APPENDIX D

COST ANALYSIS METHODOLOGY
D-1

I. Cost Analysis Methodology

This cost analysis addresses only two of the four options presented to the Air

Resources Board (ARB) in this rule-making. As discussed in the Staff Report, there are

two main options: 1) changing the statewide urban bus emission standards and 2)

requiring all transit agencies in the South Coast Air Quality Management District

(SCAQMD) to follow the alternative-fuel path for urban buses. Within option #1 there

are three ways the ARB could choose to change the statewide standards, and only the

third option (Alternative 1.3), of requiring all transit agencies statewide to follow the

alternative-fuel path for urban buses, would require additional expenditures by transit

agencies and hence entail a specific cost analysis. Alternative 2, where all transit

agencies in the SCAQMD would be required to follow the alternative-fuel path for urban

buses, would also entail additional costs for transit agencies.

California transit agencies provide the ARB with annual reports of the composition of

their urban bus fleets, as required in the Fleet Rule for Transit Agencies. The complete

inventory of urban buses operated by transit agencies is described in Appendix C.

Alternative 1.3 would require all California transit agencies to convert to the alternativefuel path in the next year or so, while Alternative 2 would only require that all transit

agencies located in the SCAQMD that are on the diesel path switch to the alternativefuel path. To determine the number of alternative-fuel buses which transit agencies

would buy instead of diesel buses for Alternative 1.3, staff modeled the urban bus

purchases which would be alternative-fuel rather than diesel (Table 1). For Alternative

2, staff surveyed the six transit fleets on the diesel path and requested their purchasing

plans for 2005 to 2009. Estimated costs of Alternative 2 are based on these planned

purchases (Table 2).

Table 1. Modeled Statewide Purchases of Alternative-Fuel Urban Bus Purchases

Year CNG Bus1

2005 127

2006 84

2007 382

2008 400

2009 379

2010 992

2011 776

2012 189

2013 240

2014 273

2015 327

1

Compressed Natural Gas Bus
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Table 2. Reported Plans for Alternative-Fuel Urban Bus Purchases, SCAQMD

Diesel Path Agencies Only

Year GHEB1 CNG Bus2

2005 71 14

2006 23 -

2007 55 9

2008 64 -

2009 51 -

1

Gasoline Hybrid Electric Bus

2

Compressed Natural Gas Bus

A. Cost Calculations

The cost-effectiveness analysis is based on estimates of expected emissions reductions

and of costs for implementation for Alternatives 1.3 and 2. Staff estimated the

incremental cost of each Alternative by determining the difference between the capital

and operations and maintenance costs of diesel urban buses and alternative-fuel urban

buses.

Cost estimates were obtained from technicians and engineers in the field, as well as

from published references. For the main cost categories, ARB staff determined typical

or average costs based on the cost estimates obtained for each category. Alternatefuel urban buses represent relatively new and still-evolving technology, and so there is a

dearth of operating experience on which to base cost estimates.

As is explained below, natural gas buses entail a number of cost categories that are

avoided when gasoline HEBs are used. Thus, although gasoline HEBs themselves are

more expensive than natural gas buses, the auxiliary costs for the latter result in higher

estimated lifetime costs for natural gas buses.

1. Capital Costs for Buses

For bus replacement costs, current prices of new buses were used to determine the

premium of an alternative-fuel bus over a comparable diesel fuel bus (Table 2). The

Federal Transportation Authority provides 80%-83% of the capital cost of new buses, so

transit agencies see only a portion of the per-bus additional capital cost (FTA 2004). As

a conservative estimate, staff assumed a 20 percent transit agency share (Table 3),

although the cost to society is the full incremental difference. Staff did not subtract from

the capital cost any incentive funds that may be available to offset the purchase of

alternative-fuel buses. Staff has shown the two different types of buses that transit

agencies in the SCAQMD are purchasing: gasoline hybrid-electric (HEB) and

compressed natural gas (CNG) buses.
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Table 3. Estimated Premiums for Alternative-Fuel Vehicles

Bus Type 100% Premium 20% Premium

Gasoline HEB $122,700 $24,546

CNG Bus $50,000 $10,000

2. Capital Costs for Fueling Stations and Maintenance Facilities

Staff expects that many transit agencies affected by Alternative 1.3 will have to

construct new alternative-fueling facilities, while the six transit providers affected by

Alternative 2 have already either built a fueling station or have one planned and

financed, based on staff’s survey of transit agencies. Thus, only the cost analysis for

Alternative 1.3 includes the capital costs of new fueling facilities, although both

Alternatives include operating and maintenance costs for fueling infrastructure. Staff

assumed that half of the natural gas fueling facilities constructed pursuant to Alternative

1.3 would be L/CNG stations (gasification) and that half would be CNG (compression)

stations.

