In Libya, eastern military leader General Khalifa Haftar looked to be pushing for greater control over the country, adding to other supply-side concerns that have recently driven sentiment in crude oil markets.
Further south in the continent, industry members gathered in Malabo, Equatorial Guinea, for the APPO Cape VII conference. At the event, OPEC’s secretary general said the group and its allies would not ease recent output cuts despite recent price increases.
GRAPHIC OF THE WEEK
The aging US coal fleet is being squeezed from all sides, with policy, cheap domestic gas supply and developments in clean energy generation all contributing to fast-paced closures. S&P Global Platts Analytics data show that since peaking at 317 GW at the end of 2011, US generating capacity with coal as the primary fuel fell by 73 GW, or 23%.
PODCAST: BIG THEMES IN AMERICAS CRUDE AND PRODUCTS
S&P Global Platts oil market editors Seth Clare, Laura Huchzermeyer, Maria Eugenia Garcia and Daron Jones discuss the most talked about topics at the American Fuel and Petrochemical Manufacturers’ Annual Meeting in San Antonio, one of the largest energy industry events in the US.
Topics include a new grade of US crude oil, challenges in
Venezuela, the US-Mexico jet fuel relationship, and two fires that erupted near
Houston during AFPM.
A new breed of plastic recycling plants capable of
recovering crude and fuels from plastic waste is piling more pressure on global
oil demand forecasts. The growing backlash against single-use plastics has seen
a number of companies looking to launch these new plants at commercial scale.
China’s mine safety watchdog ordered inspections at “high risk” mines after recent industry accidents, stoking fears that thermal coal availability might be affected in the near term. The checks will start with immediate effect and run until June.
Corn planting in some areas of the US is likely to be
delayed after recent floods led to saturated fields, but the effect on the
market will be limited because of plentiful carryover stocks, sources said.
THE LAST WORD
“No one has the right answer as to which fuel to use. Look for where you need fuels for your particular ships. Pick for individual vessels. Companies that pick the right fuel will win.”
Ahead of the S&P Global Platts Global Power Markets conference in Las Vegas, April 8-10, 2019, The Barrel presents a series of articles on the global and US electricity sectors. In this last post of the series, Steve Piper analyzes S&P Global Market Intelligence data to show that renewables are increasingly able to compete with conventional generation.
Wind and solar photovoltaic (PV) electric facilities only
account for an estimated 11% of US generation, but they are fast closing on a
tipping point where they may outperform conventional generation as an asset
Several factors have come together to drive this result,
starting with a rapid decline in costs for new renewable facilities, both wind
and solar, that has offset the advantage to natural gas generation brought
about by abundant and economical supply.
Improved efficiency of renewables also means every facility
can generate more power, delivering greater value and revenue to the
off-takers. Declining cost and increased output drives a cycle of improving
competitiveness and returns when compared to conventional generation.
Supportive economic policies such as Investment Tax Credits
(ITC) and tradeable Renewable Energy Certificates (RECs) also provide a source
of financial support to green energy, although both are expected to be reduced
in the future.
Finally, the progressive restructuring of wholesale
electricity markets, while traditionally viewed as providing principal support
to conventional merchant generation, has also facilitated the spread of green
energy. It has enabled multiple points of interconnection, and broad
integration of both the green electricity markets and the markets for their environmental
The ability to plug into the grid and realize a backstop price and secure marker for value, at a time when per-MWh costs of production are falling, has further allowed renewable projects to proliferate.S&P Global Market Intelligence has examined the revenue generation attributes of wind, solar, and natural gas generation across three major US investment markets to illustrate the respective drivers of value as well as the enormous potential for green energy to disrupt generating fleets well into the future.
Federal subsidy phase-out
Federal subsidies for renewable energy have fluctuated in
recent years, with current law phasing subsidies out over the next two years.
The current landscape for federal renewable incentives is as follows:
Solar – The Investment Tax Credit (ITC) equal to 30% of the installed cost of qualified solar panels or grid-scale solar projects that start construction before 2021, and then falling to zero by 2024
Wind – The Production Tax Credit (PTC) for wind resources was extended to include resources that commence construction by January 1, 2020, falling to zero after that time.
The lapse of federal subsidies will drive up the effective
cost of wind and solar facilities beginning in 2021-2022, although some of this
increased cost will be offset by falling costs on installation and technology
improvements that boost output. Unlike in Western Europe, only about 25% of US
electric load in California and the Northeast is subject to taxes on CO2
emissions, and the Northeast program is directed solely to electric sector
Instead, states increasingly focus on mandates to expand zero carbon generation. In 2018 California followed Hawaii’s lead to mandate 60% of electricity come from renewables by 2030, with a 2045 goal of 100% carbon emissions-free generation.
Many Western US states are introducing similar targets, with Arizona and Nevada pushing a 50% target by 2030. In the East, New York recently issued an executive order bumping its 2030 target from 50% to 70%.
The emphasis on mandates over prior tools such as Renewable Energy Certificates (RECs) and tradeable carbon emission credits reflects a growing consensus on commitment to the infrastructure aspects of the US generating fleet transition, much of which is expressed in early congressional proposals for the “Green New Deal”.
The charts below present 10-year forecast merchant
development returns to natural gas, wind, and solar PV in three key US markets:
the Electric Reliability Council of Texas (ERCOT); the PJM Interconnection
(PJM), and the California Independent System Operator (CAISO). As a whole, low
load growth and generation oversupply ensures that none of these asset classes
is forecast to achieve a full return (estimated at 9.7%). What is noteworthy,
however, is the relative consistency of returns to all classes and the
narrowing of spreads between renewable asset classes and new natural gas
ERCOT: King of the hill in energy
If you were going to choose a market with the best odds of
success for a natural gas power plant, you could hardly do better than Texas,
where industrial-zoned land is cheap, electricity demand is growing, older coal
plants have retired, and natural gas produced here may just be the lowest-cost
on the planet.
