Final Staff Report and Recommendations on Agricultural Burning



## Chapter 7

Biomass Power PlantsFinal Staff Report and Recommendations on Agricultural Burning This page intentionally blank.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-3 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning 

### Chapter 7: BIOMASS POWER PLANTS

7.1 CURRENT BIOMASS POWER PLANTS

Currently there are nine biomass power plants opera ting in the San Joaquin Valley Air Basin (SJVAB), with three biomass power plants that are located

outside of the SJVAB. While there are a total of 1 2 biomass power plants that could accept agricultural materials in the SJVAB, D istrict’s data is available only

for those facilities located in the SJVAB. Five of the nine biomass power plants are required to burn agricultural material in order to offset emissions as required by conditions on their operating permits with the D istrict. District staff found that biomass facilities generally accept agricultural ma terials, forestry materials, and

urban wood residues to be used as fuel for their bo ilers. Information from some biomass fuel buyers and operators indicate that bio mass power plants will accept any clean and untreated organic material that is fr ee of dirt and other unburnable contaminants like pressure treated and painted wood material. According to CBEA, several plants are now operating above 90% av ailability and many are in the mid to high 80 percent range, which is recogniz ed in the industry as excellent performance.

Although biomass power plant operations and facilit ies are unique, they do follow the same general process to produce electricity fro m biomass fuel. The following biomass process description is a generalized repres entation of the process the biomass facilities utilize. This description is an aggregate derived from several biomass power plant operational procedures and equi pment. Again, it is important to note that this description is not of o ne particular facility, but a combination of several facilities to provide a gene ral understanding of the processes biomass power plants use to produce elect ricity from biomass fuel.

Trucks deliver the biomass fuel to the biomass powe r plant site. Biomass fuel can be agricultural materials, urban wood waste, or forestry materials. Biomass fuel types are discussed further in Section 7.1.2. The material is unloaded using either self-unloading trucks or a trailer tipper. A trailer tipper operates as follows: the truck trailer is driven onto the tipper, then t he entire trailer is elevated to an angle such that the material free falls out the bac k of the trailer. The unloaded fuel is transported to conveyors for direct feed to the boiler or to a fuel storage

area.

The first conveyor discharges the biomass material onto another conveyor, which then feeds through a fuel sizing system. The sizin g system screens the fuel before delivery to metering bins. The enclosed con veyors are ventilated to fabric collectors. A large magnet removes magnetic materi als and the non-metallic material passes to a hog screen and then to the fix ed stacker. The material inSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-4 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning the storage piles is mixed and fed to the boiler fe ed conveyor. The blended

biomass fuel is then fed to the boiler.

Hot combustion gases flow upward through the boiler , where heat is transferred through water tubes to produce high-pressure steam. The steam is then directed to a steam turbine generator to create electricity. Low-pressure steam discharged from the turbine is condensed and return ed to the boiler as boiler feed water. Flyash from the combustor operation is collected from various points in the flue gas system in an enclosed dry mechanica l system in order to minimize fugitive dust emissions. After collection, the Fly ash is delivered to an ash storage bin, or a silo, for transfer offsite. According to the permit information for biomass facilities, the ash can be disposed of, or used to make soil additives, agricultural fertilizer, for use in the corrals at dairies or fo r road construction.

Flue gasses pass through the super heater, boiler, multi-cyclones, and economizer before entering the pulsejet baghouse. Alternatively, the boiler flue gas is injected with ammonia for NOx control, injec ted with limestone for SOx control, and injected with sodium bicarbonate injec tion for corrosion control,

before it is vented to a fabric filter dust collect or. Alternatively, exhaust gases are controlled with Non-Selective Catalytic Reduction ( NSCR) and an Electrostatic Precipitator (ESP) before discharging through a sta ck.

All nine power plants in the SJVAB utilize both agr icultural wood materials and non-agricultural materials as biomass fuel for thei r operations. Five of the nine facilities are required to have agricultural fuel o ffsets per permit conditions with the District. The table below illustrates the perm itted mega watt (MW) output capacity at each facility and if the facility is re quired to have agricultural fuel offsets per permit conditions.

Table 7-1 Facility Megawatt Capacity and Agricultu ral Offsets Required Facility

ID Permitted Output Capacity

(MW) Ag Offsets Required

A 12.5 No

B 30 Yes

C 56.5 Yes

D 11.5 No

E 25.8 Yes

F 12.5 No*

G 28.5 Yes

H 9.4 No

I 20.5 Yes

* Language in the permit states that if quarterly a ctual NOx emissions from this boiler exceed 5,000 l bs, then agricultural offsets are required. If the quarterl y NOx emissions from this boiler do not exceed 5,00 0 lbs, then agricultural offsets are not required.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-5 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning 7.1.1 Locations

District staff expects that prohibition of open bur ning of additional agricultural material would generate a substantial amount of agr icultural material to be dealt with alternatively. A key question to ask is wheth er biomass power plants have the capacity to handle agricultural material that w ould otherwise be open burned. Other aspects of that question are: 1) are the powe r plants located near the crops and 2) are they distributed enough throughout the SJVAB so that they could effectively accept additional agricultural ma terial as biomass fuel. The currently operating biomass plants are located in s ix of the eight counties within

the SJVAB. Table 7-2 below lists each biomass faci lity and its location.

Table 7-2 Facility Name and Location in the San J oaquin Valley Air Basin
Facility Name City County Region

Rio Bravo Fresno Fresno Fresno Central SJVAB

Covanta Mendota LP Mendota Fresno Central SJVAB
Madera Power, LLC Firebaugh Madera Central SJVAB
Ampersand Chowchilla

Biomass LLC Chowchilla Madera Central SJVAB

Covanta Delano Delano Kern South SJVAB
Sierra Power Corporation Terra Bella Tulare South S JVAB Dinuba Energy Reedley Tulare South SJVAB

Merced Power LLC EL Nido Merced North SJVAB Thermal Energy Dev Partnership LP Tracy San Joaquin North SJVAB

The California Biomass Energy Alliance (CBEA) is a trade association representing 33 biomass energy facilities located i n 19 counties throughout California generating more than 650 MW of renewable electric power. CBEA has brought to the attention of District staff that the re are three, biomass power plants

located outside of the District boundaries that als o accept agricultural materials from the SJVAB as fuel. The three plants identifie d by the CBEA are the Chinese Station power plant and Sierra Pacific Sono ra power plant in Tuolumne County, and the Sierra Pacific Lincoln power plant in Placer County. However, staff does not have the five-year history through q uarterly reports for these plants as to operating hours, or how much bone dry tons (B DT) per year they accept and burn or how much of the BDT used is agricultura l material from the SJVAB. Therefore, these plants were not included in the an alysis later in this chapter, or in other chapters of this report.

To better illustrate the locations of the biomass p ower plants, staff have included a map, as Figure 7-1, on the next page. As illustr ated in the map, the nine existing biomass power plants are located at variou s locations throughout theSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-6 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning SJVAB. The locations of the three biomass power pl ants that are not in the SJVAB that accept agricultural materials as biomass fuel. All three plants are

located north of the SJVAB.

Also illustrated in Figure 7-1 are the locations of four of the potential future biomass power plants. These future power plants ar e currently undergoing the permitting process with the District and further di scussed in Section 7.2.6. Not illustrated on the map on the following page are th e two biomass power plants in Stockton that may potentially accept agricultural m aterial as biomass fuel in the future. These six plants are discussed further in Section 7.2.6.

Figure 7-1 Map of the San Joaquin Valley Air Basin with Locations of Existing

and Potential Biomass PlantsSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-7 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural BurningSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-8 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning 7.1.2 Fuel Use and Storage Capacities

The percentage of agricultural material fuel versus non-agricultural material fuel that a biomass power plant accepts is constantly ch anging. Upon reviewing District database information and snapshot data of biomass power plant activities provided by the Compliance Department, it appears t he percentage of agricultural material accepted generally varies gre atly; from as little as 0% of accepted fuel to as high as 70%.

Biomass power plants accept urban waste materials a nd some forestry materials in addition to agricultural materials as fuel. Non -agricultural fuels include such materials as mill chips, cedar bark, forest slash/c ull, hog fuel (mill residue), sawdust, construction wood waste, landfill derived wood, landscape tree trimmings, pallet/bin wood, and urban development c learing trees. Urban wood waste must contain less than 1% by weight of plasti c, rubber, metals, roofing felt paper, and other non-wood contaminants other than d irt or ash. No asbestoscontaining materials are approved as fuel.

SJVAB biomass power plants have very broad acceptan ce policies for agricultural wood fuel. This includes citrus and g rape wood along with the other commonly accepted wood types. The limitation the b iomass power plants have are that all treated wood posts, wire and drip line must be removed from the grape wood prior to grinding. CBEA states that the biomass power plants do have the ability to accept vines and that the remov al of the wiring from the vineyard wood is a relatively minor issue in terms of the plants’ ability to accept

those materials.

Biomass power plant operators have indicated that p revious concerns regarding certain materials have been alleviated over the pas t few years as the operators have improved the methods in processing the materia ls to better suit the needs of the plant. For example, in the past citrus mate rials caused concern for plant operators because the stringy citrus materials have the tendency to bind on the fuel handling conveyors and plug the fuel metering bins and this upsets the combustion process resulting in higher emissions an d equipment deterioration due to temperature cycling. The operator also indi cated that citrus wood ground to about 3-inch size screen poses minimal plugging problem. Now, due to considerable changes in the processing of the citru s materials, it has been reported that the operators no longer believe this is the case. Biomass power plant operators have indicated that they now mix ci trus chips with chips from other crops to promote better flow of the materials through the equipment. Conversations with biomass plant operators and comm ents from the California Citrus Mutual indicate that the biomass power plant s that do accept citrus materials can blend up to 25% citrus chips with oth er biomass fuel for combustion. It is important to note however, that it is relatively more affordableSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-9 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning for the biomass power plants to accept urban waste than agricultural materials because the residents of the community typically su bsidize urban waste.

The combined storage capacity for the biomass facil ities in the SJVAB at the time this report is about 266 acres. It is important to note that the available storage capacity at any given facility at any given time ca n vary. The primary factors affecting the amount of available storage are the a mount of fuel previously received, and the tons of fuel stored per acre comb ined with the tons of fuel burned each day. Another source for uncertainty re garding the storage capacity of a facility is that the tons of material stored p er acre could vary from one acre to the next. Conversations with biomass power plant o perators indicated the amount of tons of material stored per acre varies b y factors including: (1) if the material is received green or bone dry, (2) if the material is urban or agriculture, and (3) how high and wide the material is piled whe n it is received. Due to the variability of tons/acre storage capacity, it would be difficult to calculate that amount of material that the biomass plants can actu ally store the remaining crop
type.

