EXECUTIVE SUMMARY
Fuel is critical to California's economy. Consumer
expenditures on fuel alone amount to $34 billion each year
in California. But the contribution goes well beyond
consumer expenses on the fuel itself. These fuels enable
countless transactions in the marketplace each day between
buyers and sellers of goods and services. The delivery of
nearly every product sold in the marketplace depends on
fuel, greatly magnifying its total contribution to our
economy and lifestyle. The Fuels Report is unique in that
it describes, under one cover, California's emerging fuel
trends and future fuel price and supply expectations.
Furthermore, it is the State's primary fuels policy
document.
WORLD OIL MARKET AND PRICE TRENDS
World oil demand has been growing at roughly 1.5 percent
per year since 1986 and now amounts to about 74 million
barrels per day. Demand growth in developing countries has
been more pronounced at 5 percent per year. China's oil
demand alone has been growing at an annual rate of almost 8
percent since 1992. During 1998, however, the rate of Asian
oil demand fell off dramatically largely due to their
economic downturn, although demand in the US and Europe
steadily increased. Extrapolating these trends to the
future is risky since small changes in the factors affecting
oil demand growth can have cumulatively large impacts over
time. Taken as a whole, though, the overall steady nature
of demand growth may itself be a source of stability in oil
markets in that it provides the petroleum industry a clear
incentive to invest in exploration and development.
Despite ample current US oil inventories, in a global
market no region is immune to the effects of supply
disruptions from oil exporting nations. Political struggles
and wars have been persistent features of the oil price
shocks experienced during the last few decades. The world
oil market, however, has adapted somewhat over time to this
vulnerability as seen by the results of the Iraqi invasion
of Kuwait in 1990. Over four million barrels per day of oil
export capacity were lost overnight, without leading to a
prolonged period of higher prices.
Even though the Organization of Petroleum Exporting
Countries' (OPEC) influence of the late 1970s and early
1980s is not expected to return, OPEC still maintains world
oil prices above their competitive levels by carrying unused
oil production capacity. While consumers in oil importing
countries sense an understandable vulnerability to sudden
supply disruptions, they should remember that oil exporters
need oil buyers over the long-term. Oil exporting countries
can hedge their economic position by finding friendly havens
for investment, entering into exploration and development
joint ventures at home, and launching refining,
distribution, and sales joint ventures in foreign markets.
Many oil exporting countries have recognized the necessity
of privatizing national energy industries and liberalizing
trade and investment rules, easing taxation and regulations,
and/or obtaining outside expertise and capital.
World petroleum markets now appear to be in a period of
balance between the extremes of previous decades, without
the consistently low crude oil prices and unfettered
petroleum demand growth of the pre-OPEC cartel period,
but also without the political and economic instability of
the period of OPEC-controlled pricing. Most credible
long-term world oil
price forecasts indicate still lower world oil prices,
with flatter growth rates. This change does not mean that
price volatility vanishes. In fact, rapid short-term price
fluctuations in response to changing market conditions may
be essential to a sustainable and open world oil market.
The Commission staff has proposed high, mid and low
world oil price forecasts. The high and mid-case forecasts
are flat in inflation-adjusted terms. The low price
forecast shows a decline in prices. The high price forecast
is about $21 per barrel. The mid-price forecast is about
$19 per barrel. The low price case declines from $19 per
barrel to $16 per barrel. All prices are in
inflation-adjusted 1998 dollars.
Integral to these forecasts are assumptions of
significant price variation around both annual and daily
averages of as much as $5 per barrel. In the short-term,
prices can and do vary significantly because they are
affected by many factors. When oil prices increase
consumers pay higher fuel prices; these higher prices can
adversely affect the economy.
OIL SUPPLY OUTLOOK FOR CALIFORNIA
From a broad perspective, the oil supply outlook for
California remains one of declining in-State and Alaska
supplies leading to increasing dependence on foreign oil
sources. The estimates of when foreign sources will
predominate the California market, however, have been
lengthened by five years compared to the previous Fuels
Report. The time extension relates to greater volumes of
Alaska oil production than previously expected. In
addition, recent statistics indicate that although
California production continues to decline, it is at a lower
rate (0.8 percent per year) than the 1985 to 1990 average
rate (4 percent per year).
