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Last Updated: November 7, 2019
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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.

Figure 1. Ratio of futures contract open interest to production

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.

Figure 2. Monthly trading volume

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.

Figure 3. Average daily open interest

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).

Figure 4. Non-OPEC liquid fuels supply growth outside the United States

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.

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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.

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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.

Brazil Brent crude oil financial markets Norway offshore oil petroleum production supply tight oil United States WTI West Texas Intermediate EIA
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Short-Term Energy Outlook

Highlights  

Global liquid fuels

  • Brent crude oil spot prices averaged $60 per barrel (b) in October, down $3/b from September and down $21/b from October 2018. EIA forecasts Brent spot prices will average $60/b in 2020, down from a 2019 average of $64/b. EIA forecasts that West Texas Intermediate (WTI) prices will average $5.50/b less than Brent prices in 2020. EIA expects crude oil prices will be lower on average in 2020 than in 2019 because of forecast rising global oil inventories, particularly in the first half of next year.
  • Based on preliminary data and model estimates, EIA estimates that the United States exported 140,000 b/d more total crude oil and petroleum products in September than it imported; total exports exceeded imports by 550,000 b/d in October. If confirmed in survey-collected monthly data, it would be the first time the United States exported more petroleum than it imported since EIA records began in 1949. EIA expects total crude oil and petroleum net exports to average 750,000 b/d in 2020 compared with average net imports of 520,000 b/d in 2019.
  • Distillate fuel inventories (a category that includes home heating oil) in the U.S. East Coast—Petroleum Administration for Defense District (PADD 1)—totaled 36.6 million barrels at the end of October, which was 30% lower than the five-year (2014–18) average for the end of October. The declining inventories largely reflect low U.S. refinery runs during October and low distillate fuel imports to the East Coast. EIA does not forecast regional distillate prices, but low inventories could put upward pressure on East Coast distillate fuel prices, including home heating oil, in the coming weeks.
  • U.S. regular gasoline retail prices averaged $2.63 per gallon (gal) in October, up 3 cents/gal from September and 11 cents/gal higher than forecast in last month’s STEO. Average U.S. regular gasoline retail prices were higher than expected, in large part, because of ongoing issues from refinery outages in California. EIA forecasts that regular gasoline prices on the West Coast (PADD 5), a region that includes California, will fall as the issues begin to resolve. EIA expects that prices in the region will average $3.44/gal in November and $3.12/gal in December. For the U.S. national average, EIA expects regular gasoline retail prices to average $2.65/gal in November and fall to $2.50/gal in December. EIA forecasts that the annual average price in 2020 will be $2.62/gal.
  • Despite low distillate fuel inventories, EIA expects that average household expenditures for home heating oil will decrease this winter. This forecast largely reflects warmer temperatures than last winter for the entire October–March period, and retail heating oil prices are expected to be unchanged compared with last winter. For households that heat with propane, EIA forecasts that expenditures will fall by 15% from last winter because of milder temperatures and lower propane prices.


