NrgEdge Editor

Sharing content and articles for users
Last Updated: November, 7 2019 10:56:29 AM
1 view
Business Trends
image

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.

Back to Top

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.

Back to Top

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
3
2 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

Geopolitical Tensions Overshadow a Year of Big Discoveries

2019 has been a fairly good year for big hydrocarbon discoveries. After several years of depressed activities, a slew of major upstream finds were announced this year as oil and gas companies recovered from the slump in oil prices to begin drilling once again. Despite the onshore shale revolution, the US Gulf of Mexico keeps giving, with Shell landing a huge oil discovery in the Perdido Corridor. In Russia, Gazprom hit payday with a 17 tcf gas find in the Dinkov and Nyarmeyskoye fields in the Yamal Peninsula. Beyond established upstream basins, large finds have also come in from new frontiers. In South Africa, Total made a huge discovery at Brulpadda that could transform the economy, while in Guyana, ExxonMobil and Tullow keep adding on to a long list of major oil finds dating back to 2015. Up to 8 tcf of gas was hit in Cyprus – though that lies in disputed waters claimed by Turkey – while Kosmos Energy announced the largest gas discovery of the year at the Orca-1 well in Mauritania.

And then there is Iran. Hammered by US sanctions that have severely curbed its oil exports – and scaring off international investors – Iran has continued to go alone in exploration work within its borders. Just last week, Iran announced that it had struck a new field in its southwest that contains up to 53 billion barrels of oil. This single field would increase Iran’s proven oil reserves by a third. In any other scenario, this would be a trigger for a swathe of investment. But in this geopolitical climate, the question instead is: can Iran even develop this field?

To be fair, the Khuzestan field isn’t actually new. Named Namavaran, the reservoir was first probed in 2016, when the relationship between Iran and the West had thawed with the nuclear agreement deal, with an initial 33 billion barrels proven. Since then, additional test wells recently revealed that Namavaran is far bigger than expected. Stretching over 2,400km from Bostan near the Iraqi border to the Omidiyeh province, an additional 20 billion barrels or so were identified, increasing the total figure to 53 billion barrels. Some of this would have been siphoned off from existing assets that were thought to be standalone – including the Ab Teymour, Mansouri, Soosangerd, Darkhovin, Jofeir and Sepehr fields – but even so, the estimated new exploitable reserves from Namavaran number in the 22-27 billion barrel range.

The problem is who will help Iran tap into this. Initially lured by the promise of the geopolitical cooldown, major players such as Total have since abandoned their assets in Iran in the wake of the new US sanctions. Even China is not immune; CNPC also exited the giant South Pars gas project this year while the imposition of sanctions on China Ocean Shipping threw the global tanker market into disarray in October. But it is apparently on China (and Russia) that Iran is depending on. News in the market suggests that Iran is in talks with Chinese companies to develop and commercialise Namavaran, as part of the latter’s Belt and Road global plan. The same news also suggests that a few international firms – hinted to include Shell and Total – are also interested in participating. But given the current tension between Iran and the US and its Middle East allies, foreign participation is a huge question mark at the moment.

A few months ago, it looked like war was imminent in the Middle East. Today, it seems as if the situation has thawed slightly. Some experts even believe that the US may begin easing sanctions – particularly with the exit of ultra-Iran-hawk John Bolton as National Security Advisor. If this happens (and it is a big if), there are many willing parties waiting at Iran’s doors to help exploit the giant Namavaran field. Even if the door is shut, Iran is ready to go ahead alone, not least because it needs a fair amount of oil for its own domestic use. And when this happen, it will spin a new problem: in a world where OPEC is trying desperately to control prices, how will it deal with an Iran whose oil reserves have just increased by a third?

