Pakistan’s new Prime Minister loves skydiving and he is bringing that adrenaline-seeking attitude in a bid to reshape a country that has long languished from crippled energy infrastructure. Fuel demand is soaring – gasoline volumes alone has tripled between 2010 and 2016 – but aging domestic refineries means much of this has to be imported. Rolling blackouts across the country are common, product of a power grid that is old and underfed.
One of Prime Minister Shahid Khaqan Abbasi’s first moves as Prime Minster, after Nawaz Sharif was barred from public office by the Supreme Court over Panamagate corruption charges, was to merge the country’s petroleum and power ministries. The new Ministry of Energy, headed by Abbasi himself, acknowledges the intrinsic link between all aspects of the country’s energy industry in an attempt to prevent the in-fighting and cross-purposes that the old bureaucratic structure promoted.
The solution, according to Abbasi, is to champion the use of LNG and promote foreign investment in the oil sector to move the onus away from beleaguered state companies. The LNG slant is nothing new; Abbasi served in the Pakistan cabinet under the PML-N party and promoted LNG as a solution to Pakistan’s ailing electricity network. To that end, his position as Prime Minister merely hastens a transition that was originally in the works. His vision is to depend on import LNG and domestic coal in a two-pronged approach to boost power generation and reduce dependence on imported gasoil/fuel oil, with an ambitious deadline to end blackouts by November 2017, giving his party a boost ahead of elections due in 2018.
To that end, Pakistan needs to be to import and re-gas LNG. Pakistan has signed two LNG supply contracts so far this year – a five-year deal with Gunvor and a 15-year deal with Italy’s Eni that will bring 3.6 million tons and 11 million tons (across 60 and 180 cargoes) to Pakistan. Competition for the tender was stiff, with all major traders including Glencore, Trafigura, Shell and Petronas taking part. This adds to Pakistan’s existing contracts with Gunvor and Qatargas, which began when LNG imports first started in 2015. On the receiving end, Pakistan is n a multi-billion spending spree that includes the construction of a second and third LNG import terminal and pipelines linking coastal Karachi with inland Lahore, the country’s industrial heartland. Up to five more terminals are being considered – in Karachi and in Gwadar – which could conceivably make Pakistan one of the world’s top five LNG importers by 2022.
The massive influx of LNG would help in providing power to a fast-growing population – especially when combined with domestic coal power expansion – but the other side of the equation is oil. The 120 kb/d Balochistan refinery – the largest in Pakistan – has been out of commission since 2015 due to fire damage. Aging refineries elsewhere have curbed the ability to provide domestic sources of fuel. This is a gap that foreign traders have exploited. Vitol bought a stake in local retailer Hascol Petroleum in 2015, recently increasing its share from 15% to 25%, followed by Trafigura (via subsidiary Puma Energy) this month through the purchase of a stake in the Admore Gas fuel retail network – capitalising on a gap in the market that requires imported supply to fill.
The longer term solution will be to beef up refining capabilities. Byco Petroleum has restarted operations at the Balochistan refinery after two years of repairs, supplying its own retail network as well as others owned by Pakistan State Oil, Shell, Hascol and Admore. Beyond that, Pakistan is looking to the usual suspect – China – for more capacity. The WAK Group and Guangdong Electrical Design Institute are building a US$3.58 billion 100 kb/d refinery for private player Falcon Oil, expected to be ready by 2020.
Almost all of the crude required to run these refineries will have to be imported. Domestic crude supplies are drying up, with Pakistan’s state-owned firms focusing on new exploration activities. Oil & Gas Development Co and Pakistan Petroleum have both doubled well drilling and seismic activity in the last two years, capitalising on cheaper costs, though this is bringing them to areas of the country rife with insurgent activity. And once again, it is China to the rescue. Chinese firms Poly-GCL and Sino-PEC have agreed to invest in Pakistan’s upstream sector, tempted by oil and shale gas reserves in Sindh and Balochistan. If successful, increased domestic production could reduce Pakistan’s dependence on imports. But that’s in the long run.
For now, Abbasi has set an achievable path to energy optimisation for Pakistan. All that’s left is to implement it successfully. Which is always the harder part of that equation.
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Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.
In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.
In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.
The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.
But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.