District staff received additional information from CBEA regarding the storage capacity at the 12 biomass power plants. According to CBEA, the wood fuel storage capacity, using current storage practices, from the 12 biomass plants is summarized below. The current storage capacity of C ovanta Delano alone is 125,000 green tons. The total maximum storage capac ity at all 12 facilities that use SJ Valley Ag Waste is 782,500 tons. Further, th e majority of these facilities can store 60-175 operating days of fuel. This large storage capacity allows the use of wood fuel such as citrus and other types of fuel that may be stockpiled at significantly higher amounts and percentages than t he actual fuel mix to the boiler (i.e. Covanta Delano may receive 50% citrus in the total agriculture

deliveries for several months and then blend the fu el later to achieve an ideal mix to the boilers of 30% citrus). CBEA also indicated that many of the larger orchard removal contractors have storage capabiliti es. For example, one northern District contractor regularly stores as mu ch as 20,000 tons of agriculture waste at its truck re-load facility.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-10 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Table 7-3 Fuel Storage Capacity for 12 Existing Bio mass Plants That Use Ag Waste From SJVAD

Daily Fuel Maximum Fuel Storage Capacity Facility Name Region Served Use (GT) Acres Tons Day s Rio Bravo Fresno Central 850 8 35,000 41
Covanta Mendota Central 800 35 54,000 68
Madera Power Central 830 80 145,000 175 Ampersand Chowchilla Central 360 2 6,000 17

Subtotal/Average 2,840 125 240,000 85
Covanta Delano South 1,625 77 125,000 77 Dinuba Energy South 415 20 45,000 108
Sierra Power South 295 4 20,000 68

Subtotal/Average 2,335 101 190,000 81
Merced Power North 360 10 19,000 53 Thermal Energy North 631 28 24,000 38
SPI Sonora North 250 5 7,500 30
Chinese Station North 710 15 45,000 63
SPI Lincoln North 600 20 36,000 60

Subtotal/Average 2,551 78 112,500 44

TOTAL ALL 7,726 304 542,500 70

7.1.3 Historical Fuel Usage

All nine power plants in the SJVAB utilize both agr icultural wood materials and non-agricultural materials in their operations. Th e power plants generate electricity by burning the biomass fuel in combusto rs or boilers to produce steam. The steam is used to spin turbines, which in turn g enerate electricity.

District staff analyzed the historical fuel usage o f the annual bone dry tons (BDT)

burned at the nine biomass facilities in the SJVAB. In order to do so, staff reviewed quarterly reports submitted to the Distric t for the past five years (2005- 2009) from the biomass plants. It is important to note that at the time of this analysis, two of the facilities had not been in ope ration for five full years.

For the analysis, staff made the following assumpti ons:

1. For facilities with data from one or two quarter s of a year unavailable at the time of this report, staff assumed the unavailable data to be equivalent to the average of the other quarters for the same facility for the same year.

2. Facilities reporting agricultural fuel received instead of burned, staff assumed the facility burned the total quantity of agricultu ral fuel received.

3. For facilities that only reported agricultural o ffset records, staff assumed the agricultural offsets burned is the total agricultur al fuel burned.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-11 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning 4. For the two facilities in operation for less tha n five full years, staff assumed the average information for total time of operation s to be equivalent to a fiveyear average.

Facility A: Staff assumed the fuel usage by using d ata provided by the facility as a snapshot of activity (273 BDT/day) provided by th e District Compliance Department. Staff applied this snapshot number to the total operating days for each quarter to estimate the total annual BDT burne d. Staff assumed agricultural fuel by using data provided by the facility as a sn apshot of activity (219 BDT/day). Staff applied this snapshot number to th e total operating days for each quarter to estimate the total agricultural fue l used.

5. Facility B: Staff estimated the total annual BDT burned by assuming the facility operated at the high-end BDT capacity of 2 13,609 BDT/yr. However, historical data indicates this facility operates an average 82% of the time. Therefore, staff adjusted the estimated BDT to 82% totaling in an annual BDT of 175,159 BDT/year (213,609 BDT/year x 0.82). Agr icultural fuel records

were available.

6. Facility C: This facility advertises on it’s web site that it has a capacity of 1293 tpd of BDT biomass fuel. For purposes of this anal ysis, staff assumed the plant is operational 365 days per year, giving it a n annual fuel capacity of 471,945 BDT (1,273 BDT/day x 365 days). Staff assu med 70% of the total BDT/year was agricultural fuel based on a snapshot of fuel use provided by the District compliance department.

7. Facility D: Staff assumed that of the total BDT (84,589 BDT/year) burned, 25% is agricultural fuel based on a snapshot of usa ge for this facility provided by the District Compliance department. The total B DT of agricultural material fuel burned is 21,147 BDT/year (84,589 BDT/year x 0 .25).

8. Facility F: Staff assumed total annual BDT burne d to be equivalent to the lowend BDT capacity, as presented later in this report . Agricultural fuel records

were available.

9. Facility I: District staff estimated the total a nnual BDT fuel burned by assuming the snapshot data of BDT fuel burned and F uel percentages provided by the Compliance department is indicative of activities for an entire year. Staff multiplied the snapshot data (468 BDT/ day) by the 5-year average operating days/year (347). Staff estimated the tot al annual agricultural material fuel burned by assuming the snapshot data of BDT fuel burned (234 BDT/day) and Fuel percentages provided by the Compl iance department is indicative of the entire year. Staff multiplied th e Snapshot data (234 BDT/day) by the 5-year average operating days/year (347). The total annualSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-12 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning BDT agricultural material fuel burned is 81,198 BDT /year (234 BDT/day x 347 days).

Table 7-3 Average Annual Historical BDT Fuel Use ( 2005-2009)

Biomass Facility Annual BDT Agricultural

Material Burned (tpy) Annual BDT Urban Waste Burned (tpy) Total Annual BDT Burned (tpy)

A 49,584 12,227 61,811

B 125,838 49,321 175,159

C 330,362 141,583 471,945

D 21,147 63,442 84,589

E 41,028 88,655 129,683

F 8,660 83,367 92,027

G 117,202 106,590 223,793

H 21,992 50,674 72,666

I 81,198 81,189 162,378

District staff reviewed the five-year historical fu el usage of the biomass power plants to determine if the ratio of agricultural ma terial to urban waste has varied due to the housing market boom and subsequent econo mic downturn. Presented in Table 7-4 is the average annual percen tage of agricultural material burned at the biomass plants from the plants that r eported the total BDT and agricultural material BDT in their quarterly report s. In 2008, the use of agricultural material at the biomass power plants w as twenty-five percent of the total fuel used, in 2009 the use of agricultural ma terials increased to forty-three percent. Staff attributes this fluctuation in perc entage of agricultural fuel used to the construction industry boom and the following ec onomic downturn. However, CBEA has submitted comments stating that there was a shortage of agricultural

fuel in 2006.

Table 7-4 Average Annual Percentage of Agricultural Material Burned

Year 2005 2006 2007 2008 2009
Ave % Ag Material 58% 24% 41% 25% 43%

Historically, there have been occasions when biomas s plants had to turn away agricultural materials. During the fall of 2007, s everal biomass power plants in the District had to temporarily shut down plant ope rations due to equipment failures or maintenance purposes. In addition, som e biomass power plants had to refuse chipping material because storage space w as not available. Issues such as lack of storage space and equipment failure can create situations when the biomass power plant operators must turn away ag ricultural materials. This inability to guarantee that a facility can accept a gricultural biomass at all times creates uncertainty in the ability of the biomass p lants to accept increasedSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-13 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning amounts of agricultural fuel that would be generate d by a complete prohibition of open burning.

It is important to note that the reason the plants were off-line for several months during the period of 2007 was due to plant improvem ents and refurbishments. One of the South Valley plants did an $18 million r efurbishment of the plant in the third quarter of 2007, which lasted for several mon ths. A Central SJVAB power plant invested over $14 million in refurbishing the ir facility and came back on-line

in December 2008. In October 2008 another Central SJVAB plant invested over $10 million to refurbish the combustor, which impro ved its operational availability by 20%. One North SJVAB plant has invested $4 mill ion on refurbishments over the past 2.5 years, and plans to invest another $2 million in 2009-2010.

Although there have been periods of inoperation at the facilities, the nine facilities averaged 6,029 operating hours per year, out of a p ossible 8,760 hours per year. Converting operating hours into days translates to mean that the biomass power plants were in operation for an average of 251 of 3 65 days per year, or 69% of the time. Staff evaluated the operating hours as r eported to the District by the biomass power plants in the quarterly reports. Aga in, for the two facilities that have not been in operation for the full five years, staff assumed the average of total operating time to be equivalent to a five-yea r average.

7.1.4 Emissions and Emission Controls

7.1.4.1 Emissions

Criteria Pollutant Emissions The 2009 emission data reports are not due the Dist rict from the biomass power plants until June of 2010; therefore, an emission i nventory for 2009 is unavailable at the time of this report. Of the nine facilities , two facilities were not in operation for the full year of 2008; therefore, staff did not include emissions data from these facilities in this emission inventory. Additionall y, data is unavailable at the time of this report for one of the facilities for the year 2008. However, the 2009 emissions data is available for this facility. Sta ff substituted the 2009 emission inventory from this facility for the 2008 emission inventory.

Table 7-5 2008 Emissions Inventory for SJVAB Bioma ss Facilities

Pollutant VOC NOX PM10 SOX
Emissions (tons per year) 48.34 567.16 191.26 101.1 8San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-14 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning For purposes of the emission inventory for biomass facilities for the SJVAB for 2008, District staff made the following assumptions :

1. The 2009 emission inventory for the one facility with an unavailable inventory for 2008 is equivalent to the 2008 inventory.

2. The best available inventory for one facility on ly includes NOX emissions. To determine VOC, PM, and SOX emissions, staff assumed the ratio of VOC, PM, and SOX to NOX emissions is equivalent for this facility to the ratio reported by another facility with similar NOX emiss ions.

Green House Gas Emissions As discussed in the CEQA analysis and report, Globa l Climate Change (GCC) is now generally accepted by the scientific community to be caused by Greenhouse Gases (GHGs). GHGs are gases that trap heat in the atmosphere. Some greenhouse gases such as water vapor occur naturall y and are emitted to the atmosphere through natural processes while others a re emitted through human

activities. The most common GHG that results from human activity is carbon dioxide, followed by methane and nitrous oxide.

The analysis in this report identifies biomass faci lities as one of the feasible alternatives to open burning. The identified alter natives have the potential to result in changes in GHG emissions because of possi ble increased fuel consumption associated with equipment used to grind /chip and transport agricultural biomass. District staff examined the recommendations to determine their potential to have a cumulatively significant impact on global climate change, results of which are presented below. The analysis demonstrates that implementation of the recommended alternatives to o pen burning will not have a cumulative significant impact on global climate cha nge.

Potential Greenhouse Gas Impacts Staff is exploring alternatives to the existing pra ctice for disposing of orchard removal material by burning it in place (open burni ng). The alternative to open burning of orchard removal materials is chipping th e organic matter and using the chipped material as fuel in a biomass plant to prod uce electricity. Sources of

GHG emissions from this alternative include fuel co nsumed in chipping the plant material; fuel consumed in transporting the chipped material to a biomass plant; fuel consumed in processing the chipped material at the biomass plant; and combustion of the chipped material to produce elect ricity at the biomass facility.

The alternative practice of burning chipped materia l in a biomass power plant

would not result in an increase in GHG emissions co mpared to open burning the material. In fact, burning the material in a bioma ss plant would produce a net GHG benefit by producing electric power from a rene wable source of energy rather than a fossil fuel. This concept is one of the strategies adopted by theSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-15 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning State of California to reduce GHG emissions to 1990 levels by the year 2020 by requiring the state's load serving entities to meet a 33 percent renewable energy target by 2020 (Executive Order S-21-09). Biomass fuels burned in existing facilities are currently transported from various l ocations outside and within the San Joaquin Valley Air Basin. Use of locally produ ced fuel could reduce VMT associated with transporting materials, and thus re sult in a net GHG benefit. GHG emissions associated with chipping orchard remo val material are expected to be offset by the benefits associated with displa cing fossil fuels and reducing

VMT.

The District concludes, GHG emissions resulting fro m alternatives to open burning of orchard removal materials and prunings a re expected to have a net positive benefit on global climatic change compared to the status quo of open burning. Therefore, the District concludes that im plementation of the recommendations would have a less than cumulatively significant impact on global climatic change. For further discussion reg arding GHGs please see the published CEQA analysis report.

