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Last Updated: January 4, 2018
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n 2017, oil prices recovered significantly. Posting its second annual gain in a row, the commodity closed 2017 up more than 12%. The U.S. oil benchmark ended the year at $60.42 per barrel -- its highest closing since June 2015. 

However, this wasn't reflected in the budgeted exploration spending in 2018. The companies are still allocating capital on existing assets and ongoing developments. Oil giants like Anadarko Petroleum and Chevron CVX have announced exploration budget for 2018, which is lower or almost in line with 2017 figures.

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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
U.S. natural gas production, consumption, and exports set new records in 2018

U.S. natural gas dry production, consumption, and exports

Source: U.S. Energy Information Administration, Natural Gas Annual 2018

The U.S. Energy Information Administration’s (EIA) Natural Gas Annual 2018 shows that the United States set new records in natural gas production, consumption, and exports in 2018. In 2018, dry natural gas production increased by 12%, reaching a record-high average of 83.8 billion cubic feet per day (Bcf/d). This increase was the largest percentage increase since 1951 and the largest volumetric increase in the history of the series, which dates back to 1930. U.S. natural gas consumption increased by 11% in 2018, driven by increased natural gas consumption in the electric power sector. Natural gas gross exports totaled 10.0 Bcf/d in 2018, 14% more than the 2017 total of 8.6 Bcf/d. Several new liquefied natural gas (LNG) export facilities came online in 2018, allowing for more exports.

U.S. consumption of natural gas by sector

Source: U.S. Energy Information Administration, Natural Gas Annual 2018

U.S. natural gas consumption grew in each end-use sector. Demand for natural gas as a home heating fuel was greater in 2018 than in 2017 because of slightly colder weather during most of the winter. Similarly, the summer of 2018 saw record-high temperatures that increased demand for air conditioning and, therefore, electricity—much of which was fueled by natural gas. U.S. electric power sector consumption of natural gas grew by 14% in 2017, more than in any other end-use sector. The electric power sector has been shifting toward natural gas in the past decade because of favorable prices and efficiency gains.

dry natural gas production by state for 2017 and 2018

Source: U.S. Energy Information Administration, Natural Gas Annual 2018

U.S. natural gas production growth was concentrated in the Appalachian, Permian, and Haynesville regions. Pennsylvania and Ohio, states that overlay the Appalachian Basin, had the first- and third-largest year-over-year increases for 2018, increasing by 2.0 Bcf/d and 1.7 Bcf/d, respectively. Louisiana had the second-largest volumetric increase in dry production, increasing by 1.8 Bcf/d as a result of increased production from the Haynesville shale formation. Texas remained the top natural gas-producing state, with a production level of 18.7 Bcf/d, as a result of continued drilling activity in the Permian Basin in western Texas and eastern New Mexico.

November, 18 2019