In the short-term, California may see annual production
declines greater than 0.8 percent given periods of weak
prices for California's heavy crude oil with prices
sometimes below $10 per barrel. Production in 1998, for
example, declined 3 percent from the previous year. While
most of the decline occurred in federal offshore fields,
onshore production declined as California heavy crude oil
prices dropped to $7 per barrel during the last quarter of
the year. In the long-term, the staff expects continuing,
gradual California production declines as world oil prices
remain flat, but at slightly lower rates than presented in
the 1995 Fuels Report. Several factors support this
expectation.
Royalty rates have been reduced on California heavy
crude oil production from federal leases. The con-struction
of a new oil pipeline is also now complete, increasing the
capacity to transport more in-State oil from Bakersfield to
refineries in Los Angeles. Furthermore, a West Coast
technology information center now offers information to many
small producers, to help extend the life of marginal oil
wells.
The staff's revised estimate of when foreign oil imports
are expected to exceed California's supply from Alaska is
2006. The estimate for foreign oil to exceed in-State
supply is 2012. Furthermore, the estimate of when foreign
oil supplies could exceed the halfway mark in California's
total oil supply picture is 2016.
Short-term oil supply trends often differ greatly from
long-term trends. In recent years, California onshore
production has increased because of higher overall oil
prices. However, in spring 1999, prices fell below $7 per
barrel before recovering to over $15 per barrel by August.
These price conditions negatively affect production, as well
as employment and tax collections -- features that lose
visibility in long-term forecasts which "smooth out"
short-term conditions. Small independent producers who rely
solely on exploration and production earnings for their
livelihood face financial difficulties when prices decrease
dramatically. As a result, independent producers are
calling for government action to help preserve this industry
group.
While oil price was not explicitly incorporated into the
supply forecasts, the outlook for world prices in the
long-term does not offer reassurance that domestic
production will reverse itself on a sustainable basis.
Greater foreign oil dependence, however, does not
necessarily mean higher prices and may mean lower prices.
Supporting evidence can be found in the world oil price
forecast which reflects a long-term future of stable, if not
declining, international oil prices. As dependence on
foreign oil increases, California can expect to see a
variety of ready suppliers. South America and Middle East
crude oil suppliers are likely candidates. Californians can
also expect to see an increase in marine tanker traffic as
foreign imports increase. The Commission should continue to
evaluate the economic, environmental and energy policy
implications of oil import growth and potential crude oil
and product transportation and storage constraints.
PETROLEUM FUEL PRICES AND VOLATILITY
Petroleum Fuel Price Forecast
The Commission staff prepared low, mid and high price
forecasts for six fuel types including: California Air
Resources Board (CARB) Phase 2 reformulated gasoline,
CARB-specification reformulated number 2 highway diesel,
railroad diesel, agricultural diesel, commercial kerosene
jet fuel and fleet propane. Long-term price ranges are:
- CARB gasoline, $1.08 to $1.37 per gallon
- CARB diesel, $1.03 to $1.45 per gallon
- railroad and agricultural diesel, from $0.67 and $0.72
per gallon, respectively, to $0.88 to $0.91 per gallon
- commercial kerosene jet fuel, from $0.62 to $0.86 per
gallon
- fleet propane, from $0.63 to $1.02 per gallon
Petroleum Product Price Volatility
Volatility in product prices around the above long-term
prices occurs as a result of many factors, including:
- oil price variations
- refinery maintenance and unplanned outages
- seasonal and annual demand fluctuations
- changes in markup and taxation of products
Estimates of the impact of oil price volatility alone on
product prices are included in the Commission's forecast for
the first time. The staff's analysis indicates that
gasoline prices could vary by five to eight cents per gallon
higher or lower than projected due to normal variation of
oil prices around long-term forecasts. Diesel fuel
prices could vary by 13 to 20 cents per gallon higher or
lower than projected, jet fuel by 15 to 24 cents per gallon,
and propane by 23 to 35 cents per gallon as a result of oil
price variation. The effects of factors other than oil
prices are most pronounced with CARB Phase 2 gasoline.
