Category Archives: Oil exports

Flood of Oil Is Coming, Complicating Efforts to Fight Global Warming

A surge of oil production is coming, whether the world needs it or not.

A Norwegian oil platform in the North Sea. Norway’s production has declined for two decades, but its development of the Johan Sverdrup deepwater field should reverse the trend.
A Norwegian oil platform in the North Sea. Norway’s production has declined for two decades, but its development of the Johan Sverdrup deepwater field should reverse the trend. Credit…Nerijus Adomaitis/Reuters
The New York Times, by Clifford Krauss, Nov. 3, 2019

HOUSTON — The flood of crude will arrive even as concerns about climate change are growing and worldwide oil demand is slowing. And it is not coming from the usual producers, but from Brazil, Canada, Norway and Guyana — countries that are either not known for oil or whose production has been lackluster in recent years.

This looming new supply may be a key reason Saudi Arabia’s giant oil producer, Aramco, pushed ahead on Sunday with plans for what could be the world’s largest initial stock offering ever.

Together, the four countries stand to add nearly a million barrels a day to the market in 2020 and nearly a million more in 2021, on top of the current world crude output of 80 million barrels a day. That boost in production, along with global efforts to lower emissions, will almost certainly push oil prices down.

Lower prices could prove damaging for Aramco and many other oil companies, reducing profits and limiting new exploration and drilling, while also reshaping the politics of the nations that rely on oil income.

The new rise in production is likely to bring economic relief to consumers at the gas pump and to importing nations like China, India and Japan. But cheaper oil may complicate efforts to combat global warming and wean consumers and industries off their dependence on fossil fuels, because lower gasoline prices could, for example, slow the adoption of electric vehicles.

Canada, Norway, Brazil and Guyana are all relatively stable at a time of turbulence for traditional producers like Venezuela and Libya and tensions between Saudi Arabia and Iran. Their oil riches should undercut efforts by the Organization of the Petroleum Exporting Countries and Russia to support prices with cuts in production and give American and other Western policymakers an added cushion in case there are renewed attacks on oil tankers or processing facilities in the Persian Gulf.

Driving New Production

Daniel Yergin, the energy historian who wrote “The Prize: The Epic Quest for Oil, Power and Money,” compared the impact of the new production to the advent of the shale oil boom in Texas and North Dakota a decade ago.

“Since all four of these countries are largely insulated from traditional geopolitical turmoil, they will add to global energy security,” Mr. Yergin said. But he also predicted that as with shale, the incremental supply gain, combined with a sluggish world economy, could drive prices lower.

There is already a glut on the world market, even with exports from Venezuela and Iran sharply curtailed by American sanctions. Should their production come back, that glut would only expand.

Years of moderate gasoline prices have already increased the popularity of bigger cars and sports utility vehicles in the United States, and the probability of more oil on the market is bound to weigh on prices at the pump over the next few years.

The oil-supply outlook is a sharp departure from the early 2000s, when prices soared as producers strained to keep up with ballooning demand in China and some analysts warned that the world was running out of oil.

Then came the rise of hydraulic fracturing and drilling through tight shale fields, which converted the United States from a needy importer into a powerful exporter. The increase in American production, along with a choppy global economy, shaved oil prices from well over $100 a barrel before the 2007-9 recession to about $56 on Friday for the American benchmark crude.

Those low prices have forced OPEC and Russia to lower production in recent years, and this year many financially struggling American oil companies have slashed their exploration and production investments to pay down their debts and protect their dividends.

An Era of Cheaper Oil

The new oil will accelerate those trends, energy experts say, even if only for a few years as production declines in older fields in other places.

“This could spell disaster for every producer and producing country,” said Raoul LeBlanc, a vice president at IHS Markit, an energy consultancy, especially if the United States and Iran come to some sort of nuclear deal.

Like the shale boom, the coming supply surge is a sudden change in dynamics. Guyana currently produces no oil at all. Norwegian and Brazilian production has long been in decline. And in Canada, concerns about climate change, resistance to new pipelines and high production costs have curtailed investments in oil-sands fields for five consecutive years.

Production of more oil comes at a time when there is growing acknowledgment by governments and energy investors that not all the hydrocarbons in the ground can be tapped if climate change is to be controlled. But exploration decisions, made years ago, have a momentum that can be hard to stop.

