Oil prices will be lower for longer—that is the conventional wisdom. Data suggests, however, that oil supplies are tightening and that higher prices are likely in the relatively near-future.
Refined Product Demand and Crude Oil Exports
U.S. crude oil plus products comparative inventories have fallen 120 mmb (million barrels) in 26 of the last 32 weeks (Figure 1). Strong domestic demand for refined products and increased crude oil exports are the main reasons. That translates into lower net imports of both crude oil and petroleum products to the United States. The year-to-date average of U.S. product net imports is down 0.5 mmb/day from 2016. That’s 3.5 mmb/week which is about the average weekly storage withdrawal since mid-February.
Figure 1. Approximately 3.3 mmb/week (470 kb/d) Decrease in Net Petroleum Product Imports Account for Most Inventory Reductions in 2017. Comparative Inventories Have Fallen 126 mmb Since Mid-February. Source: EIA and Labyrinth Consulting Services, Inc.
U.S. crude oil exports have increased reaching a record 1.9 mmb/d during the week ending September 29 (Figure 2).
Figure 2. Record Crude Exports of 1.9 mmb/d Week Ending Sept. 29 2017. Source: EIA and Labyrinth Consulting Services, Inc.
Increased exports have been part of how producers cope with limited U.S. refining capacity for the ultra-light oil from tight oil plays. Recent increases in exports levels, however, are because of higher international oil prices compared with domestic prices.
Brent has traded at a premium to WTI since U.S. tight oil became a factor in global supply in late 2010. That was largely because of limited take-away and refining capacity for the new U.S. supply in the early days of tight oil production. The Brent-WTI “spread” reached $28 per barrel in September 2011 but decreased when infrastructure caught up with supply. It averaged about $1.68 in the first half of 2017.
In June, the spread began increasing and is currently almost $7 per barrel (Figure 3). Some of this is a “fear premium” because of tensions in the Middle East—the GCC boycott of Qatar and the Iraqi Kurdish independence referendum. Some of it is also a buildup of inventories at the Cushing, Oklahoma storage facility and WTI pricing point.
Figure 3. Brent Premium to WTI Has Increased More Than $5/barrel From 1H Average. Middle East Fear Premium plus Cushing Inventory Levels are the Cause. Source: EIA and Labyrinth Consulting Services, Inc.
Inventory increases at Cushing may be partly explained by refinery and pipeline outages following recent hurricanes but the build ups actually began in July a month before Hurricane Harvey. The causes are not entirely clear but rising inventories at Cushing especially when its storage exceeds 80% is generally a negative factor for WTI prices.
In addition to crude oil, exports of distillate, liquefied petroleum gases, and liquefied refinery gases have also increased in 2017.
Comparative Inventories and The Yield Curve
Falling U.S. comparative inventories (C.I.) in 2017 is a trend and not an anomaly. Figure 4 shows the 120 mmb decrease in C.I. since mid-February and the associated “yield curve” (Bodell, 2009) that correlates inventory with WTI price.
Figure 4. U.S. Crude + Product Comparative Inventory Has Fallen 120 mmb Since Mid-February–Yield Curve Suggests Higher Oil Prices Sooner Than Later. Source: EIA and Labyrinth Consulting Services, Inc.
The magnitude of the inventory drawdown cannot be over-stated. The fact that it is driven by increasing demand suggests that that U.S. supply is moving steadily toward balance.
OECD comparative inventory (less the U.S.) has fallen 99 mmb since July 2016 (Figure 5). Although the data frequency is lower (monthly vs. weekly) and less systematic than U.S. inventory data, the reduction in C.I. is the main point.
Figure 5. OECD (minus U.S.) Comparative Inventory Has Fallen 99 mmb Since July 2016. Source: EIA, IEA and Labyrinth Consulting Services, Inc.
The relative lack of price increase with falling C.I. for both the U.S. and OECD is because the yield curve was flat for much of the reduction because of the the magnitude of storage volume. Now, enough inventory has been drawn down that the curvature of the trend is increasing. Greater price response with incremental reduction in C.I. is likely as volumes approach the 5-year average.
Misplaced Concern About Shale Supply
Fears about burgeoning U.S. supply from shale reservoirs has been a consistent drag on market sentiment about price for at least a year. This has been based more on rig count than real evidence. Continental Resources chairman Harold Hamm has loudly blamed overly optimistic EIA supply forecasts for low U.S. oil prices. This is misplaced and typical of the hyperbole regularly heard from shale company executives.
The fact is that U.S. output has been flat since early 2017 and the EIA has adjusted its forecasts as data replaces sampling algorithms in their accounting (Figure 6).
Figure 6. U.S. Output Has Been Flat in 2017. Source: EIA and Labyrinth Consulting Services, Inc.
The reason is that despite increased drilling, frack crews and equipment are not sufficient to meet demand for well completions. Pressure pumping equipment was not maintained and parts were cannibalized after the oil price collapse, and crews were laid off. It may take another year of strong demand to rebuild this capacity.
The result is that far more tight oil wells are being drilled than completed and I expect that this pattern will continue (Figure 7).
Figure 7. More Permian Wells Have Been Drilled Than Completed in 2016 and 2017. The Number of DUCs (Drilled Uncompleted Wells) is Increasing. Source: EIA and Labyrinth Consulting Services, Inc.
Fears that DUCs (drilled uncompleted wells) will flood the market with supply are unrealistic. When these wells are completed, it will be gradual and the natural ~30% annual decline in legacy shale production will be difficult to overcome. Moreover, production from the Eagle Ford and Bakken plays is declining. Only Permian production is increasing and on balance, it is unlikely that net shale production will increase much unless production trends outside the Permian basin somehow reverse.
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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