Petroleum Fuel Reserve
Over the last two years, gasoline and diesel price
fluctuations created renewed interest in establishing a
California petroleum fuel reserve. A physical reserve of
products can be seen as one means of providing price
stability in the marketplace. The staff analyzed the
economic feasibility of using the large, unused residual
fuel oil storage facilities at electric utilities as a
price-dampening gasoline and diesel fuel reserve.
The staff concludes that a product reserve would be
marginally economic at best. This conclusion is based on a
20 year reserve life, the costs of converting existing
storage tanks, the cost of initial inventory purchases and
of ongoing storage costs. If during restocking, prices
increase by more than two cents per gallon, the reserve
would become uneconomic. One factor not incorporated into
the analysis, but that could further negate the benefits of
a reserve, is refiner behavior. With a large California
product reserve, refiners might lower their own inventories
and offset the positive effects of a reserve.
Paper Markets
Paper markets are another option for reducing possible
financial risk associated with future energy prices.
Existing paper, or financial, instruments such as futures
and options contracts reduce uncertainty by specifying the
price, quantity and the date of future energy deliveries.
Since a physical reserve was found to be of questionable
value, the staff investigated paper markets as an
alternative means of dealing with price volatility.
Generally, paper markets allow individuals and firms to
transfer their exposure to price fluctuations to traders
willing to accept this risk with expected compensation.
Since traders hedge adverse price movements in both
directions, financial instruments tend to stabilize prices.
Financial instruments specifically designed for California's
unique petroleum product market would provide refiners and
consumers with more risk management tools.
PETROLEUM PRODUCT ISSUES
The staff investigated several petroleum product issues
including fuel excise taxation, the cost and availability of
alternative fuels and vehicles, the potential for market
power in the petroleum industry, and the price and supply
effects of discontinuing MTBE in California gasoline.
Fuel Excise Taxation
The fuel excise tax issue centers around developing a
means to balance the need for transportation-related
revenues with sound energy policy and equitable fuel tax
treatment. Both federal and state excise taxes are applied
to most transportation fuels, but disparities in the amount
of the tax and the disconnection from energy policy
considerations at both the federal and state level have
posed contentious public debates.
The Commission staff compared tax rates using three
means of expressing current federal and state excise
taxes. These included taxes expressed currently in cents
per gallon, taxes based on a dollar-per-million-Btu measure
given certain assumptions on fuel Btu content, and taxes on
a cents-per-mile basis given assumptions on vehicle fuel
economy and fuel substitution factors, or the amount of
another fuel required to replace one gallon of gasoline.
These comparisons not only illustrate the disparity, but
they also show that the tax ranking for various fuels
changes, depending on the method of comparison used.
Federal and state tax exemption provisions further
complicate comparisons and influence the economics of fuel
choices in some user categories, such as state and federal
government fleets and school districts. The staff concludes
that there is a need for a uniform, accepted basis for
assessing excise taxes on all forms of transportation energy
that is technically sound, fiscally responsible, and
supportive of rational energy goals.
The Commission should take an active role in undertaking
the necessary technical analysis to develop an appropriate
method of assessing uniformity of transportation fuel taxes.
Various State and Federal decision-makers could then use
the results of this work when revisions to the application
and amount of transportation fuel taxes are considered.
Cost and Availability of Alternative Fuels and Vehicles
Legislation directs the Commission to conduct continuing
studies on the cost and availability of alternative motor
fuels, including cost comparisons of owning and operating
alternative fuel vehicles (AFVs) versus gasoline vehicles.
The staff's updated analysis, using actual costs of AFV
models available in California, shows that total AFV costs
continue to be higher than gasoline counterparts. Depending
on the vehicle model, fuel type, and purchase option --
differences range from 0.4 cents per mile for the Ford Super
Club Wagon to over 23 cents per mile for the Ford Ranger
electric pickup truck.
