Final Staff Report and 

Recommendations on Agricultural Burning 

Chapter 7 

Biomass Power Plants 
Final Staff Report and 

Recommendations on Agricultural Burning

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Chapter 7: BIOMASS POWER PLANTS

7.1 CURRENT BIOMASS POWER PLANTS 

Currently there are nine biomass power plants operating 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 12 biomass power plants that 

could accept agricultural materials in the SJVAB, District’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 District. District staff found that 

biomass facilities generally accept agricultural materials, forestry materials, and 

urban wood residues to be used as fuel for their boilers. Information from some 

biomass fuel buyers and operators indicate that biomass power plants will accept 

any clean and untreated organic material that is free of dirt and other unburnable 

contaminants like pressure treated and painted wood material. According to 

CBEA, several plants are now operating above 90% availability and many are in 

the mid to high 80 percent range, which is recognized in the industry as excellent 

performance. 

Although biomass power plant operations and facilities are unique, they do follow 

the same general process to produce electricity from biomass fuel. The following 

biomass process description is a generalized representation of the process the 

biomass facilities utilize. This description is an aggregate derived from several 

biomass power plant operational procedures and equipment. Again, it is 

important to note that this description is not of one particular facility, but a 

combination of several facilities to provide a general understanding of the 

processes biomass power plants use to produce electricity from biomass fuel. 

Trucks deliver the biomass fuel to the biomass power 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 the entire trailer is elevated to an 

angle such that the material free falls out the back 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 sizing system screens the fuel 

before delivery to metering bins. The enclosed conveyors are ventilated to fabric 

collectors. A large magnet removes magnetic materials and the non-metallic 

material passes to a hog screen and then to the fixed stacker. The material in 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

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the storage piles is mixed and fed to the boiler feed 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 returned 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 mechanical system in order to minimize 

fugitive dust emissions. After collection, the Flyash 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 for 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, injected with limestone for SOx 

control, and injected with sodium bicarbonate injection for corrosion control, 

before it is vented to a fabric filter dust collector. Alternatively, exhaust gases are 

controlled with Non-Selective Catalytic Reduction (NSCR) and an Electrostatic 

Precipitator (ESP) before discharging through a stack. 

All nine power plants in the SJVAB utilize both agricultural wood materials and 

non-agricultural materials as biomass fuel for their operations. Five of the nine 

facilities are required to have agricultural fuel offsets per permit conditions with 

the District. The table below illustrates the permitted mega watt (MW) output 

capacity at each facility and if the facility is required to have agricultural fuel 

offsets per permit conditions. 

Table 7-1 Facility Megawatt Capacity and Agricultural 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 actual NOx emissions from this boiler exceed 5,000 lbs, then 

agricultural offsets are required. If the quarterly NOx emissions from this boiler do not exceed 5,000 lbs, then 

agricultural offsets are not required. 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

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7.1.1 Locations 

District staff expects that prohibition of open burning of additional agricultural 

material would generate a substantial amount of agricultural material to be dealt 

with alternatively. A key question to ask is whether biomass power plants have 

the capacity to handle agricultural material that would otherwise be open burned. 

Other aspects of that question are: 1) are the power plants located near the 

crops and 2) are they distributed enough throughout the SJVAB so that they 

could effectively accept additional agricultural material as biomass fuel. The 

currently operating biomass plants are located in six of the eight counties within 

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

 Table 7-2 Facility Name and Location in the San Joaquin 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 SJVAB 

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 in 19 counties throughout 

California generating more than 650 MW of renewable electric power. CBEA has 

brought to the attention of District staff that there are three, biomass power plants 

located outside of the District boundaries that also accept agricultural materials 

from the SJVAB as fuel. The three plants identified by the CBEA are the 

Chinese Station power plant and Sierra Pacific Sonora 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 quarterly reports for these plants 

as to operating hours, or how much bone dry tons (BDT) per year they accept 

and burn or how much of the BDT used is agricultural material from the SJVAB. 

