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Last Updated: October 1, 2019
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The U.S. Energy Information Administration (EIA) projects that global carbon dioxide (CO2) emissions from energy-related sources will continue to grow in the coming decades. EIA’s International Energy Outlook 2019 (IEO2019) projects that global energy-related CO2 emissions will grow 0.6% per year from 2018 to 2050 in its Reference case. However, future growth in energy-related CO2 emissions is not evenly distributed across the world: relatively developed economies collectively have no emissions growth, so all of the future growth in energy-related CO2 emissions is among the group of countries outside the Organization for Economic Cooperation and Development (OECD).

Countries outside of the OECD collectively have more population, a larger gross domestic product, more energy consumption, and higher energy-related CO2 emissions compared with aggregated values from OECD countries. In IEO2019, growth rates for these data series are also higher for non-OECD countries than for OECD countries.

global economic, energy, and environmental metrics in IEO2019 reference case

Source: U.S. Energy Information Administration, International Energy Outlook 2019
Note: Gross domestic product values are expressed in 2010 U.S. dollars, converted based on purchasing power parity (PPP). OECD is the Organization for Economic Cooperation and Development.

As non-OECD countries continue to grow, so does their demand for air conditioning, electronics, personal vehicles, and other energy services. These countries also have relatively energy-intensive industries, primarily because energy-intensive industrial processes often shift to non-OECD countries. Energy consumption in non-OECD countries increases by 1.6% per year from 2018 to 2050, and energy-related CO2 emissions increase by 1.0% per year.

EIA projects that coal-related CO2 emissions in non-OECD countries, especially China, will grow at the slowest rate among fossil fuels as natural gas replaces coal in power generation and in industrial applications. China emits the most energy-related CO2 emissions in the world, and EIA projects that it will remain in that position through 2050. Although India’s coal-related CO2 emissions increase 2.8% annually from 2018 to 2050—the highest among the eight countries in EIA’s international outlook—China remains the single largest emitter of coal-related CO2 emissions in the world.

energy-related co2 emissions in IEO2019 reference case

Source: U.S. Energy Information Administration, International Energy Outlook 2019

By comparison, OECD economies are relatively mature, so many energy services such as air conditioning, electronics, and personal transportation are fairly saturated. Population and economic growth is relatively low compared with non-OECD countries, and technology improvements largely offset increases in energy demand in buildings and vehicles.

OECD economic activity continues to become less energy intensive as these economies shift from energy-intensive manufacturing to less energy-intensive manufacturing and commercial services. EIA projects that energy-related CO2 emissions from OECD countries will decrease slightly (-0.2%) from 2018 to 2050 in the IEO2019 Reference case. OECD CO2 emissions from petroleum liquids and coal consumption decline, but emissions from natural gas consumption increase.

EIA expects the United States to remain the largest emitter of energy-related CO2 emissions among OECD members and the largest emitter of natural gas-related emissions among all countries, regardless of OECD membership, through 2050. Petroleum liquids-related CO2 emissions from the United States and China—the top two petroleum liquids-related CO2 emitters—are relatively similar throughout the projection period. EIA’s IEO2019 Reference case projections for the United States are consistent with those in the Reference case of the Annual Energy Outlook 2019.

On a per capita basis, OECD countries emit far more energy-related CO2 than non-OECD countries: about 9.5 metric tons per person in OECD countries in 2018 compared with 3.6 metric tons per person in non-OECD countries. The gap between those groups is decreasing; by 2050, OECD countries will emit 8.2 metric tons per person compared with 3.8 metric tons per person in non-OECD countries.

Global energy intensities and carbon intensities also continue to decline. By 2032, non-OECD countries are expected to become less energy intensive than OECD countries, meaning they use less energy to generate economic activity. However, non-OECD countries are expected to remain more carbon intensive than OECD countries through 2050, meaning they generate more CO2 emissions per unit of energy consumed. Differences in energy and carbon intensities reflect the different mix of fuels used to provide energy in the two groups of countries. By 2050, non-OECD member economies are about as carbon intensive as OECD economies are today.

global energy and carbon intensities in IEO2019 reference case

Source: U.S. Energy Information Administration, International Energy Outlook 2019
Note: GDP is gross domestic product. OECD is the Organization for Economic Cooperation and Development.

IEO International Energy Outlook EIA emissions CO2 carbon dioxide
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Flow Meter | Types Of Flow Meters From Nagmanflow

Nagman has diversified into dealing with Flow meters or Instruments viz Electro-Magnetic Flow Meters, Coriolis Mass Flow Meter, Positive Displacement Flow Meter, Vortex Flow Meter, Turbine Flow Meter, Ultrasonic Flow Meter.