A drilling ship operated by Noble Energy for Exxon Mobil off Guyana. The South American country’s entry into the ranks of oil producers follows a string of major discoveries. Credit…Christopher Gregory for The New York Times

“Legacy decisions keep going,” said John Browne, BP’s former chief executive. “Things happen in different directions because decisions are made at different times.”

The added production in Norway comes despite the country’s embrace of the 2016 Paris climate agreement, which committed nations to cut greenhouse-gas emissions. Its sovereign wealth fund has cut investments in some oil companies, and its national oil company, Equinor, has pledged to increase its investments in wind power.

Equinor, which recently changed its name from Statoil to emphasize its partial pivot to renewable energy, nevertheless defends the new field on its company website, asserting, “The Paris Agreement is quite clear that there will still be a need for oil.”

Norway’s rebound from 19 years of decline began a few weeks ago as Equinor began production in its Johan Sverdrup deepwater field. The field will eventually produce 440,000 barrels a day, increasing the country’s output from 1.3 million barrels a day to 1.6 million next year and 1.8 million in 2021.

In Brazil, after years of scandal and delays, new offshore production platforms are coming online. Production has climbed over the last year by 300,000 barrels a day, and the country is expected to add as much as 460,000 more barrels a day by the end of 2021. In the coming days, Brazil is scheduled to hold a major auction in which some of the largest oil companies will bid for drilling rights in offshore areas with as much as 15 billion barrels of reserves.

In Canada, the 1,000-mile Line 3 pipeline that will take oil from the Alberta fields to Wisconsin, is near completion and awaiting final permitting. Energy experts say that could increase Canadian production by a half million barrels a day, or about 10 percent.

And the most striking change will be in Guyana, a tiny South American country where Exxon Mobil has made a string of major discoveries over the last four years. Production will reach 120,000 barrels a day early next year, rising to at least 750,000 barrels by 2025, and more is expected after that.

Guyana potentially has the most complicated future of the four countries. Its ethnically divided politics are sometimes turbulent, and Venezuela claims a large portion of its territory. But with the oil fields miles offshore, drilling is largely protected. In addition, Venezuela is mired in a political and economic crisis and unlikely to challenge a Chinese state company which has an oil investment in Guyana, along with Exxon Mobil and Hess.

Energy experts say the new production from the four nations will more than satisfy all the growth in global demand expected over the next two years, which is well below the growth rates of recent years before economic expansion in China, Europe and Latin America slowed.

At the same time, new pipelines in Texas are expected to increase United States exports to 3.3 million barrels a day next year, from the current 2.8 million.

That adds up to a vast surplus unless there is a resurgence of global economic growth to stimulate demand, or a prolonged conflict in the Middle East or other disruption to supply.

“To support prices, OPEC is going to have to extend and probably deepen their production cuts for a while,” said David L. Goldwyn, a top State Department energy diplomat during the Obama administration. “Getting the prices up to the point where Aramco can launch its I.P.O. is a big Saudi priority.”

The new barrels on the world market will also put pressure on companies producing in the United States, where profit margins for shale production are slim at current price levels and stock prices are falling.

“If I was in the business I would be scared to death,” said Philip K. Verleger, an energy economist who has served in both Democratic and Republican administrations. “The industry is going to face capital starvation.”

American oil executives express concern that drilling will fade in North Dakota, Oklahoma, Louisiana and Colorado as oil prices drop to as low as $50 a barrel in the next few years. Small companies are expected to merge, while others go bankrupt.

Scott D. Sheffield, chief executive of the Texas-based producer Pioneer Natural Resources, said he expected the growth of United States oil production to ease from 1.2 million barrels a day this year to 500,000 barrels next year and perhaps 400,000 barrels in 2021. Those increases are modest compared with the average increase of a million barrels a day every year from 2010 to 2018.

But Mr. Sheffield said he was optimistic, in part because new supplies coming to market could be offset by production declines in older fields in Mexico and elsewhere after 2021.

“There are no more big, giant new projects except Guyana,” he said. “We just have to be patient for a couple of more years.”


A version of this article appears in print on , Section A, Page 1 of the New York edition with the headline: Needed or Not, Oil Production Is Set to Surge.