Therefore, these plants were not included in the analysis later in this chapter, or 

in other chapters of this report. 

To better illustrate the locations of the biomass power plants, staff have included 

a map, as Figure 7-1, on the next page. As illustrated in the map, the nine 

existing biomass power plants are located at various locations throughout the 
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SJVAB. The locations of the three biomass power plants 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 are currently undergoing the 

permitting process with the District and further discussed in Section 7.2.6. Not 

illustrated on the map on the following page are the two biomass power plants in 

Stockton that may potentially accept agricultural material 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 Plants 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

 Revised July 21, 2010 

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Recommendations on Agricultural Burning
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

 Revised July 21, 2010 

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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 changing. Upon reviewing 

District database information and snapshot data of biomass power plant activities 

provided by the Compliance Department, it appears the percentage of 

agricultural material accepted generally varies greatly; from as little as 0% of 

accepted fuel to as high as 70%. 

Biomass power plants accept urban waste materials and some forestry materials 

in addition to agricultural materials as fuel. Non-agricultural fuels include such 

materials as mill chips, cedar bark, forest slash/cull, hog fuel (mill residue), 

sawdust, construction wood waste, landfill derived wood, landscape tree 

trimmings, pallet/bin wood, and urban development clearing trees. Urban wood 

waste must contain less than 1% by weight of plastic, rubber, metals, roofing felt 

paper, and other non-wood contaminants other than dirt or ash. No asbestoscontaining materials are approved as fuel. 

SJVAB biomass power plants have very broad acceptance policies for 

agricultural wood fuel. This includes citrus and grape wood along with the other 

commonly accepted wood types. The limitation the biomass 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 removal 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 previous concerns regarding 

certain materials have been alleviated over the past few years as the operators 

have improved the methods in processing the materials to better suit the needs 

of the plant. For example, in the past citrus materials 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 and equipment deterioration 

due to temperature cycling. The operator also indicated that citrus wood ground 

to about 3-inch size screen poses minimal plugging problem. Now, due to 

considerable changes in the processing of the citrus 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 citrus chips with chips from 

other crops to promote better flow of the materials through the equipment. 

Conversations with biomass plant operators and comments from the California 

Citrus Mutual indicate that the biomass power plants that do accept citrus 

materials can blend up to 25% citrus chips with other biomass fuel for 

combustion. It is important to note however, that it is relatively more affordable 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

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for the biomass power plants to accept urban waste than agricultural materials 

because the residents of the community typically subsidize urban waste. 

The combined storage capacity for the biomass facilities 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 can vary. The primary factors 

affecting the amount of available storage are the amount of fuel previously 

received, and the tons of fuel stored per acre combined with the tons of fuel 

burned each day. Another source for uncertainty regarding the storage capacity 

of a facility is that the tons of material stored per acre could vary from one acre to 

the next. Conversations with biomass power plant operators indicated the 

amount of tons of material stored per acre varies by 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 when 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 actually 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 Covanta Delano alone is 

125,000 green tons. The total maximum storage capacity at all 12 facilities that 

use SJ Valley Ag Waste is 782,500 tons. Further, the 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 the 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 fuel 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 capabilities. For example, one 

northern District contractor regularly stores as much as 20,000 tons of agriculture 

waste at its truck re-load facility. 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

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Table 7-3 Fuel Storage Capacity for 12 Existing Biomass Plants That Use 

Ag Waste From SJVAD 

 Daily Fuel Maximum Fuel Storage Capacity 

Facility Name Region Served Use (GT) Acres Tons Days 

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 agricultural wood materials and 

non-agricultural materials in their operations. The power plants generate 

electricity by burning the biomass fuel in combustors or boilers to produce steam. 

The steam is used to spin turbines, which in turn generate electricity. 

District staff analyzed the historical fuel usage of 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 District 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 operation for five full years. 

For the analysis, staff made the following assumptions: 

1. For facilities with data from one or two quarters 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 agricultural fuel received. 