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Measuring Range : DN 15 – DN 6000


January, 24 2020
EIA expects U.S. net natural gas exports to almost double by 2021

In its Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that U.S. natural gas exports will exceed natural gas imports by an average 7.3 billion cubic feet per day (Bcf/d) in 2020 (2.0 Bcf/d higher than in 2019) and 8.9 Bcf/d in 2021. Growth in U.S. net exports is led primarily by increases in liquefied natural gas (LNG) exports and pipeline exports to Mexico. Net natural gas exports more than doubled in 2019, compared with 2018, and EIA expects that they will almost double again by 2021 from 2019 levels.

The United States trades natural gas by pipeline with Canada and Mexico and as LNG with dozens of countries. Historically, the United States has imported more natural gas than it exports by pipeline from Canada. In contrast, the United States has been a net exporter of natural gas by pipeline to Mexico. The United States has been a net exporter of LNG since 2016 and delivers LNG to more than 30 countries.

In 2019, growth in demand for U.S. natural gas exports exceeded growth in natural gas consumption in the U.S. electric power sector. Natural gas deliveries to U.S. LNG export facilities and by pipeline to Mexico accounted for 12% of dry natural gas production in 2019. EIA forecasts these deliveries to account for an increasingly larger share through 2021 as new LNG facilities are placed in service and new pipelines in Mexico that connect to U.S. export pipelines begin operations.

Net U.S. natural gas imports from Canada have steadily declined in the past four years as new supplies from Appalachia into the Midwestern states have displaced some pipeline imports from Canada. U.S. pipeline exports to Canada have increased since 2018 when the NEXUS pipeline and Phase 2 of the Rover pipeline entered service. Overall, EIA projects the United States will remain a net natural gas importer from Canada through 2050.

U.S. pipeline exports to Mexico increased following expansions of cross-border pipeline capacity, averaging 5.1 Bcf/d from January through October 2019, 0.5 Bcf/d more than the 2018 annual average, according to EIA’s Natural Gas Monthly. The increase in exports was primarily the result of increased flows on the newly commissioned Sur de Texas–Tuxpan pipeline in Mexico, which transports natural gas from Texas to the southern Mexican state of Veracruz. Several new pipelines in Mexico that were scheduled to come online in 2019 were delayed are expected to enter service in 2020:

  • Pipelines in Central and Southwest Mexico (1.2 Bcf/d La Laguna–Aguascalientes and 0.9 Bcf/d Villa de Reyes–Aguascalientes–Guadalajara)
  • Pipelines in Western Mexico (0.5 Bcf/d Samalayuca–Sásabe)

U.S. LNG exports averaged 5 Bcf/d in 2019, 2 Bcf/d more than in 2018, as a result of several new facilities that placed their first trains in service. This year, several new liquefaction units (referred to as trains) are scheduled to be placed in service:

  • Trains 2 and 3 at Cameron LNG in Louisiana
  • Train 3 at Freeport LNG in Texas
  • Trains 5–10, six Moveable Modular Liquefaction System (MMLS) units, at Elba Island in Georgia

In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction capacity to 10.2 Bcf/d (baseload) and 10.8 Bcf/d (peak). EIA expects LNG exports to continue to grow and average 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021, as facilities gradually ramp up to full production.

monthly natural gas trade

Source: U.S. Energy Information Administration, Natural Gas Monthly

January, 24 2020
EIA forecasts U.S. crude oil production growth to slow in 2021

In the January 2020 update of its Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that U.S. crude oil production will average 13.3 million barrels per day (b/d) in 2020, a 9% increase from 2019 production levels, and 13.7 million b/d in 2021, a 3% increase from 2020. Slowing crude oil production growth results from a decline in drilling rigs during the past year that EIA expects will continue through most of 2020. Despite the decline in rigs, EIA forecasts production will continue to grow as rig efficiency and well-level productivity rise, offsetting the decline in the number of rigs until drilling activity accelerates in 2021.

Figure 1. U.S. crude oil production

EIA’s U.S. crude oil production forecast is based on the West Texas Intermediate (WTI) price forecast in the January 2020 STEO, which rises from an average of $57 per barrel (b) in 2019 to an average of $59/b in 2020 and $62/b in 2021. The price forecast is highly uncertain, and any significant divergence of actual prices from the projected price path could change the pace of drilling and new well completion, which would in turn affect production.

Crude oil production in the Lower 48 states has a relatively short investment and production cycle. Changes in Lower 48 crude oil production typically follow changes in crude oil prices and rig counts with about a four- to six-month lag. Because EIA forecasts WTI prices will decline during the first half of 2020 but begin increasing in the second half of the year and into 2021, forecast U.S. crude oil production grows slowly month over month until the end of 2020. In contrast, crude oil production in Alaska and the Federal Offshore Gulf of Mexico (GOM) is driven by long-term investment that is typically less sensitive to short-term price movements.

In 2019, Lower 48 production reached its largest annual average volume of 9.9 million b/d, and EIA expects it to increase further by an average of 1.0 million b/d in 2020 and 0.4 million b/d in 2021. EIA forecasts the GOM region will grow by 0.1 million b/d in 2020 to 2.0 million b/d and to remain relatively flat in 2021 because several projects expected to come online in 2021 will not start producing until late in the year and will be offset by declines from other producing fields. Alaska’s crude oil production will remain relatively unchanged at about 0.5 million b/d in 2020 and in 2021.