The Namavaran field in Iran:

  • Initial discovery in 2016, expanded discovery in 2019
  • Iran’s second largest field, after Ahvaz
  • Some 53 billion barrel of proven oil in place
  • Increases Iran’s proven oil reserves from 155.6 billion barrels to 208.6 billion barrels
November, 21 2019
EIA increases U.S. crude oil production forecast

The U.S. Energy Information Administration (EIA) revises the U.S. crude oil production forecast it publishes in each Short-Term Energy Outlook (STEO) based mainly on two factors: updates to EIA’s published historical data and EIA’s crude oil price forecast. In the November 2019 STEO, EIA increased its forecast of U.S. crude oil production in 2019 by 30,000 barrels per day (b/d) (0.2%) from the October STEO. EIA increased its 2020 crude oil production forecast by 119,000 b/d (0.9%) compared with the October STEO (Figure 1). The increases in crude oil production forecast in the November STEO were primarily driven by

  • EIA’s upward revision to historical production in the Lower 48 states of about 90,000 b/d for August, based on EIA’s most recent–October 31, 2019–914 monthly crude oil and natural gas production survey
  • Higher initial production for future wells that will be drilled in the Texas Permian region
  • Slightly higher crude oil price forecast for the November 2019–January 2020 time period than in the October STEO

Figure 1. U.S. crude oil production forecast

In the November STEO, EIA increased its U.S. benchmark West Texas Intermediate (WTI) crude oil price forecast by $2 per barrel (b) in November to $56/b and by $1/b in both December and January to $55/b and $54/b, respectively. The slight increase in crude oil prices also contributed to EIA’s increased production forecast for the first half of 2020 because of EIA’s assumption of a six-month lag between a crude oil price change and a production response.

In the November STEO, EIA now forecasts U.S. crude oil production will increase to 12.3 million b/d in 2019 from 11.0 million b/d in 2018. Production in the Permian region is the primary driver of EIA’s forecast crude oil production growth, and EIA forecasts Permian production will grow by 915,000 b/d in 2019 and by 809,000 b/d in 2020 (Figure 2). Increases in Permian production are supported by the crude oil pipeline infrastructure expansion seen earlier this year, which helped alleviate the transportation bottleneck and supported prices for WTI in Midland, Texas (the price producers may expect to receive in the Permian region), relative to prices for WTI-Cushing. The higher relative prices in the Permian should continue to encourage production in the region. EIA forecasts that the Bakken region will have the next largest crude oil production growth in 2019, and it is forecast to grow by 152,000 b/d in 2019 and 96,000 b/d in 2020. EIA forecasts that production in the Federal Offshore Gulf of Mexico will increase by 138,000 b/d in 2019 and 116,000 b/d in 2020.

Figure 2. Monthly U.S. crude oil production by region

Although EIA forecasts that overall U.S. crude oil production will increase, EIA expects the growth rate to decline from 11.8% in 2019 to 8.1% in 2020. One of the primary indicators of a slowdown in production growth is the decline in oil-directed rigs. According to Baker Hughes, active rig counts fell from 877 oil-directed rigs in the beginning of January 2019 to 674 rigs in mid-November. Rig counts in the Permian region also declined during this period, falling from 487 to 408 (Figure 3). Because EIA expects WTI-Cushing crude oil prices to stay below $55/b until August 2020, EIA anticipates that drilling rigs will continue to decline as producers cut back on their capital spending, resulting in notable slowing in the growth of domestic crude oil production over the next 14 months.

Figure 3. Total U.S. and Permian Basin region oil rigs

Although U.S. rig counts are declining, improvements in rig efficiency, which allows fewer rigs to drill the same number of wells, partially offset declining rig counts. In addition, higher initial production from wells (although not necessarily the total estimated ultimate recovery) is offsetting some of the slowdown in rigs.