7.1.4.2 Emission Controls

Although biomass power plant operations and facilit ies are unique, they do follow the same general process to reduce emissions from t he processing of biomass fuel. The following is a description of methodolog ies and technologies the biomass facilities use, or could use, to reduce emi ssions. District staff

researched information on solid fuel-fired boilers by examining the District’s Permit database, California Air Resources Board (AR B) Best Available Control Technology (BACT) Clearinghouse, other air district s’ BACT Clearinghouses.

District staff also researched the United States En vironmental Protection Agency (EPA) BACT Clearinghouse, European Commission Integ rated Pollution Prevention and Control (IPPC) Best Available Techni ques, other local air districts and other states’ regulations, and technical docume nts published in the internet. District staff also reviewed the Permit-to Operate (PTO) for each biomass facility.

NOx Emission Control Technologies Common fuel types for solid fuel-fired boilers are agricultural material (biomass), coke, coal, wood wastes, paper, walnut shells, pist achio shells, tire-derived fuel, municipal solid waste, and other solid waste. For the purpose of this analysis, NOx emission limits are based on the fuel type, and are divided into three categories based on their composition. The categor ies include municipal solid waste, biomass, and others. Each solid fuel is eit her homogeneous or heterogeneous. Under a homogeneous condition, the fuel meets specific criteria and is sorted by content. Examples of homogeneous fuels are walnut shells, coke, and woodchips. Heterogeneous fuel is unsorte d, and untreated. An example is municipal solid waste, which contains a wide variety of combustible materials having widely varying heat content values . The fuel type is importantSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-16 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning when considering the emission reduction effectivene ss of an emission control technology. Unlike gaseous fuel-fired units, solid fuel-fired units present more difficult technological challenges in controlling N Ox, PM, and SOx emissions to a much lower because of varying fuel composition.

NOx emission control techniques generally fall into two categories: (a) combustion modifications; and (b) post combustion m odifications (add-on controls). Typically, these control systems are su ccessful in simultaneously attaining low NOx and CO emission levels. Most of the NOx formed during combustion of natural gas is from high temperature reaction of nitrogen (N 2 ) with oxygen (O 2 ). NOx formed this way is referred to as “thermal NOx” and is considered a function of flame temperature and oxyg en concentration. Studies of combustion processes indicate that significant a mounts thermal NOx are formed when the flame temperature is above 2,300°F.

Combustion Modification Combustion modification systems are designed to red uce thermal NOx formation by changing the flame characteristics to reduce pea k flame temperature. Combustion controls include low excess air operatio n, staged combustion, over fire air ports, biased firing, and burners out of servic e.

Combustion modification is also achieved by differe nt burner designs such as Low NOx and Ultra Low NOx burners. Some of the design principles used in Ultra low NOx and Low NOx burner include staged air burners, staged fuel burners, pre-mix burners, internal recirculation, and radiant burner s.

Combustion control systems may be used by itself or in combination with Flue Gas Recirculation (FGR). FGR recycles a portion of the exhaust stream back into the burner wind box, mixing low oxygen air with combust ion air prior to entering the combustion chamber. This technique reduces thermal NOx formation by reducing the peak temperature and by reducing oxygen in the combustion zone.

Low Excess Air Low excess air is a comparatively simple and easy t o implement operational measure for reducing NOx emissions. By reducing th e amount of oxygen

available in the combustion zone to the minimum amo unt needed for complete combustion, fuel-bound nitrogen conversion and to t he less extent thermal NOx

formation are reduced. There is no additional ener gy required for low excess air firing, and if properly operated, no reduction in a vailability of the power plant should result from this type of emission control te chnique. As the oxygen level is reduced, however, combustion may become incomplete and the amount of unburned carbon in the ash may increase. Reducing the amount of oxygen in the combustion zone in the primary zones to very lo w amounts can also lead to high levels of carbon monoxide. The results of suc h changes can be a reductionSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-17 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning in the boiler efficiency, slagging, corrosion, and counteractive overall impact on the boiler performance.

Air Staging NOx reduction by air staging is based on the creati on of two divided combustion zones: a primary combustion zone with a lack of oxy gen, and a secondary combustion zone with excess oxygen in order to ensu re complete burn-out. Air staging reduces the amount of available oxygen (in 70 – 90% of the primary air) in the primary combustion zone. The sub-stoichiome tric condition in the primary combustion zone suppresses the conversion of fuel-b ound nitrogen to NOx. In addition, the formation of thermal NOx is reduced t o some extent by resulting lower peak flame temperature. In the secondary zon e, 10-30% of the combustion air is injected above the combustion zon e. Combustion is completed at this increased flame volume. Therefore, the rel atively low-temperature secondary stage limits the production of thermal NO x.

In boilers, the following options exist for achievi ng air-staging:

• Biased Burner Firing

Biased burner firing is frequently used as a retrof it measure at existing installations (only for vertical boilers) as it doe s not require major alteration

of the combustion installation. The lower burners operate fuel-rich whereas upper burners are supplied with excess air.

• Burners Out of Service (BOOS)

Since putting some burners out of service does not require a major alteration of the combustion installation, it is fr equently used as a retrofit measure at existing vertical boilers. The lower bu rners are operated under fuel-rich conditions, whereas the upper burne rs are not in use, injecting only air. The effect is similar to over fire air, but NOx reduction by BOOS is not as efficient. Problems may arise with maintaining the fuel input, because the same amount of thermal energy ha s to be supplied to the unit with fewer operating burners. Therefore, this control technique is generally restricted to gas- or oil-fired combustio n processes.

• Over Fire Air (OFA)

For over fire air operation, air ports (wind boxes) are installed in addition to existing burners. A part of the combustion air is injected through these separate ports, which are located above the top row of burners. Burners can then be operated with low excess air, which inh ibits NOx formation, the over fire air ensuring complete burn-out. Typi cally 15-30% of the totalSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-18 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning combustion air that would normally pass through the burners is diverted to the over fire ports. Retrofitting over fire air to an existing boiler involves applying water-wall tube modifications to create th e ports for the secondary air nozzles and the addition of ducts and wind box.

Flue Gas Recirculation The recirculation of flue gas results in a reductio n of available oxygen in the combustion zone, and since it directly cools the fl ame, in a decrease of the flame temperature; therefore, both fuel-bound nitrogen co nversion and thermal NOx

formation are reduced. The recirculation of the fl ue gas into the combustion air has proven to be a successful method for NOx abatem ent in high temperature combustion systems such as wet bottom boilers and o il-or-gas-fired units.

Reduced Air Preheat The combustion air preheat temperature has a signif icant impact on NOx formation mainly for gas and oil firing systems. F or these fuels, the main part of NOx is determined by thermal NO mechanism, which de pends on the combustion temperature. Reducing air preheat tempe rature results in lower flame temperatures (peak temperatures) in the combu stion zone. There are two major drawbacks of this technology. First, in seve ral boilers, e.g., in coal burning, high combustion temperatures are required and accordingly high air preheater temperatures are essential for the proper functioning of the combustion installation. Secondly, lowering the air preheat t emperature results in a higher fuel consumption, since the higher portion of the t hermal energy contained in the flue gas cannot be utilized and ends up leaving the plant via the stack. This can, however, be counterbalanced by utilizing certain en ergy conservation methods, such as increasing the size of the economizer.

Fuel Staging Fuel staging (also called reburning) is based on th e creation of different zones in the boiler by staged injection of fuel and air. Th e aim is to reduce back to nitrogen the nitrogen oxides that have already been formed. Reburning involves combustion in three zones. In the primary combusti on zone, 80-85% of the fuel is burned in an oxidizing or slight reducing atmosp here. This primary burn-out zone is necessary in order to avoid the transfer of excess oxygen in the reburning zone, which would otherwise support possi ble NOx formation. In the second combustion zone (often called reburning zone ), secondary or reburning fuel is injected in a reducing atmosphere. Hydroca rbon radicals are produced, reacting with the nitrogen oxides already formed in the primary zone; other unwanted volatile nitrogen compounds like ammonia a re generated as well. In the third zone, the combustion completes through th e addition of final air into the

burn-out zone. Different fuels can serve as reburn ing fuel (pulverized coal, fuel oil, natural gas, etc.), but natural gas is general ly used due to its inherent properties.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-19 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Low NOx Burner (LNB) Low NOx burners modify the means of introducing air and fuel to delay the mixing, reduce the availability of oxygen, and redu ce the peak flame temperature. LNBs retard the conversion of fuel-bo und nitrogen to NOx and the formation of thermal NOx, while maintaining high co mbustion efficiency. The pressure drop in the ducts increases, causing more operational expenses. There could also be some corrosion problems especially if the process is not properly controlled. The low NOx burning techniques require s, at least, the burners to be changed and installation of OFA. If existing burne rs are classical burners, then changing the burners can usually be done very cost- effectively. However, if the burners are delayed combustion low NOx burners (old type), the benefits of retrofitting such burners into rapid injection low NOx burners can only be effectively assessed on a case-by-case basis.

Dilution-based Combustion Control Dilution-based combustion control strategies reduce thermal NOx formation by introducing inert material into the flame. The inj ected inert absorbs heat without reacting, thereby reducing peak flame temperature a nd reducing the potential for NOx formation. Water or steam injection reduces fl ame temperatures by using a portion of the flame’s heat to convert water from l iquid to vapor. The disadvantage of this control technique is that the heat efficiency of the device is reduced by one to four percent. In flue gas recirc ulation (FGR), about 10% to 25% of the flue gas is siphoned off from the combus tion exhaust stream to be

used as combustion air for the burner. Since the f lue gas has less oxygen than atmospheric air, the additional nitrogen in the flu e gas acts as an inert component in the combustion process, reducing peak flame temperature. Flue gas recirculation may not be a feasible retrofit te chnology for many devices due to size or layout constraints.

Post Combustion Controls (Flue Gas Treatment) Selective Non-Catalytic Reduction (SNCR) SNCR involves direct injection of ammonia or urea a t the flue gas temperatures

of about 1600 0 F to 1900 0 F. Ammonia or urea reacts with NOx in the flue gas to produce N 2 and water. The reactions in the SNCR are due to t he thermal decomposition of ammonia or urea and the subsequent NOx reduction. A simplified NOx reduction reaction in SNCR is shown below.

Ammonia: 4NH 3 + 4NO + O 2 → 4N 2 + 6H 2 O

Urea: CO(NH 2 ) 2 + 2NO +1/2O 2 → 2N 2 + CO 2 + 2H 2 O

The temperature of the flue gas at the point of amm onia or urea injection and the

amount of unreacted NH 3 (ammonia slip) that will pass through the SNCR can significantly affect the efficiency of NOx reductio n. At temperatures below the desired operating range, the reduction reactions di minish and ammonia slipSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-20 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning increases. Above the desired temperature range, NH 3 is oxidized to NOx, which

results in decreased NOx reduction efficiencies.

An important factor to the performance of SNCR is t he mixing of the reactant and the flue gas within the reaction zone. Design cons iderations include delivering the reagent in the proper temperature window, and a llowing sufficient residence time of the reagent and flue gas in the proper temp erature window. Additionally, other factors such as reagent to NOx ratio and fuel sulfur content also influence the performance and reduction efficiency of SNCR.

Selective Catalytic Reduction (SCR) SCR involves injecting ammonia into the flue gas in the presence of a catalyst to reduce NOx to elemental nitrogen (N 2 ) and water. The overall SCR reactions are

shown below.