For methanol, both higher fuel and vehicle costs
contribute to the difference. Compressed natural gas,
liquefied petroleum gas and electricity cost less than the
energy equivalent of gasoline, but higher vehicle prices
override this fuel cost component. The result is that
compressed natural gas vehicle operation costs about 0.5 to
6 cents more per mile than gasoline counterparts. Similar
results were found with liquefied petroleum gas vehicles,
which cost about 1.5 to 7 cents per gallon more than
gasoline models.
The disparity between gasoline and electric vehicle
operation and ownership costs is greater still with
differences ranging from 13 to 23 more cents per mile to
lease and operate an electric vehicle versus owning and
operating a similar gasoline vehicle. Despite these
findings, AFV use may increase further as regulations
increasingly restrict emissions. Today, the limited slate
of original equipment manufacturer AFV models and cost
considerations restrict greater consumer use.
Retail Station Divestiture
Gasoline prices are higher in some localities than
others. The price difference can be related to many factors
including local competition, customer conveniences provided,
station sales volumes and location, brand loyalty, etc.
Because of gasoline price differences between and within
regions of California, some independent retailers and
consumers are calling for divestiture of the wholesale sales
function from the retail function for vertically integrated
oil companies.
It is argued that this separation would increase
competition in the market and lead to more uniform or
equitable gasoline pricing. The Commission is not aware of
any studies concluding that these market changes would
produce the desired result, but the concern over gasoline
price variations identifies the need to more fully inform
the public of factors that influence gasoline prices.
The Commission should methodically evaluate factors
other than oil prices that contribute to regional retail
gasoline price differences and publish the results to better
inform the public about the causes for price differences.
Market Power
Market power refers to the ability of companies to
maintain prices above competitive levels for a significant
period of time. Mergers and joint ventures among large
companies, in any industry, raise the concern of the
possible exercising of market power by the restructured
firms. The question emerging from the abundance of
consolidations in the petroleum production, refining and
marketing industry is whether these activities result in
increased market power being exercised. The Commission staff
analyzed the market power issue relating to the refining and
marketing segments of the California petroleum industry.
Using four different cases with differing assumptions on
specific company merger activity, the staff estimated market
share of the four largest firms and calculated the
Herfindahl-Hirschman Index (HHI) numbers which indicate
relative market concentration. The five parameters studied
include product refining capacity, retail gasoline sales,
gasoline production, wholesale gasoline sales and diesel
production. Company consolidations increase both the market
share of the four largest firms and the HHI for California.
The four largest firm measure produced numbers well above
the 60 percent threshold value established by industry
analysts. The post-merger HHI numbers suggest a moderately
concentrated market according to the federal guidelines for
mergers. The increase of the post merger HHIs indicates
that the consolidation can enhance market power. Only a
more rigorous analysis, however, that considers additional
factors can confirm or disprove this notion.
The Commission should conduct a more rigorous market
power analysis of gasoline production and sales to confirm
or disprove that existing merger activity enhances market
power.
Underground Fuel Storage Tanks
As of December 22, 1998, underground petroleum product
storage tanks must have been replaced or upgraded to meet
federal and state standards for leak prevention and
monitoring. In California, the concern was that station
owners in more remote rural areas of the State would not
complete the improvements and result in facility closures.
The closures would then cause important public services Ð
such as fire, emergency, school and other services Ð from
accessing refueling facilities.
The Commission staff assessed the available compliance
data and found that most existing stations in rural areas
have remained in business since additional financing for
tank replacements is now available and some owners chose to
install above-ground tanks. Some remote areas permanently
losing refueling facilities, however, remains a strong
possibility for stations that have been only marginally
viable in recent years. The Commission will continue to
monitor these trends to identify where serious fuel
availability problems may arise and make necessary
recommendations.