3. For facilities that only reported agricultural offset records, staff assumed the 

agricultural offsets burned is the total agricultural fuel burned. 
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4. For the two facilities in operation for less than five full years, staff assumed 

the average information for total time of operations to be equivalent to a fiveyear average. 

Facility A: Staff assumed the fuel usage by using data provided by the facility as 

a snapshot of activity (273 BDT/day) provided by the District Compliance 

Department. Staff applied this snapshot number to the total operating days for 

each quarter to estimate the total annual BDT burned. Staff assumed agricultural 

fuel by using data provided by the facility as a snapshot of activity (219 

BDT/day). Staff applied this snapshot number to the total operating days for 

each quarter to estimate the total agricultural fuel used. 

5. Facility B: Staff estimated the total annual BDT burned by assuming the 

facility operated at the high-end BDT capacity of 213,609 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). Agricultural fuel records 

were available. 

6. Facility C: This facility advertises on it’s website that it has a capacity of 1293 

tpd of BDT biomass fuel. For purposes of this analysis, staff assumed the 

plant is operational 365 days per year, giving it an annual fuel capacity of 

471,945 BDT (1,273 BDT/day x 365 days). Staff assumed 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 usage for this facility provided 

by the District Compliance department. The total BDT 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 burned 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 annual BDT fuel burned by 

assuming the snapshot data of BDT fuel burned and Fuel 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 total annual agricultural 

material fuel burned by assuming the snapshot data of BDT fuel burned (234 

BDT/day) and Fuel percentages provided by the Compliance department is 

indicative of the entire year. Staff multiplied the Snapshot data (234 

BDT/day) by the 5-year average operating days/year (347). The total annual 
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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 fuel usage of the biomass power 

plants to determine if the ratio of agricultural material to urban waste has varied 

due to the housing market boom and subsequent economic downturn. 

Presented in Table 7-4 is the average annual percentage of agricultural material 

burned at the biomass plants from the plants that reported the total BDT and 

agricultural material BDT in their quarterly reports. In 2008, the use of 

agricultural material at the biomass power plants was twenty-five percent of the 

total fuel used, in 2009 the use of agricultural materials increased to forty-three 

percent. Staff attributes this fluctuation in percentage of agricultural fuel used to 

the construction industry boom and the following economic 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 biomass plants had to turn away 

agricultural materials. During the fall of 2007, several biomass power plants in 

the District had to temporarily shut down plant operations due to equipment 

failures or maintenance purposes. In addition, some biomass power plants had 

to refuse chipping material because storage space was not available. Issues 

such as lack of storage space and equipment failure can create situations when 

the biomass power plant operators must turn away agricultural materials. This 

inability to guarantee that a facility can accept agricultural biomass at all times 

creates uncertainty in the ability of the biomass plants to accept increased 
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amounts of agricultural fuel that would be generated 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 improvements and refurbishments. 

One of the South Valley plants did an $18 million refurbishment of the plant in the 

third quarter of 2007, which lasted for several months. A Central SJVAB power 

plant invested over $14 million in refurbishing their 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 improved its operational availability 

by 20%. One North SJVAB plant has invested $4 million 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 possible 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 365 days per year, or 69% of 

the time. Staff evaluated the operating hours as reported to the District by the 

biomass power plants in the quarterly reports. Again, 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-year 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 District from the biomass power 

plants until June of 2010; therefore, an emission inventory 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. Additionally, 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. Staff substituted the 2009 emission 

inventory from this facility for the 2008 emission inventory. 

Table 7-5 2008 Emissions Inventory for SJVAB Biomass Facilities 

Pollutant VOC NOX PM10 SOX 

Emissions (tons per year) 48.34 567.16 191.26 101.18 
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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 only 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 emissions. 

Green House Gas Emissions 

As discussed in the CEQA analysis and report, Global 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 naturally and are emitted to the 

atmosphere through natural processes while others are 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 facilities as one of the feasible 

alternatives to open burning. The identified alternatives have the potential to 

result in changes in GHG emissions because of possible 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 open burning will not have a 

cumulative significant impact on global climate change. 