4NH 3 + 4NO + O 2 → 4N 2 + 6 H 2 O

8NH 3 +4NO 2 + O 2 → 6N 2 + 12H 2 O

Flue gas temperature, SCR inlet NOx concentration, catalyst surface area, volume, and age of the catalyst, and acceptable amo unt of ammonia slip influence the performance of the SCR. The catalyst lowers the activation energy of the NOx decomposition reaction and allows NOx re duction to proceed at a lower temperature that is required by SNCR. Depend ing on the type of catalyst used, the optimal temperature range is typically be tween 650 0 F to 800 0 F. Below this temperature range ammonium sulfate can form wh ich causes catalyst deactivation. Above the optimum temperature, the c atalyst will sinter and rapidly deactivate. SCR is considered technological feasib le for control of NOx from

solid fuel-fired units.

Regenerative Selective Catalytic Reduction (RSCR) The following information is an extract from a tech nical document published by Babcock Power Environmental: “RSCR is a regenerativ e selective catalytic device achieving NOx reductions of >80%, applied to the cold gas (after the boiler and particulate removal equipment) prior to discharge to the stack achieving NOx reductions of >80%. RSCR is a combin ation of two established and proven technologies: Regenerative Thermal Oxidi zer (RTO) and SCR. By utilizing the direct contact regenerative heater te chnology (usually associated with an RTO, in which cycling beds of ceramic media used to transfer heat, the low temperature issue is resolved. NOx reduction t akes place in SCR catalyst modules positioned above the heat transfer bed, whe re the flue gas has been

heated to around 600 o F and the proper amount of ammonia has been added upstream of the canisters. Either anhydrous or aqu eous ammonia can be used.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-21 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning The primary application of RSCR is the reduction of NOx emissions in the flue gas found at the tail end of the biomass boiler whe re the gas temperatures are cool, typically 300 o F to 400 o F. In an RSCR, the temperature of the flue gas is temporarily elevated for optimal catalyst performan ce and the heat is recovered before sending the cleaned flue gas to the stack. The main advantage of RSCR is its high thermal temperature versus standard tai l-end solutions in which the heat exchanger and duct is used. The RSCR thermal efficiency can be guaranteed as high as 95% in contrast to the standa rd tail end solutions that typically achieve 70 to 75% efficiency.

Hybrid Selective Reduction (HSR) HSR is a combination of SNCR and SCR that is design ed to provide the performance of full SCR with significantly lower co sts. In HSR, an SNCR is used to achieve some NOx reduction and to produce a cont rolled amount of ammonia slip that is used in a downstream in-duct SCR react or for additional reduction.

HSR has been demonstrated to reduce NOx emissions b y 50% to 98% on a 320 MMBtu/hr coal fired boiler; therefore, it is consid ered technologically feasible for

control of NOx from solid-fuel fired boilers. Curr ently, the District has received an application for an operating permit for biomass fue l fired boilers where the applicant is proposing to install and operate both SNCR and SCR on four boilers to achieve 0.012 lb NOx/MMBtu (about 9.8 ppmv at 3% oxygen) . It is important to mention that the District has recently received a permit application from a company that intends to operate four biomass fired boilers that will utilize SCR

and SNCR to achieve a NOx emission level of 0.012 l b/MMBtu.

Particulate Matter Control Technologies Particulate matter (PM) in solid fuel-fired unit is formed due to the inert solids contained in the fuel, the unburned hydrocarbon fue ls, as well as byproducts of limestone injection, which accumulate to form parti cles. District staff reviewed the EPA BACT Clearinghouse to determine technologie s to control PM emissions from solid fuel-fired units. PM control technologi es that were listed in the database include electrostatic precipitators, fabri c filter/baghouses, wet scrubbers, and mechanical separators. The PM and S Ox control technologies and emission limits of the permitted units operatin g in the SJVAB are shown in the Table on the next page. It is important to not e that one of the biomass power plants has two boilers and both are included in thi s list. As such, there are ten

boilers listed here for the nine facilities.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-22 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Table 7-6 Permit PM10 and SOx Limits of Solid Fuel -Fired Biomass Units in the District

Unit Size

MMBtu/hr Existing PM and

SOx Control Technology Permit PM10 Limit Permit SOx

Limit lb/MMBtu Fuel Type

171.2 Multicyclone and

ESP 0.016 gr/dscf @

12% CO 2 0.061 Biomass and

construction wood

waste 185 Multicyclone and

baghouse;

limestone injection 0.04 lb/MMbtu 0.04 lb/MMbtu Biomass

185 Baghouse and

limestone injection 0.04 lb/MMbtu 0.04 lb/MMbtu Biomass, construction wood waste, and urban

wood waste

11.5 MW (189 MMBtu/hr) Multicyclone and

ESP; Lime and soda ash injection 0.0144 gr/dscf @

12% CO 2 9.9 lb/hr Biomass, construction wood waste, and urban

wood waste

259 ESP and Lime

injection 8.75 lb/hr 6.25 lb/hr Biomass

400 Multicyclone and

Fabric Filter 0.010 gr/dscf @

12% CO 2 23 ppmv @ 3%

O 2 Biomass, construction

wood waste, and urban

wood waste

315 Fabric Filter and

lime and NAHCO 3 0.045 lb/MMbtu 23 ppmv @ 3%

O 2 Biomass, construction

wood waste, and urban

wood waste

317 Baghouse 0.010 gr/dscf @

12% CO 2 247 lb/day Biomass

352 ESP 17.4 lb/hr for

condensable and

5.8 lb/hr for

filterable 10 lb/hr Biomass, construction wood waste, and urban

wood waste

460 Multicyclone and

Baghouse 0.03 lb/MMBtu 1.2 lb/MMBtu Biomass, construction wood waste, and urban

wood waste

Electrostatic Precipitator (ESP) An ESP is a particle control device that uses elect rical forces to move the particles out by flowing gas stream onto collector plate. Th e particles are given electrical charge by forcing them to pass through a corona, a region in which gaseous ions flow. The electrical field forces the charged part icles to the walls comes from electrodes maintained at high voltage in the center of the flow lane. One the particles are collected on the plates, they must be removed from the plates without re-entraining them into the gas stream. This is do ne by knocking them loose from the plates and allowing the collected layer to slid e down into a hopper. Some ESPs remove the particles by intermittent or continuous washing with water. ESPs are configured in several ways. Some of these configur ations have been developed for special control action, and others have evolved for economic reasons. The types ofSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-23 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning ESPs are plate-wire precipitator, flat plate precip itator, tubular precipitator, and twostage precipitator.

Units using limestone injection in a dry scrubber f or control of SOx rarely use ESPs because the use of flue gas desulfurization/baghous e combination significantly increases control of SOx emissions while achieving comparable PM control. When flue gas passes through the filter cake, additional SOx is removed by unreacted limestone and CaO in the filter cake. Also, due to the high resistivity of the PM10 (mostly CaO and CaSO 3 ), a large ESP plate area would be required to matc h the control efficiency of baghouses, which makes ESP mo re expensive than baghouses.

Fabric Filter/Baghouse

A fabric filter consists of one or more isolated co mpartments containing rows of filter bags in the form of round, flat, or shaped tubes, o r pleated cartridges. Particleladen gas passes up along the surface of the bags t hen radially through the fabric. Particles are retained on the upstream face of the bags, and the cleaned gas stream is vented to the atmosphere. The filters ar e cyclically operated, alternating between relatively long periods of filtering and sh ort periods of cleaning. During cleaning, dust that has accumulated on the bags is removed from the fabric surface and deposited in a hopper for subsequent disposal.

Fabric filters collect particles with sizes ranging from submicron to several hundred microns in diameter, with efficiencies in excess of 99 percent. The layer of dust or dust cake collected on the fabric is primarily resp onsible for such high efficiency. As the flue gas passes the filter cake additional S Ox is removed. Gas temperatures up to about 500 o F with surges to about 550 o F can be routinely accommodated in some configurations. Most of the e nergy used to operate the system appears as pressure drop across the bags and associated hardware and ducting. The primary disadvantage of baghouses com pared to ESPs is the higherpressure drop across the baghouse resulting in incr eased fan power requirements for the system.

Wet Scrubber

A wet scrubber is a control device that removes PM and acid gases from waste gas streams of stationary point sources. The pollutant s are removed primarily through impaction, diffusion, interception, and/or absorpti on of the pollutants onto droplets of liquid. Collection efficiencies for wet scrubbe rs vary with particle size and distribution of the waste stream. Generally, colle ction efficiency decreases as the particle size decreases. Collection efficiencies a lso vary with scrubber type. The efficiency ranges from greater than 99% for venture scrubbers to 40-60% (or lower) for simple spray towers. It is important to note t hat none of the permitted solid fuelfired units in the SJVAB currently operates wet scr ubbers.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-24 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning SOx Control Technologies

SO 2 is formed during the combustion process because of thermal oxidation of the sulfur contained in the fuel. A portion of the sul fur is further oxidized to SO 3. At temperatures below approximately 600 o F, sulfur trioxide readily combines with moisture in the flue gas or in the atmosphere to fo rm sulfuric acid (H 2 SO4). These sulfur compounds are acidic and can be controlled u sing the same technology.

SO 2 and H 2 SO 4 control technologies are discussed below.

Dry Flue Gas Desulfurization The use of a dry flue gas desulfurization system su ch as lime spray drying followed by a baghouse has the potential to reduce Sox emiss ions by 75% to 90%. The lowest permitted SO 2 emission rate for a biomass-fired boiler using lime spray scrubbing technology is 0.10 lb/MMBtu.

Circulating Dry Scrubber (CDS) The CDS is a once-through dry technology where flue gas, ash, and lime sorbent

form in a fluidized bed in an adsorbent vessel. Th e flue gas is humidified in the vessel to assist the adsorption reactions between l ime and SOx. The by-products leave the absorber in a dry form with the flue gas and are subsequently captured in a downstream particulate collection device. It is important to note that CDS have only been domestically applied to two coal fired bo ilers.

Wet Scrubber Wet scrubber is a one-through control technology wh ere a reagent is slurried with water and sprayed into the flue gas stream in an ab sorber vessel. The SO 2 is removed from the flue gas by sorption and reaction with the slurry. The byproducts of the sorption and reaction are in a wet form upon leaving the system and must be dewatered prior to transport and disposal. Wet scrubbers can be classified on the basis of the reagents used and the by-produc ts generated. The typical reagents used in this process are lime and limeston e. Additives, such as magnesium, may be added to the lime or limestone to increase the reactivity of the reagent. The reaction by-products are calcium sulf ite and calcium sulfate. Calcium

sulfite to calcium sulfate reaction is a result of oxidation, which can be inhibited or forced depending on the desired by-product. The mo st common wet scrubber application uses limestone as the reagent and force d oxidation of the reaction byproducts to form calcium sulfate. Wet scrubbers ar e commercially available and are generally only applied on coal-fired boilers.

Regenerable Wet Scrubber (RWS) RWS technology uses sodium sulfite, magnesium oxide , calcium carbonate, amine,

or ammonia as the sorbent for removal of SO 2 from the flue gas. The spent sorbet is regenerated to produce concentrated streams of S O 2 or other sulfur compounds, which may be further processed to produce other pro ducts. This technology may require additional flue gas treatment prior to SO 2 absorption process to remove other flue gas constituents such as hydrogen chlori de and hydrogen fluoride thatSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-25 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning may affect the sorbent and/or final by-product. So dium sulfite and ammonia-based technologies are commercially available and have co ntrol efficiencies ranging from

90% to 95%.

7.1.5 Economics – Agricultural Fuel vs. Urban Fuel

In the SJVAB, several biomass power plants are requ ired to burn agricultural material in order to offset emissions under permit with the District. Before this permit requirement, biomass power plants received a gricultural material to burn for free. Today, however, selling agricultural mat erial to biomass plants is a source of revenue for chipping operators.