MTBE and Fuel Supply and Price
The Energy Commission, at the request of the Legislature
and the Governor, examined the potential supply and price
effects of discontinuing Methyl Tertiary Butyl Ether (MTBE)
in gasoline. This undertaking included analyzing
California's refinery infrastructure, researching the
availability and price of alternative oxygenates, and
determining product import capabilities and distribution
system limitations. The work considered four alternative
oxygenates and entailed constructing several cases to model
California's gasoline supply and price response, under three
time horizons, to differing economic and regulatory
conditions.
The cost impact to consumers is reduced as the time
permitted to accomplish a potential transition to other, or
reduced, oxygenate use is increased. If MTBE is
discontinued with no phase-out time permitted, gasoline
supplies could decline 15 to 40 percent, with retail price
increases of 30 cents and more per gallon, regardless of the
oxygenate option chosen. This option would significantly
damage consumer lifestyles and the State's economy. Under a
three year phase-out plan, the gasoline production cost
change ranges from a decrease of 0.2 cents per gallon to an
increase of nearly 9 cents per gallon. With a six year
phase-out, the average production cost ranges from a 0.3
cent per gallon decrease to a 3.7 cent per gallon increase.
Average changes in cost do not represent retail gasoline
price changes, which may be higher still, because factors
other than production cost influence pump prices. The
Commission staff report, Supply and Cost of Alternatives to
MTBE in Gasoline, December 1998 discusses study results and
key findings in more detail.
Based on the results of the Commission's study, an in
depth University of California study on the water quality
impacts of MTBE, and public testimony received in several
hearings, Governor Davis signed an executive order on March
25, 1999, to remove MTBE from gasoline at the earliest
possible date, but not later than December 31, 2002. The
Commission held a hearing on June 28, 1999, and determined
that it was not possible to advance this date. Finally, the
Commission was directed to evaluate the potential for
developing a waste-based or other biomass ethanol industry
in California.
The Commission will fulfill the directives in the
Governor's executive order relating to the timetable for
phasing out MTBE in gasoline and evaluating the potential
for developing a waste-based or other biomass ethanol
industry in California. Transportation Fuel Demand
The Commission staff prepared transportation fuel demand
forecasts for gasoline, diesel, compressed natural gas and
electricity. The base case gasoline forecast indicates that
demand could increase from 0.5 to 1.2 percent per year,
resulting in 14.4 to 16.3 billion gallons of fuel use per
year by 2015. Differing assumptions on improvements in new
light-duty vehicle fuel efficiency and the influence of
alternative fueled vehicles account for the variation.
Diesel fuel demand is forecast to increase at 1.5 percent
per year to 3.3 billion gallons per year by 2015.
Compressed natural gas transportation demand increases from
0 to 10 percent per year in the high and low gasoline demand
scenario, respectively. Electricity use increases from 2 to
14 percent per year in the forecast.
The staff also extrapolated historical sales trends for
sport utility vehicles to estimate future gasoline demand.
Approximately 1.4 million more sport utility vehicles would
be on the road by 2015 with a resulting 0.4 billion gallon,
or 2.5 percent, increase in gasoline demand over the base
case high demand scenario.
NATURAL GAS SUPPLY, DEMAND AND PRICE
Regulatory reforms over the past two decades have
changed the way natural gas markets function. More options
are available to many end users in today's progressively
competitive market. Two regulatory proceedings now underway
will continue to affect direction of the gas industry during
the coming decade.
At the State level, the California Public Utilities
Commission instituted a rulemaking proceeding in January
1998 designed to provide residential and commercial
customers with the competitive choices currently available
to large industrial and power generation customers. At the
national level, the Federal Energy Regulatory Commission
issued a Notice of Proposed Rulemaking in July 1998 to
eliminate cost-based regulation for gas transportation
services of less than one year. The intent is to reduce the
number of captive customers and provide greater flexibility
to allow pipeline companies to redesign services to better
meet customer needs. Since both proceedings are in the
early stages of investigation, the Commission does not
expect new natural gas rules to be adopted for at least two
years. A wide range of issues must be addressed before any
action is taken by either agency.
