Source: U.S. Energy Information Administration, Annual Energy Outlook 2019
EIA’s long-term projections show that most of the electricity generating capacity additions installed in the United States through 2050 will be natural gas combined-cycle and solar photovoltaic (PV). Onshore wind looks to be competitive in only a few regions before the legislated phase-out of the production tax credit (PTC), but it becomes competitive later in the projection period as demand increases and the cost for installing wind turbines continues to decline.
For EIA’s Annual Energy Outlook 2019 (AEO2019), EIA calculates two measures that, when used together, provide an intuitive framework for understanding the capacity expansion decisions modeled for utility-scale power plants—those with a capacity rating of 1 megawatt (MW) or greater.
The levelized cost of electricity (LCOE) represents the cost to build and operate a power plant, converted to a level stream of payments over the plant’s assumed financial lifetime. Installed capital costs include construction costs and financing costs. Operating costs include fuel costs (for power plants that consume fuel) and expected maintenance costs. LCOEs may also include other applicable tax credits or subsidies.
The levelized avoided cost of electricity (LACE) accounts for the differences in the grid services each generating technology is providing (a power plant’s value) to the grid. For example, natural gas combined-cycle plants and coal plants provide dispatchable baseload services to the grid and thus have similar LACE values, even if their LCOE values differ. A generator’s avoided cost provides a proxy for the potential revenues from sales of electricity generated. As with LCOE, these revenues are converted to a level stream of payments over the plant’s assumed financial lifetime.
The ratio of these two measures serves as a value-to-cost ratio. Power plants are considered economically attractive when their projected LACE exceeds their projected LCOE, meaning their value-cost ratio exceeds one.
The relative costs and values of several technology options are calculated for each of the 22 electricity regions in the modeling system used to inform EIA’s Annual Energy Outlook. Calculations start in 2021 because that is the first feasible year that all three technologies are available to come online in the model, given the assumed construction lead-time and licensing requirements.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2019 and Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2019
Because both LCOE and LACE are levelized over the lifetime of the plant, these values change over time. Natural gas combined-cycle units’ LCOEs increases gradually as natural gas prices rise. Utility-scale solar photovoltaic (PV) and onshore wind’s LCOEs initially increase as a result of the loss of the tax credits but then decrease because of the continued decline in installed costs. Wind’s LCOE may also increase as the best wind resource sites are built out and new projects must be installed in areas that have either lower wind resources or less ease of access.
Natural gas combined-cycle units are considered, on average, the marginal source of electricity generation through 2050, meaning the cost of electricity generation from this technology is most often the basis of comparison for new power plants. As natural gas prices increase, the marginal source becomes more expensive to operate, and the value to the grid of avoiding this cost by building new capacity increases, as seen in the general upward trend in LACE for natural gas combined-cycle and onshore wind.
Conversely, solar PV’s LACE is generally flat to declining during the projection period. As solar penetration in the grid increases, solar capacity saturates during the midday hours, causing the value of electricity delivered in those hours to decrease.
In the AEO2019 Reference case, natural gas combined-cycle’s value-cost ratio is closest to 1.0 throughout the projection, indicating that its value just covers its costs. Natural gas combined-cycle units account for the largest share of new power plants (43% of the utility-scale total from 2021 through 2050). Solar PV’s value-cost ratio is slightly less than 1.0, indicating that, on average, its value does not cover its costs, but capacity is still added. In some cases, these solar PV additions may be uneconomic, but they still occur to satisfy the renewable portfolio standard (RPS) requirements in 29 states and the District of Columbia.
Onshore wind’s value-cost ratio remains lower than 1.0 throughout the projection period and lower than solar PV. Consequently, little onshore wind is installed in the Reference case, except in the near term when wind capacity is built to take advantage of the available PTC.
More information about LCOE, LACE, and economic competitiveness of electricity generating technologies is available in EIA’s Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2019 report.
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
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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