Potential Greenhouse Gas Impacts

Staff is exploring alternatives to the existing practice for disposing of orchard 

removal material by burning it in place (open burning). The alternative to open 

burning of orchard removal materials is chipping the organic matter and using the 

chipped material as fuel in a biomass plant to produce electricity. Sources of 

GHG emissions from this alternative include fuel consumed 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 electricity at the biomass facility. 

The alternative practice of burning chipped material in a biomass power plant 

would not result in an increase in GHG emissions compared to open burning the 

material. In fact, burning the material in a biomass plant would produce a net 

GHG benefit by producing electric power from a renewable source of energy 

rather than a fossil fuel. This concept is one of the strategies adopted by the 
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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 locations outside and within the 

San Joaquin Valley Air Basin. Use of locally produced fuel could reduce VMT 

associated with transporting materials, and thus result in a net GHG benefit. 

GHG emissions associated with chipping orchard removal material are expected 

to be offset by the benefits associated with displacing fossil fuels and reducing 

VMT. 

The District concludes, GHG emissions resulting from alternatives to open 

burning of orchard removal materials and prunings are expected to have a net 

positive benefit on global climatic change compared to the status quo of open 

burning. Therefore, the District concludes that implementation of the 

recommendations would have a less than cumulatively significant impact on 

global climatic change. For further discussion regarding GHGs please see the 

published CEQA analysis report. 

 

7.1.4.2 Emission Controls 

Although biomass power plant operations and facilities are unique, they do follow 

the same general process to reduce emissions from the processing of biomass 

fuel. The following is a description of methodologies and technologies the 

biomass facilities use, or could use, to reduce emissions. District staff 

researched information on solid fuel-fired boilers by examining the District’s 

Permit database, California Air Resources Board (ARB) Best Available Control 

Technology (BACT) Clearinghouse, other air districts’ BACT Clearinghouses. 

District staff also researched the United States Environmental Protection Agency 

(EPA) BACT Clearinghouse, European Commission Integrated Pollution 

Prevention and Control (IPPC) Best Available Techniques, other local air districts 

and other states’ regulations, and technical documents 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, pistachio 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 categories include municipal solid 

waste, biomass, and others. Each solid fuel is either 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 unsorted, 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 important 
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when considering the emission reduction effectiveness of an emission control 

technology. Unlike gaseous fuel-fired units, solid fuel-fired units present more 

difficult technological challenges in controlling NOx, 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 modifications (add-on 

controls). Typically, these control systems are successful 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 (N2) with 

oxygen (O2). NOx formed this way is referred to as “thermal NOx” and is 

considered a function of flame temperature and oxygen concentration. Studies 

of combustion processes indicate that significant amounts thermal NOx are 

formed when the flame temperature is above 2,300°F. 

Combustion Modification 

Combustion modification systems are designed to reduce thermal NOx formation 

by changing the flame characteristics to reduce peak flame temperature. 

Combustion controls include low excess air operation, staged combustion, over fire 

air ports, biased firing, and burners out of service. 

Combustion modification is also achieved by different 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 burners. 

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 combustion 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 to implement operational 

measure for reducing NOx emissions. By reducing the amount of oxygen 

available in the combustion zone to the minimum amount needed for complete 

combustion, fuel-bound nitrogen conversion and to the less extent thermal NOx 

formation are reduced. There is no additional energy required for low excess air 

firing, and if properly operated, no reduction in availability of the power plant 

should result from this type of emission control technique. 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 low amounts can also lead to 

high levels of carbon monoxide. The results of such changes can be a reduction 
San Joaquin Valley Unified Air Pollution Control District 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 creation of two divided combustion 

zones: a primary combustion zone with a lack of oxygen, and a secondary 

combustion zone with excess oxygen in order to ensure 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-stoichiometric condition in the primary 

combustion zone suppresses the conversion of fuel-bound nitrogen to NOx. In 

addition, the formation of thermal NOx is reduced to some extent by resulting 

lower peak flame temperature. In the secondary zone, 10-30% of the 

combustion air is injected above the combustion zone. Combustion is completed 

at this increased flame volume. Therefore, the relatively low-temperature 

secondary stage limits the production of thermal NOx. 