Infographic: Venezuela oil nationalisation dispute timeline
In 2018, U.S. exports of crude oil continued to increase to 2.0 million barrels per day (b/d), up 846,000 b/d (73%) from 2017 (Figure 1). The number of destinations for U.S. crude oil exports also increased from 37 to 42. Volumes by destination changed significantly between the first and second halves of 2018.
The increase in U.S. crude oil exports was the result of increasing U.S. crude oil production and infrastructure changes. U.S. crude oil production increased 1.6 million b/d from 2017 to 10.9 million b/d in 2018, with the U.S. Gulf Coast—where more than 90% of U.S. crude oil exports depart from—producing 7.1 million b/d. The increased production is mostly of light, sweet crude oils, but U.S. Gulf Coast refineries are configured mostly to process heavy, sour crude oils. This increasing production and mismatch between crude oil type and refinery configuration causes more of the increasing U.S. crude oil production to be exported.
In early 2018, modifications were made at the Louisiana Offshore Oil Port (LOOP) in the Gulf of Mexico to enable the loading of vessels for crude oil exports. LOOP is currently the only U.S. facility capable of accommodating fully loaded Very Large Crude Carriers (VLCC), vessels capable of carrying approximately 2 million barrels of crude oil. After LOOP was modified to also allow exports, the increase in cargo scale led U.S. crude oil exports to surpass 2 million b/d for 25 weeks in 2018 compared with just 1 week in 2017. In addition to LOOP, other U.S Gulf Coast export facilities in and around Houston and Corpus Christi, Texas, have been investing in increasing the scale of U.S. crude oil export cargos.
In 2018, Asia was the largest regional destination for U.S. crude oil exports, followed by Europe, and, as in previous years, Canada was the largest single destination for U.S. crude oil exports. Canada received 378,000 b/d of U.S. crude oil exports, representing 19% of total U.S. crude oil exports in 2018. South Korea surpassed China to become the second-largest single destination for U.S. crude oil exports in 2018, receiving 236,000 b/d compared with China’s 228,000 b/d (Figure 2).
However, the distribution of U.S. crude oil exports by destination varied significantly from the first half of 2018 to the second half. In the first half of 2018, the United States exported 376,000 b/d of crude oil to China, which made China the largest single destination for U.S. crude oil exports for that period. However, in August, September, and October of 2018, the United States exported no crude oil to China, and then in November and December it exported significantly less than in earlier months. In the second half of 2018, the United States exported 83,000 b/d of crude oil to China, a decrease of 294,000 b/d from the first half (Figure 3).
In the summer of 2018, as part of ongoing trade negotiations between the United States and China, China temporarily included U.S. crude oil on a list of goods potentially subject to an increase in import tariffs. At the same time, the difference between the international crude oil benchmark Brent and the U.S. domestic price West Texas Intermediate (WTI) futures prices narrowed rapidly between June and July 2018. Brent prices went from $9 per barrel (b) higher than WTI in June to $6/b higher than WTI in July. The rapidly narrowing price discount of U.S. crude oils versus international crude oils and the potential for higher import tariffs caused Chinese buying of U.S. crude oil to slow.
Although U.S. crude oil exports to China slowed in the second half of 2018, exports to South Korea, Taiwan, Canada, and India increased significantly. U.S. crude oil exports to South Korea increased 247,000 b/d (222%) between the first and second half of 2018. U.S. crude oil exports to other destinations in Asia also increased, particularly to Taiwan, which rose 111,000 b/d (168%) in the second half of 2018 compared with the first half, and to India, which increased 86,000 b/d (97%) during the same period.
Despite the volume changes in U.S. crude oil destination between the first and second halves of 2018, the list of destinations has remained consistent over the past three years. Of the 27 destinations that took U.S. crude oil in 2016, the first year of unrestricted U.S. crude oil exports, 22 destinations did so again in 2017 and again in 2018 (Figure 4). Furthermore, few destinations appear to be one-time recipients of U.S. crude oil, other than those such as the Marshall Islands that were listed because of data collection methods and ship-to-ship transfers.
U.S. average regular gasoline price increases, diesel price falls
The U.S. average regular gasoline retail price rose nearly 8 cents from the previous week to $2.55 per gallon on March 18, down 5 cents from the same time last year. The East Coast price rose nearly 9 cents to $2.52 per gallon, the Gulf Coast price rose over 8 cents to $2.30 per gallon, the Midwest price rose nearly 8 cents to $2.48 per gallon, the Rocky Mountain price rose nearly 7 cents to $2.32 per gallon, and the West Coast price rose nearly 5 cents to $3.03 per gallon.