Natural gas supplies to California will remain plentiful
for the next several decades. The total resource base (gas
recoverable with today's technology) for the lower 48 states
is estimated to be about 975 trillion cubic feet (TCF),
enough to continue current production levels for more than
50 years. Technology enhancements will continue to enlarge
the resource base; however, production capacity increases
remain less certain. Despite this concern, production from
lower 48 states is expected to increase from 17.1 TCF in the
1994 base year to 25.9 TCF in 2019. The Gulf Coast and
Rocky Mountain supply regions account for most of the
increase during the next two decades. Alberta continues to
provide the bulk of Canadian production. Canadian exports
to the United States are projected to rise to 3.9 TCF in
2014 and remain at that level thereafter.
In 1997, Californians consumed 5.5 billion cubic feet
(BCF) of natural gas per day, the highest level reached
since the drought of 1994. Approximately one-third of this
consumption was for electricity generation, a leading growth
market in California. Residential consumption represented
one-fourth of California natural gas use with the balance
consumed by the industrial, resource extraction and
commercial sectors. The Commission's gas demand forecast is
for continued growth at 1.3 percent per year, exceeding 7
BCF by 2019.
The average wellhead price in the lower 48 states is
expected to increase from $1.65 per thousand cubic feet
(MCF) in 1999 to $2.18 per MCF in 2019, representing an
annual average increase of 1.4 percent. In Canada, the
average price is projected to increase 2 percent per year in
real terms from $1.17 per MCF in 1999 to $1.75 per MCF by
the year 2019. The expected growth rate in wellhead prices
is considerably lower than previous Commission estimates,
which have consistently been in the range of 3 to 4 percent.
A major factor contributing to this lower growth rate is
due to the incorporation of reserve appreciation.
Natural Gas Supplies and Prices at the California Border
Four producing regions supply California with natural
gas. Three of them -- the Southwest US, the Rocky Mountains
and Canada -- provide approxi-mately 85 percent of all gas
used in the State. The remainder is produced inside
California. The total supply to meet California consumption
is expected to increase from 5.9 BCF per day in the 1994
base year to 7.8 BCF per day by 2019.
No significant changes are anticipated in the market
shares of supplies from these four supply regions over the
forecast horizon. Southwest supplies will continue to
dominate, holding approximately half of the market.
Canadian producers will supply another quarter of the market
with the remainder split between Rocky Mountain and
California suppliers. The average California border price
is expected to increase by 1.9 percent per year from $1.79
per MCF in 1999 to $2.62 per MCF in the year 2019.
California End-Use Natural Gas Price Forecast
The analysis indicates that natural gas prices to
generate electricity in the PG&E and SoCal Gas service areas
will be very competitive. Because of additional costs to
transport natural gas through the SoCal Gas service area,
SDG&E natural gas prices for electric generation are about
30 cents higher than that in the SoCal Gas service area.
This trend will continue as long as the current pricing
structure is maintained. The merger of SDG&E and SoCal Gas
and separation of gas utility services could change this
situation.
Need for Additional Interstate Pipeline Capacity to
California
Despite the fact that excess interstate pipeline
capacity now exists, additional pipeline capacity is
expected to be needed at the California border during the
next two decades. The Commission estimates a need for
additional delivery capacity from the Rocky Mountains in
2004 and Canada in 2009. Additional delivery capacity at
Wheeler Ridge, located south of Bakersfield, will also be
needed by 2009 to accommodate additional flows from these
regions. No additional delivery capacity will be needed
from the Southwest; however, the expansion of the pipelines
moving San Juan Basin gas, in the Four Corners area, to
California will be needed by 2004. Additional capacity will
be needed on the SoCal Gas system at Topock by 2009 to
receive increasing supplies from the Southwest. Topock is
located at the California/ Arizona border near Needles,
California.
Market Fundamentals
Although the forecast is based on a "most likely"
perspective of market expectations, many uncertainties
surround the competitive natural gas marketplace. To
address this critical issue, several cases were created to
test the bounds of supply, demand and price over the
forecasted horizon.
These cases addressed the power generation market,
resource availability, technology advances, overall demand
and market structural changes. A high price and low price
case were also generated to provide a lower and upper bound
on the direction of future natural gas prices. The high
price case generated wellhead prices that are 50 to 75 cents
per MCF higher than the base case over the forecast horizon.