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    U.S. petroleum product exports set record high in 2018

    Annual average now at 5.6 million barrels per day (b/d), an increase of 366,000 b/d from 2017 levels

    Principle contributor Matt French, Today In Energy (US Energy Information Administration), April 23, 2019
    U.S. petroleum product exports
    Source: U.S. Energy Information Administration, Petroleum Supply Monthly

    U.S. exports of total petroleum products set a record high in 2018, reaching an annual average of 5.6 million barrels per day (b/d), an increase of 366,000 b/d from 2017 levels. The three largest petroleum product exports from the United States in 2018 were distillate, propane, and motor gasoline. U.S. exports of motor gasoline (including blending components) and propane reached record highs in 2018, and exports of distillate reached their second-highest volume on record, following the high set in 2017.

    Total U.S. petroleum product exports set a record high in 2018 for the 16th consecutive year. From 2009 to 2013, distillate exports contributed the most to annual growth. However, from 2014 to 2018, exports of hydrocarbon gas liquids, which include propane, drove U.S. petroleum product export growth.

    As U.S. crude oil production increased over the past decade, gross inputs into refineries also increased. Petroleum products can be used domestically, exported, or put into inventory. In 2018, record-high levels of U.S. crude oil production and refinery runs helped refiners export large volumes of petroleum products, even with high levels of domestic demand.

    monthly U.S. distillate exports and destinations
    Source: U.S. Energy Information Administration, Petroleum Supply Monthly

    Despite an 80,000 b/d decrease in exports in 2018 from 2017, distillate remained the most exported petroleum product in 2018, averaging 1.3 million b/d, or approximately 25% of U.S. refinery net production. Distillate exports were still more than 100,000 b/d higher than the previous five-year average (2013–2017). The United States exported distillate to 64 destinations in 2018, with the largest volumes destined for Mexico.

    Mexico received an average of 298,000 b/d, or 23% of U.S. distillate exports, increasing 42,000 b/d from 2017. Mexico’s increasing exports were likely driven by the country’s refineries that continued to operate below capacity in 2018, as reported by trade press. Brazil received the second-largest share of distillate exported from the United States, averaging 151,000 b/d (12% of U.S. distillate exports), down by 57,000 b/d from 2017. Chile, Peru, and the Netherlands comprise the remainder of the top five recipients of U.S. distillate exports.

    monthly U.S. propane exports and destinations
    Source: U.S. Energy Information Administration, Petroleum Supply Monthly

    U.S. propane exports reached a record high of 972,000 b/d in 2018, surpassing the previous record of 914,000 b/d set in 2017. Propane exports in 2018 were greater than motor gasoline exports for the third consecutive year, and propane remained the second-largest U.S. petroleum product export. Unlike other U.S. petroleum product exports, which tend to stay in the Western Hemisphere, significant volumes of U.S. propane often reach Asian markets. Three of the top five destinations are in Asia. Propane is used in many Asian countries as a feedstock for producing ethylene and propylene, which are building blocks for chemical and plastic manufacturing.

    Japan received the largest share of U.S. propane exports, more than 258,000 b/d (or 7%) of total U.S. propane exports, an increase of 48,000 b/d from 2017 volumes. Exports to Korea and the Netherlands increased by 25,000 b/d and 21,000 b/d, respectively. However, exports to China fell by 62,000 b/d, a 49% year-over-year decline. Mexico received the second-largest share of U.S. propane exports in 2018 at an average of 131,000 b/d, which was down 7,000 b/d from 2017 levels.

    monthly U.S. motor gas exports and destinations
    Source: U.S. Energy Information Administration, Petroleum Supply Monthly

    U.S. exports of motor gasoline (including blending components) reached 44 destinations in 2018 and set a record high of 951,000 b/d, up 126,000 b/d from 2017 levels. This increase in exports came despite high levels of domestic gasoline consumption, averaging 9.3 million b/d in 2018, only slightly lower than the record-high level set in 2017.

