated crude prices, according to media reports citing sources privy to the discussions taking place between energy ministers on the sidelines of the St. Petersburg International Economic Forum in Russia.
The proposed addition of 1 million b/d would be a fair correction, in line with our estimate that the market has been deprived of as much as 3 million b/d of supply from the 22 OPEC/non-OPEC producers in the reduction pact in recent months.
Benchmark crude futures, which had closed more than $1/barrel lower Thursday on talk of OPEC looking to ease supply, plummeted by another $2/barrel on Friday’s headlines out of St. Petersburg. Brent, which had pierced the $80/barrel psychological mark a few times during intraday trading over the past fortnight, had slid below $77, while WTI was changing hands under $69 as of 1300 GMT.
Russian Energy Minister Alexander Novak took the lead Thursday, telling reporters that the supply restrictions could be unwound gradually, though the output cut deal should remain in place. Novak said he and Saudi Arabia had a common position on the future of the deal, suggesting an amicable meeting of the minds between the de facto leaders of the OPEC and non-OPEC blocs.
Novak, Saudi Energy Minister Khalid Al-Falih, UAE Energy Minister and current OPEC president Suhail al-Mazrouei, and OPEC secretary-general Mohammad Barkindo were scheduled to hold discussions on the global oil markets in St. Petersburg.
The leaders have less than four weeks to chart a new course, which would be formally adopted at the OPEC/non-OPEC ministerial meeting in Vienna on June 22. Deciding to release more barrels into the market might be the easier part. Agreeing on how exactly it will be done could prove to be far more difficult.
A major reason behind the OPEC/non-OPEC supply cuts reaching far deeper than agreed over the past few months has been the inability of several producers in both groups to fulfill their agreed quotas. The most prominent OPEC member with production woes is Venezuela, which languished around 460,000 b/d below its quota of 1.972 million b/d on average in the first four months of this year. Angola has also been struggling to maintain its output, falling short of its target by around 160,000 b/d in April, according to the latest OPEC data.
Libya and Nigeria, which do not have production limits, continue to be plagued by outages from militant attacks on infrastructure. The only voluntary overshooting of the targeted cut within OPEC has been by Saudi Arabia, which could be corrected, but that would put only about 100,000 b/d more into the market.
Within the non-OPEC group of 10 collaborators, Russia has the capacity to raise output by the 300,000 b/d that it took off the market gradually starting in 2017. However, at least three major producers in this bloc — Mexico, Kazakhstan and Azerbaijan — have under-delivered against their targets in recent months, causing a collective shortfall of nearly 730,000 b/d in March, according to the latest monthly data available. Of these, Kazakhstan is expected to catch up to its ceiling in the second half of this year, but not Mexico and Azerbaijan.
This means Russia and Saudi Arabia will have to do most of the heavy lifting to put more barrels into the market. That would mark a major departure from OPEC’s policy of apportioning any agreed reductions or additions in supply to all members in proportion to their share of the group’s overall production.
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Headline crude prices for the week beginning 9 September 2019 – Brent: US$61/b; WTI: US$56/b
Headlines of the week
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:
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.
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.
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