Thanks to burgeoning unconventional oil production,
especially that coming out of West Texas, the supply of natural gas that comes
along for the ride has expanded faster than generators (or anyone else) can use
it. But Texas is also blessed with high levels of wind, be it from the wide
flat plains of the West or from the steady coastal breezes. Texas is also at a
favorable latitude for solar resource. Furthermore, the Electric Reliability
Council of Texas (ERCOT) market only pays for peak generating capacity on an
hour-to-hour basis, a situation independent merchant power developers have long
decried. With last year’s improvement in prices, Market Intelligence estimates
spark spreads sufficient to deliver returns to generation equity owners this
summer, with growth into the future as the market stays tight on generation.
Compare the struggle for returns of a gas-fired
combined-cycle (CCGT) plant in ERCOT to a new solar facility. Although solar
facilities can’t avail themselves of hour-to-hour capacity payments, solar PV drives
value during the peak times of the day, receiving arbitrage between the
fluctuating price of coal and natural gas and their own marginal cost of zero.
Solar PV plants also receive at least a nominal contribution from ERCOT’s REC
market. While low power prices in ERCOT mean solar PV owners must accept less
than a full 9-10% return on capital, Market Intelligence estimates superior
returns to solar than those for natural gas.
Wind clean spreads look better still. With modern wind
turbines operating close to 45% of the year, the long-cited deficiency in
summer peak contribution becomes less relevant. Wind captures more value in
winter months than solar PV does, driving a higher overall estimated return.
Pennsylvania: Renewables close in on gas
If the Permian Basin
of West Texas produces the cheapest natural gas on the planet, the Marcellus
Shale centered in western Pennsylvania, eastern Ohio, and West Virginia may
come in a close second. Combined with a more stable revenue stream for
generating capacity via the PJM Interconnection’s capacity auctions, this
region has been targeted for merchant CCGT investment.
Market Intelligence estimates 16.7 GW of new CCGT capacity
will come on-line 2018- 2020, offsetting the impact of recently retired coal
and nuclear capacity. Together with a robust capacity payment, Market
Intelligence estimates that a new CCGT will generate a solid return, exceeding
that of ERCOT gas plants, over the next 10 years.
But states in the PJM region also support renewable
facilities, using Renewable Portfolio Standards (RPS) backed by tradeable RECs.
Utilities in Pennsylvania, Maryland, and New Jersey in particular can contract
with green facilities or purchase RECs created by a facility potentially
anywhere within PJM’s 14-state footprint. As in ERCOT, typical wind plants in
PJM generate substantial value for their owners, with REC contributions driving
comparable returns for wind compared to those estimated for a natural gas
California: Gas out of favour
In efforts to modernize its natural gas generation fleet,
California has mandated replacement of once-through cooling systems with
zero-discharge water towers. Many plants are instead opting to decommission. At
the same time, the aggressive build out, especially of solar PV, both
distributed and wholesale, has depressed power prices substantially and will
continue to do so.
This is essentially the wholesale price version of the
infamous ‘duck curve’ for hourly load, resulting in very low prices when solar
PV generation is highest. As a result, a new CCGT stands out as a
higher-performing asset in our forecast than wind or solar, as the state’s
enthusiasm for these resources saturates the market. Importantly, however, the
hourly wholesale electricity market supported by CAISO has expanded to cover
multiple states of the Western US, allowing developers to site plants in areas
less picked-over and still serve California’s RPS standard. While total returns
in California appear low, stronger returns are achievable elsewhere in the
Bottom line: Tilting towards renewables
The revolution in US shale gas seemed destined to drive most future generation investment toward natural gas power plants. And indeed it did – for a few years. As costs have fallen for wind and solar PV facilities, Market Intelligence forecasts indicate returns are converging with new natural gas, even in markets where natural gas competes best.
This begs an important question: how competitive is green electricity today in parts of the world where fossil supplies are lagging? With just modest additional improvements in technology, we could see capital begin to tilt even further towards renewable energy, and further away from conventional generation.
planned 55 Bcm/year Nord Stream 2 gas link to Germany has prompted heated
political debates, changes in EU law and threats of US sanctions, but its fate in
the end may be decided by Danish civil servants enforcing local planning rules.
development is that the Danish Energy Agency has asked the Nord Stream 2
project company to provide information on a third possible route for the Danish
section of the two 1,200 km parallel pipelines, while it is still assessing two
pending permit requests for other routes.
for Nord Stream 2 is that it cannot complete the pipe-laying without a permit
from Denmark, and there is no legal deadline for approving or rejecting such
permits, creating uncertainty about when gas will start flowing through it.
company wants to bring Nord Stream 2 online by the end of this year, before
Russian gas pipeline export monopoly, Gazprom, reaches the expiry of its
transit contract to Europe with Ukraine’s Naftogaz. Gazprom has not said yet what it
will do if that date slips.
officials have said Gazprom could meet its minimum contractual commitments to
European customers without Nord Stream 2 or Ukrainian transit from January 1,
2020, as long as its 31.5 Bcm/year Turk Stream pipeline to Turkey starts by the
end of this year as expected. That could see European gas prices spike in
2020, as customers make up any shortfall from storage and more expensive LNG
more likely outcome, according to Naftogaz CEO Andriy Kobolyev, is that Gazprom
will continue to use the Ukrainian route during any Nord Stream 2 delay. Gazprom
sent 87 Bcm through Ukraine to Europe in 2018, and has said these volumes would
likely drop to less than 20 Bcm/year once Nord Stream 2 and Turk Stream are
The European Commission and Naftogaz are keen for Gazprom to sign a long-term capacity commitment for the Ukrainian route after 2019 at volumes high enough to keep it viable. EC vice president for energy union Maros Sefcovic has reportedly suggested Gazprom commit to a minimum 60 Bcm/year capacity contract for 10 years, on a ship or pay basis, with Naftogaz ensuring another 30 Bcm/year capacity is available to cover any short-term extra needs.
and Naftogaz are locked in a protracted legal dispute over the current transit
contract that will not be resolved till the middle of 2020 at the earliest.