    U.S. refiner and blender net production of finished motor gasoline increased more than 100,000 b/d to 10.1 million b/d in 2018, a record high, and helped contribute to the simultaneous high levels of domestic consumption and export volumes. The five largest shares of U.S. gasoline exports were all in the Americas. In 2018, Mexico received 529,000 b/d of U.S. gasoline exports, or 56% of total U.S. gasoline exports, which was 60,000 b/d more than in 2017. Exports to Canada increased by 25,000 b/d, to average 62,000 b/d, or 6% of U.S. gasoline exports in 2018.

    Principal contributor: Matt French

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      Until California curbs its oil refineries, it won’t meet its climate goals (Benicia & others are heroes)

      Repost from the Los Angeles Times
      [Editor: Significant quote, Benicia in final paragraph – “In the absence of action at the state level, it has fallen to localities to prevent refineries from at least increasing crude oil imports to their facilities. Over the last decade elected officials in half-a-dozen communities from Benicia to San Luis Obispo County have blocked refinery infrastructure projects that would allow more crude oil imports. They’re the real heroes of California’s climate saga — too bad they won’t be the ones in the spotlight at the summit.”  – RS]

      Until California curbs its oil refineries, it won’t meet its climate goals

      By Jacques Leslie, Sep 11, 2018 | 4:15 AM
      Until California curbs its oil refineries, it won't meet its climate goals
      The Phillips 66 refinery in the Wilmington neighborhood of Los Angeles. (Rick Loomis / Los Angeles Times)

      While Gov. Jerry Brown and other California leaders bask under an international spotlight at this week’s Global Climate Action Summit in San Francisco, there is one highly relevant topic they’re not likely to bring up: oil refineries.

      That’s because refineries are crucially absent from California’s climate change strategy. The state has justifiably gotten credit for addressing climate change issues that the nation won’t — promoting renewable energy, cap-and-trade greenhouse gas emission limits, and electric vehicles — but it has backed off from challenging refineries, the centerpieces of California’s oil supply infrastructure.

      Concentrated in Los Angeles’ South Bay and the San Francisco Bay Area, the state’s 17 refineries comprise the largest oil processing center in western North America. Unless emissions from those refineries are curbed, the state has no chance of meeting its long-range climate change goals.

      Greg Karras, a senior scientist at Huntington Park-based Communities for a Better Environment, calculates that without restraints on refineries, even if emission reductions from all other sources hit their targets, oil sector pollution through 2050 would cause the state to exceed its overall climate goals by roughly 40%.

      “Refineries have been largely exempted from the state’s cap and trade program, which charges fees for emissions.”

      That’s primarily because refineries have been largely exempted from the state’s cap and trade program, which charges fees for emissions. Last year, the legislature extended the program for another decade, from 2020 to 2030, but only after bowing to the oil industry’s wishes. To win a needed two-thirds majority, cap and trade supporters exempted the industry from fees for all but a tenth of refinery emissions through 2030. The legislation also prohibited regional air districts from imposing their own limits on refinery carbon dioxide emissions, a severe blow to communities suffering from pollution from nearby operations. Instead of curbing refineries, these provisions gave them a decade-long free pass.

      To make matters worse, the oil that is being processed is bound to get dirtier, resulting in a higher rate of greenhouse gas emissions throughout the fuel-production chain. Oil used by the state’s refineries already contains the highest intensity of greenhouse gas pollutants of any refining region in the country. As drillers pump the dregs from the state’s nearly spent fields, that intensity is increasing.

      With California oil extraction in decline, its refineries will want to import more crude oil from other states and nations. That could include tapping the Canadian tar sands, notorious for its off-the-charts, climate-busting pollutants. Completion of the stalled Trans Mountain pipeline expansion in Canada would facilitate what Greenpeace calls a “tanker superhighway” from Vancouver to California ports. California refineries have tried to win approval for rail terminals and ports that would receive tar sands oil but have so far been blocked by local governments.

      The refineries’ contributions to greenhouse gas emissions don’t end with their own production, of course. When the fuel they produce is used, it’s one of the primary contributors to climate change. As California shifts to renewable energy and electric vehicles, less refined fuel will be consumed here and more will be exported to other states and nations.

      As a result, the state could become, in Karras’ words, “the gas station of the Pacific Rim.” And as exports grow to countries like India with lax environmental standards, refineries won’t even need to meet California’s more stringent regulations on fuel composition; instead, they will export more pollution.