In addition, transit agencies that are purchasing gasoline HEBs will use existing

facilities. One transit agency, Long Beach Transit, has financed an upgraded gasoline

fueling station already and thus those costs were also not attributed to this rule. Thus,

no capital costs were accounted for constructing fueling facilities for Alternative 2.

In some cases transit agencies have upgraded maintenance facilities or constructed

new ones, often in conjunction with onsite fueling stations, and in other cases they have

been able to rearrange existing facilities to accommodate the additional safety

requirements for working with natural gas engines. Since such upgrades are apparently

optional, staff did not include capital costs for construction or upgrades of maintenance

facilities in the estimated cost of the rule.

3. Maintenance Costs

Staff believes that maintenance costs for natural gas buses are likely to be somewhat

higher than for diesel buses for a variety of reasons. Natural gas engines and fuel

systems are somewhat more complex, and mechanics may not have had as much

experience with them. In addition, spare parts are more expensive primarily because

natural gas engines and their replacement parts are simply not manufactured in the

same high volumes as diesel engines. Also, it appears that natural gas engines are

much more sensitive to deferred maintenance than traditional diesel engines. On the

other hand, diesel bus engines are becoming significantly more complex than they have

been in the past, which tends to reduce the extra cost entailed in selecting alternativefuel buses.

Based on transit agency staff estimates, extra maintenance costs range from $0.06 to

$0.17 per mile, with an average of $0.10 per mile. Assuming 43,500 miles per year,

per-bus extra maintenance costs are expected to be about $4,300 per year.
D-4

Extra maintenance costs for gasoline HEBs relative to diesel buses are quite uncertain,

because gasoline HEBs are an even newer technology and are all still under warranty.

Gasoline HEBs are expected to offer excellent fuel economy and thus lower fuel costs.

Some preliminary data indicates that lifetime repair costs for gasoline HEBs may be

lower than those for diesel buses because diesel buses typically require at least one

engine and transmission replacement or major overhaul during the life of the bus, while

the gasoline HEB has no transmission and a much less expensive engine. Gasoline

HEBs may also have significantly lower costs on brake repair.

Transit agencies may find that extended warranties on new technologies, while likely

more expensive per year than staff’s maintenance estimates, greatly reduce downside

risk and uncertainty. Also, it appears that there may be significant differences in natural

gas bus maintenance costs among transit agencies. Transit operators with higher perbus maintenance costs may well be able to learn from the practices of operators with

lower per-bus maintenance costs. Of course, accurate comparison of these costs

requires careful attention to operators’ variations in internal accounting practices.

4. Operational Costs or Benefits

In the absence of published, verifiable data, staff made several assumptions regarding

the costs of labor and fuel. The cost analyses are based on the incremental cost

differences between diesel and alternative-fuel urban bus purchase and use. Labor

costs for natural gas buses and gasoline HEBs are expected to increase modestly over

typical diesel bus costs. Initial training costs, and ongoing training associated with

regular recertification of technicians for natural gas maintenance, are primarily

responsible for expected minor increases in labor costs.

Fuel costs are the primary and most uncertain operational cost. Staff assumed an

annual mileage of 43,500 miles/year for urban buses. Natural gas engines are about 10

percent less efficient than diesel. Fuel cost differences in running buses on natural gas

rather than diesel are therefore technologically precise, but, as is explained below,

economically highly uncertain over the life of the regulation.