Gazprom has said it will not sign new terms before that dispute is resolved.
approach works for Gazprom as long as Nord Stream 2 comes online by the end of
the year. Everything that puts that in doubt – such as uncertainty over when
Denmark will grant the permit – puts pressure on Gazprom to come to the
negotiating table to agree new transit terms before the end of this year.
has said Gazprom could also book short-term entry and exit capacity, for
example for a year, under Ukraine’s current tariffs and capacity booking
products. Such short-term tariffs would be higher than those possible with a
long-term contract, he said.
2 already has all the other planning permits it needs from Finland, Germany,
Russia and Sweden on its route across the Baltic Sea, and it has laid more than
800 km of pipe. The project company has said the Danish section can be filled
in last if needed, so the project could stay on schedule even if the final
permit is not granted until August.
gas sales to Europe are on the rise, meanwhile, despite stable European gas
demand. Sales hit a record 201 Bcm in 2018, using Russian measurements, as
lower domestic European output boosted demand for imports.
The US continues to warn Europe against becoming more dependent on Russian gas, even while recognizing that it is currently cheaper than the alternatives, including US LNG. It is also a consistent, vocal critic of Nord Stream 2 for the negative impact it will have on Ukraine’s Russian gas transit revenues.
sympathizes with the US view on Nord Stream 2, but there is no legal way to
stop the pipeline being built as long as the project company complies with all
EU rules. The US President has the power to impose financial sanctions on the
companies helping to build Nord Stream 2, which could disrupt or delay the
project, but the current incumbent, Donald Trump, has shown no sign of using
the EC has been courting the US and its potential to increase LNG exports to Europe.
It is planning a high-level EU-US industry meeting on May 2 in Brussels to
discuss “competitive pricing,” among other things, with US secretary for energy
Rick Perry due to give a keynote address.
imports from the US remain tiny compared with Russian pipeline gas, at just 3.3
Bcm in 2018, or less than 1% of total EU gas demand. The EC wants this to more
than double to at least 8 Bcm/year over the next four years, and European
demand for US LNG is growing rapidly – but from a very low base.
example, US LNG exports to Europe, including Turkey, surged
75% on the year in February to 411.5 million cubic meters, but were still
eclipsed by Russian LNG exports of 1.4 Bcm, up 67%, according to
S&P Global Platts Analytics data.
Mexico’s new president Andres Manuel Lopez
Obrador, popularly known as AMLO, has said there will be no fracking during his
six-year term, igniting a debate about Mexico’s energy security amid rising gas
consumption. But mixed signals on the issue have emerged from elsewhere in the
So what is all the fuss about? Saying no to fracking will mean leaving more than half of Mexico’s total natural gas reserves in the ground. This could be risky for Mexico, since the country’s natural gas production has fallen dramatically in recent years, descending to 2.6-2.7 Bcf/d in 2018 from a historical high of 5.1 Bcf/d in 2010, according to S&P Global Platts Analytics.
The decline in production coincided with rising domestic gas consumption off the back of growing gas-fired power generation, new factories, and favorable gas prices in the US. This combination of factors has caused a rapid increase in natural gas imports from the US through pipelines and as LNG.
Mexico’s gas imports now account for more
than 70% of total demand. Pipeline flows
amounted to around 4.2-4.5 Bcf/d in 2018, but insufficient pipeline infrastructure
amid surging demand has led Mexico to become the second-largest buyer of US LNG,
taking around 19% of the overall LNG exports from the country.
This growing reliance on imported natural gas from the US is fueling a debate on self-sufficiency goals, and energy security. Mexico is one of the few countries in the world that depend on a single other state for gas imports. That leaves its energy supply heavily exposed to US export strategy. What would happen if the US decided to liquefy more of its natural gas and sell it to other countries that pay more than Mexico?
Fracking could yield significant domestic gas output, alleviating the country’s dependence on natural gas imports. The technique dramatically altered the US energy balance, taking it from a country heavily reliant on the Middle East for its energy needs, to an oil and gas powerhouse. Oil production in 2018 reached around 11 billion b/d, and natural gas production reached 16.86 Tcf in 2017, a 39% increase over the last decade, according to the US Energy Information Administration. Furthermore, the US hydrocarbon bonanza has helped reduce energy prices, saving consumers billions of dollars and spurring economic growth.
In Mexico, fracking has been used for more than half a century, and has been applied to about one in five conventional oil and gas wells, according to former energy secretary, Pedro Joaquin Coldwell. This year, there were plans to start applying the technique in unconventional basins. However, AMLO cancelled a bidding round scheduled for February 2019, which involved nine unconventional onshore blocks.
Without the use of fracking for shale gas extraction,
hydrocarbon production will depend on the country’s conventional basins.
According to the National Hydrocarbons Commission (CNH), more than 50% of
Mexico’s gas reserves are in non-conventional resources, and the only way to
extract them is by hydraulic fracturing.