A grower that needs to remove agricultural material off-site will hire a chipping operator. In the SJVAB, the chipping companies typ ically propose an initial contract with growers to chip their orchard removal material. The contract is written prior to the job and establishes a tentativ e agreement, which includes an estimated cost for the removal, chipping and transp ortation of the material to a biomass power plant. The contract usually includes a line item that states the

terms of the contract based on when a local biomass power plant accepts the chipped material. A grower's final cost of chippin g orchard removals can vary due to the presiding condition of each contract tha t all material is accepted and paid for by a biomass power plant. If the biomass power plant rejects the chipped materials, then the chipping company would likely return the materials back to the grower.

If the agricultural material is sent to a landfill, the chipper must pay a tipping fee of about $25.00 to $32.00 per ton to the operator. If sent to a compost facility, the cost is less for the chipper, ranging from $18. 00 to $25.00 per ton for the tipping fee. However, if sent to a biomass power p lant, the biomass operators pay the chipper around $34.00 per BDT. Considering the availability of agricultural, forestry, and urban residues, it is r elatively more affordable to accept urban residues at the biomass power plants. The Fi gure 7-2, diagrams the movement of money through a SJVAB biomass market.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-26 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Figure 7-2 Current Biomass Fuel Market: Movement o f Money

Growers

Growers pay the chipper to dispose of Agricultural Material

Chippers (Agricultural Fuel) Chippers pay the Landfill a tipping fee ($25-32/ ton) Compost fee ($18-25/ ton)

Urban Fuel Suppliers Landfills/ Compost

Biomass plants can buy urban fuel for $20-$23.00 per BDT Biomass Plants can buy Agricultural Fuel for $33-$34.00 per BDT

Biomass Power Facilities

Within the biomass fuel market, there is a consider able price difference between the cost of urban fuels and agricultural fuels. Da ta throughout the state shows an average price difference of about $12 per BDT of fu el between urban fuel and agricultural fuel. Figure 7-3 diagrams the price d ifference between biomass fuel markets, showing a consistent gap between agricultu ral fuel and urban fuel.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-27 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Figure 7-3 Biomass Fuel Prices by Category1988198919901991199219931994199519961997199819992000200120022003200420052006 10 15 20 25 30 35 40 45 50 $ / bdt Biomass Fuel Prices by Category

Urban Residue

Ag. Residue

In-Forest Residue

Mill Residues

Morris, G., Biomass Energy Production in California 2006: Updat e of the California Biomass Database , report of the Green Power Institute, December 2006.

While prices may vary, the price difference between agricultural fuel and urban

fuel of the SJVAB has maintained consistent as illu strated by the Figure 7-4.

Figure 7-4 California Biomass Fuels Market by Type of Fuel198019811982198319841985198619871988198919901991199219931994199519961997199819992000200120022003200420052006 - 500 1,000 1,500 2,000 2,500 3,000thousand BDT/year California Biomass Fuels Market by Category

In-Forest Residue

Ag. Residue

Urban Residue

Mill Residues

Morris, G., Biomass Energy Production in California 2006: Updat e of the California Biomass Database , report of the Green Power Institute, December 2006.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-28 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning 7.2 OUTLOOK

7.2.1 How Much More Agricultural Material Do We Ant icipate?

Figure 7-5 Map of Annual Agricultural Burn Tons in the San Joaquin Valley Air

BasinSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-29 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Current analysis indicates that of the crops that m ay possibly be prohibited from further open burning activities, three of those cro ps would most likely be sent to biomass facilities as an alternative to open burnin g. The three crops include fig orchard removal, <20 acre orchard removal reduced t o <15 acre orchard removal, and citrus orchard removal. Based on this information, District staff analyzed the current burn tons of material for each crop type and activity to determine how much more agricultural material would be generated and sent to the biomass plants as a result of prohibition of op en burning.

For purposes of this analysis, staff reviewed a thr ee-year history of each crop and activities with those crops using the best avai lable information from the District Smoke Management System (SMS). The review ed information included the acreage and tonnage of material open burned. S taff averaged the three-year data to create an outlook as to crop and burn activ ities. Staff assumes the threeyear average to be indicative of future activities.

Fig Orchard Removal Staff is recommending that fig orchard removals wou ld be prohibited from open burning acreage greater than 15 acres. Staff assum es that the total annual tonnage of material previously burned at amounts gr eater than 15 acres will be

sent to biomass facilities as fuel.

The trend for the burning of fig orchard removal ma terial appears to be from November through June in the North SJVAB and Novemb er through March in the Central SJVAB. There is no data indicating fig orc hard removal burning in the South SJVAB for the three years averaged for this a nalysis. The Central SJVAB region peaked for fig orchard removal tons burned i n the month of March at 1,200 tons of material burned, with ten tons burned in October. The North SJVAB peaked for fig orchard removal tons burned in April at 400 tons of material burned. Little to no burning of fig orcha rd removal material occurs in the late summer months and early fall months of July th rough October. Figure 7-6 is an illustration of the average monthly fig orchard removal burn tons in the SJVAB, distributed by region, for the years of 2007 through 2009.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-30 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Figure 7-6 Monthly Fig Orchard Removal Burn Distrib ution

Average Monthly Fig Orchard Removal Burn Tons per

Region (2007-2009)

0 200 400 600 800 1000 1200 1400

J an u ar y Febru a ry Ma r c h April M

ay Jun e Jul y August Sept e mber

O c tober

N ov emb e r

D e cember

MonthBurn Tons
Central Valley

North Valley

To further analyze the quantity and location of fig orchard removal material burned the chart below illustrates the monthly aver age fig orchard removal material burn tons by county (2007-2009). As seen in the chart below, Madera County has the highest average quantity of burn ton s of fig orchard removal materials at 1,200 tons for the month of January.

Figure 7-7 Average Monthly Fig Orchard Removal Burn Distribution by County

Average Monthly Fig Orchard Removal Burn Tons per

County (2007-2009)

0 200 400 600 800 1000 1200

January

F eb r u a r y M a rch A p ril M a y J u n e July Au g u st

S e pt e mb e r

O ct o b er Novem b er

D e ce mb e r

MonthBurn Tons Fresno County

Madera County

Merced CountySan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-31 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning For purposes of this analysis, staff assumes the fi g orchard removal acreage that was burned that were greater than 15 acres in size would no longer burn, but would find an alternative method of disposal of the material. Staff added each individual approved burn of fig orchard removal fro m the three years (2007-2009) to determine the average number of burns greater th an 15 acres. Of the average 80 burn acres, 61 acres would no longer be allowed to burn. Converting acres to tons, translates into 1,830 tons of fig orchard rem oval material that would be forwarded to the biomass plants per year for the en tire SJVAB.

<20 Acre Orchard Removal Staff analyzed the average monthly burning of <20 a cre orchard removals to illustrate a comprehensive look at this crop catego ry. The burning trends were calculated using a three-year average of the best a vailable information from the District SMS. The trend for the burning of <20 acr e orchard removal appears to occur throughout the year, through out the SJVAB wi th peak times ranging from October to May. The Central SJVAB region peaks for <20 acre orchard removal burning in the month of December at 6,582 tons of m aterial burned. The South SJVAB region peaks for <20 acre orchard removal bur ning in the month of October at 4,331 tons of material burned. While th e North SJVAB peaks in December 3,531 tons of material burned. Figure 7-8 illustrates the average monthly <20 acre orchard removal burn ton distribut ion by region of the SJVAB.

Figure 7-8 Average <20 Acre Orchard Removal Burn Di stribution



### Average Monthly "<20 Acre Orchard Removal" Burn

Tons by Region (2007-2009)

0 1000 2000 3000 4000 5000 6000 7000

J anu ary

F ebr uar y M ar ch April May June July

A ugust Sept em ber

O ct ober November

D ecem ber

MonthBurn Tons Central Valley

North Valley

South ValleySan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-32 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Current analysis indicates that it would be feasibl e to reduce burning of orchard

removals from <20 acres to <15 acres. Staff determ ined the increase in agricultural material sent to the biomass plants by first calculating the amount of crop burns that occurred in sizes ranging from 15 a cres to 20 acres. Staff did this by reviewing the SMS database for approved bur n sizes and quantities for a three year average from 2007-2009.

For purposes of this analysis, staff assumes the cr ops that were burned that were greater than 15 acres in size would continue t o burn in the future, but at 15 acres. Staff subtracted the 15 acres from each app roved burn greater than 15 acres to determine the quantity of acres that would no longer be approved for burning. For example, a burn that in the past woul d have been for 50 acres would be allowed to burn 15 acres in the future, le aving a difference of 35 acres that would no longer be allowed to burn and would b e sent to the biomass power plants as fuel. Staff applied this methodology to each burn over 15 acres during the three years (2007-2009) to determine the averag e. Of the average 2,334 burn acres, 254 acres would no longer be allowed to burn. Converting acres to tons, translates into 7,620 tons of orchard removal material that would be forwarded to the biomass plants per year for the en tire SJVAB.

Citrus Orchard Removal Staff analyzed the average monthly burning of citru s orchard removals to illustrate a comprehensive look at this crop catego ry. The burning trends were calculated using a three-year average of the best a vailable information from the District SMS. The trend for the burning of citrus orchard removal appears to occur throughout the year, through out the Central and South SJVAB. The Central SJVAB region appears to peak for citrus orc hard removal burning in the month of August at 4,120 tons of material burned. The South SJVAB region appears to peak for citrus orchard removal burning also in the month of August at 6,442 tons of material burned. Data indicates that there was no burning of citrus orchard removal materials in the North SJVAB during the three years that were averaged for this analysis. Figure 7-9 illustrates the average monthly citrus orchard removal burn distribution through the SJVAB by region.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-33 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Figure 7-9 Average Monthly Citrus Orchard Removal B urn Distribution

Average Monthly Citrus Orchard Removal Burn Tons by Region
(2007-2009)

0 1000 2000 3000 4000 5000 6000 7000

J a n ua r y

Fe b r u ary Mar c h Ap r il May Jun

e J u l y

A u g u s t

S e p t e mb e r October

N o vemb e r

D e c e mb e r

MonthBurn Tons Central Valley

South Valley

7.2.2 Could the Current Biomass Power Plants Physic ally Handle the

Increase in Materials?

The 2010 and future capacity of biomass fuel rate, from nine biomass power plants located in the SJVAB, is estimated to be bet ween 1,409,360 and 1,909,141 bone dry tons (BDT’s) per year 1 . These estimates were calculated using the following assumptions:

1. Size of each boiler unit, in MMBtu/hr, is based on the district permitted solid fuel-fired boiler units subject to Rule 4352.

2. The lower bound capacity is calculated using Bio mass heat content value of 0.008805 MMBtu/lbm Higher Heating Value (H HV). The value is based on ultimate analysis from 1999 source test ing (page 47 in a technical support document submitted with project S -1010053). Using the 1999 ultimate analysis, nitrogen was lower, hea t content value of the fuel was higher. This results in considerably less fuel consumed with a higher yield of airflow.

1 It should be noted that the CBEA estimates that th e capacity of the biomass power plants (including those plants just outside the Valley) is estimated to be 945,000 BDT to 1,000,000 BDT with an average availability ranging from 80% to 85 %. Since the CBEA’s estimates are less than the District’s estimate, the District will utilize the District estimates as the more conservative

values.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-34 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning 3. The heat content value of 0.0065 MMBtu/lbm (HHV) is used to estimate the upper bound fuel rate capacity. The v alue is based on heat content values reported in the Phyllis databas e, the United States Department of Energy, Energy Efficiency and Renewab le Energy (DOE/EERE) feedstock database, and selected literat ure sources.