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

• Biased Burner Firing 

Biased burner firing is frequently used as a retrofit measure at existing 

installations (only for vertical boilers) as it does 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 frequently used as a retrofit 

measure at existing vertical boilers. The lower burners are operated 

under fuel-rich conditions, whereas the upper burners 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 has to be supplied to 

the unit with fewer operating burners. Therefore, this control technique is 

generally restricted to gas- or oil-fired combustion 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 inhibits NOx formation, 

the over fire air ensuring complete burn-out. Typically 15-30% of the total 
San Joaquin Valley Unified Air Pollution Control District 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 the 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 reduction of available oxygen in the 

combustion zone, and since it directly cools the flame, in a decrease of the flame 

temperature; therefore, both fuel-bound nitrogen conversion and thermal NOx 

formation are reduced. The recirculation of the flue gas into the combustion air 

has proven to be a successful method for NOx abatement in high temperature 

combustion systems such as wet bottom boilers and oil-or-gas-fired units. 

Reduced Air Preheat 

The combustion air preheat temperature has a significant impact on NOx 

formation mainly for gas and oil firing systems. For these fuels, the main part of 

NOx is determined by thermal NO mechanism, which depends on the 

combustion temperature. Reducing air preheat temperature results in lower 

flame temperatures (peak temperatures) in the combustion zone. There are two 

major drawbacks of this technology. First, in several 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 temperature results in a higher 

fuel consumption, since the higher portion of the thermal 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 energy conservation methods, 

such as increasing the size of the economizer. 

Fuel Staging 

Fuel staging (also called reburning) is based on the creation of different zones in 

the boiler by staged injection of fuel and air. The aim is to reduce back to 

nitrogen the nitrogen oxides that have already been formed. Reburning involves 

combustion in three zones. In the primary combustion zone, 80-85% of the fuel 

is burned in an oxidizing or slight reducing atmosphere. This primary burn-out 

zone is necessary in order to avoid the transfer of excess oxygen in the 

reburning zone, which would otherwise support possible NOx formation. In the 

second combustion zone (often called reburning zone), secondary or reburning 

fuel is injected in a reducing atmosphere. Hydrocarbon radicals are produced, 

reacting with the nitrogen oxides already formed in the primary zone; other 

unwanted volatile nitrogen compounds like ammonia are generated as well. In 

the third zone, the combustion completes through the addition of final air into the 

burn-out zone. Different fuels can serve as reburning fuel (pulverized coal, fuel 

oil, natural gas, etc.), but natural gas is generally used due to its inherent 

properties. 
San Joaquin Valley Unified Air Pollution Control District 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 reduce the peak flame 

temperature. LNBs retard the conversion of fuel-bound nitrogen to NOx and the 

formation of thermal NOx, while maintaining high combustion 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 requires, at least, the burners to be 

changed and installation of OFA. If existing burners 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 injected inert absorbs heat without 

reacting, thereby reducing peak flame temperature and reducing the potential for 

NOx formation. Water or steam injection reduces flame temperatures by using a 

portion of the flame’s heat to convert water from liquid 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 recirculation (FGR), about 10% to 

25% of the flue gas is siphoned off from the combustion exhaust stream to be 

used as combustion air for the burner. Since the flue gas has less oxygen than 

atmospheric air, the additional nitrogen in the flue gas acts as an inert 

component in the combustion process, reducing peak flame temperature. Flue 

gas recirculation may not be a feasible retrofit technology 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 at the flue gas temperatures 

of about 16000

F to 19000F. Ammonia or urea reacts with NOx in the flue gas to 

produce N2 and water. The reactions in the SNCR are due to the thermal 

decomposition of ammonia or urea and the subsequent NOx reduction. A 

simplified NOx reduction reaction in SNCR is shown below. 