Furthermore, Mexico ranks sixth worldwide in volume of unconventional resources. It is estimated that the hydrocarbons contained in shale across all the oil provinces of the country are equivalent to 4.1 times the total historical production of oil and gas of the mega deposit Cantarell, according to Coldwell.
But despite AMLO’s blunt fracking ban, there is a twist: Pemex, the state oil and gas company, contemplates investing in fracking in its 2019 budget, devoting about Mexican Peso 3.8 billion to evaluating multiple areas with oil and shale gas. Additionally, the Energy Secretary, Rocio Nahle, mentioned in early 2019 that this government will use fracking, though she was careful to emphasize that she was not advocating a free-for-all. Strict conditions would apply, she said, including the use of the most modern and environmentally-friendly technology.
Furthermore, in February, CNH approved Pemex’s plan to
test shale potential in up to eight exploratory natural gas wells in northwest
Veracruz. This suggests the new administration has no clear position on
fracking, and it is watching to see what happens with the exploratory wells to
inform its next steps.
Politics aside, there are other
obstacles to producing shale gas in Mexico. Firstly, there are the
environmental concerns about water use, air and groundwater pollution and
earthquakes that have drawn opposition to fracking in Mexico just as they have
in other countries including the US.
There are also challenges more specific to Mexico, of land holding and mineral rights; a lack of knowledge on unconventional resource geology; a small service industry; a poor regulatory framework; lack of pipelines; and security issues.
Meanwhile, given the efficiency and
abundance of US shale gas plays, and the resulting low prices, Mexico faces
stiff competition in its bid to develop domestic resources. Given a green light
for fracking, would Mexico
be able to emulate US efficiency? To promote the production of natural gas in unconventional
reservoirs, at least in early stages, the government would
need to implement a
comprehensive program including incentives and tax
breaks, as was done in the US in the 1980s.
To frack or not to frack, is the dilemma
that lingers. Either continue relying on the US to meet Mexico’s natural gas demand
and let go of the country’s vast shale reserves, or start the exploitation of
these deposits to attempt to reverse the significant fall of conventional
All oil and gas activities carry a risk,
and what Mexico needs is to tighten regulation in all processes, not only for
fracking, but also for traditional extraction, in order to reduce any
possibility of damage to the environment. And before allowing or prohibiting
fracking, there should be a deeper analysis and discussion that covers not only
gas and oil output, but also the impact it might have on the petrochemical and
electricity industry, employment, and national security.
Deliveries of LOOP sour crude dropped in March, one month
after flows reached their highest level in half a year, a Louisiana Offshore
Oil Port report showed Monday.
LOOP delivered more than 845,000 barrels of the sour crude from its storage in March. That is compared with the six-month record high of 1.135 million barrels of LOOP sour crude that was delivered in February.
US Gulf Coast refining activity hit its lowest point in
about a year during March. The Energy Information Administration data showed
that in the week that ended March 22, the USGC refining complex ran at 87% of
capacity, the lowest level since the week that ended February 16, 2018.
Market sources said this was partly due to a fire at ExxonMobil’s Baytown refinery, one of the largest in the US, as well as other planned and unplanned repair work in the region. With regional refining appetite quelled, demand for LOOP sour may have been dampened.
However, March’s deliveries of LOOP sour still remained
relatively strong, when compared with the six-month average of about 730,000 barrels
There has been strong demand for sour, heavier crude grades
such as LOOP sour in recent months as there has been limited supply due to OPEC
production cuts, in addition to dwindling supplies out of Venezuela.
LOOP also reported that the crude delivered ex-cavern in
March maintained its density with an average API of 29.8 degrees. LOOP Sour’s
sulfur content decreased to 2.06% in March, compared to 2.21% sulfur reported
in February. LOOP’s six-month sulfur quality average is 2.18%.
Separately, LOOP will auction 7,200 capacity allocation
contracts in its monthly crude storage auction on Tuesday, which collectively
equal 7.2 million barrels of storage for the medium crude blend. The minimum
bid price LOOP will accept during the auction is 5 cents/b. Monthly storage for
LOOP Sour traded around 5 cents/b for all of 2018.
Auction co-host Matrix Markets said LOOP will sell up to
3,600 storage futures contracts and 3,600 physical forward agreements. The
front-month contract of May will see 300 CACs put up for sale.
LOOP and Matrix in March sold a total of 2.175
million barrels of storage capacity of the 7.4 million barrels that were
Ahead of the S&P Global Platts Global Power Markets conference in Las Vegas, April 8-10, 2019, The Barrel presents a series of articles on the global and US electricity sectors. Here, Morris Greenberg explores the drivers behind US coal generation retirements in recent years.
The aging US coal
fleet is being squeezed from all sides, with policy, cheap domestic gas supply
and developments in clean energy generation all contributing to fast-paced
Since peaking at 317 GW at the end of 2011, US generating capacity with coal as the primary fuel fell by 73 GW, or 23%, due to retirement of 61 GW and primary fuel conversion – mainly to natural gas – of 16 GW. This was offset by additions of 4 GW.
Most of the
additions were made early on in this eight-year period. Coal-fired generation
has fallen even more steeply than capacity, with a decline of 33.5% between
calendar years 2011 and 2018. The drop reflects a reduction in average capacity
factor (utilization rate) from 62% to 52%.
factors have stabilized during the past three years, announced plans for
retirement of around 20 GW and conversion of around 5 GW indicate that, without
some form of policy support, capacity declines will continue.
announcements may only reflect the tip of an iceberg that includes many more GW
of capacity at risk. To get a better handle on that number, it is useful to
review first the economics of retirement and then factors that have driven the
restructuring observed to date. These factors are: an aging coal fleet; stagnating
demand; low natural gas prices; environmental regulation; and finally, cost declines
and policy support for clean energy.
