## APPENDIX D

COST ANALYSIS METHODOLOGYD-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 state wide urban bus emission standards and 2) requiring all transit agencies in the Sout h Coast Air Quality Management District (SCAQMD) to follow the alter native-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 analys is. 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 requi red in the Fleet Rule for Transit Agencies. The complete inventory of urban buses operated by trans it agencies is described in Appendix C. Alternative 1.3 would require all California transit agencies toconvert to the alternativefuel path in the next year or so, while Alte rnative 2 would only require that all transit agencies located in the SCAQMD that are on t he diesel path switch to the alternativefuel path. To determine the number of alte rnative-fuel buses which transit agencies would buy instead of diesel buses for Al ternative 1.3, sta ff modeled the urban bus purchases which would be alternative-fuel rat her 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 Bus 1

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 BusD-2 Table 2. Reported Plans for Alternat ive-Fuel Urban Bus Purchases, SCAQMD Diesel Path Agencies Only

Year GHEB 1 CNG Bus 2 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 Alternat ives 1.3 and 2. Staff estimated the incremental cost of each Alternative by det ermining the difference between the capital and operations and maintenance costs of dies el urban buses and alternative-fuel urban buses.

Cost estimates were obtained from technici ans and engineers in the field, as well as from published references. For the main costcategories, ARB staff determined typical or average costs based on the cost estimate s obtained for each category. Alternatefuel urban buses represent relatively new an d 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 costcategories that are avoided when gasoline HEBs are used. T hus, although gasoline HEBs themselves are more expensive than natural gas buses, the auxilia ry costs for the latter result in higher estimated lifetime costs for natural gas buses.

1. Capital Costs for Buses

For bus replacement costs, current pricesof 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 t he two different types of buses that transit agencies in the SCAQMD are purchasing: gasoline hybrid-electric (HEB) and compressed natural gas (CNG) buses.D-3 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 Stat ions 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 cost s of new fueling facilities, although both Alternatives include operating and maintenance co sts for fueling infrastructure. Staff assumed that half of t he natural gas fueling facilities c onstructed 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 Beac h 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 fuel ing stations, and in other cases they have been able to rearrange existing facilitie s to accommodate the additional safety requirements for working with natural gas engines. Since such upgrades are apparently optional, staff did not incl ude 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 nat ural 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 moreexpensive primarily because natural gas engines and their replacement parts are simply not manufactured in the same high volumes as diesel engines. Al so, it appears that natural gas engines are much more sensitive to deferred maintenanc e 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 rela tive 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 excell ent fuel economy and thus lower fuel costs. Some preliminary data indicates that lifet ime repair costs for gasoline HEBs may be lower than those for diesel buses because dies el 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 maint enance estimates, greatly reduce downside risk and uncertainty. Also, it appears that there may be signifi cant differences in natural gas bus maintenance costs among transit agencie s. Transit operators with higher perbus maintenance costs may well be able to l earn from the practices of operators with lower per-bus maintenance costs. Of course, accurate comparison of these costs requires careful attention to operators’ vari ations 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 trai ning 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/y ear 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 ov er the life of the regulation.

Although at present natural gas is less ex pensive 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 re cent historical prices were based on the past few years using California data from U.S. DOE EIA and South Coas t agencies, which yielded a price difference of $0.10/gallon. Historica lly, natural gas prices have been between residual oil (#6) prices and heati ng oil (#2) prices. Diesel fuel is essentially the same as #2 oil. Thus, if market stability cont inues, 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 obser vers 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 leas t 5 years to permit and construct. Natural gas prices are apparently now high enough tomotivate investment in LNG import facilities. Also, it appears that LNG impor t terminals will be primarily designed to gasify LNG imports for pipeline distribution; it’s unc lear if sufficient LNG demand exists to also include dedicated LNG distribution which woul d avoid re-refrigeration costs. Staff estimates that transit agencies using LNG c ould realize noticeable if modest savings by avoiding these energy-based processing cost s, 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 tofavor natural gas combustion over oil and coal, and demand for cleaner fuels may well c ontinue 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 majo rity 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 forc es 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 regi on. Lack of sufficient storage may expose natural gas buyers to short-term pric e 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 pr ice stability for themselves, as well as to obtain the lower per-unit prices typical of larger contracts.

Lastly, reduced heating demand due to consis tent 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 gaso line 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 te rms of 2005 dollars, where the “present” is defined as July 1, 2005. Capital costs are si mply 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 pres ent values (PV), the standard formula PV/FV = 1/((1+r)^n) is used, where r is the real inte rest rate and n is the number of years in the future. The standard formula for converti ng present value to an equal amount (AV) spread over a certain number of years can al so 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 pr ices, 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 wit h 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 predict ions 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 ex pensive, 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 Al ternative 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 t he 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 futu re fuel prices are byfar the most uncertain of the estimates used in the cost analysis of this regulation. Based on current market conditions where diesel is more expensiv e, 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 fo r 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 fo r 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

u el 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

u el 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 al so 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 fo r 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 $16,077,096D-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 Transporta tion Federal Transit Administration10-01-98. Urbanized Area Formula Program: Grant App lication 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-Re ference Handbook, 7th Edition. National Council of Examiners for Engineering and Surveying. Pages 92-93. National Council of Examiners for Engineeri ng and Surveying, Clemson, South Carolina 29631. http://www.ncees.org/exams/study_mater ials/fe_handbook/fe_engineering_economics.p df

Consulted for Background:

Avera, Dave. Personal Communication. April 13, 2004. D epartment of General Services. E-mail from Dave Avera to Kathleen MeadD-10 Fujime, Kazuya. April 2002. LNG Market and Pr ice Formation in East Asia. Institute of Energy Economics, Japan. http://eneken.ieej.or.jp /en/data/pdf/127.pdf

Mundy, Dan. Personal Communication. A ugust 13, 2004. Telephone conversation with Muriel Strand, Project Manager, Transit and Procurement, Department of Transportation, Division of Mass Trans portation, Sacramento, California.

Norton, Paul. The Right Way to Calculate F uel 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-i ntl.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/o iaf/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 Repo rt. Energy Efficiency and Renewable Energy, Alternative Fuels Data Center. March 28, 2005 http://www.eere.energy.gov/afdc/res ources/pricereport/p dfs/afpr_03_28_05.pdf

Vauthier, Max. LNG Trade: the 2006/2008 Hori zon, LNG Journal, March/April 2004., Drewry House, 213 Marsh Wall, London, E14 9FJ, UK http://www.lngjournal.com/a rticleMarApr04p13-15.htm

Vaitheeswaran, Vijay. Oil in troubled waters. The Economist. April, 28, 2005 http://www.economist.com/displ aystory.cfm?story_id=3884623