Natural gas

  • Natural gas storage injections in the United States outpaced the previous five-year (2014–18) average during the 2019 injection season as a result of rising natural gas production. At the beginning of April, when the injection season started, working inventories were 28% lower than the five-year average for the same period. By October 31, U.S. total working gas inventories reached 3,762 billion cubic feet (Bcf), which was 1% higher than the five-year average and 16% higher than a year ago.
  • EIA expects natural gas storage withdrawals to total 1.9 trillion cubic feet (Tcf) between the end of October and the end of March, which is less than the previous five-year average winter withdrawal. Withdrawal of this amount would leave end-of-March inventories at almost 1.9 Tcf, 9% higher than the five-year average.
  • The Henry Hub natural gas spot price averaged $2.33 per million British thermal units (MMBtu) in October, down 23 cents/MMBtu from September. The decline largely reflected strong inventory injections. However, forecast cold temperatures across much of the country caused prices to rise in early November, and EIA forecasts Henry Hub prices to average $2.73/MMBtu for the final two months of 2019. EIA forecasts Henry Hub spot prices to average $2.48/MMBtu in 2020, down 13 cents/MMBtu from the 2019 average. Lower forecast prices in 2020 reflect a decline in U.S. natural gas demand and slowing U.S. natural gas export growth, allowing inventories to remain higher than the five-year average during the year even as natural gas production growth is forecast to slow.
  • EIA forecasts that annual U.S. dry natural gas production will average 92.1 billion cubic feet per day (Bcf/d) in 2019, up 10% from 2018. EIA expects that natural gas production will grow much less in 2020 because of the lag between changes in price and changes in future drilling activity, with low prices in the third quarter of 2019 reducing natural gas-directed drilling in the first half of 2020. EIA forecasts natural gas production in 2020 will average 94.9 Bcf/d.
  • EIA expects U.S. liquefied natural gas (LNG) exports to average 4.7 Bcf/d in 2019 and 6.4 Bcf/d in 2020 as three new liquefaction projects come online. In 2019, three new liquefaction facilities—Cameron LNG, Freeport LNG, and Elba Island LNG—commissioned their first trains. Natural gas deliveries to LNG projects set a new record in July, averaging 6.0 Bcf/d, and increased further to 6.6 Bcf/d in October, when new trains at Cameron and Freeport began ramping up. Cameron LNG exported its first cargo in May, Corpus Christi LNG’s newly commissioned Train 2 in July, and Freeport in September. Elba Island plans to ship its first export cargo by the end of this year. In 2020, Cameron, Freeport, and Elba Island expect to place their remaining trains in service, bringing the total U.S. LNG export capacity to 8.9 Bcf/d by the end of the year.


Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and to 38% in 2020. EIA forecasts the share of U.S. electric generation from coal to average 25% in 2019 and 22% in 2020, down from 28% in 2018. EIA’s forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, down from almost 8% in 2018. Wind, solar, and other nonhydropower renewables provided 9% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects total U.S. coal production in 2019 to total 698 million short tons (MMst), an 8% decrease from the 2018 level of 756 MMst. The decline reflects lower demand for coal in the U.S. electric power sector and reduced competitiveness of U.S. exports in the global market. EIA expects U.S. steam coal exports to face increasing competition from Eastern European sources, and that Russia will fill a growing share of steam coal trade, causing U.S. coal exports to fall in 2020. EIA forecasts that coal production in 2020 will total 607 MMst.
  • EIA expects U.S. electric power sector generation from renewables other than hydropower—principally wind and solar—to grow from 408 billion kilowatthours (kWh) in 2019 to 466 billion kWh in 2020. In EIA’s forecast, Texas accounts for 19% of the U.S. nonhydropower renewables generation in 2019 and 22% in 2020. California’s forecast share of nonhydropower renewables generation falls from 15% in 2019 to 14% in 2020. EIA expects that the Midwest and Central power regions will see shares in the 16% to 18% range for 2019 and 2020.
  • EIA forecasts that, after rising by 2.7% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.7% in 2019 and by 2.0% in 2020, partially as a result of lower forecast energy consumption. In 2019, EIA forecasts less demand for space cooling because of cooler summer months; an expected 5% decline in cooling degree days from 2018, when it was significantly higher than the previous 10-year (2008–17) average. In addition, EIA also expects U.S. CO2 emissions in 2019 to decline because the forecast share of electricity generated from natural gas and renewables will increase, and the share generated from coal, which is a more carbon-intensive energy source, will decrease.
November, 14 2019
The U.S. placed near-record volumes of natural gas in storage this injection season

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.

weekly net changes in natural gas storage

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.

November, 11 2019
Your Weekly Update: 4 - 8 November 2019

Market Watch  

Headline crude prices for the week beginning 4 November 2019 – Brent: US$62/b; WTI: US$56/b

