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Last Updated: May 30, 2017
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OPEC extended oil production cuts last week and oil prices plunged.

OPEC’s goal was to keep a floor under current prices but the market expected the cartel to move prices higher through inventory reduction. OPEC was satisfied with greater revenues from higher prices compared to a year ago, but the market wanted deeper production cuts. OPEC takes the long view but the market is concerned with the near term. OPEC extended the cuts and the market reacted with lower prices.

Analysts have created the unfounded but widely accepted belief that OPEC has a strategy that involves a price war with U.S. tight oil producers and a play for greater market share. The cartel’s inaction before last November’s production cuts reflected an unwillingness to repeat the mistake of cutting 14 million barrels per day between 1980 and 1985 with little effect on world over-supply and financial damage for OPEC members.

OPEC’s  members have disparate needs and interests. They are not unified behind any mission statement or over-arching principles except to maximize revenues and minimize losses. IEA calculated that recent production cuts earned the cartel an additional $75 million per day year-over-year in the first quarter of 2017. It also was a gift to competitors so the idea of making deeper cuts had no cost benefit.

Last week’s price plunge was the third time in 2017 that prices have adjusted downward toward the $45 per barrel level suggested by market fundamentals (Figure 1). 300w, 768w, 470w" sizes="(max-width: 1024px) 100vw, 1024px">

Figure 1. Third Deflation of the OPEC Expectation Premium in 2017. Source: EIA, Bloomberg and Labyrinth Consulting Services, Inc.

At first, OPEC did nothing after oil prices collapsed in 2014. When prices fell to $26 per barrel in early 2016, OPEC floated the idea of a production freeze and that established a floor from which prices increased to more than $50 per barrel during the first half of the year (Figure 2). 300w, 768w, 470w" sizes="(max-width: 1024px) 100vw, 1024px">

Figure 2. Oil Markets Continue Testing $55 Ceiling & $45 Floor. Source: EIA, CBOE, Bloomberg and Labyrinth Consulting Services, Inc.

In June 2016, markets lost faith in OPEC’s resolve and prices fell from $51 to below $40 per barrel. OPEC then set another price floor by announcing tentative agreement on a production cut. When prices fell below $43 in November, another price floor was created when OPEC enacted production cuts.

The world price floor moved up almost 75% from $26 to $45 per barrel in just over a year. That looks like success to me. Production cuts were extended last week to reinforce the current $45 floor without helping the competition too much—not to meet market expectations of higher prices.

Oil traders understand this better than analysts and they began unwinding their long positions in February. Net long positions on WTI futures have fallen 25% since then but most of the sell-off has been since April 2017 (Figure 3). 300w, 768w, 470w" sizes="(max-width: 1024px) 100vw, 1024px">

Figure 3. Net Long Futures Positions Have Fallen 17% Since Mid-April 2017 and 25% Since March 2017. Source: CFTC, EIA and Labyrinth Consulting Services, Inc.

Reasons For Lower Prices

Many analysts proclaim that Brent prices will be near $65 by the end of the year. Although IEA and EIA production data suggests good OPEC compliance with the November agreement, global markets remain well supplied.  OPEC shipments to its biggest customers—the U.S. and China—are more than 10% higher than a year ago. Production cuts are not reflected in well-supplied markets nor are global inventories falling much.

Market concerns are valid that U.S. tight oil output may cancel OPEC production cuts. Despite frack crew shortages and limits to pressure pumping equipment, 2017 well completion rates appear strong in the Bakken, Eagle Ford and Permian basin plays (Figure 4). 300w, 768w, 470w" sizes="(max-width: 1024px) 100vw, 1024px">

Figure 4. Increased Tight Oil Well Completion in 2017. Source: EIA and Labyrinth Consulting Services, Inc.