Although at present natural gas is less expensive than diesel, it is impossible to be

certain about fossil fuel market conditions between now and 2020. In recent years CNG

has been 15 - 20 percent more expensive (on a $/mile basis) than diesel. Thus, two

cases were presented; one based on current fuel prices (D>NG) and another based on

recent history (NG>D) (Tables 4 though 7). The current fuel prices were averages of

retail and transit agency contract prices, and yielded a price difference of about

$0.70/equivalent gallon. The recent historical prices were based on the past few years

using California data from U.S. DOE EIA and South Coast agencies, which yielded a

price difference of $0.10/gallon. Historically, natural gas prices have been between

residual oil (#6) prices and heating oil (#2) prices. Diesel fuel is essentially the same as

#2 oil. Thus, if market stability continues, natural gas may continue to be less

expensive than diesel.
D-5

However, key parameters of the natural gas market appear to be changing. Canadian

imports, which have met domestic demand growth in the past 10-15 years, are

becoming insufficient. Knowledgeable observers expect liquefied natural gas (LNG)

imports from Asia or the Mideast to meet demand growth for the foreseeable future,

however there may be a period of turbulence as LNG terminals on the Pacific coast are

still in the planning stages, and require at least 5 years to permit and construct. Natural

gas prices are apparently now high enough to motivate investment in LNG import

facilities. Also, it appears that LNG import terminals will be primarily designed to gasify

LNG imports for pipeline distribution; it’s unclear if sufficient LNG demand exists to also

include dedicated LNG distribution which would avoid re-refrigeration costs. Staff

estimates that transit agencies using LNG could realize noticeable if modest savings by

avoiding these energy-based processing costs, given typical bus mileage and current

and future energy prices.

At the same time, it is in the interests of oil producers to keep prices high enough to

make as much money as they can, but low enough so users aren’t really motivated to

make changes which will reduce structural demand for oil and decrease their sales

revenues.

In addition, environmental concerns continue to favor natural gas combustion over oil

and coal, and demand for cleaner fuels may well continue to push up natural gas prices.

However, it should be noted that imported LNG tends to include minor fractions of

petroleum gases heavier than methane; if used as-is for transportation, these fractions

would affect emissions slightly. The vast majority of natural gas is used for heating and

other industrial processes; transportation is a minuscule portion of consumption. Thus,

natural gas prices will be determined by forces largely unrelated to motor vehicle use.

Another aspect of infrastructure that may affect short-term prices would be the amount

of natural gas storage in the South Coast region. Lack of sufficient storage may expose

natural gas buyers to short-term price spikes, especially when demand equals or

exceeds supply.

Historically, almost all LNG has been sold in long-term contracts with stable (though not

necessarily unchanging) prices. Observers report that the market is diversifying, with

short and medium term contracts becoming more available. Transit agencies that

commit themselves to natural gas as a fuel would be well-advised to seriously consider

medium or long-term contracts to ensure price stability for themselves, as well as to

obtain the lower per-unit prices typical of larger contracts.

Lastly, reduced heating demand due to consistent weather changes such as global

warming would tend to keep natural gas prices from rising as much as otherwise.

No extra fuel cost was included for gasoline HEBs, as HEB efficiencies and modest

repair costs are expected to offset any price premium between gasoline HEBs and

diesel.
D-6

5. Present-Value Cost Basis

All costs are presented in present value terms of 2005 dollars, where the “present” is

defined as July 1, 2005. Capital costs are simply discounted at the annual real interest

rate of 0.05, exclusive of inflation. Thus, current prices can be used for future

purchases. Ongoing annual costs, such as maintenance and fuel, are also discounted

at the real interest rate to put them in terms of 2005 dollars.

For converting future values (FV) to present values (PV), the standard formula PV/FV =

1/((1+r)^n) is used, where r is the real interest rate and n is the number of years in the

future. The standard formula for converting present value to an equal amount (AV)

spread over a certain number of years can also be used to evaluate how initial capital

expenditures can be financed. AV/PV = ((r(1+r)^n)/((1+r)^n-1), where r is the real

interest rate and n is the number of years for which equal (amortized) annual amounts

are desired. These equations can be found in many standard references, such as the

study guide for the professional engineering exam (NCEES 2003).

All these costs are predictions of future prices, so they could vary noticeably depending

on demand, competition, and economic conditions, among other reasons.

6. Summary of Expected Costs

The most likely cost of complying with Alternative 1.3 is about $319,000,000, not

including fuel surcharges or savings over the years. On an annualized basis, this is

equivalent to about $29,400,000 per year over the 16 years from 2005 to 2021. These

values are in 2005 dollars. As mentioned above, substituting CNG for diesel may turn

out to yield either costs or savings, as predictions of future fuel prices are by far the

most uncertain of the estimates used in the cost analysis of this regulation. Based on

current market conditions where diesel is more expensive, average savings are

estimated to be about $200,000,000 over the life of the regulation. Based on recent

years when natural gas has been more expensive, additional costs of about

$128,000,000 are estimated. Thus, estimated total costs are presented without fuel,

and with estimates for both possible fuel savings and costs, for clarity.