The decision to
permanently retire a merchant coal unit, or really any merchant unit, is made
by comparing the present value of future revenues from sale of energy, capacity
and ancillary services to the present value of costs including fuel, non fuel variable
operating and maintenance expense, fixed operating and maintenance expense, and
required capital spending. For regulated units, the relevant measure is the
present value of revenue requirements. The calculations are similar if
replacement energy and capacity is acquired from the market. There are several
factors that play into this calculation and have driven the restructuring seen
in the US market in recent years.
Of the 317 GW of
operable capacity in 2011, 125 GW exceeded 40 years of age and 50 GW exceeded
50 years. Older units are less efficient, require higher spending per unit of
capacity to maintain availability, and tend to face higher capital requirements
for environmental retrofits, leaving them more vulnerable to changes in market
Stagnating power demand
A combination of improving energy efficiency among consumers combined with rising behind-the-meter generation has led to stagnating demand, leaving US retail electricity sales virtually unchanged from 2011 to 2017. Weak demand depresses energy and capacity prices for all generation, but coal units were exposed due to the factors that follow.
Lower natural gas prices
Low natural gas
prices have had a major impact on the erosion of US coal-fired capacity. The
direct impact is the conversion of existing capacity from coal to gas. But
there is also an indirect impact, as lower electric energy and capacity prices
reduce the value of coal capacity and may boost operating costs due to
Since 2011, rising gas supply associated with shale gas development has allowed US consumption of gas for power generation to increase by 38%, from 21 Bcf/d to 29 Bcf/d and accommodated higher net exports with no upward pressure on prices.
Accounting for permitting, financing and engineering, the development cycle for gas capacity ranges from about two years for fuel conversions, to five years for greenfield development. As a result, while gas prices have an immediate impact on energy prices, the impact on capacity prices and decisions to build or retire plants occurs with a lag of that duration.
moving average of Gulf Coast gas prices lagged by two years peaked in late 2010
near $8/MMBtu, fell to the $3.50 range in 2015-17, and to the low $3 range in
2018. It will fall below $3/MMBtu this spring and likely remain there for
several years. That means gas markets will remain a drag on coal unit economics
for years to come.
Coal units must
comply with air, water and solid waste emissions standards. Air emissions
include sulfur dioxide, nitrogen oxide, particulates, mercury and other air
toxics, and carbon dioxide. Water standards cover plant effluents as well as
cooling water intake structures and temperature impacts. Coal combustion
residuals are also regulated.
The Mercury and Air
Toxics rule, which took effect in April 2015, was the most important regulation
to impact coal capacity during the 2011-18 period, driving units facing high compliance
costs to retire. In some cases, units that remained in service faced increased
costs associated with operating emissions controls or purchasing coal additives
to improve mercury capture.
While the Obama administration’s
Clean Power Plan proposed in 2014 was never implemented, the potential for
future carbon regulations must be considered in a decision to retire or
maintain coal capacity, particularly if capital infusions are required. In
addition, while the federal regulatory role is currently limited, carbon
emissions caps are in effect in California and the Northeast, through the
Regional Greenhouse Gas Initiative (RGGI), and several other states have
emission reduction targets.
Cost declines and policy support for clean energy
A combination of
falling costs and state, as well as federal, policy has led to rapid growth in
US wind and solar generation. Solar PV costs have declined from about $4,000/kW-AC
in 2011 to about $1,200/kW-AC at present. During the same period, onshore wind
costs fell from over $2,000/kW to about $1,500/kW. In addition, the cost of
battery storage that can help integrate intermittent renewables, particularly
solar, has fallen dramatically.
played a role in renewables growth primarily through renewable portfolio
standards (RPS), which mandate a certain proportion of renewables in the energy
mix. Twenty-nine states and the District of Columbia currently have mandatory
RPS. Qualifying technologies vary from state to state – though solar and wind
qualify everywhere – and percentage requirements vary over a wide range. Based
on current law, renewable generation to meet RPS requirements of load serving
entities – that is, companies that provide power on a retail basis, mainly
utilities but also unregulated marketers – will more than double between 2018
and 2030. Corporations in pursuit of sustainability goals have also stepped up
their purchases of renewable energy, signing deals for over 6 GW of capacity in
State support for
merchant nuclear units challenged by weak margins may come at the expense of
coal capacity. Unlike intermittent renewables, nuclear units provide significant
capacity value – meaning they can provide energy whenever needed. New York and
Illinois are already providing support, with New Jersey and Connecticut also
moving down this path. Pennsylvania, home to 10 GW of nuclear capacity, may follow.
The federal role in
promoting renewables has mainly been through tax credits, including production
tax credits (PTC) for onshore wind and investment tax credits (ITC) for solar.
Under legislation enacted in late 2015, wind projects starting construction in
2016 are eligible for a PTC of $23/MWh for 10 years; the value of the credit
steps down for projects started in subsequent years and is phased out for
projects begun after 2019.
The ITC is 30%
for projects started by the end of 2019 and then steps down over the following
two years with the residential credit expiring for projects begun after 2021
while the ITC for non-residential systems falls to 10%.
The cost of wind generation (including ROI) from projects qualifying for the full PTC in areas with high average wind speeds is in the $15-20/MWh range, competitive with the variable cost of coal and gas generation. The cost of solar PV qualifying for the full ITC in areas with high insolation is in the $25/MWh range. Variable production costs are lower, and producers are often willing to sell at negative prices to capture tax credits (in the case of wind) and renewable energy credits (used for RPS compliance).