      The main reason state leaders have done little to limit oil supply is obvious: The oil industry remains a formidable adversary, wielding its financial and lobbying might to head off restraints. For virtually all Republican state legislators and a substantial number of Democrats, oil supply is too hot a topic to touch, Karras told me.

      Meanwhile, state policy calls for greenhouse gas emissions to drop by 80% of 1990 levels by 2050. Given the oil industry’s cap and trade refinery exemptions in place through 2030, the only way to achieve that level is to place drastic limits on refineries as soon as those exemptions expire, which is unlikely to happen. A more realistic approach would remove the oil industry’s exemptions and impose cuts of 5% a year on refinery emissions immediately — an urgent task that state leaders have shown no interest in carrying out.

      In the absence of action at the state level, it has fallen to localities to prevent refineries from at least increasing crude oil imports to their facilities. Over the last decade elected officials in half-a-dozen communities from Benicia to San Luis Obispo County have blocked refinery infrastructure projects that would allow more crude oil imports. They’re the real heroes of California’s climate saga — too bad they won’t be the ones in the spotlight at the summit.

      Jacques Leslie is contributing writer to Opinion.
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        BLOOMBERG: Local opposition to crude by rail is succeeding in California

        Repost from Bloomberg
        [Editor:  Note 3 mentions of crude by rail, and in the final paragraph a reference to local opposition to CBR in Santa Maria, Pittsburg and Benicia.  – RS]

        California Isn’t Feeling U.S. Oil Boom as OPEC Dependence Grows

        By Robert Tuttle, May 4, 2016 9:01 PM PDT

        • State sourced a record 52% of its crude from overseas in 2015
        • Falling in-state and Alaska production is driving imports

        BBGThe shale oil boom that cut U.S. crude imports by 32 percent in a decade isn’t being felt out west as California grows increasingly dependent on Middle East supplies.

        California brought in a record 52 percent of its crude from abroad last year, up from just 9 percent 20 years earlier, according to California Energy Commission data. The state hasn’t yet released the specific countries that supplied that oil in 2015, but in 2014, about 58 percent came from Saudi Arabia and Iraq, the most recent data show.

        Foreign dependence is only expected to grow as supplies from within the state and Alaska diminish and efforts to bring U.S. crude from the Midwest by rail face local opposition.

        “Regulatory impediments have kept California isolated from the growing sources of domestic crude production,” John Auers, executive vice president at Turner Mason & Co., said by phone from Dallas. “California refiners won’t be able to take advantage”’ of lower-priced domestic crude.

        Growing imports mean that California refiners have some of the highest crude costs in the U.S., which are passed onto consumers in the form of higher gasoline prices, David Hackett, president of Irving, California-based Stillwater Associates, said in a phone interview.

        Imported crude is priced off Brent, which was selling at less than a $1 premium to U.S. West Texas Intermediate Wednesday. While the lifting of restrictions on U.S. oil exports has narrowed the gap from as high as $15 a barrel in 2014, the spread between the grades could widen again when oil rises and U.S. shale oil production picks up, Hackett said.

        Drivers in Los Angeles paid the highest pump prices in the U.S. for much of last year, exceeding $4 a gallon last summer, according to AAA.

        Domestic Supply

        Alaska supplied the state with 73,000 barrels a day of crude in 2015, about 12 percent of California’s total supply, state data show. That’s down from as high as 46 percent in the early 1990s and may fall further as Alaska’s production is forecast to drop to 319,100 barrels a day in 2023, down from almost 500,000 barrels a day this year, official datashow.

        California itself produced about 225,000 barrels a day in 2015, supplying about 36 percent of its own needs, according to state data. That’s a drop from 240,000 barrels a day in 2014. The decline in the state’s own production came as producers cut output amid falling oil prices and following the shutdown of the Plains All American pipeline near Santa Barbara after a spill curtailed about 38,000 barrels a day of offshore production, Stillwater’s Hackett said.

        California could benefit from cheaper Midwestern oil if crude by rail terminals were built. New terminals planned for Santa Maria, Pittsburg and Benicia have been stymied by local opposition and regulatory holdups, Hackett said. In February, for example, Valero Energy Corp’s planned crude-by-rail project was rejected by a city commission.

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