The Permian region remains the most prolific growth region in the United States. Favorable geology combined with technological improvements have contributed to the Permian region’s high returns on investment and years of remaining oil production growth potential. EIA forecasts that Permian production will average 5.2 million b/d in 2020, an increase of 0.8 million b/d from 2019 production levels. For 2021, the Permian will produce an average of 5.6 million b/d. EIA forecasts that the Bakken region in North Dakota will be the second-largest growth area in 2020 and 2021, growing by about 0.1 million b/d in each year (Figure 2).

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

EIA expects crude oil prices higher than $60/b in 2021 will contribute to rising crude oil production because producers will be able to fund drilling programs through cash flow and other funding sources, despite a somewhat more restrictive capital market. Financial statements of 46 publically-traded U.S. oil producers reveal that these companies generated sufficient cash from operating activities to fund investment and grow production with WTI prices in the $55/b–$60/b range. The 46 selected companies produced more than 30% of total U.S. liquids production in the third quarter of 2019. The four-quarter moving average free cash flow for these companies ranged between $1.7 billion and $3.5 billion from the fourth quarter of 2017 through the second quarter of 2019. The third quarter of 2019—the latest quarter for which data are available—had less cash from operations than investing activities, but this figure was skewed by the large, one-time acquisition cost of Anadarko Petroleum by Occidental, valued at $55 billion (Figure 3).

Figure 3. Cash flow statement items for 46 U.S. oil producers

Results for these 46 publicly traded companies do not represent all U.S. oil producers because private companies that do not publish financial statements are not included in EIA’s analysis. The Federal Reserve Bank of Dallas Energy Survey sheds some light on the financial position of a broader set of companies. Released quarterly, the bank’s survey asks oil companies about business activity and employment and asks a few special questions that change each quarter. The number of companies that participate varies each quarter, but generally the survey includes about 100 exploration and production companies. In the most recent survey (from the fourth quarter of 2019), 75% of survey respondents said they can cover their capital expenditures through cash flow from operations at a WTI price of less than $60/b. In addition, 40% of survey respondents plan to increase capital expenditures in 2020 compared with 2019, while 24% of respondents expect to spend about the same (Figure 4).

Figure 4. Selected questions from the Federal Reserve Bank of Dallas' Energy Survey

Since about 2017, large, globally integrated oil companies have acquired more acreage in Lower 48 regions, particularly in the Permian. These companies have announced investment plans to make Lower 48 production an increasing portion of their portfolios. These companies can typically fund their investment programs through cash flow from operations and are generally less susceptible to tighter capital markets than smaller oil companies. The financial results of the public companies shown in Figure 3 and the Federal Reserve survey support EIA’s production forecast and suggest that U.S. crude oil production can continue to grow under EIA’s price forecast for 2020 and 2021 because many companies are less dependent on debt or equity to fund investment.

U.S. average regular gasoline and diesel prices decline

The U.S. average regular gasoline retail price fell more than 3 cents from the previous week to $2.54 per gallon on January 20, 29 cents higher than the same time last year. The Midwest price fell over 5 cents to $2.39 per gallon, the Gulf Coast price fell nearly 5 cents to $2.23 per gallon, the Rocky Mountain price fell more than 3 cents to $2.57 per gallon, the East Coast price fell more than 2 cents to $2.50 per gallon, and the West Coast price fell nearly 2 cents to $3.18 per gallon.

The U.S. average diesel fuel price fell nearly 3 cents from the previous week to $3.04 per gallon on January 20, 7 cents higher than a year ago. The Rocky Mountain price fell nearly 6 cents to $3.01 per gallon, the East Coast price fell nearly 4 cents to $3.08 per gallon, the Midwest price declined almost 3 cents to $2.94 per gallon, the West Coast price fell nearly 2 cents to $3.57 per gallon, and the Gulf Coast price dropped more than 1 cent to $2.80 per gallon.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 1.4 million barrels last week to 86.5 million barrels as of January 17, 2020, 17.1 million barrels (24.6%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, East Coast, Gulf Coast, and Rocky Mountain/West Coast inventories decreased by 0.7 million barrels, 0.4 million barrels, 0.2 million barrels, and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 6.9% of total propane/propylene inventories.

Residential heating fuel prices decrease

As of January 20, 2020, residential heating oil prices averaged nearly $3.07 per gallon, 3 cents per gallon below last week’s price and 10 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged almost $1.96 per gallon, more than 7 cents per gallon below last week’s price and more than 7 cents per gallon lower than a year ago.

Residential propane prices averaged almost $2.01 per gallon, less than 1 cent per gallon below last week’s price and more than 42 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.60 per gallon, nearly 4 cents per gallon lower than last week’s price and 20 cents per gallon below last year’s price.

January, 24 2020