District staff acknowledges that the use of differe nce heat content values will result in differences, particularly when fuel rate capacity is calculated. The following table illustrates the calculations used t o determine the lower and upper bound capacities of the facilities based.

Table 7-7 Illustration of Calculations Used to De termine Annual Boiler BDT Capacity

Lower Bound Upper Bound Power

Production Permitted

Output Capacity 0.008805

1 0.0005 24 365 0.0065

2 0.0005 24 365 Facility

ID

(MW) (MMBtu/hr) (lb/hr) (ton/hr) (ton/day) (ton/year) (lb/hr) (ton/hr) (ton/day) (ton/year)

A 12.5 185 21,011 11 252 92,027 28,462 14 342 124,662

B 30 317 36,002 18 432 157,690 48,769 24 585 213,609

C 56.5 715 81,204 41 974 355,673 110,000 55 1,320 481,800

D 11.5 189 21,465 11 258 94,017 29,077 15 349 127,357

E 28.5 460 52,243 26 627 228,825 70,769 35 849 309,969

F 13 185 21,011 11 252 92,027 28,462 14 342 124,662

G 28.5 352 39,977 20 480 175,101 54,154 27 650 237,194

H 9.4 171.2 19,443 10 233 85,163 26,338 13 316 115,362

I 20.5 259 29,415 15 353 128,838 39,846 20 478 174,526

Total: 1,409,360 Total: 1,909,141

1. The value was based on ultimate analysis from 19 99 source testing. Using the 1999 ultimate analysi s, nitrogen was lower, heating value of the fuel wa s higher. This results in considerably less fuel bei ng consumed with a higher yield of air flow.

2. The value is based on 6500 Btu/lb in the past pr oject for biomass facility C.

For purposes of determining if the biomass power pl ants have the capacity to accept the additional agricultural materials that w ould be generated by the prohibition of open burning of specific crops, Dist rict staff analyzed the agricultural material increase by region of the SJV AB rather than by county. To analyze if the biomass power plants have the capaci ty to accept the additional agricultural material, staff made the following ass umptions:

1. The average monthly burn tons per region (2007-2 009) will remain constant in future years.

2. The biomass facilities would burn 100% of agricu ltural materials received

each month.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-35 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Data presented in Table 7-7 indicates that the biom ass power plants in the Central SJVAB have a combined capacity ranging from 653,643 BDT/yr to 885,439 BDT/yr. Historical data shows that these f acilities have been operating at 590,401 BDT/yr. If the Central SJVAB biomass pl ants increase use of the boilers up to the potential capacity, as presented in Table 7-7, they could increase biomass fuel consumption by up to 295,038 BDT/yr. Divided into monthly increments, the biomass plants have the abi lity to increase fuel consumption by up to 24,586 BDT per month. Another option for biomass power plants would be to increase the percentage of agric ultural materials accepted and burned instead of increasing overall consumption an d energy production.

Data presented in Table 7-7 indicates that the biom ass power plants in the North SJVAB have a combined capacity ranging from 220,865 BDT/yr to 299,188 BDT/yr. Historical data shows that these facilitie s have been operating at 287,040 BDT/yr. If the North SJVAB biomass plants increase use of the boilers up to the potential capacity they could increase bi omass fuel consumption by up to 12,148 BDT/yr. Divided into monthly increments, the biomass plants have the ability to increase fuel consumption by 1,012 BDT p er month. Another option for biomass power plants would be to increase the perce ntage of agricultural materials accepted and burned instead of increasing overall consumption and energy production.

Data presented in Table 7-7 indicates that the biom ass power plants in the South SJVAB have a combined capacity ranging from 534,853 BDT/yr to 724,519 BDT/yr. Historical data shows that these facilitie s have been operating at 639,055 BDT/yr. If the South SJVAB biomass plants increase use of the boilers up to the potential capacity they could increase bi omass fuel consumption by up to 85,464 BDT/yr. Divided into monthly increments, the biomass plants have the ability to increase fuel consumption by 7,122 BDT p er month. Another option for biomass power plants would be to increase the perce ntage of agricultural materials accepted and burned instead of increasing overall consumption and energy production.

Fig Orchard Removal Decreasing allowed open burning of fig orchard remo val materials to <15 acres would generate an increase of 1,830 tons of agricul tural material throughout the SJVAB to the biomass plants per year. The followin g analysis was performed assuming the 1,830 tons of agricultural material fr om fig orchard removal would be forwarded to the biomass power plants. Because there are no historical burns in the South SJVAB for this crop category staff ass umes the additional tonnage would be sent to biomass power plants in the Centra l and North SJVAB.

Analysis, as illustrated in Figure 7-6, indicates t hat 51% of the fig orchard

removal burn tons occur in the Central SJVAB. Staf f assumes the burn acreage from this crop category above 15 acres is distribut ed throughout the SJVABSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-36 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning parallel to the total acreage from this crop catego ry. Therefore, staff applied the 51% to the 1,830 tons of material to determine the increase of agricultural material forwarded to the biomass plants (1,830 BDT x 0.51).

Staff estimate by reducing allowed burns of fig orc hard removals to <15 acres

results in an increase of 933 tons of material to b e forwarded to the biomass plants in the Central SJVAB per year. Therefore, s taff believes the biomass facilities have the capacity to accept the addition al agricultural biomass fuel generated by decreasing the allowed open burning of fig orchard removal

materials to <15 acres in the Central SJVAB.

Analysis, as illustrated in Figure 7-6, indicates t hat 49% of the fig orchard

removal burn tons occur in the North SJVAB. Staff assumes the burn acreage from this crop category above 15 acres is distribut ed throughout the SJVAB parallel to the total acreage from this crop catego ry. Therefore, staff applied the 49% to the 1,830 tons of material to determine the increase of agricultural material forwarded to the biomass plants (1830 BDT x 0.49).

Staff estimate by reducing allowed burns of fig orc hard removals to <15 acres

results in an increase of 897 tons of material to b e forwarded to the biomass plants in the North SJVAB per year. Therefore, sta ff believes the biomass facilities have the capacity to accept the addition al agricultural biomass fuel generated by decreasing the allowed open burning of fig orchard removal

materials to <15 acres in the SJVAB.

Less Than 20 Acre Orchard Removal Decreasing allowed open burning of orchard removals from <20 acres to <15 acres would generate an increase of 7,620 tons of a gricultural material throughout the SJVAB to the biomass plants per year

.

Analysis indicate that 46% of the <20 acre orchard removal burn tons occur in the Central SJVAB. Staff assumes the burn acreage from this crop category above 15 acres is distributed throughout the SJVAB parallel to the total acreage from this crop category. Therefore, staff applied the 46% to the 7,620 tons of material to determine the increase of agricultural material forwarded to the biomass plants. Staff estimate by reducing allowed burns of orchard removals

from <20 acres to <15 acres results in an increase of 3,505 tons of material to be forwarded to the biomass plants in the Central SJVA B per year.

Analysis indicate that 18% of the <20 acre orchard removal burn tons occur in the North SJVAB. Staff assumes the burn acreage fr om this crop category above 15 acres is distributed throughout the SJVAB parallel to the total acreage from this crop category. Therefore, staff applied the 18% to the 7,620 tons of material to determine the increase of agricultural material forwarded to the biomass plants. Staff estimate by reducing allowed burns of orchard removalsSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-37 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning from <20 acres to <15 acres results in an increase of 1,371 tons of material to be forwarded to the biomass plants in the North SJVAB per year.

Analysis indicate that 36% of the <20 acre orchard removal burn tons occur in the South SJVAB. Staff assumes the burn acreage fr om this crop category above 15 acres is distributed throughout the SJVAB parallel to the total acreage from this crop category. Therefore, staff applied the 36% to the 7,620 tons of material to determine the increase of agricultural material forwarded to the biomass plants. Staff estimate by reducing allowed burns of orchard removals

from <20 acres to <15 acres results in an increase of 2,744 tons of material to be forwarded to the biomass plants in the South SJVAB per year.

Based on the analysis presented above staff believe s the biomass power plants have the capacity to accept the additional tonnage of agricultural material generated by the reduction of allowed burns of orch ard removal materials from <20 acres to <15 acres in all three regions of the SJVAB.

Citrus Orchard Removal Assuming the total citrus orchard removal burn tons would be forwarded to the biomass power plants rather than be burned, this wo uld cause an increase of citrus orchard material to the biomass power plants of more than 54,000 tons per year. More specifically, in the peak citrus orchar d removal burn month of August, the quantity of agricultural material forwarded to the biomass power plants would increase by up to 4,120 tons in the Central SJVAB a nd by 6,442 tons in the

South SJVAB. This would be an increase that is abo ve and beyond what the power plants are currently accepting.

It is important to note citrus is a unique crop tha t faces unique challenges regarding biomass consumption. Biomass facilities consider citrus material to be the least desirable of all fuel types. Due to the stringy nature of the material, biomass power plants do not burn citrus material by itself. Rather, they blend it

with other biomass fuels. Citrus material is blend ed with other biomass fuels in ratios up to 25%.

Additionally, comments from the California Citrus M utual stated that not all biomass facilities accept citrus materials. Staff reviewed quarterly reports submitted to the District by the biomass plants, an d could only confirm definitively that two of the nine biomass plants in the SJVAB ac cepted citrus wood products in the past five years. The California Citrus Mutu al comments, mentioned a third biomass facility that accepts citrus wood material. Based on this information, staff can verify that three biomass facilities acce pt and use citrus material as biomass fuel. One facility is located in each regi on of the SJVAB. However, CBEA has indicated that all 12 biomass power plants have very broad acceptance policies for wood fuel, which include ci trus orchard and vineyard

removals.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-38 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Based on best available data at the time, staff has analyzed the capacity of the facility in the South SJVAB that staff can definiti vely verify accepts citrus material. In order to analyze a worst case scenario, this ana lysis is specific to the month of August, which is the peak burn month for citrus orc hard removal materials. The facility in the South SJVAB is known to blend up to 30% of citrus material into its fuel blend. This is the only facility in the SJVAB to blend at this high a level. This facility has advertised on it’s website that it has a rated capacity of 1,293 tpd of biomass fuel. The five-year historical data indica tes that the boilers at this facility are operational on an average of approximately 25 d ays per month of the third quarter of each year. District staff assumes the a verage of the historical data is indicative of future activities. Therefore, staff assumes this facility is operational 25 days for the month of August giving it a biomass fuel capacity of 32,325 tons.

For purposes of this analysis, staff conservatively estimated that the plant will use a fuel blend with 15% citrus material during al l hours of operation and will accept the corresponding amount of citrus material for storage, since a fuel blend using 30% of citrus material could vary by amount a nd availability of the material. Using the previously stated assumptions, staff esti mates the biomass plant could use 4,848 tons of citrus material in the month of A ugust. The five-year historical data indicates that this facility accepts an averag e of 24,265 tons of non-almond agricultural orchard material each August. Assumin g 15% of that orchard material is citrus orchard material, staff would as sume this plant is currently accepting 3,637 tons of citrus material each August . As previously stated, each August the South SJVAB biomass plant would see an i ncrease of 6,442 tons of

citrus orchard removal material in addition to what is currently being accepted.

Using the data above for the following analysis. E ach August, the plant has a capacity of 4,848 tons of citrus material, and is c urrently accepting about 3,637 tons of citrus material resulting in an available c apacity of 1,211 tons of additional citrus material. Meaning, there would be a surplus of 5,231 tons of citrus

material in the South SJVAB if citrus orchard remov al burning is prohibited.

