Changing nature of non-OPEC supply types may be affecting the crude oil futures market
Changes in the oil investment and production cycle may be affecting trading dynamics for West Texas Intermediate (WTI) and Brent crude oil futures contracts. Many U.S. producers that may have traditionally hedged production years in advance may now only need to hedge using short-dated portions of the futures curve. Many domestic producers have shifted their production portfolios toward tight oil production, which has a short investment and production cycle, and could be reducing their participation in long-dated WTI futures. For example, the ratio of open interest for WTI contract months 13 and longer to current U.S. monthly production has declined since 2013. In contrast, as of October 2019, a similar ratio for Brent crude oil to production outside the Organization of the Petroleum Exporting Countries (OPEC) and the United States increased to its third-highest level, suggesting increased liquidity in long-dated Brent futures (Figure 1). Brent is the relevant crude oil benchmark used among non-OPEC, non-U.S. oil producers. Similar research from the U.S. Commodity Futures Trading Commission (CFTC) published last year suggests the lower open interest among long-dated WTI futures contracts is a result of the changing investment and production cycle for U.S. oil production. In contrast, new upstream projects outside the United States are primarily deepwater projects, which have a long investment and production horizon. These qualities could be contributing to increased participation in the long-dated portion of the Brent future curve.
Financial markets are tightly connected with physical crude oil supply and demand. Because the dynamics of the financial markets are discussed less frequently in U.S. Energy Information Administration (EIA) publications, EIA included a glossary of key terms at the end of this article.
Trading volume for long-dated Brent crude oil futures contracts is higher than WTI (Figure 2). Market participants’ increased use of these long-dated Brent futures contracts could reflect some of the production growth in non-OPEC countries, particularly in countries other than the United States, such as Brazil and Norway. EIA forecasts that next year, crude oil and other liquids production in non-OPEC countries other than the United States will grow at the fastest rate since 2014, increasing by 0.6 million barrels per day (b/d) from 45.9 million b/d, the estimated 2019 production level. Deepwater offshore projects are the main type of upstream project expected to come online and contribute to production growth next year. These projects typically take years to develop but also have relatively shallow decline rates once in production. For market participants, such qualities could make using long-dated futures contracts attractive for managing financial risk.
Most of the total trading volume for both Brent and WTI is for crude oil contracts 1 through 12—which represent approximately the next calendar year of delivery—and about 5% of the volume is for contract months 13 and longer. Although total trading volume for contracts 1 through 12 is higher for WTI than for Brent, the long-dated contracts of Brent typically have more trading volume than those of WTI, particularly since 2014. Volume for long-dated Brent futures contracts was 11 million contracts in 2019 through October, and WTI volume was 10 million contracts for the same period. September 2019 trading volume for long-dated Brent futures contracts was the third highest ever at 1.6 million contracts for the month.
Open interest—the stock of futures contracts outstanding—has also shifted more to Brent. Long-dated Brent open interest increased to a higher level than WTI long-dated open interest beginning in about 2015 and remained higher for most months since then (Figure 3). As of October 2019, WTI long-dated open interest remains lower than its all-time high of 0.69 million contracts in September 2013, averaging 0.54 million contracts in October 2019. Long-dated Brent open interest averaged 0.61 million contracts in October 2019, slightly lower than the all-time high of 0.62 million contracts in October 2017.
These changes in trading volume and open interest could reflect the different investment horizons for upstream oil supply projects, particularly the different types of upstream projects in the United States compared with those in other non-OPEC countries. The increase in crude oil production in the United States during the past decade has been primarily from tight shale formations in the Lower 48 states, which generally have shorter investment and production cycles than the types of upstream projects financed in other non-OPEC countries. EIA’s Short-Term Energy Outlook model for U.S. Lower 48 crude oil production, for example, acknowledges that changes in Lower 48 states’ crude oil production follow changes in prices and rig counts, with about a four-to six-month lag. In contrast, offshore deepwater projects often take years of appraisal and development before production volumes come online. EIA forecasts that offshore production from Brazil and Norway will be the largest contributors to non-OPEC liquids production growth outside of the United States in 2020 (Figure 4).