Ammonia: 4NH3 + 4NO + O2 → 4N2 + 6H2O 

Urea: CO(NH2) 2 + 2NO +1/2O2 → 2N2 + CO2 + 2H2O 

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

amount of unreacted NH3 (ammonia slip) that will pass through the SNCR can 

significantly affect the efficiency of NOx reduction. At temperatures below the 

desired operating range, the reduction reactions diminish and ammonia slip 
San Joaquin Valley Unified Air Pollution Control District 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, NH3 is oxidized to NOx, which 

results in decreased NOx reduction efficiencies. 

An important factor to the performance of SNCR is the mixing of the reactant and 

the flue gas within the reaction zone. Design considerations include delivering 

the reagent in the proper temperature window, and allowing sufficient residence 

time of the reagent and flue gas in the proper temperature 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 (N2) and water. The overall SCR reactions are 

shown below. 

4NH3 + 4NO + O2 → 4N2 + 6 H2O 

8NH3 +4NO2 + O2 → 6N2 + 12H2O 

Flue gas temperature, SCR inlet NOx concentration, catalyst surface area, 

volume, and age of the catalyst, and acceptable amount of ammonia slip 

influence the performance of the SCR. The catalyst lowers the activation energy 

of the NOx decomposition reaction and allows NOx reduction to proceed at a 

lower temperature that is required by SNCR. Depending on the type of catalyst 

used, the optimal temperature range is typically between 6500F to 8000F. Below 

this temperature range ammonium sulfate can form which causes catalyst 

deactivation. Above the optimum temperature, the catalyst will sinter and rapidly 

deactivate. SCR is considered technological feasible for control of NOx from 

solid fuel-fired units. 

Regenerative Selective Catalytic Reduction (RSCR) 

The following information is an extract from a technical document published by 

Babcock Power Environmental: “RSCR is a regenerative 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 combination of two established 

and proven technologies: Regenerative Thermal Oxidizer (RTO) and SCR. By 

utilizing the direct contact regenerative heater technology (usually associated 

with an RTO, in which cycling beds of ceramic media used to transfer heat, the 

low temperature issue is resolved. NOx reduction takes place in SCR catalyst 

modules positioned above the heat transfer bed, where the flue gas has been 

heated to around 600o

F and the proper amount of ammonia has been added 

upstream of the canisters. Either anhydrous or aqueous ammonia can be used. 
San Joaquin Valley Unified Air Pollution Control District 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 where the gas temperatures are 

cool, typically 300oF to 400oF. In an RSCR, the temperature of the flue gas is 

temporarily elevated for optimal catalyst performance 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 tail-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 standard tail end solutions that 

typically achieve 70 to 75% efficiency. 

Hybrid Selective Reduction (HSR) 

HSR is a combination of SNCR and SCR that is designed to provide the 

performance of full SCR with significantly lower costs. In HSR, an SNCR is used 

to achieve some NOx reduction and to produce a controlled amount of ammonia 

slip that is used in a downstream in-duct SCR reactor for additional reduction. 

HSR has been demonstrated to reduce NOx emissions by 50% to 98% on a 320 

MMBtu/hr coal fired boiler; therefore, it is considered technologically feasible for 

control of NOx from solid-fuel fired boilers. Currently, the District has received an 

application for an operating permit for biomass fuel 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 lb/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 fuels, as well as byproducts of 

limestone injection, which accumulate to form particles. District staff reviewed 

the EPA BACT Clearinghouse to determine technologies to control PM emissions 

from solid fuel-fired units. PM control technologies that were listed in the 

database include electrostatic precipitators, fabric filter/baghouses, wet 

scrubbers, and mechanical separators. The PM and SOx control technologies 

and emission limits of the permitted units operating in the SJVAB are shown in 

the Table on the next page. It is important to note that one of the biomass power 

plants has two boilers and both are included in this list. As such, there are ten 

boilers listed here for the nine facilities. 
San Joaquin Valley Unified Air Pollution Control District 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% CO2