In contrast, the low price case produced prices 40 to 60
cents per MCF lower than the base case, depending upon the
assumptions made in each case.
Importance of Natural Gas Market Centers
Increasing competition among producers, transporters and
distributors has created market centers or "hubs" where
natural gas is bought and sold competitively. Market hubs
clearly impact the price at which natural gas is traded.
Producers have the option of selling to high bidders while
consumers have the option to go to the lowest price seller.
Through electronic bulletin boards and other mechanisms,
market participants are more informed, which enhances
competition, putting downward pressure on prices.
Transactions occur for various contract periods, such as
long-term contracts and spot or daily contracts. It is
probable that these market transactions in the future might
even occur hourly.
Today, the choices in competitive markets are available
mainly to large gas consumers such as industrial customers
and, to some extent, smaller customers through core
aggregators or marketers. The number of players will
increase as small and large consumers gain better access to
competitive service options envisioned in the restructured
natural gas market.
SYNTHETIC PETROLEUM FUEL AND FUEL CELL PROSPECTS
Synthetic Diesel Fuel
Some companies are using a gas-to-liquid process to
convert remote natural gas resources into synthetic
petroleum products, such as diesel fuel. The fuel produces
exhaust emissions that are 5 to 40 percent lower than those
from conventional diesel fuel, and technology improvements
are reducing conversion costs. When blended with
conventional diesel fuel, the resulting mix can meet CARB's
stringent diesel fuel standards.
While no facilities for producing the fuel exist in
California, synthetic diesel was used to a limited extent in
1997 as a feedstock in California refineries. Several
conversion plants are operating or under construction
worldwide, and California refiners may show greater interest
in obtaining synthetic diesel fuel as an option for
increasing clean diesel fuel production without costly
refinery modifications. Cost reductions in the conversion
technology may also result in many smaller gas fields being
developed in the future. While difficult to quantify, the
volume of worldwide production that may make an inroad to
California, the qualities of the fuel, strict diesel fuel
standards and its initial use in the State suggest that a
market may be found here.
The Commission should continue to monitor worldwide
research, development, demonstration and commercialization
efforts associated with synthetic diesel fuel for possible
application and use in California.
Fuel Cell Vehicles
While one manufacturer has announced plans to produce
fuel cell vehicles (FCVs) within six years, the widespread
use of FCVs will require a well developed fueling
infrastructure for fuels other than gasoline. Even the
significant infrastructure advantages of gasoline, however,
are accompanied by questions on gasoline sulfur content
which presently poisons the catalyst used in fuel cell
technology. Gasoline-fueled FCVs would likely require the
use of a new formulation that would then need to be kept
separate from conventional gasoline supplies.
Despite the current absence of a hydrogen or methanol
fueling infrastructure, a survey of knowledgeable
individuals indicated that these two fuels are expected to
be the preferred fuels in the coming years for use in FCVs.
Hydrogen and methanol producers expect that they could meet
fuel demand if FCVs came into widespread use, but many
retail level issues remain. In the case of hydrogen,
adequate storage on board vehicles and fuel cost are primary
issues. Hydrogen fueling infrastructure also requires large
capital investments compared to traditional fuels.
Estimates for a complete system are in the hundreds of
billions of dollars.
California's experience with methanol as a vehicle fuel
would benefit efforts to commercialize methanol use in FCVs;
however, caution must be exercised in ensuring that existing
storage tanks, piping and other components used in a
gasoline fuel station are methanol compatible. Vehicle
purchasers must also see clear and significant benefits if
they are to choose non-conventional fuels such as methanol.
Because providing FCV infrastructure requires time, planning
today for potential future needs is prudent. If
manufacturer plans materialize, FCVs may begin displacing
some conventionally fueled internal combustion engines with
near zero emission vehicles in the future.
The Commission should continue to monitor fuel cell
technology progress, infrastructure development and the
potential use of FCVs.
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1999 Fuels Report 
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