The most likely cost of complying with Alternative 2 is about $7,676,000, not including

fuel surcharges or savings over the years. On an annualized basis, this is equivalent

about $708,000 per year over the 16 years from 2005 to 2021. These values are in

2005 dollars. As mentioned above, substituting CNG for diesel may turn out to yield

either costs or savings, as predictions of future fuel prices are by far the most uncertain

of the estimates used in the cost analysis of this regulation. Based on current market

conditions where diesel is more expensive, average savings are estimated to be about

$1,552,000 over the life of the regulation. Based on recent years when natural gas has

been more expensive, additional costs of about $984,000 are estimated. As with

Alternative 1.3, estimated total costs are presented without fuel, and with estimates for

both possible fuel savings and costs, for clarity.
D-7

As mentioned above, overall total costs for natural gas buses are higher than for

gasoline HEBs, so the per-bus costs for natural gas buses shown in Table 4 are higher

than in Table 5 where most of the buses are gasoline HEBs.

Table 4. Total Typical Costs for Statewide Alternative-Fuel Case

Total Typical

All But Fuel $319,000,125

w/ Fuel NG>D $446,670,798

w/ Fuel D>NG $117,677,083

Total Per Bus

All But Fuel $76,517

w/ Fuel NG>D $107,141

uel D>NG $28,227

Annualized

All But Fuel $29,434,112

w/ Fuel NG>D $41,214,273

w/ Fuel D>NG $10,858,054

Table 5. Total Typical Costs for SCAQMD Diesel Path Agencies Only

Total Typical

All But Fuel $7,675,748

w/ Fuel NG>D $8,659,981

w/ Fuel D>NG $6,123,718

Total Per Bus

All But Fuel $26,745

w/ Fuel NG>D $30,174

uel D>NG $21,337

Annualized

All But Fuel $708,241

w/ Fuel NG>D $799,056

w/ Fuel D>NG $565,035

The overall costs of this scenario can also be presented on an actual expected annual

basis. The averages of the cost estimates in 2005 dollars were used in Tables 6 and 7

below.
D-8

Table 6. Annual Expected Costs for Statewide Alternative-Fuel Case

Expected Annual Costs in

$2005

Capital Operations Fuel D>NG Total (D>NG) Fuel NG>D Total (NG>D)

2005 $5,188,703 $833,237 -$898,976 $5,122,965 $570,093 $6,592,033

2006 $3,268,475 $1,318,432 -$1,422,451 $3,164,456 $902,059 $5,488,966

2007 $14,155,979 $3,528,911 -$3,807,327 $13,877,562 $2,414,448 $20,099,338

2008 $14,117,156 $5,627,895 -$6,071,912 $13,673,139 $3,850,553 $23,595,605

2009 $12,739,053 $7,405,622 -$7,989,895 $12,154,781 $5,066,858 $25,211,533

2010 $31,755,599 $12,152,500 -$13,111,281 $30,796,818 $8,314,627 $52,222,726

2011 $23,658,165 $15,372,996 -$16,585,860 $22,445,301 $10,518,060 $49,549,221

2012 $5,487,719 $15,522,203 -$16,746,839 $4,263,083 $10,620,146 $31,630,068

2013 $6,636,697 $15,848,815 -$17,099,220 $5,386,292 $10,843,612 $33,329,124

2014 $7,189,755 $16,248,689 -$17,530,642 $5,907,802 $11,117,201 $34,555,645

2015 $8,201,814 $16,792,044 -$18,116,865 $6,876,992 $11,488,960 $36,482,817

2016 $15,992,423 -$17,254,157 -$1,261,734 $10,941,866 $26,934,289

2017 $14,766,901 -$15,931,947 -$1,165,046 $10,103,376 $24,870,277

2018 $13,771,446 -$14,857,955 -$1,086,509 $9,422,295 $23,193,741

2019 $11,849,826 -$12,784,727 -$934,901 $8,107,540 $19,957,366

2020 $10,023,183 -$10,813,970 -$790,787 $6,857,768 $16,880,951

2021 $9,545,889 -$10,299,019 -$753,130 $6,531,208 $16,077,096
D-9

Table 7. Annual Expected Costs for SCAQMD Diesel Path Agencies Only

Expected Annual Costs in

$2005

Capital Operations Fuel D>NG Total (D>NG) Fuel NG>D Total (NG>D)