OECD comparative inventory for April was approximately 300 million barrels above the 5-year average. The price vs. comparative inventory yield curve suggests that Brent is as much as $7 per barrel over-valued at $52 per barrel (Figure 5).  If recent withdrawal levels hold, it may take a year to reduce inventories to levels that support $65 Brent prices. On the other hand, EIA forecasts suggest relatively minor OECD inventory drawdowns through year-end and rising inventories in 2018. 300w, 768w, 470w" sizes="(max-width: 1024px) 100vw, 1024px">

Figure 5. Brent is ~ $7 over-valued at $52.31. Source: EIA STEO May 2017 and Labyrinth Consulting Services, Inc.

World production surpluses have been falling for the last year but EIA expects these to start increasing as early as May (Figure 6). Surpluses may persist through the middle of 2018 before decreasing again. Its forecast is for Brent prices to remain less than $60 per barrel through the end of 2018. 300w, 768w, 470w" sizes="(max-width: 1024px) 100vw, 1024px">

Figure 6. EIA Forecasts Production Surplus To Increase in the Second Half of 2017 Through the First Half of 2018. Source: EIA STEO May 2017 and Labyrinth Consulting Services, Inc.

Recent modeling by Macquarie Research supports this view and predicts sub-$60 Brent prices through the second quarter of 2019 (Figure 7). 300w, 768w, 470w" sizes="(max-width: 1024px) 100vw, 1024px">

Figure 7. Macquarie Forecasts Brent Prices Below $60 Through the Second Quarter of 2019. Source: Macquarie Research and Labyrinth Consulting Services, Inc.

Although OPEC cuts appear to be real, Macquarie sees U.S., Russia and Brazil production growth as bearish drivers on price. Maintaining OPEC cuts beyond the end of 2017 will be difficult and recent talk of selling half of U.S. strategic reserves potentially puts an additional 300 million barrels of oil on an already over-supplied market.

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In 2018, the United States consumed more energy than ever before

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Primary energy consumption in the United States reached a record high of 101.3 quadrillion British thermal units (Btu) in 2018, up 4% from 2017 and 0.3% above the previous record set in 2007. The increase in 2018 was the largest increase in energy consumption, in both absolute and percentage terms, since 2010.

Consumption of fossil fuels—petroleum, natural gas, and coal—grew by 4% in 2018 and accounted for 80% of U.S. total energy consumption. Natural gas consumption reached a record high, rising by 10% from 2017. This increase in natural gas, along with relatively smaller increases in the consumption of petroleum fuels, renewable energy, and nuclear electric power, more than offset a 4% decline in coal consumption.

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Petroleum consumption in the United States increased to 20.5 million barrels per day (b/d), or 37 quadrillion Btu in 2018, up nearly 500,000 b/d from 2017 and the highest level since 2007. Growth was driven primarily by increased use in the industrial sector, which grew by about 200,000 b/d in 2018. The transportation sector grew by about 140,000 b/d in 2018 as a result of increased demand for fuels such as petroleum diesel and jet fuel.

Natural gas consumption in the United States reached a record high 83.1 billion cubic feet/day (Bcf/d), the equivalent of 31 quadrillion Btu, in 2018. Natural gas use rose across all sectors in 2018, primarily driven by weather-related factors that increased demand for space heating during the winter and for air conditioning during the summer. As more natural gas-fired power plants came online and existing natural gas-fired power plants were used more often, natural gas consumption in the electric power sector increased 15% from 2017 levels to 29.1 Bcf/d. Natural gas consumption also grew in the residential, commercial, and industrial sectors in 2018, increasing 13%, 10%, and 4% compared with 2017 levels, respectively.

Coal consumption in the United States fell to 688 million short tons (13 quadrillion Btu) in 2018, the fifth consecutive year of decline. Almost all of the reduction came from the electric power sector, which fell 4% from 2017 levels. Coal-fired power plants continued to be displaced by newer, more efficient natural gas and renewable power generation sources. In 2018, 12.9 gigawatts (GW) of coal-fired capacity were retired, while 14.6 GW of net natural gas-fired capacity were added.

