Global liquid fuels
· Significant disruptions in the U.S. energy market have occurred in recent weeks as a result of Hurricane Harvey. At the time of publication, continuing uncertainty exists regarding the timeline for the return to normal operations for a broad range of upstream production, refining, pipeline, and terminal and distribution infrastructure. The severity and duration of these outages create additional uncertainty about the path of energy prices in the coming weeks and months. Although this STEO attempts to incorporate a baseline scenario for energy production, flows, and prices, actual outcomes could deviate significantly from this forecast. This month’s forecast does not include any projected effects from Hurricane Irma, which made landfall in Florida on September 10. At the time of publication, it was too early to have meaningful information on the extent to which Hurricane Irma will cause disruptions to the U.S. energy system.
· U.S. regular gasoline retail prices reached $2.69 per gallon (gal) on September 11, up 29 cents/gal from August 28 and the highest weekly average since August 2015. EIA forecasts the average U.S. regular gasoline retail price to be $2.61/gal in September and then fall to $2.40/gal in October, which are 25 cents/gal and 10 cents/gal higher, respectively, than projected in the August STEO. EIA forecasts the regular gasoline retail price to fall to $2.23/gal in December.
· Refinery operations declined significantly following Hurricane Harvey. Based on EIA’sWeekly Petroleum Status Report, U.S. gross refinery runs averaged 14.8 million barrels per day (b/d) the week ending September 1, down by 3.1 million b/d from the previous week. EIA forecasts refinery runs to average 15.3 million b/d in September, down from an estimated average of 17.1 million b/d in August. Refinery runs are forecast to increase to 15.9 million b/d in October.
· EIA expects much of the reduction in refinery production of petroleum products to be offset by a decline in petroleum product net exports. EIA expects net petroleum product exports to average 1.1 million b/d in September, down from an average of 2.9 million b/d during the first eight months of 2017. A reduction in net exports can either come from a decrease in exports or an increase in imports. Additionally, the reduction in production of petroleum products could contribute to larger-than-typical inventory draws for September.
· U.S. crude oil production is estimated to have averaged 9.2 million b/d in August, down about 40,000 b/d from the July average. Crude oil production in the Gulf of Mexico fell to a monthly average of 1.6 million b/d in August, down by 70,000 b/d from the July level. At the time of publication, many oil production platforms in the Gulf of Mexico had returned to operation, and EIA forecasts overall U.S. crude oil production will continue to grow in the coming months. EIA forecasts total U.S. crude oil production to average 9.3 million b/d for all of 2017 and 9.8 million b/d in 2018, which would mark the highest annual average production in U.S. history, surpassing the previous record of 9.6 million b/d set in 1970.
· U.S. dry natural gas production is forecast to average 73.7 billion cubic feet per day (Bcf/d) in 2017, a 1.4 Bcf/d increase from the 2016 level. Natural gas production in 2018 is forecast to be 4.4 Bcf/d higher than the 2017 level.
· In August, the average Henry Hub natural gas spot price was $2.90 per million British thermal units (MMBtu), down 8 cents/MMBtu from the July level. Expected growth in natural gas exports and domestic natural gas consumption in 2018 contribute to the forecast Henry Hub natural gas spot price rising from an annual average of $3.05/MMBtu in 2017 to $3.29/MMBtu in 2018. NYMEX contract values for December 2017 delivery that traded during the five-day period ending September 7 suggest that a range of $2.39/MMBtu to $4.34/MMBtu encompasses the market expectation for December Henry Hub natural gas prices at the 95% confidence level.Electricity, coal, renewables, and emissions
· EIA expects the share of U.S. total utility-scale electricity generation from natural gas to fall from an average of 34% in 2016 to about 31% in 2017 as a result of higher natural gas prices and increased generation from renewables and coal. Coal's forecast generation share rises from 30% last year to 31% in 2017. The projected generation shares for natural gas and coal in 2018 average 31% and 32%, respectively.
· Coal production for August 2017 is estimated to have been 74 million short tons (MMst), 6 MMst (8%) higher than last August. August is also the first month that had production higher than 70 MMst since October 2015. Production for the first eight months of 2017 is estimated to have been 528 MMst, 64 MMst (14%) higher than production for the same period in 2016. Production is expected to increase by 8% in 2017 and by 2% in 2018.
· Coal exports for the first six months of 2017 were 55% higher than exports over the same period last year. EIA expects growth in coal exports to slow in the coming months, with exports for all of 2017 forecast at 73 MMst, 21% higher than the 2016 level.
· Wind electricity generating capacity at the end of 2016 was 82 gigawatts (GW). EIA expects wind capacity additions in the forecast to bring total wind capacity to 88 GW by the end of 2017 and to 96 GW by the end of 2018.
· Total utility-scale solar electricity generating capacity at the end of 2016 was 22 GW. EIA expects solar capacity additions in the forecast will bring total utility-scale solar capacity to 29 GW by the end of 2017 and to 33 GW by the end of 2018.
After declining 1.7% in 2016, energy-related carbon dioxide (CO2) emissions are projected to decrease by 0.5% in 2017 and then to increase by 2.6% in 2018. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, and energy prices.
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
Midstream & Downstream
Risk and reward – improving recovery rates versus exploration
A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.
How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.
1. Reserve growth
An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.
2. pre-drill tight oil inventory and conventional pre-FID projects
They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve.
3. Contingent resource
These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.
Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.
Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.
But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.
To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).
Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.
Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.
If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects.
Global oil supply through 2040
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