According to CBEA, this biomass power plant current ly has the capacity to accept approximately 130,000 BDT of citrus annually , but only took in 34,000 BDT for the year of 2009. CBEA also stated that bi omass plants are seeking additional agricultural material at this time. The accepted 34,000 tons of citrus material for 2009 supports the staff analysis that the plant is accepting about 3,637 tons of citrus material each August. CBEA ha s also indicated that citrus handling and grinding practices have changed result ing in a wood product that may be used in higher percentages than in past year s. For example, Covanta Delano alone may now burn up to 100,000 Bone Dry To ns (BDT’s) of this fuel in any one year. Rio Bravo Fresno and Covanta Mendota are capable of burning up to 40,000 BDTs and 20,000 BDTs of citrus annually, respectively. It is important to note, however, that all these facilities receive d considerably less than 10,000

BDTs of citrus in 2009. All of the facilities continue to fall short of the ir goals forSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-39 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning more citrus orchard waste, where a number of plants continue to be extremely short of wood fuel and are currently curtailed or operati ng at reduced loads. The Biomass plants are in need of more fuel at this time. The District looks forward to working with the biomass industry to achieve long-term comm itments toward the extensive use of agricultural biomass.

7.2.3 Policies for Renewable Energy

The California Renewable Portfolio Standard (RPS) p rogram was established by Senate Bill 1078, effective January 1, 2003. It re quires that a retail seller of electricity such as Pacific Gas and Electric (PG&E) purchase a certain percentage of electricity generated by Eligible Ren ewable Energy Resources (ERR). Each utility is required to increase its to tal procurement of ERRs by at least 1% of annual retail sales per year so that 20 percent of its retail sales are supplied by ERRs by 2017.

The State’s Energy Action Plan (EAP) called for acc eleration of this RPS goal to reach 20 percent by 2010. This was reiterated agai n in the Order Instituting Rulemaking (R.04-04-026) issued on April 28, 2004, which encouraged the utilities to procure cost-effective renewable gener ation in excess of their RPS annual procurement targets (APTs), in order to make progress towards the goal expressed in the EAP. On September 26, 2006, Gover nor Schwarzenegger signed SB 107, which officially accelerates the Sta te’s RPS targets to 20 percent by 2010. The bill took effect on January 1, 2007.

According to CBEA, there are current developments i n increasing the requirement to 33%. The Governor’s Executive Order S-21-09, Septem ber 2009, directs the ARB, under its AB 32 authority, to adopt a regulation co nsistent with the 33 percent renewable energy target established in Executive Or der S-14-08 by July 31, 2010. The Legislature is also actively pursuing its own 3 3% RPS policy with SB 722 (Simitian). There is a high likelihood that one of these two policy making bodies will have enacted a 33% RPS standard into law by the end of this year.

ERRs include such sources as wind power, biogas, bi omass, geothermal, ocean, small hydro, solar thermal, and solar photovoltaic. Charts on the CPUC website

indicate that biomass is one of the smallest contri butors of ERR utilized by electric companies to meet the RPS standards.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-40 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Figure 7-10 Renewable Energy Capacity Currently Und er Contract

CPUC.ca.gov. Renewable Energy Capacity Currently Un der Contract from Contracts Signed Since 2002, by T ype and Vintage.

District staff explored the specific PPA contracts that PG&E currently has to

determine the distribution of ERRs in the SJVAB. B iomass power plants make up approximately 2% of PG&E’s RPS portfolio. The E RRs contracted with PG&E as a larger portion of the RPS portfolio include so lar thermal power (38%), solar photovoltaic power (23%), and wind power (26%).

According to CBEA, Biomass actually represents 30% of PG&E RPS existing RPS procurement portfolio, more than any other util ity in the State.

7.2.4 Contracts with Utilities

District’s staff’s analysis below was based on the nine biomass facilities in the

SJVAB and did not account for the three facilities located outside of the SJVAB at the time. Of those nine facilities, seven have contracts with investor owned utility (IOU) companies. District staff surveyed t he California Public Utilities Commission (CPUC) website and found the following f acilities have approved projects online as a part of the RPS program. Powe r Purchase Agreement (PPA) Contracts that were scheduled to terminate, p er contract agreement have been extended through additional terms with the uti lity companies. At the time of this report, staff was unable to confirm if the Del ano contract has also been

extended to more terms.

Renewable Energy Capacity Currently Under Contract from Contracts Signed Since 2002, by Type and Vintage (m inimum
MW)

0 1000 2000 3000 4000 5000 6000 7000 8000

w

ind biogas

b iom a s s

g e ot h erm a l ocean

s

m all h y d r o

so l a r therm a l

s o l a r photovoltaicCapacity (MW) New/Repower/Re-Start

ExistingSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-41 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Table 7-8 Approved Operational Projects for Contrac ts

Projects Approved and

Online Investor Owned Utility Min

Expected GWh/yr Contract

Term (years) Term

Number Online Date/

Contracted Delivery Date

AES Delano SDG&E 386 5 unknown 1/1/2003

Madera Power PG&E 160 5 2 7/9/2009

Dinuba Energy PG&E 90 5 3 7/9/2009

Sierra Power Corp. PG&E 75 5 3 7/9/2009

AES Delano SDG&E 365 10 1 1/1/2008

Global Common's Chowchilla PG&E 72 15 1 12/12/2008

Global Common's El Nido PG&E 72 15 1 2/21/2009

The table above indicates that at least six biomass power plants have PPA contracts with IOUs for up to fourteen yeas in the future. Historical data indicates that PG&E will continue to extend its five-year PPA s with Dinuba Energy and Sierra Power Corp, for as long as the RPS requires renewable energy to be a part of its portfolio.

Staff reviewed the CPUC web page regarding renewabl e energy capacity currently under contract for Pacific Gas and Electr ic. Based on information presented there it appears to staff that biomass fu el makes up a mere 2% of the total capacity of renewable energy capacity current ly under contract. Staff chose to review PG&E’s information because they are the p rimary utility company purchasing power from the SJVAB’s biomass power pla nts, as presented in Table 7-8 above. Other technologies PG&E have unde r contract for renewable energy include wind, biogas, geothermal, small hydr o, solar thermal and solar photovoltaic.

Table 7-9 shows additional information from CBEA fo r the 12 biomass power plants that use agricultural material in the SJVAB for fuel. According to CBEA, the 12 member biomass power plants generates over 2 40 MW of renewable capacity and are all under contract with California ’s investor owned utilities.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-42 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Table 7-9 Biomass Power Plants and Contracts

Facility Name Region

Served Contracting

Utility Contract

Length Online

Date

Rio Bravo Fresno Central

SJVAB PG&E 30 7/15/88

Covanta Mendoa Central

SJVAB PG&E 25 1/1/90

Community Recycling Madera

Power Central

SJVAB PG&E 10 6/1/01

Ampersand Chowchilla Central

SJVAB PG&E 15 12/12/08

Covanta Delano South SJVAB 10 1/1/08 Community Recycling Dinuba Energy South SJVAB PG&E 11 7/1/03

Sierra Power South SJVAB PG&E 15 2001 Ampersand Merced Power North SJVAB PG&E 15 12/12/08 Thermal Energy Tracy Power North SJVAB PG&E 30 3/31 /90 SPI Sonora North Valley Merchant n/a 1999 Covanta Chinese Station North Valley PG&E 30 1/31/ 87 SPI Lincoln North Valley PG&E 30 1985

Source: CBEA

7.2.5 Legislative Platform

On January 21, 2010, the District Governing Board a dopted the Districts 2010 Legislative Platform. On that Legislative Platform are two 2010 Legislative

Priorities that will affect biomass facilities. Th ese legislative priorities will provide policy guidance for legislative action and recogniz e the unique needs of the District during the upcoming legislative session. T he District supports legislation that will encourage, promote, and facilitate altern ative uses for agricultural

material.

7.2.5.1 Cost-Effective Alternatives to Agricultural Burning

The District has been phasing out agricultural burn ing based upon the schedule outlined in the CH&SC. State law specifies that if there are no economically feasible alternatives to burning, the burning can c ontinue. In implementing the latest phase of the CH&SC, District staff has analy zed the amount of agricultural material that are currently and has been historical ly accepted by the biomass power plants and other related information.

District staff released a Draft Feasibility Study o n Biomass Incentives in December 2008. In that study, District staff analy zed past incentive programs and determined that the programs appeared to be cos t-effective; however, there was no long-term incentive funding available to sup port this conclusion.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-43 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning 7.2.5.2 Energy

The District has identified energy efficiency and r enewable energy as part of its effort to attain air quality standards as expeditio usly as possible. When utilized properly, biomass to generate energy is a viable al ternative to open burning of these materials. The District supports policies an d initiatives that encourage renewable energy and energy efficiency including su pporting legislation that provides additional biomass capacity utilizing agri cultural materials.

7.2.6 New Facilities

There are currently four biomass facilities undergo ing the permitting process through the District. These biomass facilities are mentioned in this report for purposes of completeness of the report. The four p otential facilities are spread throughout the SJVAB as illustrated in the maps pre sented in Section 3.1 and again in Sections 7.1 and 7.2. Conversations with an operator from one of the potential biomass facilities in the North SJVAB rev ealed that the facility has no intention to accept agricultural materials from orc hard removals or prunings.

According to CBEA, there are additional Greenfield or new biomass plants under development, which includes San Joaquin Solar/Therm al Biomass, Modesto Bioenergy, and Buena Vista Biomass Power. These pl ants could require an additional 800,000 to 1,000,000 BDTs of wood fuel r esources within a two to five year development timeframe.

The California Biomass Energy Alliance (CBEA) also brought to the attention of District staff that there are several existing coal fired plants in the District that are undergoing conversions to co-fire up to 50% or conv ert to 100%. CBEA indicated that the three plants are Millenium Mt. P oso, Stockton AP Cogen, and

POSDEF. Staff researched the District database and confirmed that the Air Products plant has applied for an ATC to install an d operate an ag derived biomass fuel handling system with a max amount of b iomass to be received of 300 tons per day. According to CBEA, most of the fu el used in the three facilities mentioned above will be agricultural waste from the SJVAB.

At this time, staff will not include these faciliti es as an alternative option to open burning of agricultural materials. Future reports will reexamine if the new facilities will be a viable alternative to open bur ning and if they will increase the overall biomass capacities for agricultural fuel.

7.3 STATE AND FEDERAL COMMITMENTS FOR CONTINUED

OPERATION

Tax credits are available to biomass power plants, and five of the nine existing plants in the SJVAB are required to have agricultur al offsets. However, there areSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-44 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning no long-term federal or state funding commitments f or the biomass facilities in

the SJVAB.

District staff found that there are no long-term fe deral or state funding commitments for biomass power plants in place at th is time. Staff was successful in identifying one short-term federal pr ogram that is currently in place, one short-term state-funding program that is curren tly in place, and one shortterm program that is expired.

7.3.1 Renewable Electricity Production Tax Credit

The short-term federal program is called the Renewa ble Electricity Production Tax Credit (PTC). The PTC is a federal corporate t ax credit that provides a perkilowatt-hour (kWh) tax credit for electricity gene rated by qualified energy resources and sold by the taxpayer to an unrelated person during the taxable year. The PTC offers the tax credit for short peri ods and the in-service deadline to qualify for the tax credit is set to expire on D ecember 31, 2013.

The applicable sectors for the PTC tax credit are c ommercial and industrial using technologies such as wind, biomass, hydroelectric, geothermal electric, municipal solid waste, and hydrokinetic power among others. The tax credit amount is 2.1¢ for wind, geothermal, closed loop biomass, and 1.1¢ kWh for other eligible technologies. However, this tax credit is only ava ilable to a facility for the first ten years of operation.