Due to lower variable production costs, rising renewables generation will displace both coal and gas generation and result in lower energy prices. In addition, more extensive cycling of dispatchable generation to balance supply and demand will result in higher operating costs.
Despite its impacts on energy prices and
operating costs, growth in renewables output by itself has not been a major
driver of coal retirements because the resources do not provide much capacity
value, and lost energy revenues can be partially recouped in capacity markets.
That may change, however, with additional investment and the ability of battery
storage to add capacity value. According to the American Wind Energy
Association, there are 35 GW of wind capacity in advanced development and the
Solar Energy Industry Association report 27 GW of solar projects with signed
PPAs and another 37 GW announced.
While this discussion has been focused on US developments, the same factors apply elsewhere in the world as well, though their relative importance may vary. Europe, for example, is expected to see a significant reduction in coal-fired generating capacity during the next two decades. Slow demand growth, policy support for renewables, and explicit coal shutdown plans play a role. As a gas importer, gas prices tend to be higher in Europe, but the impact is offset by carbon allowance prices that boost the effective cost of burning coal relative to gas.
In Asia, the picture for coal is a little brighter thanks to high gas prices, faster load growth and looser environmental regulations. However, renewables are making inroads, particularly in China, causing growth in coal to slow.
Fuel quality is the great unknown for the shipping and oil refining industry. The International Maritime Organization’s (IMO) January 2020 deadline could see the majority of vessel owners switching to cleaner marine fuels incompatible with each other. Other solutions look similarly haphazard.
The IMO’s global sulfur limit for marine fuels drops to 0.5% next January from 3.5%, and the industry is developing a wide range of very low sulfur fuel oils, which may be compliant but also vary in other qualities.
specifications of the new fuels matter because marine engineers need to know
how they will interact with their vessels, and bunker purchasers need to
start planning which fuels they will be able to buy, at which ports and in
which combinations. Imagine a driver in a car pulling up outside a filling
station uncertain as to whether the gasoline at the pump would cause their car
to break down.
this unthinkable scenario looms large at sea. There is at present no guarantee
any of the new bunker fuels will be compatible with each other — when
mixed in a single bunker tank, they may separate and form sludge that will block
filters and ultimately damage the engine.
differences could be vast, the fuels could have much higher presence of
substances like silicon or aluminum compounds or there could be questions over
fuel blends when mixing aromatic and paraffinic refinery streams.
have to learn on the behavior of these fuels, it will take quite some time to
find the right balance and understanding across the global market,” said Damien
Valdenaire, science executive at oil industry research body Concawe.
buyer with ships travelling between Fujairah and Singapore – the two biggest
bunkering hubs – may have no idea whether the fuel bought at the Middle East
hub will be compatible with any of the products available in the Far East.
cost could be huge, and not confined to a handful of credit-starved shipowners.
Higher oil prices, slower-sailing ships, bankruptcies and squeezed margins
across many connected industries, along with risks to world trade, could all define the
years that follow.
then there’s the danger of high-profile engine failures in shipping arteries
such as the Strait of Hormuz, the world’s most important chokepoint that allows
30% of the world’s crude oil and other liquids
as well as 30% of global LNG trade into the Gulf.
message from the bunker industry has been unequivocal. “No co-mingling of
fuels,” said Unni Einemo, the IMO representative at the International Bunker
recently. And at the Fujairah Bunkering & Fuel Oil Forum, top executives
said they expect most shipowners to switch to marine gasoil or marine diesel in
the short term, and to 0.5% low sulfur fuel oil blends in the mid to long term.
International Bunkering Chief Executive Carsten Ladekjaer said at Fujcon that
the industry generally does not yet know enough about the 0.5% sulfur products
of the future – including their origin, components, stability and not least their
compatibility – to make longer-term
The IMO has shown it won’t be backing down. But similarly, the United Nations’ body responsible for the safety and environmental performance of the shipping sector has left ownership of the issue up to the individuals concerned.
Some seafarers have rushed to fit
scrubbers – kit to clean up the pollutants – so they can carry on burning fuel
oil, while refiners are yet to come up with the goods on iron-clad
specification-ready middle distillates.
The energy majors have been
scrambling to be ready as the clock ticks down. BP said this month it was set
to launch “a new very low sulfur fuel oil” with maximum 0.5% sulfur content
following sea trials of product produced and supplied in Northwest Europe and
Singapore. But details of specifications or when it plans to make the first
sale were not given.
ExxonMobil announced in October that
its range of 0.5% sulfur marine fuel blends will be compatible with each
other. That could mean shipowners end up willing to pay a premium for
Exxon’s products that are likely to be available at a wide range of
ports. However, it still leaves open the question of whether shippers can
mix Exxon’s fuel with other refiners’ brands.
Shell is conducting trials of its new
0.5% sulfur fuels with customers in Rotterdam, Singapore and New Orleans.
Meanwhile, the world’s largest
consumer of bunker fuel is increasingly becoming a supplier of the product as
well, as it takes back control of its supply chain ahead of disruptive changes
to emissions regulation next year.
AP Moller-Maersk, the parent company
of container shipping firm Maersk Line, signed a deal with New Jersey-based PBF
Logistics last month to produce and store 0.5% sulfur bunker fuels both for its
own needs and third-party customers on the east coast of the US. The agreement
follows a similar one made with Vopak in Rotterdam in August, and its leasing
of storage capacity in Singapore in October.
Individual solutions point the way
forward until the industry is able to figure out compatibility.
At an S&P Global Platts industry event earlier this year, participants felt that mixing fuels was too big a gamble but that in time an answer will be found. After all, the industry has already had a wake-up call. Last year hundreds of tankers in Houston and Singapore suffered damage due to contaminants in fuel clogging filters and pumps. While it was a very different issue and didn’t lead to engine failures, it sparked panic after shipowners in Asia were reluctant to buy US Gulf Coast-origin fuel.
