Despite the forecasted trend of
declining demand for transportation fuels, many markets still depend heavily on
these crude oil derivatives to sustain economic activity. This is especially
true in developing economies like Brazil and India. The production of
high-quality gasoline from refinery naphtha streams is still fundamental to
refiners aiming to meet market demand. In addition, considering the current
specifications, the synergy between fluid catalytic cracking (FCC) and cracked
naphtha hydrodesulfurization (HDS) is fundamental for refiners to reach
profitable operations.
Cracked naphtha is produced from
refining processes like FCC that chemically crack low-value, heavy molecules
into light fractions (naphthas) suitable for use in blending gasoline. Compared
to the FCC process, which has been in use for 70 yr, cracked naphtha HDS is a relatively
new process with only a 20-yr history of commercial use—its use has grown
steadily since 2000 due to new ultra-low-sulfur (ULS) gasoline specifications
such as Tier 2 and Tier 3 specifications in the U.S. Today, more than 200 cracked
naphtha HDS units are in operation globally, and new units continue to be built
as more stringent gasoline sulfur specifications spread around the world (FIG. 1).
Cracked naphtha processes are
described in literature.1 These units remove sulfur from FCC
naphtha, which is the largest component in the U.S. gasoline pool and its
largest source of octane barrels.
The North
American market is an interesting case study that perfectly describes the
challenges of producing modern, ULS and high-performance gasoline. The U.S.
Tier 3 specification is putting pressure on North American refiners by imposing
a maximum sulfur content of 10 parts per million (ppm) in gasoline. This
regulation causes difficulties for refiners to use their FCC naphtha—which may
contain more than 2,000 ppm of sulfur—in the gasoline pool. Such extremely deep
HDS (which must remove more than 99% of the sulfur in cracked naphtha) causes
side reactions in HDS units that greatly reduce the octane of the cracked
naphtha and blended gasoline. To maintain the supply of marketable Tier 3
gasoline, these octane barrels must be replaced, which comes at a cost.2
A cat-feed hydrotreater (CFHT) is
often used instead of—or in combination with—a cracked naphtha HDS unit in the
FCC train to remove sulfur and deliver additional upgraded margins through
increased yields of clean gasoline and diesel.
Investment alternatives for ULS gasoline. The authors’ previous article “Tier 3 gasoline
production: Challenges and opportunities for refiners“ published in the February issue
of Hydrocarbon Processing,3 described the cracked naphtha HDS
and CFHT processes and analyzed their investment costs and returns for a
hypothetical 100,000-bpd refinery with a 55,000-bpd FCC unit (FCCU) in a market
that will adopt a new 30-ppm sulfur gasoline specification. The refinery’s
current FCC naphtha, which has been suitable for use in gasoline, will then be
too high in sulfur for that market. In addition, there is a possibility that
the 30-ppm sulfur specification will be tightened to 10 ppm in 7 yr.
The analysis considered three FCCU
train configurations (red, yellow and green), with capital investment costs and
annual benefits shown in TABLE
1.
In this article, the authors have
extended the economic analysis to consider the implications of gasoline margin
volatility in this investment decision.
Red refinery investment. To adhere
to the new 30-ppm sulfur specification, the refinery needs, at the very least, a
gasoline HDS unit, which costs approximately $90 MM. This is the red
configuration (TABLE 1).
This pathway will enable the refinery to stay in business producing 30-ppm
sulfur gasoline and maintain its current profit margin. However, there is a
fork in the road in year seven. Should the sulfur specification tighten from 30
ppm to 10 ppm, there will be a margin penalty of $25 MM/yr caused by additional
octane loss in the HDS unit when pushing it to make 10-ppm sulfur gasoline. FIG. 2 shows the cash flow data and net present values (NPVs) for
this investment.
The red investment scenario can be
viewed as a minimum compliance investment of $90 MM required to maintain
current business. It also carries a risk of $25 MM/yr profit loss in years 7–20,
a contingency that would reduce its present value by $104 MM.
Green refinery investment. An
alternative pathway is to build a HDS unit for $90 MM and a CFHT for $300 MM. This
green configuration, which constitutes a total capital investment of $390 MM, would
enable the refinery to meet the 30-ppm sulfur specification and deliver profit
growth of $56 MM/yr by way of increased upgraded value in the FCC train. Should
the sulfur mandate tighten to 10 ppm in year seven, the annual margin benefit
will decrease from $56 MM/yr to $50 MM/yr due to additional octane loss caused
by increased severity on the HDS unit. FIG. 3 shows the cash flow data and NPVs for
this investment.