Originally enacted in 1992 by the Energy Policy Act of 1992, the PTC has been renewed and expanded numerous times, the most recen t amendments being in February 2009. The tax credit amount is 1.5¢kWh in 1993 dollars (indexed for inflation) for some technologies and half that amou nt for others. The rules governing the PTC vary by resource and by facility type. In addition, the tax credit is reduced for projects that receive other f ederal tax credits, grants, taxexempt financing, or subsidized energy financing. Table 7-10 outlines two of the most important characteristics of the tax credit: t he in-service deadline and the credit amount as they apply to each type of biomass facility.

Table 7-10 In-Service Deadline and Credit Amount fo r PTC Resource Type In-Service Deadline Credit Amount
Closed-Loop Biomass December 31, 2013 2.1¢/kWh
Open-Loop Biomass December 31, 2013 1.1¢/kWh

The duration of the credit is generally, ten years after the date the facility begins service, however, there are two exceptions. (1) Op en-loop biomass, geothermal, small irrigation hydro, landfill gas and municipal solid waste combustion facilities placed into service after October 22, 2004, and bef ore enactment of the EnergySan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-45 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Policy Act of 2005, on August 8, 2005, are only eli gible for the credit for a fiveyear period. (2) Open-loop biomass facilities plac ed in service before October 22, 2004, are eligible for a five-year period begin ning January 1, 2005.

7.3.2 Existing Renewable Facilities Program

The Existing Renewable Facilities Program (ERFP) is a short-term state funding program. The California Energy Commission (CEC) ha s developed and currently administers renewable energy incentive programs, an d the ERFP is one of several program elements within the renewable energ y incentives program.

The ERFP was implemented to allocate state funds to increase the competitiveness of existing in-state renewable gene rating facilities and to help

achieve the California Renewable Portfolio Standard ’s (RPS) goal of 20% of retail electricity generated from renewables by 201 0.

ERFP eligible technologies include solid-fuel bioma ss, solar thermal electric, and wind power. Facilities must have commenced commerc ial operations as a renewable energy facility, consistent with the requ irements of the federal Public Utility Regulatory Policies Act of 1978 and Section 292.204, Subdivision (b), of Title 18 of the Code of Federal Regulations, on or before September 26, 1996. For the purpose of the ERFP, self-sustainability re fers to the ability of these facilities to continue operation without public fun ding by no later than December
31, 2011.

To qualify for ERFP funding, a facility’s electrica l generation must satisfy the following criteria:

• The energy must be generated after 1/1/07.

• The energy must be sold to customers within the St ate of California.

• The energy must not receive monthly energy payment s at a price equal to or greater than the applicable target price as determi ned by the Energy Commission for the entire year.

• Eligible generation is net-metered generation.

• The energy must not be sold to customers of local publicly owned electric

utilities.

• The energy must not receive incentive payments or funding from any other
state program.

In addition, the facility must be located either wi thin the state or near the state’s border with its first point of interconnection to t he transmission systems within the state. The facility must not be owned by an electr ical corporation or local publicly owned electric utility and must be certified by the CEC as eligible for payment, the generation must not be sold at an energy price that is above the applicable target price, or be used on-site.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-46 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning The existing renewable facilities are considered fo r incentives by the ERFP based on individual need and market price. Facilit ies receive funding based on production incentives (cent(s) per kWh). A target price and incentive cap is assigned to each facility based on need. If the ma rket price of energy of a facility drops below the target price, then the CEC will inc entivize the facility for each kilowatt-hour generated up to a maximum incentive c ap.

Funding tiers for facilities participating in the E RFP have been created and are based on the facility’s renewable energy resource t ype, average annual energy price or contract type, and utility power purchase contract under which the generation is sold.

Table 7-12 Existing Renewable Facilities Program Fu nding Tiers
Energy

Resource Average Annual Energy Price InvestorOwned Utility

Contract

Tier

1 Solar

Thermal

Electric Facilities with power purchase contracts receiving

fixed or variable monthly average energy prices for a majority of their generation at 4.0 cents/kWh or

less PG&E, SCE

and SDG&E

Tier

2 Biomass Facilities with power purchase contracts re ceiving

fixed or variable monthly average energy prices for a majority of their generation at 5.0 cents/kWh or

less PG&E and

Sierra Pacific

Power Company

Tier

3 Biomass Facilities with power purchase contracts re ceiving

fixed or variable monthly average energy prices for a majority of their generation at 5.0 cents/kWh or

less. SCE, SDG&E

Tier

4 Biomass and

Solar

Thermal

Electric Facilities with power purchase contracts receiving

variable monthly energy payments based on the short-run avoided cost (SRAC) or facilities with contracts receiving fixed monthly average energy prices for a majority of their generation greater than 5.0 cents/kWh but less than or equal to 6.5 cents/kWh or facilities receiving all-in prices. SCE, SDG&E

Tier

5 Biomass and

Solar

Thermal

Electric Facilities with power purchase contracts receiving

variable monthly energy payments based on the SRAC or facilities with contracts receiving fixed monthly average energy prices for a majority of their generation greater than 5.0 cents/kWh but less than or equal to 6.8 cents/kWh or facilities receiving all-in prices. PG&E and

Sierra Pacific

Power Company

The predetermined target prices and incentive caps for each tier are shown in the table below. The CEC may adjust the target prices and incentive caps, if appropriate, to reflect changing market and contrac tual conditions and to account

for inflation.San Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-47 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning Table 7-13 Existing Renewable Facilities Program Ta rget Prices Target Price Production Incentive Cap

Tier 1 6.2 cents/kWh 2.0 cents/kWh

Tier 2 6.5 cents/kWh 1.5 cents/kWh

Tier 3 6.2 cents/kWh 1.5 cents/kWh

Tier 4 6.2 cents/kWh 1.5 cents/kWh

Tier 5 6.5 cents/kWh 1.5 cents/kWh

The ERFP appropriates 20% of deposited funds into t he Renewable Resource Trust Fund per Senate Bill 1036. It is estimated t hat approximately $75 million would be allocated to the ERFP by the CEC for calen dar years 2007 through

2011.

7.3.3 Biomass-to-Energy Incentive Grant Program

The Biomass-to-Energy (BTE) Incentive Grant Program was a state funded program in operation from 2000 to 2003 that promote d the increased use of agricultural materials. The State allocated $6 to $7.7 million per year to qualified biomass power plant applicants. The BTE incentive program allocated about ten-dollars ($10) per ton for the qualified agricul tural biomass purchased by biomass power plants. District staff estimated tha t emissions reductions achieved from this program were over 5,200 tons of emissions in FY 2000/2001 and over 6,400 tons of emissions in FY 2001/2002. District staff believes that the Biomass-to-Energy incentive program provided a cost -effective alternative method for the growers and contributed to the incre ased use of agricultural

materials for biomass fuel.

One northern SJVAB biomass power plant, while parti cipating in the BTE incentive program, was burning 109,500 tons of agri cultural material, up from around 87,000 tons of agricultural material in 1999 before the beginning of the program. As of the December of 2008, the plant has dropped back down to about 83,000 tons burned; hovering around permit of fset requirements of 75- 85,000 tons of agricultural material. The graph be low demonstrates this shift from the end of the BTE incentive program in 2003 t o 2007. At full capacity, this biomass power plant could burn up to 115,000 tons o f agricultural material annually. There is a similar trend seen in a South ern SJVAB power plant that by permit is not required to offset emissions. At thi s facility agricultural material use went from 45,000 BDT burned in 2003 down to zero bu rned in 2008.

Under the BTE grant program the District saw a sign ificant increase in the quantity of agricultural materials burned. Before the program, from 1994-1999, an average of 483,000 tons of agricultural material s was burned in the SJVAB. In 2000, the average agricultural material use incr eased to 636,469 tons for the year. The second year of the program (2001) showed an even bigger increase inSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-48 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning agricultural materials burned with an average of 96 1,247 tons for the SJVAB with $7.7 million in funding.

Figure 7-11 further demonstrates this trend of more agricultural material consumed during the two years of the BTE. The figu re illustrates a four-year period; the third year only had partial funding.

Figure 7-11 Agricultural Biomass from 2000 to 2004

Morris, G., Biomass Energy Production in California 2006: Updat e of the California Biomass

Database , report of the Green Power Institute, December 200 6.

According to CBEA, the Biomass Crop Assistance Prog ram is also a short term incentive program, which was authorized by the 2008 Farm Bill. Under this program, owners of all types of agricultural materi al can receive a dollar-for-dollar matching payment for agricultural material sold to a Qualified Bioenergy Facility. This program is intended to be a direct payment to growers and chipping operators to encourage use of the material to produ ce bioenergy. This program

does not include biomass facilities. The BCAP went into effect toward the end of 2009 and is expected to continue funding for five y ears. California Ag Grant Fuel Programs

- 100 200 300 400 500 600 700 800 900 1,000

2000 2001 2002 2003 2004thousand BDT/yearSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

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7-49 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning 7.4 DISCUSSION

Biomass facilities have no firm commitment for how much agricultural materials they will accept in the future. The lower cost of urban versus agricultural fuel for biomass facilities, combined with the historical ov erview of fuel usage, creates uncertainty for staff about biomass operators willi ngness increase and maintain the use of agricultural materials in the future, pa rticularly when the construction industry recovers. Although there are regulations and policies in place for renewable energy use for the utility companies, the re are several other sources of renewable energy fuels besides biomass fuel that the utility companies are using. Therefore, there is no guarantee that bioma ss facilities will obtain and maintain contracts with utility companies to encour age continued and increased use of agricultural materials as a renewable fuel.

Biomass power plants are unlikely to increase agric ultural fuel usage to one hundred percent of their fuel usage. Historical da ta shows that the biomass plants accept more than fifty percent of the fuel f rom urban or other sources rather than from agricultural material suppliers. The recent decline in the construction industry has limited the amount of urb an fuel available from that industry and which may explain why biomass faciliti es have increased their intake of agricultural materials as fuel. When the construction industry recovers with the recovery of the economy, it is likely that the lower cost urban waste will again cause it to increase as a larger percent of t he biomass fuel source.

Renewable energy contracts between the biomass plan ts and utility companies exist but research was only able to find a few of t he biomass facilities have such

contracts. There are several other sources of rene wable energy, such as wind and solar power, available to the utility companies and they are taking full advantage of those opportunities. The deadline for utilities to meet the 20% requirement for renewable energy is 2010. The util ities are meeting this requirement with a mix of renewable energies. This makes the possibility of increased biomass production to meet increased dema nd from utilities uncertain,

at this time.

There are currently no long-term federal or state f unding commitments for biomass power plants. There are currently short-te rm state and federal commitments that are scheduled to expire within the next few years. Research indicates that the federal Renewable Energy Product ion Tax Credit program is set to expire in 2013, and the state Existing Renew able Facilities Program is set to expire in 2011. District staff is unaware of an y other Federal or State programs currently in place or in the planning stag es. Both of these programs indirectly subsidize the growers through reduce cos ts for chipping and hauling the agricultural materials instead of open burning. Given the narrow operating margin common to agricultural operations, loss of s uch subsidies could increase the removal costs for crops that are currently bann ed from open burning andSan Joaquin Valley Unified Air Pollution Control Di strict May 20, 2010

Revised July 21, 2010

7-50 Chapter 7: Biomass Power Plants Final Staff Report and Recommendations on Agricultural Burning those that are being considered for such a prohibit ion. Therefore, reliance on biomass facilities as a primary, long-term alternat ive method to open burning is not possible since there are no long-term federal o r state funding commitments

for the biomass facilities in the SJVAB.