  • Good broader economic data helped push crude prices up, as better-than-expected US job numbers and a big uptick in Chinese manufacturing orders allayed some fears over the health of the global economy
  • Those worries still persist, but the upbeat data does show that the slowdown might not be prolonged, especially if the US and China manage to hammer out a comprehensive trade deal that White House officials have hinted is in the works
  • The USA, under Trump, has formally withdrawn from the Paris climate accord, placing the USA as one of only 3 countries not to be a party to the comprehensive collection of emission reductions by country
  • OPEC production rebounded to 29.7 mmb/d in October, recovering from the 1.23 mmb/d drop in September caused by the attacks on Saudi crude facilities
  • Having recently lost Qatar and Ecuador, OPEC – via Saudi Arabia – has reportedly informally reached out to Brazil to join the oil club, highlighting the growing importance of Brazilian output; President Jair Bolsonaro has indicated that he would be ‘eager to accept’ the offer
  • Ahead of the OPEC meeting in Vienna on 5-7 December, Saudi Aramco is now scheduled for public listing on the Saudi stock exchange on December 11; this might lead to a push for a deeper or longer tenure for the current supply deal at the Vienna meeting, as Aramco seeks to bolster its valuation
  • The massacre in onshore drilling countries in the US, as the Baker Hughes index indicates that five oil and three gas rigs were dropped last week for a net loss of 8 and a total of 822, as bankruptcies increase in major shale areas
  • There isn’t much room for crude prices to grow in the current environment; indeed, prices are likely to trade with a downward bias at US$58-60/b for Brent and US$53-55/bd for WTI

Headlines of the week

Upstream

  • Total has chosen to sell off its 86.95% stake in Brunei’s offshore Block CA1 to Shell for some US$300 million in line with its global non-core asset divestment
  • Myanmar’s delayed upstream licensing round has now been set for early 2020, with the government aiming to pass a draft oil and gas bill before moving ahead
  • Apache expects to bring two ‘high volume’ wells in the North Sea online over the next two months, with Storr operating by November and Garten by the end of the year, which could double its current 54,000 b/d North Sea output
  • A new offshore oil discovery has been announced in Equatorial Guinea by Kosmos Energy, with the S-5 well in the Rio Muni Basin yielding crude flows

Midstream/Downstream

  • ExxonMobil has put its refinery in Billings, Montana up for sale once again, looking to fetch US$500 million for the 60 kb/d plant, with interested buyers including Valero and Marathon
  • Russia is moving ahead with settling the cases of contaminated crude oil transported via its Druzhba pipeline; Lukoil and Hungary’s MOL have signed a settlement deal, while Total has opted to sell its 720,000-barrel cargo on the open market at a discount of over US$25/b
  • Saudi Aramco may be gaining a bigger foothold in Africa, as NNPC announced plans to collaborate with the Saudi oil firm to revamp Nigeria’s four ailing state refineries that are buckling from age
  • Marathon has folded under pressure from activist investors, announcing that it will be spinning off its fuel retail business while also reviewing a future possibility to spin off its pipeline business as well
  • ALFA Mexico’s petchems subsidiary Alpek has agreed to acquire PET manufacturer Lotte Chemical UK from South Korea’s Lotte Chemical
  • Kuwait Petroleum has started up the 2,264 b/d LPG processing plant at its Mina al-Ahmedi refinery, focusing on delivering LPG for petchems usage

Natural Gas/LNG

  • Kosmos Energy has announced a ‘major’ gas discovery in Mauritania at its Orca-1 well; combined with the Marsouin-1 discovery in the BirAllah, Orca-1 is the largest deepwater oil and gas discovery so far in 2019 and could underpin standalone LNG development in the West African nation
  • BP has announced it is on track to start production from the deepwater Raven field in Egypt by end-2019 – the third stage of its West Nile Delta project that also encompasses the producing Giza and Fayoum developments
  • Denmark’s state energy regulator has given permission for the controversial Nord Stream 2 pipeline to be built in its waters to connect Russia to Germany
  • Plans to expand the Sakhalin-2 LNG plant in Russia’s far east have been put on hold, reportedly due to a lack of gas resources and international sanctions in place, with Gazprom also looking to pipe gas to China instead of liquefying
  • Cheniere expects its Corpus Christi LNG Train 3 in Texas to start-up ahead of its previous timeline of 2H2021, while also expecting to begin operations at the Sabine Pass LNG Train 6 in Louisiana by 1H2023
  • Turkey’s state energy firm Botas is accepting tenders for up to 70 cargoes of LNG for delivery over 2020-2023, as it aims to diversify its gas sources
  • Sempra Energy and Japan’s Mitsui & Co have signed a new MoU to collaborate on more LNG projects, including the Cameron LNG Phase 2 and the future expansion of the Energia Costa Azul project in Baja California
November, 08 2019