The different types of upstream projects could be reflected in the volume and open interest trends for WTI and Brent. For the WTI futures contract, although the long-dated open interest is only slightly lower than levels earlier in the decade, the levels are low relative to the significant increase in U.S. crude oil and other liquids production since then, as shown in the ratio of the open interest to production in Figure 1. In other words, pre-2014 WTI consistently had more than one barrel in long-dated futures contract open interest per barrel of existing production, suggesting high liquidity for producers that wished to hedge future production. Using this same metric for long-dated Brent contracts compared with non-OPEC production outside the United States, Brent remains lower than WTI, but it has increased significantly since the beginning of the decade, suggesting increasing liquidity in long-dated Brent futures contracts.Glossary
Futures market: A trade center for quoting prices on contracts for delivering a specified quantity of a commodity at a specified time and place in the future. Market participants primarily use the crude oil futures market to manage financial risk associated with price uncertainty.
Volume: The number of futures contracts traded per month, which can vary seasonally.
Short-dated vs. long-dated: For the purposes of this article, listed futures contracts 1 through 12—approximately one calendar year into the future—is considered short-dated, and futures contract months 13 and longer is considered long-dated. Long-dated futures contracts’ trading volume and open interest are lower than short-dated futures contracts primarily because most participants—such as money managers or trading companies—can meet their financial management needs using the first few months of the futures curve. Crude oil producers that use the futures market to hedge future planned production often use the long-dated portions of the futures curve.
Open interest: The total number of futures contracts outstanding that have not yet been settled financially or through physical delivery. One futures contract represents 1,000 barrels of crude oil.
Liquidity: The ability of market participants to enter and exit trades quickly and with low transaction costs. Although liquidity can be measured several ways, in general, futures contracts with higher volume and open interest tend to be more liquid than those with lower volume and open interest.
U.S. average regular gasoline price increases, diesel price decreases
The U.S. average regular gasoline retail price rose nearly 1 cent from the previous week to $2.61 per gallon on November 4, 15 cents lower than the same time last year. The Rocky Mountain price increased more than 5 cents to $2.79 per gallon, the East Coast price rose by more than 2 cents to $2.48 per gallon, and the Midwest price rose by nearly 1 cent to $2.42 per gallon. The Gulf Coast price fell by nearly 2 cents to $2.23 per gallon, while the West Coast price remained unchanged at $3.60 per gallon.
The U.S. average diesel fuel price fell by less than 1 cent, remaining virtually unchanged at $3.06 per gallon on November 4, 28 cents lower than a year ago. The East Coast price fell nearly 2 cents to $3.04 per gallon, the Gulf Clast price declined by more than 1 cent to $2.80 per gallon, and the Midwest price fell by less than 1 cent, remaining at $2.96 per gallon. The Rocky Mountain price increased by more than 8 cents to $3.17 per gallon, and the West Coast price increased more than 2 cents to $3.75 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 0.3 million barrels last week to 100.2 million barrels as of November 1, 2019, 11.1 million barrels (12.5%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast and East Coast inventories each increased by 0.5 million barrels, and Rocky Mountain/West Coast inventories increased by 0.1 million barrels. Midwest inventories decreased by 0.8 million barrels. Propylene non-fuel-use inventories represented 4.6% of total propane/propylene inventories.
Residential heating fuel prices increase
As of November 4, 2019, residential heating oil prices averaged almost $2.98 per gallon, nearly 1 cent per gallon above last week’s price but nearly 38 cents per gallon below last year’s price at this time. Wholesale heating oil prices averaged almost $2.04 per gallon, nearly 5 cents per gallon less than last week’s price and almost 25 cents per gallon less than a year ago.