Time is running out and the whole
value chain could benefit from a dose of collective responsibility rather than
individual accountability. It could be in as short supply as the right sort of
fuel come 2020.
launched IMO 2020-compliant 0.5% sulfur marine fuel cargo assessments in
Fujairah and Singapore at the start of this year.
Metals are playing a starring role in the transition towards renewables and electric vehicles, and the past week saw plenty of activity in the sector. There were also positive indicators pointing to strong demand ahead for a number of products.
According to the Japan Mining Industry Association, development in transport and telecoms should bolster demand for base metals, which include nickel, copper and zinc, despite economic headwinds. “With the EV and 5G coming, demand fall is unlikely in the longer term,” said association chairman Naoki Ono on March 27.
Away from EVs, development in conventional autos continues to bolster the price of palladium, used in catalytic converters to reduce emissions. Palladium is currently priced at around $1,600 per ounce, a rise of more than 50% since October.
GRAPHIC OF THE WEEK
The gas discovery off Cyprus announced in late February by US major ExxonMobil and its partner Qatar Petroleum has contributed to the fast-shifting dynamics of the East Mediterranean gas market.
PODCAST: BUYING FLURRY ON DATED BRENT
S&P Global Platts reporters Emma Kettley and Gillian Carr speak to Joel Hanley about the sudden strong buying interest in the North Sea Dated Brent crude complex, as well as the knock-on effect on grades such as Russia’s Urals.
Africa’s downstream sector has seen an injection of $30
billion in investment, as the continent is one of the few regions where oil
demand is expected to grow steadily for the next two decades, the African
Refiners and Distributors Association (ARA) said Thursday.
The 2019-20 sugarcane season will officially start April 1
in the Center-South, the world’s largest sugarcane- and sugar-producing region.
The continued strength of ethanol prices has maintained a wide spot premium to
sugar, which, coupled with higher-than-expected fuel consumption rates in 2019,
is tilting the balance toward ethanol.
The role of bunker traders is undergoing a transformation as 2020 approaches, with many likely to play an increasingly vital role as harbingers of credit and information to a market which is dealing with the complexity of the International Maritime Organization’s global sulfur limit rule for marine fuels.
THE LAST WORD
“We’re not looking to trade battery metals in the short term, we are focused on the energy side of commodities.”
Ahead of the S&P Global Platts Global Power Markets conference in Las Vegas, April 8-10, 2019, The Barrel presents a series of articles on the global and US electricity sectors. Here, Felix Maire and Jared Anderson look at the prospects for battery storage across the US.
Battery energy storage deployment in the US has rapidly increased in recent years and appears set for further growth, assuming costs continue decreasing and pending market rule changes increase opportunities for storage resources to participate in wholesale power markets.
But importantly, the economics, policy drivers and use cases differ widely among regions.
The US currently has a little over 1 GW of installed battery storage capacity and could have more than 7 GW of utility-scale and grid-connected battery storage operating by 2022, according to S&P Global Platts Analytics’ most recent US Power Storage Outlook.
Lithium-ion battery prices have sharply
declined in recent years driven by steadily expanding manufacturing capacity,
which has led to economies of scale and improved learning. That learning curve
is expected to continue as battery companies are planning a six-fold
manufacturing capacity increase by 2023.
Over the medium to longer term, Platts
Analytics anticipates that mass-market electric vehicle adoption will continue
to drive battery costs down despite concerns around raw material prices.
Lithium-ion battery prices are expected to decline 40% by 2025, making it
difficult for other technologies such as flow-batteries to compete,
particularly for shorter durations.
One potential battery storage deployment growth metric lies in the interconnection queues maintained by each wholesale power market operator, known as independent system operators (ISO) or regional transmission organizations (RTO). Any resource that wants to connect to a regional power grid must progress through a formal interconnection process. Not every resource will ultimately connect to the grid, but the queues provide a view of the level of market participants’ interest in storage.
Battery capacity in RTO/ISO interconnection
queues more than doubled in 2018, surpassing 30 GW of capacity. The largest
queued capacities are in the California ISO (CAISO), supported by storage
mandates, and in the Southwest Power Pool (SPP), where several large
solar-PV-with-battery projects entered the queue in 2018.
The Federal Energy Regulatory Commission’s
(FERC) energy storage order 841 will impact the volume of wholesale power
market energy storage participation over the longer term, but the impact is
expected to vary by region.
The ISOs filed plans with FERC detailing
market rule changes that would allow energy storage resources to participate in
regional power markets on a level playing field with other resources. FERC is
reviewing the proposals that were filed in December.
Market observers were initially concerned that a 10-hour participation requirement for storage in PJM Interconnection’s proposal would limit the ability of battery storage to engage. PJM Interconnection is an RTO whose territory spans a number of states in the eastern US.
However, president and CEO Andy Ott explained in a recent interview that changes to its energy and reserves markets are expected, to allow storage resources to earn the bulk of their revenue from those market segments. The 10-hour requirement only applies to the capacity market, which is not ideal for storage resource participation, according to Ott.
Outside those regions covered by RTOs/ISOs,
several utilities have announced plans to procure battery storage as part of
their Integrated Resource Plan processes. Portland General Electric recently
announced a first-of-a-kind combined facility with 300 MW of wind, 50 MW of
solar PV and 30 MW of batteries. And Arizona Public Service Company in February
said it plans to add 850 MW of battery storage and at least 100 MW of new solar
generation by 2025.
