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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The amount of natural gas held in storage in 2019 went from a relatively low value of 1,155 billion cubic feet (Bcf) at the beginning of April to 3,724 Bcf at the end of October because of near-record injection activity during the natural gas injection, or refill, season (April 1–October 31). Inventories as of October 31 were 37 Bcf higher than the previous five-year end-of-October average, according to interpolated values in the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report.
Although the end of the natural gas storage injection season is traditionally defined as October 31, injections often occur in November. Working natural gas stocks ended the previous heating season at 1,155 Bcf on March 31, 2019—the second-lowest level for that time of year since 2004. The 2019 injection season included several weeks with relatively high injections: weekly changes exceeded 100 Bcf nine times in 2019. Certain weeks in April, June, and September were the highest weekly net injections in those months since at least 2010.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report
From April 1 through October 31, 2019, more than 2,569 Bcf of natural gas was placed into storage in the Lower 48 states. This volume was the second-highest net injected volume for the injection season, falling short of the record 2,727 Bcf injected during the 2014 injection season. In 2014, a particularly cold winter left natural gas inventories in the Lower 48 states at 837 Bcf—the lowest level for that time of year since 2003.
Headline crude prices for the week beginning 4 November 2019 – Brent: US$62/b; WTI: US$56/b
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