Residential propane prices averaged more than $1.89 per gallon, nearly 5 cents per gallon higher than last week’s price but almost 53 cents per gallon lower than a year ago. Wholesale propane prices averaged nearly $0.69 per gallon, 8 cents per gallon higher than last week’s price but more than 18 cents per gallon below last year’s price.
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At the start of February, a major new find was jointly announced by the two largest emirates within the UAE: the oil-rich Abu Dhabi and the ambitious Dubai. Between them, they literally made the world’s largest natural gas discovery since 2005. Located at the border between the two sheikdoms, the Jebel Ali field is estimated to contain some 80 trillion scf of natural gas, the largest global find since the Galkynysh field in Turkmenistan.
Stretching over 5,000 square km, an exploration campaign by Abu Dhabi involving over 10 wells confirmed the enormous discovery in early January 2020. The shallow nature of the onshore reserves should make it easier to extract gas at lower costs, hastening the time-to-market. At current estimated figures, Jebel Ali would be the fourth-largest gas field in the Middle East, behind Qatar’s North Field, Iran’s South Pars and Abu Dhabi’s own Bab field.
The politics of the UAE can be complicated; each emirate is essentially self-governing with federal oversight, which is dominated by Abu Dhabi and Dubai (which always hold the President and Prime Minister roles, according to convention). This essentially means that each emirate has grew quite independently. Fujairah, for example, developed into a bunkering port, while Sharjah went into industry and manufacturing. Dubai is globally famous for its titanic real estate projects, pursued finance, services and media, while Abu Dhabi, the largest and most blessed of all with hydrocarbon resources, turned into an energy powerhouse. Oil & gas wealth in the UAE is mainly in Abu Dhabi; so while the Jebel Ali discovery is a welcome addition for Abu Dhabi, it is a game changer for Dubai, which imports most of its energy needs.
Speculation has raised that possibility that the Jebel Ali field could vault the UAE into gas self-sufficiency, because even Abu Dhabi imports gas. The UAE has a stated goal to be gas independent by 2030. On paper, that’s possible. Abu Dhabi’s ADNOC has agreed to develop the field with Dubai’s gas supplier, the Dubai Supply Authority (DUSUP), with the entire supply will be channel to DUSUP for use in Dubai. Jebel Ali could begin producing gas by 2023, and will likely be distributed domestically through pipeline. The enormous reserves could supply the entire UAE’s gas demand for nearly 30 years, assuming optimal recovery conditions. However, in practice, self-sufficiency might take longer to achieve.
Dubai and indeed, Abu Dhabi are currently reliant on Qatar for their gas supply. An existing sales agreement that expires in 2032 sees Qatar pipe 2 bcf/d of gas to the UAE through Abu Dhabi. The problem is that these neighbours are erstwhile friends. A division in the Middle East between the pro-Saudi Arabia and pro-Iran blocs has caused a rift. Led by Saudi Arabia, several Persian Gulf states including the UAE implemented a diplomatic and trade blockade on Qatar, isolating it. The blockade, slightly weakened, still continues today. Even now, planes flying into Qatar have to make strange manoeuvres when approaching to avoid encroaching on Saudi and UAE airspace. However, the gas supply arrangement remains in place.
And this is where the Jebel Ali discovery could come in handy. Qatar is already on track to be self-sufficient in gas terms by 2025, but will probably honour the Qatar deal until expiration. Dubai has been increasingly reliant on LNG through an FSRU for power generation, but has attempted over the years to kick-start a number of coal or solar-power projects. Jebel Ali won’t kick the addiction, but it could definitely reduce Dubai’s reliance on Qatari gas.