The green investment can be viewed
as a compliance investment plus a growth opportunity. The NPV is $86 MM, which decreases
by $24 MM to $62 MM if the sulfur specification is tightened to 10 ppm in year seven.
Comparing investments with a real options perspective. Real options occur naturally as
flexibility and growth opportunities that can be exercised over time in an
environment of uncertainty.4,5 An oil refinery with the flexibility
to switch inputs and outputs has an embedded real option to switch when crude
price differentials or product values change or when diesel is in greater
demand than gasoline. Flexibility increases the value of every asset under
conditions of uncertainty.
In this article’s example, for the
red investment, if the sulfur specification is tightened from 30 ppm to 10 ppm
in year seven, the NPV decreases by $104 MM. By comparison, for the green
investment, the tightened sulfur specification reduces the NPV by only $24 MM.
The difference of $80 MM is a measure of the payoff on a real option that goes
“in-the-money” for the green refinery if the sulfur mandate is tightened to 10
ppm in year seven. That option is embedded in the green refinery investment and
stems from its flexibility to reduce the sulfur of its gasoline from 30 ppm to
10 ppm at a lower incremental cost than the red refinery scenario.
Gasoline margin volatility. The
analysis focused on how changing sulfur specifications affect the economics of
the red and green investment pathways, particularly how those investments
differ in their flexibility to respond to an uncertain future specification
change. The analysis does not consider other uncertainties that would affect
the green vs. red investment decision.
Perhaps the largest uncertainty is
the overall level of gasoline margins in the market. The “fixed benefit”
analysis essentially assumes that the overall level of gasoline margins will
stay constant over time. The green investment would deliver a benefit of $56 MM/yr,
which corresponds to $2.80/bbl of FCC feed, over what would otherwise occur. However,
to an investor who is bearish on gasoline margins, that $2.80/bbl benefit could
easily be wiped out by declining gasoline market margins that would work
against the higher cost green alternative. Similarly, an investor who is
bullish on gasoline margins would be even more inclined to make the green
investment due to the possibility that the $2.80/bbl benefit will be higher if
gasoline margins increase in the future.
U.S. gasoline margins have been
unusually high and volatile in recent years. FIG. 4 shows probability distributions derived
from historical data on the price spread between West Texas Intermediate (WTI)
crude oil and NYMEX front-month reformulated blendstock for oxygenate blending
(RBOB) gasoline futures—RBOB is a gasoline product produced by refineries for
blending with ethanol to make finished gasoline.
The margin between RBOB and the WTI crude price will be used to
represent the behavior of gasoline margins in the U.S. Noteworthy points in FIG. 4 include:
This picture of increasing
gasoline margins and margin volatility heightens the interest in considering
margin volatility in refining investment analysis.
The value of flexibility. Margin
volatility is important because flexible refineries can capture much higher
margins in more volatile market environments. This is a key principle of real
options: flexibility provides managers with real options to adjust operations
in response to market changes as they occur—the greater the volatility, the
higher the value of those options.
What does this margin volatility
mean for the green vs. red Tier 3 investment decision example? Suppose some
combination of events causes gasoline market margins to increase. A red
refinery, handcuffed by the limits of its FCC train, has little flexibility to
adjust operations to capture higher margins when they arise. Conversely, the
green refinery pathway has many options to adjust. It can adjust CFHT severity
to boost the FCCU’s yield of low-sulfur gasoline; it can feed higher sulfur
feedstocks, coker gasoils, metal-containing feeds and low-value intermediates
to the FCC train when those feedstocks are cheap and crack them into fully
valued Tier 3 gasoline; or it can make sub-10 ppm sulfur gasoline and generate
sulfur credits at competitive prices to sell to refiners that have high
incremental costs for sulfur reduction.
To factor margin volatility and
flexibility into the investment analysis, the annual benefit of the green
investment pathway will be treated as an uncertain variable rather than a known
constant. Consider the $56 MM/yr, or $2.80/bbl fixed-benefit estimate, as the
expected value (mean) of a probability distribution that describes the green
investment payoff in an uncertain margin environment. If the variance rate of
the 2012–2020 WTI-RBOB margin is applied to represent the effect of other
uncertainties on the market margin, the annual benefit from the green
investment can be viewed as a normal probability distribution centered around
$2.80/bbl (FIG. 5).
This indicates that margin
volatility provides an opportunity for benefits four times higher than the
fixed $2.80/bbl estimated in the fixed-benefit analysis. Those benefits can
only be captured by refineries with flexible FCCU trains and that make the
necessary operational adjustments to move to the right of the curve and capture
the high market margins when they occur.