U.S. fossil fuel energy consumption by sector

Source: U.S. Energy Information Administration, Monthly Energy Review

Renewable energy consumption in the United States reached a record high 11.5 quadrillion Btu in 2018, rising 3% from 2017, largely driven by the addition of new wind and solar power plants. Wind electricity consumption increased by 8% while solar consumption rose 22%. Biomass consumption, primarily in the form of transportation fuels such as fuel ethanol and biodiesel, accounted for 45% of all renewable consumption in 2018, up 1% from 2017 levels. Increases in wind, solar, and biomass consumption were partially offset by a 3% decrease in hydroelectricity consumption.

U.S. energy consumption of selected fuels

Source: U.S. Energy Information Administration, Monthly Energy Review

Nuclear consumption in the United States increased less than 1% compared with 2017 levels but still set a record for electricity generation in 2018. The number of total operable nuclear generating units decreased to 98 in September 2018 when the Oyster Creek Nuclear Generating Station in New Jersey was retired. Annual average nuclear capacity factors, which reflect the use of power plants, were slightly higher at 92.6% in 2018 compared with 92.2% in 2017.

More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

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A New Frontier for LNG Pricing and Contracts

How’s this for a first? As the world’s demand for LNG continues to grow, the world’s largest LNG supplier (Shell) has inked an innovative new deal with one of the world’s largest LNG buyers (Tokyo Gas), including a coal pricing formula link for the first time in a large-scale LNG contract. It’s a notable change in an industry that has long depended on pricing gas off crude, but could this be a sign of new things to come?

Both parties have named the deal an ‘innovative solution’, with Tokyo Gas hailing it as a ‘further diversification of price indexation’ and Shell calling it a ‘tailored solutions including flexible contract terms under a variety of pricing indices.’ Beneath the rhetoric, the actual nuts and bolts is slightly more mundane. The pricing formula link to coal indexation will only be used for part of the supply, with the remainder priced off the conventional oil & gas-linked indexation ie. Brent and Henry Hub pricing. This makes sense, since Tokyo Gas will be sourcing LNG from Shell’s global portfolio – which includes upcoming projects in Canada and the US Gulf Coast. Neither party provided the split of volumes under each pricing method, meaning that the coal-linked portion could be small, acting as a hedge.

However, it is likely that the push for this came from Tokyo Gas. As one of the world’s largest LNG buyers, Tokyo Gas has been at the forefront of redefining the strict traditions of LNG contracts. Reading between the lines, this deal most likely does not include any destination restriction clauses, a change that Tokyo Gas has been particularly pushing for. With the trajectory for Brent crude prices uncertain – owing to a difficult-to-predict balance between OPEC+ and US shale – creating a third link in the pricing formula might be a good move. Particularly since in Japan, LNG faces off directly with coal in power generation. With the general retreat from nuclear power in the country, the coal-LNG battle will intensify.

What does this mean for the rest of the industry? Could coal-linked contracts become the norm? The industry has been discussing new innovations in LNG contracts at the recent LNG2019 conference in Shanghai, while the influx of new American LNG players hungry to seal deals has unleashed a new sense of flexibility. But will there be takers?

I am not a pricing expert but the answer is maybe. While Tokyo Gas predominantly uses natural gas as its power generation fuel (hence the name), it is competing with other players using cheaper coal-based generation. So in Japan, LNG and coal are direct competitors. This is also true in South Korea and much of Southeast Asia. In the two rising Asian LNG powerhouses, however, the situation is different. In China – on track to become the world’s largest LNG buyer in the next two decades – LNG is rarely used in power generation, consumed instead by residential heating. In India – where LNG imports are also rising sharply – LNG is primarily aimed at petrochemicals and fertiliser. LNG based power generation in China and India could see a surge, of course, but that will take plenty of infrastructure, and time, to build. It is far more likely that their contracts will be based off existing LNG or natural gas benchmarks, several of which are being developed in Asia alone.

If it takes off  the coal-link LNG formula is likely to remain a Asian-based development. But with the huge volumes demanded by countries in this region, that’s still a very big niche. Enough perhaps for the innovation to slowly gain traction elsewhere, next stop -  Europe?

The Shell-Tokyo Gas Deal:

Contract – April 2020-March 2030 (10 Years)

Volume – 500,000 metric tons per year

Source – Shell global portfolio

Pricing – Formula based on coal and oil & gas-linked indexes

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