2005 $1,882,737 $91,853 -$99,100 $1,875,491 $62,845 $2,037,435

2006 $537,665 $87,479 -$94,381 $530,764 $59,852 $684,997

2007 $1,306,129 $136,872 -$147,670 $1,295,331 $93,646 $1,536,648

2008 $1,357,018 $130,354 -$140,638 $1,346,734 $89,187 $1,576,559

2009 $1,029,880 $124,147 -$133,941 $1,020,085 $84,940 $1,238,967

2010 $118,235 -$127,563 -$9,328 $80,895 $199,130

2011 $112,605 -$121,489 -$8,884 $77,043 $189,648

2012 $107,243 -$115,704 -$8,461 $73,374 $180,617

2013 $102,136 -$110,194 -$8,058 $69,880 $172,016

2014 $97,272 -$104,947 -$7,674 $66,553 $163,825

2015 $92,640 -$99,949 -$7,309 $63,384 $156,024

2016 $88,229 -$95,190 -$6,961 $60,365 $148,594

2017 $66,528 -$35,474 $31,053 $22,496 $89,024

2018 $63,360 -$33,785 $29,575 $21,425 $84,785

2019 $50,139 -$32,176 $17,962 $20,405 $70,543

2020 $47,751 -$30,644 $17,107 $19,433 $67,184

2021 $45,477 -$29,185 $16,292 $18,508 $63,985

II. References

FTA 2004. U.S. Department of Transportation Federal Transit Administration10-01-98.

Urbanized Area Formula Program: Grant Application Instructions. Number C 9030.1C

http://www.fta.dot.gov/legal/guidance/circulars/9000/433_1152_ENG_HTML.htm

NCEES 2005. Fundamentals of Engineering Supplied-Reference Handbook, 7th

Edition. National Council of Examiners for Engineering and Surveying. Pages 92-93.

National Council of Examiners for Engineering and Surveying, Clemson, South Carolina

29631.

http://www.ncees.org/exams/study_materials/fe_handbook/fe_engineering_economics.p

df

Consulted for Background:

Avera, Dave. Personal Communication. April 13, 2004. Department of General

Services. E-mail from Dave Avera to Kathleen Mead
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Fujime, Kazuya. April 2002. LNG Market and Price Formation in East Asia. Institute of

Energy Economics, Japan. http://eneken.ieej.or.jp/en/data/pdf/127.pdf

Mundy, Dan. Personal Communication. August 13, 2004. Telephone conversation with

Muriel Strand, Project Manager, Transit and Procurement, Department of

Transportation, Division of Mass Transportation, Sacramento, California.

Norton, Paul. The Right Way to Calculate Fuel Cost Conversions. Natural Gas Fuels,

August 1996, p. 13-14.

Simmons & Co International. January 18, 2005. Outlook for Natural Gas: 2005 and

Beyond. http://www.simmonsco-intl.com/files/011805.pdf via http://www.simmonscointl.com/research.aspx?Type=researchreports

U.S. DOE. World LNG Market Structure April, 19, 2004. Energy Information

Administration, http://www.eia.doe.gov/oiaf/analysispaper/global/lngmarket.html

U.S. DOE. Annual Energy Outlook 2005. Energy Information Administration.

http://www.eia.doe.gov/oiaf/aeo/overview.html

U.S. DOE, The Alternative Fuel Price Report. Energy Efficiency and Renewable Energy,

Alternative Fuels Data Center. March 28, 2005

http://www.eere.energy.gov/afdc/resources/pricereport/pdfs/afpr_03_28_05.pdf

Vauthier, Max. LNG Trade: the 2006/2008 Horizon, LNG Journal, March/April 2004.,

Drewry House, 213 Marsh Wall, London, E14 9FJ, UK

http://www.lngjournal.com/articleMarApr04p13-15.htm

Vaitheeswaran, Vijay. Oil in troubled waters. The Economist. April, 28, 2005

http://www.economist.com/displaystory.cfm?story_id=3884623