Jebel Ali wasn’t the only recent gas discovery made in the UAE. Further north, the Sharjah National Oil Corp and Italy’s Eni announced a new onshore gas and condensate discovery. Though tiny in comparison to Jebel Ali, some 50 mscf/d of lean gas and condensate. The cumulative effects of these discoveries could make gas self-sufficiency a reality sooner. At this point, the UAE consumes some 7.4 bcf gas per day, while marketed production is some 6.2 bcf/d. An ambitious plan to develop Abu Dhabi’s large gas fields was the rationale behind naming the 2030 self-sufficiency deadline. With the discovery of Jebel Ali, that can now be brought forward by a couple of years at least. And there might even be some left over to be exported as LNG
The UAE Major Gas Projects:
Headline crude prices for the week beginning 17 February 2020 – Brent: US$53/b; WTI: US$49/b
Headlines of the week
Forecast growth in demand for U.S. petroleum and other liquids is not driven by transportation and not supplied by refineries
The U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO) forecasts that in 2021, U.S. consumption (as measured by product supplied) of total petroleum and other liquid fuels will average 20.71 million barrels per day (b/d), surpassing the 2007 pre-recession level of 20.68 million b/d. However, the drivers of this consumption growth have changed. Since the 2007–09 recession, U.S. consumption growth has shifted toward liquid fuels that are used primarily outside the transportation sector and are supplied mostly from non-refinery sources. Despite this shift away from domestic demand for refinery-produced fuels, U.S. refinery runs have increased, and the excess products have been exported, greatly contributing to the United States becoming a net exporter of petroleum in September 2019. EIA expects these trends to continue for at least the next 10 years.
Hydrocarbon gas liquids (HGL) have been the main driver of U.S. petroleum and other liquids demand growth since 2007 (Figure 1). U.S. production and consumption of HGLs—a group of products that include ethane, propane, normal butane and isobutane, natural gasoline, and refinery olefins—have risen with increased natural gas production and demand from an expanding petrochemical sector. As a result, EIA forecasts U.S. HGL consumption will be 1.27 million b/d more in 2021 than in 2007, and will average 3.45 million b/d.
With the exception of jet fuel, EIA expects less U.S. consumption of refinery-produced products in 2021 than in 2007. Since 2007, increases in U.S. vehicle miles traveled, which normally increases total motor gasoline consumption, have been countered to some extent by increases in vehicle fuel efficiency. In addition, although U.S. total motor gasoline consumption exceeded 2007 levels for the first time in 2016, increased blending of ethanol into finished motor gasoline has displaced some of the petroleum-based, or refinery-produced, portion of gasoline consumption. Therefore, EIA forecasts 570,000 b/d less consumption of refinery-produced gasoline in the United States in 2021 than in 2007, while ethanol will be 0.5 million b/d higher. Ethanol is almost exclusively produced at non-petroleum refinery sites.
Some HGLs can be produced by both refineries and natural gas processing plants. Natural gas plant liquids (NGPLs)—a subset of HGLs that includes ethane, propane, normal butanes and isobutanes, and natural gasoline—can be extracted from natural gas production streams or produced at refineries that process crude oil. However, as U.S. natural gas production increased from 55.3 billion cubic feet per day (Bcf/d) in 2007 to 98.9 Bcf/d in 2019, the amount of HGLs extracted from natural gas production increased from 1.78 million b/d in 2007 to 4.83 million b/d in 2019. EIA expects HGL production from natural gas processing plants to continue to increase to 5.47 million b/d in 2021. Meanwhile, refinery HGL production has been flat at about 600,000 b/d (Figure 2).
Although HGLs have several different end uses, such as propane for space heating and normal butane for blending with motor gasoline, most of the growth in consumption stems from the use of HGLs as feedstock for petrochemical processes. The large increase in U.S. production of HGLs, and the resulting low prices, led to large investments in U.S. infrastructure to extract and transport HGLs to market, as well as investments in petrochemical facilities to consume it. Many of these facilities consume ethane, and to a lesser degree propane and normal butane, as feedstocks to produce intermediate building blocks for plastics, resins, and other materials with nonenergy uses. EIA forecasts that U.S. ethane consumption will reach 1.96 million b/d in 2021, up from 743,000 b/d in 2007, which represents 96% of the increase in U.S. HGL consumption between 2007 and 2021.