Platts Analytics estimates that solar PV with storage will become increasingly competitive with natural gas peaking plants in regions with high solar resources.
It’s now a year since China took the first
steps to opening up its mainly domestic futures market to the world with the
launch of the Shanghai crude oil futures contract.
It was the first of three to be “internationalized” last year – the other two were the existing iron ore and PTA futures contracts. But Shanghai crude was different to those in that it was a new contract, hosted on a new trading venue – the Shanghai International Energy Exchange (INE) – and designed specifically to attract international participants.
The goal was to create a new China-based global pricing point for crude alongside incumbent international crude futures contracts NYMEX WTI and ICE Brent.
The success of a new futures contract is
typically measured by its liquidity, market depth and open interest. In the case
of a physically settled contract, the delivery mechanism of any new contract
will also be closely scrutinized by the market.
& market depth
While liquidity is not everything when it comes to benchmarks, when it comes to derivatives it certainly helps. In February, less than a year after it started trading, 2,116 million barrels of Shanghai Crude were traded. It took ICE Brent more than 14 years to reach a similar monthly volume.
But the comparison has to be seen in historic context. When Brent was launched in 1988, electronic trading had yet to be invented and orders were taken by brokers in colorful jackets shouting at each other across the trading floor. It was only when ICE moved Brent over to fully electronic trading in 2005 that volumes really soared and it became the derivatives success it is today.
Liquidity on Shanghai crude is generally concentrated in just one contract. This is usually the contract that expires at the end of the current month. However, in the last 10 days before expiry liquidity moves to the next month forward as traders who are not allowed to take physical delivery are forced to liquidate their positions and roll them into the next contract.
On March 25, with just four days before the April 2019 contract expires, virtually all the volume and open interest had moved to the May 2019 contract, which expires at the end of April.
medium sour contract
The price of Shanghai crude reflects the price of one of seven medium sour crudes – all but one of them from the Middle East – held in bonded tanks located on the coast of China. While one might expect the price to track Platts Dubai, the Middle East benchmark, the price of Shanghai crude actually more closely follows ICE Brent.
This is reflected in its trading patterns: Shanghai crude is most active during the night session after 9 pm Beijing time when European and US exchanges are active and it can be traded against other futures like ICE Brent and NYMEX WTI.
It is also worth noting that because the
Shanghai contract is denominated in Chinese yuan not US dollars, the value of
the contract is susceptible to changes in the yuan-dollar exchange rate; as the
Chinese currency strengthened against the dollar in February, the price of
Shanghai crude when converted into dollars fell by around $2/b against ICE
Brent and Dubai.
Seven monthly contracts have expired since the INE launched Shanghai crude, with six of these being settled by physical delivery. The first delivery in September last year saw 600,000 barrels change hands. The very low volume of crude in exchange-approved tanks in the month of the first contract expiry – at one point it fell to just 100,000 barrels – saw the price of the contract whipsaw compared to other crude benchmarks, in response to fears that there would not be enough oil in tank to meet delivery.
Since then the volume of crude on warrant and volume delivered has risen, averaging slightly over 2 million barrels over the last three deliveries. And prices have been less volatile versus international benchmarks over the last few deliveries.
While the intention of the INE is to
internationalize the contract, a year after its start it remains primarily a
domestic affair. INE data from mid-December shows that around 92% of the
trading volume and around 80% of the open interest was accounted for by Chinese
traders. Retail investors account for slightly over three-quarters of the
volume and more than half the open interest, with oil companies, physical traders
as well as funds and investment companies making up the remainder.
The exchange does not release information on parties involved in delivery but market sources suggest that not only physical traders and Chinese oil majors, but also financial firms like domestic futures brokerages, used the physical settlement mechanism.
It may seem surprising that companies with no use for physical oil have chosen to close positions physically but the settlement process does not require scheduling logistics and chartering vessels. Delivery is typically done by transferring ownership of a warrant – a receipt that allows the holder to take delivery of oil held in a specific tank – from seller to buyer. The seller chooses the grade and location of the warrant they wish to deliver to settle their position.
In a contango market – where prices in later months are higher than the current month – money can be made by selling a later month and buying the current month. This works as long as the profit from this trade is greater than the cost of holding the oil on warrant until it has to be delivered to settle the short position. The Shanghai crude contract was in quite a strong contango for much of the period from November to mid-March, making this trade possible.
The first year of the Shanghai crude contract has been a success in many ways, but from a physical market perspective, it is still early days. There has been talk of independent refiners possibly using Shanghai crude rather than ICE Brent as the basis on which they buy cargoes. But currently there does not appear to be much, if any, use of Shanghai crude as a basis on which to price term contracts or spot cargoes.
On March 22, 131 million barrels of Shanghai crude were traded with open interest of 28 million barrels. ICE Brent saw 946 million barrels traded with open interest of 2.4 billion barrels. This was more than eighty times that of the Shanghai crude and reflects the widespread use of Brent as a risk management tool across the global oil sector.
It is worth remembering that Shanghai crude has only been trading for 12 months – ICE Brent turned 30 last year. As it passes its first birthday the challenge for Shanghai crude will be to draw in more international participation and build market depth and open interest along the curve. It will also take time to build trust in the physical settlement mechanism. But if these issues can be successfully addressed, Shanghai crude may well find its seat at the table with Brent, WTI and Dubai.
When the first premier of the People’s
Republic of China, Zhou Enlai, was asked in 1972 about the impact of the French
revolution he famously retorted that it was “too early to tell”. History does
not relate whether he was referring to the revolt of 1789 or the student riots
of 1968, but taking a long view may be wise advice for those trying to judge
the success or otherwise of the Shanghai crude oil futures contract.