The U.S. average diesel fuel price fell nearly 1 cent to $3.07 per gallon on March 18, nearly 10 cents higher than a year ago. The Midwest price fell nearly 2 cents to $2.99 per gallon, the Gulf Coast price fell over 1 cent to $2.87 per gallon, and the West Coast price fell nearly 1 cent to $3.50 per gallon. The Rocky Mountain price increased nearly 1 cent, remaining at $2.94 per gallon, and the East Coast price rose less than 1 cent, remaining at $3.12 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 1.0 million barrels last week to 51.1 million barrels as of March 15, 2019, 6.3 million barrels (14.0%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories increased by 1.2 million barrels, 0.4 million barrels, and 0.1 million barrels, respectively, while Midwest inventories decreased by 0.7 million barrels. Propylene non-fuel-use inventories represented 12.1% of total propane/propylene inventories.
Residential heating fuel prices decrease
As of March 18, 2019, residential heating oil prices averaged nearly $3.22 per gallon, 1 cent per gallon below last week’s price but 16 cents per gallon above last year’s price at this time. Wholesale heating oil prices averaged $2.09 per gallon, nearly 4 cents per gallon less than last week’s price but 8 cents per gallon more than a year ago.
Residential propane prices averaged $2.41 per gallon, less than 1 cent per gallon lower than last week’s price and almost 8 cents per gallon lower than a year ago. Wholesale propane prices averaged nearly $0.84 per gallon, less than 1 cent per gallon above last week’s price but 3 cents per gallon below last year’s price.
Source: U.S. Energy Information Administration, Electric Power Monthly
Renewable generation provided a new record of 742 million megawatthours (MWh) of electricity in 2018, nearly double the 382 million MWh produced in 2008. Renewables provided 17.6% of electricity generation in the United States in 2018.
Nearly 90% of the increase in U.S. renewable electricity between 2008 and 2018 came from wind and solar generation. Wind generation rose from 55 million MWh in 2008 to 275 million MWh in 2018 (6.5% of total electricity generation), exceeded only by conventional hydroelectric at 292 million MWh (6.9% of total generation).
U.S. solar generation has increased from 2 million MWh in 2008 to 96 million MWh in 2018. Solar generation accounted for 2.3% of electricity generation in 2018. Solar generation is generally categorized as small-scale (customer-sited or rooftop) solar installations or utility-scale installations. In 2018, 69% of solar generation, or 67 million MWh, was utility-scale solar.
Source: U.S. Energy Information Administration, Electric Power Monthly
Increases in U.S. wind and solar generation are driven largely by capacity additions. In 2008, the United States had 25 gigawatts (GW) of wind generating capacity. By the end of 2018, 94 GW of wind generating capacity was operating on the electric grid. Almost all of this capacity is onshore; one offshore wind plant, located on Block Island, off the coast of Rhode Island, has a capacity of 30 megawatts. Similarly, installed solar capacity grew from an estimated less than 1 GW in 2008 to 51 GW in 2018. In 2018, 1.8 GW of this solar capacity was solar thermal, 30 GW was utility-scale solar photovoltaics (PV), and the remaining 20 GW was small-scale solar PV.
Growth in renewable technologies in the United States, particularly in wind and solar, has been driven by federal and state policies and declining costs. Federal policies such as the American Reinvestment and Recovery Act of 2009 and the Production Tax Credit and Investment Tax Credits for wind and solar have spurred project development.
In addition, state-level policies, such as renewable portfolio standards, which require a certain share of electricity to come from renewable sources, have increasing targets over time. As more wind and solar projects have come online, economies of scale have led to more efficient project development and financing mechanisms, which has led to continued cost declines.
Conventional hydroelectric capacity has remained relatively unchanged in the United States, increasing by 2% since 2008. Changes in hydroelectric generation year-over-year typically reflect changes in precipitation and drought conditions. Between 2008 and 2018, annual U.S. hydroelectric generation was as low as 249 million MWh and as high as 319 million MWh, with hydroelectric generation in 2018 totaling 292 million MWh. Generation from other renewable resources, including biomass and geothermal, increased from 70 million MWh to 79 million MWh in the United States between 2008 and 2018, and it collectively represented 1.9% of total generation in 2018.