Removing HGL and ethanol consumption from the total demand for U.S. petroleum and other liquids indicates that EIA’s 2021 forecast U.S. demand for principally refinery-produced products is about 16.31 million b/d, on par with the 1997 level (Figure 3).
Despite domestic demand shifting away from traditionally refinery-produced products, U.S. refinery capacity has increased 1.7 million b/d between 2007 and 2019. U.S. refineries have adapted to falling domestic demand for certain products, such as residual fuel, by investing in downstream coking capacity to upgrade it into more valuable products. More importantly, international demand for refinery-produced products has increased since 2007, allowing U.S. refineries to increase runs and utilization beyond what the domestic market demanded to supply products to export markets. As a result, the United States became a net exporter on an annual basis of distillate and residual fuel in 2008, of jet fuel in 2011, and of motor gasoline in 2016.
Similarly, demand for HGLs outside of the United States has increased and caused U.S exports of HGLs to increase from 70,000 b/d in 2007 to 2.07 million b/d in November 2019. Between 2013 and 2016, exports of HGLs were the largest contributor to the increase in U.S. exports of petroleum products. U.S. exports of HGLs are mostly of propane and ethane to markets in Asia and Europe, where they are also displacing refinery-produced naphtha as a petrochemical feedstock.
EIA projects that these trends of increasing U.S. production of HGLs, increasing domestic consumption of HGLs, and increasing exports of HGLs will continue beyond 2021. EIA’s Annual Energy Outlook 2020 (AEO2020), released in January, shows projections for further growth in HGL production at natural gas processing plants from 4.91 million b/d in 2019 to a peak of 6.58 million b/d in 2029 and then slowly decline to 6.17 million b/d by 2050. Domestic consumption of HGLs will also increase, driven by continued petrochemical demand for feedstock, which rises from about 3.14 million b/d in 2019 to more than 4.0 million b/d in 2029. Meanwhile, in the AEO2020 Reference case, U.S. consumption of motor gasoline declines until 2042, distillate consumption declines until 2040, and residual fuel consumption continues declining out to 2050.
U.S. average regular gasoline prices rise, diesel prices decline
The U.S. average regular gasoline retail price increased nearly 1 cent from the previous week to $2.43 per gallon on February 17, 11 cents higher than the same time last year. The Midwest price rose nearly 5 cents to $2.31 per gallon. The Rocky Mountain price fell more than 3 cents to $2.47 per gallon, the West Coast price fell 1 cent to $3.14 per gallon, the East Coast price fell nearly 1 cent to $2.36 per gallon, and the Gulf Coast price declined by less than 1 cent to $2.08 per gallon.
The U.S. average diesel fuel price fell 2 cents from the previous week to $2.89 per gallon on February 17, 12 cents lower than a year ago. The Rocky Mountain price fell nearly 4 cents to $2.86 per gallon, the East Coast price fell more than 2 cents to $2.94 per gallon, the Midwest and Gulf Coast prices each fell nearly 2 cents to $2.76 per gallon and $2.66 per gallon, respectively, and the West Coast price fell more than 1 cent to $3.47 per gallon.
Residential heating oil prices increase, propane prices decrease
As of February 17, 2020, residential heating oil prices averaged more than $2.91 per gallon, almost 1 cent per gallon above last week’s price but more than 31 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged $1.80 per gallon, more than 5 cents per gallon above last week’s price but 34 cents per gallon lower than a year ago.
Residential propane prices averaged more than $1.98 per gallon, less than 1 cent per gallon below last week’s price and nearly 45 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.56 per gallon, more than 1 cent per gallon higher than last week’s price but almost 27 cents per gallon below last year’s price.
Propane/propylene inventories decline
U.S. propane/propylene stocks decreased by 3.0 million barrels last week to 74.3 million barrels as of February 14, 2020, 18.4 million barrels (32.9%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories decreased by 1.1 million barrels, 1.0 million barrels, 0.6 million barrels, and 0.4 million barrels, respectively. Propylene non-fuel-use inventories represented 7.5% of total propane/propylene inventories.