U.S. average regular gasoline prices fall, diesel prices increase slightly

The U.S. average regular gasoline retail fell more than 2 cents from the previous week to $2.59 per gallon on November 18, 2 cents lower than the same time last year. The West Coast price fell by more than 5 cents to $3.54 per gallon, the Gulf Coast price fell by more than 4 cents to $2.22 per gallon, the East Coast price fell by more than 2 cents to $2.45 per gallon, and the Midwest price fell less than 1 cent, remaining at $2.44 per gallon. The Rocky Mountain price increased by nearly 2 cents to $2.84 per gallon.

The U.S. average diesel fuel price rose by less than 1 cent to remain at $3.07 per gallon on November 18, 21 cents lower than a year ago. The Rocky Mountain price increased by nearly 3 cents to 3.23 per gallon, and the East Coast price rose by less than 1 cent, remaining at $3.05 per gallon. The Gulf Coast price fell by less than 1 cent to $2.79 per gallon, and the West Coast and Midwest prices each decreased by less than 1 cent, remaining at $3.76 per gallon and $2.97 per gallon, respectively.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 3.4 million barrels last week to 94.2 million barrels as of November 15, 2019, 5.8 million barrels (6.6%) greater than the five-year (2014-18) average inventory levels for this same time of year. Gulf Coast and Midwest inventories decreased by 2.5 million barrels and 1.5 million barrels, respectively. East Coast inventories increased by 0.5 million barrels, and Rocky Mountain/West Coast inventories increased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 5.4% of total propane/propylene inventories.

Residential heating fuel prices

As of November 18, 2019, residential heating oil prices averaged almost $2.99 per gallon, more than 1 cent per gallon above last week’s price but 33 cents per gallon below last year’s price at this time. Wholesale heating oil prices averaged nearly $2.06 per gallon, almost 3 cents per gallon more than last week’s price but nearly 13 cents per gallon less than a year ago.

Residential propane prices averaged more than $1.99 per gallon, 5 cents per gallon higher than last week’s price but more than 43 cents per gallon lower than a year ago. Wholesale propane prices averaged nearly $0.85 per gallon, almost 9 cents per gallon higher than last week’s price but nearly 6 cents per gallon below last year’s price.

November, 21 2019
Brazil’s net metering policy leads to growth in solar distributed generation

Brazil’s growth in distributed generation from renewable resources—especially solar—has increased since it implemented net metering policies in 2012. As of mid-November 2019, owners have installed more than 135,000 renewable distributed generation systems in Brazil, totaling about 1.72 gigawatts (GW) of capacity, according to the Brazilian Electricity Regulatory Agency (ANEEL).

Solar photovoltaic accounts for the largest share of the total installed distributed generating resources, representing about 1,571 megawatts (MW), or 91%, of the country’s total distributed generation capacity. Small hydroelectric and wind account for 97 MW and 10 MW, respectively. Net metering policies allow owners of the renewable distributed generation systems to sell excess electricity to the grid for billing credits.

ANEEL’s policy initially allowed small generators using hydro, solar, biomass, wind, and qualified cogeneration of renewable sources of up to 1 MW of capacity to qualify for net metering. In 2015, ANEEL amended the rule to increase the maximum capacity for up to 3 MW for small hydropower and up to 5 MW for other qualified renewable sources.

Qualified generators can choose to sell surplus generated electricity back to Brazil’s grid in return for billing credits. As part of the billing credit structure, net-metering customers can generate credits earned on days when they generated more electricity than they consumed. Before 2015, these credits expired after 36 months, but now credits for excess generation expire after 60 months.

Most of Brazil’s distributed generation units are in the southern, southeastern, and northeastern regions of the country. The states with the most distributed generation units are Minas Gerais with 372 MW, Rio Grande do Sul with 223 MW, and São Paulo with 194 MW.

Brazil distributed generation by technology

Source: U.S. Energy Information Administration, based on data from the Brazilian Electricity Regulatory Agency (ANEEL)

At the end of 2018, ANEEL released a regulatory impact analysis and conducted a series of public hearing meetings to discuss economic aspects and sustainable growth of distributed generation in the country.

November, 20 2019