The left side of FIG. 5 shows the
potential downside from falling gasoline margins, which could cause the
investment payoffs to be less than $2.80/bbl, or even turn negative. However, the
green refinery pathway has the option to throttle down the CFHT, or even idle
it at times when net benefits are low. Note: When the CFHT is idled, the green
investment reduces to the red investment. Therefore, the green investment
option’s payoff is never less than the red investment pathway.
Assuming the refiner exercises its
real options to flex CFHT operations as gasoline margins change, including
throttling down or idling the unit when needed, the actual payoff distribution
for the green investment can be viewed as a truncated distribution (FIG. 6).
This is equivalent to the payoff
distribution of a stock option—the owner of an option is positioned to capture
the upside benefits of a volatile stock with strictly limited exposure to its
downside risk. Similarly, the flexibility of the green refinery positions it to
capture the upside potential of a volatile gasoline margin environment with
limited exposure to its downside risk.
The value of this real option can be quantified for any refinery using
option pricing theory, and that option value should be added to the fixed-benefit
estimate to provide a more accurate picture of the payoff from the investment.
An implication of the real options
perspective is that higher gasoline margin volatility increases the value of
the green investment the same way that higher stock price volatility increases
the value of a stock option.
The authors have seen these
factors at play recently in refining operations and refining company earnings.
Refining operations have flexed over wide ranges in response to unpredictable
events that have shocked fuel markets in the last 3 yr. In addition, unusually
high differences in fuel margin capture rates emerged in refiners’ 2021 and
2022 earnings reports. Once examined, refiners with modern, flexible FCCU
trains are delivering higher refining margin capture rates in today’s volatile
fuel market vs. those without flexibility.6
For clarity, this article shows
smooth symmetric price curves. Real options work in all three economic regimes
of risk, uncertainty and extreme events.7
Takeaways. This economic analysis shows that
a FCC’s train configuration—consisting of both a CFHT and an HDS unit—is the
most profitable configuration to meet Tier 3 specifications due to its capability
to consistently produce high yields of ULS gasoline from low-value
feedstocks. Additional value comes from
its flexibility to adjust to changing product requirements and market margins.
Gasoline margins and margin volatility have increased in the U.S. in recent
years, to an extent that suggests a flexible CFHT-FCC-HDS configuration can
capture margins four times higher than those indicated by a fixed-benefit
analysis. Refiners that have and use this flexibility are the ones that are
capturing full market margins in today’s volatile fuels market. This example
demonstrates how margin volatility data, and the theory of real options, can be
used in refining investment analysis to bring insight that informs
decision-makers by showing the value of flexibility over a project’s life. This
approach will lead to better decisions in an industry with an uncertain
regulatory environment and increasingly volatile input and output prices. HP
LITERATURE CITED
MARCIO WAGNER DA SILVA is a Process Engineer and Stockpiling Manager at Petrobras. He has extensive experience in research, design and construction in the oil and gas industry, including developing and coordinating projects for operational improvements and debottlenecking bottom-barrel units. Dr. Silva earned a Bch degree in chemical engineering from the University of Maringa, Brazil, and a PhD in chemical engineering from the University of Campinas (UNICAMP), Brazil. In addition, he earned an MBA degree in project management from the Federal University of Rio de Janeiro, and in digital transformation at PUC/RS, and is certified in business from the Getúlio Vargas Foundation.
GEORGE HOEKSTRA is President of Hoekstra Trading LLC, which conducts multi-client research projects on topics with high profit impacts in the refining business, including pilot plant testing, field testing and market research. Hoekstra Trading is the only company that does multi-client independent catalyst testing programs on refining catalysts. Prior to founding Hoekstra Trading, he worked 35 yr for Amoco and bp in refinery process research and technology management. He earned a BS degree in chemical engineering from Purdue University, and an MBA degree from the University of Chicago.
THOMAS MURPHY is CEO of Valuation Risk & Strategy LLC, an interdisciplinary consulting firm established in 1995 to measure the value and assess the risk embedded in alternative technologies and chemical processes for energy and energy-intensive industries. Prior to this role, he was a research chemical engineer with the DuPont Company. An expert in derivatives and complex financial models, Dr. Murphy’s experience includes 11 yr of hands-on experience in chemical process engineering and production management. He earned a BS degree in chemical engineering (with distinction) from Clarkson University, a PhD in quantitative finance and a JD degree in technology management law at Syracuse University.