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% CO2

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% CO2

23 ppmv @ 3% 

O2

Biomass, construction 

wood waste, and urban 

wood waste 

315 Fabric Filter and 

lime and NAHCO3

0.045 lb/MMbtu 23 ppmv @ 3% 

O2

Biomass, construction 

wood waste, and urban 

wood waste 

317 Baghouse 0.010 gr/dscf @ 

12% CO2

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 electrical forces to move the particles 

out by flowing gas stream onto collector plate. The 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 particles 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 done by knocking them loose from 

the plates and allowing the collected layer to slide 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 configurations have been developed for 

special control action, and others have evolved for economic reasons. The types of 
San Joaquin Valley Unified Air Pollution Control District 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 precipitator, tubular precipitator, and twostage precipitator. 

Units using limestone injection in a dry scrubber for control of SOx rarely use ESPs 

because the use of flue gas desulfurization/baghouse 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 CaSO3), a large ESP plate area would be required to match the 

control efficiency of baghouses, which makes ESP more expensive than 

baghouses. 

Fabric Filter/Baghouse 

A fabric filter consists of one or more isolated compartments containing rows of filter 

bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particleladen gas passes up along the surface of the bags then 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 are cyclically operated, alternating 

between relatively long periods of filtering and short 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 responsible for such high efficiency. 

As the flue gas passes the filter cake additional SOx is removed. Gas 

temperatures up to about 500o

F with surges to about 550oF can be routinely 

accommodated in some configurations. Most of the energy used to operate the 

system appears as pressure drop across the bags and associated hardware and 

ducting. The primary disadvantage of baghouses compared to ESPs is the higherpressure drop across the baghouse resulting in increased 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 pollutants are removed primarily through 

impaction, diffusion, interception, and/or absorption of the pollutants onto droplets 

of liquid. Collection efficiencies for wet scrubbers vary with particle size and 

distribution of the waste stream. Generally, collection efficiency decreases as the 

particle size decreases. Collection efficiencies also 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 that none of the permitted solid fuelfired units in the SJVAB currently operates wet scrubbers. 

 
San Joaquin Valley Unified Air Pollution Control District 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 

SO2 is formed during the combustion process because of thermal oxidation of the 

sulfur contained in the fuel. A portion of the sulfur is further oxidized to SO3. At 

temperatures below approximately 600oF, sulfur trioxide readily combines with 

moisture in the flue gas or in the atmosphere to form sulfuric acid (H2SO4). These 

sulfur compounds are acidic and can be controlled using the same technology. 

SO2 and H2SO4 control technologies are discussed below. 

Dry Flue Gas Desulfurization 

The use of a dry flue gas desulfurization system such as lime spray drying followed 

by a baghouse has the potential to reduce Sox emissions by 75% to 90%. The 

lowest permitted SO2 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. The flue gas is humidified in the 

vessel to assist the adsorption reactions between lime 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 boilers. 

Wet Scrubber 

Wet scrubber is a one-through control technology where a reagent is slurried with 

water and sprayed into the flue gas stream in an absorber vessel. The SO2 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-products generated. The typical 

reagents used in this process are lime and limestone. 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 sulfite 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 most common wet scrubber 

application uses limestone as the reagent and forced oxidation of the reaction byproducts to form calcium sulfate. Wet scrubbers are 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 SO2 from the flue gas. The spent sorbet 

is regenerated to produce concentrated streams of SO2 or other sulfur compounds, 

which may be further processed to produce other products. This technology may 

require additional flue gas treatment prior to SO2 absorption process to remove 

other flue gas constituents such as hydrogen chloride and hydrogen fluoride that 
San Joaquin Valley Unified Air Pollution Control District 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. Sodium sulfite and ammonia-based 

technologies are commercially available and have control efficiencies ranging from 

90% to 95%. 

7.1.5 Economics – Agricultural Fuel vs. Urban Fuel 

In the SJVAB, several biomass power plants are required to burn agricultural 

material in order to offset emissions under permit with the District. Before this 

permit requirement, biomass power plants received agricultural material to burn 

for free. Today, however, selling agricultural material 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 typically propose an initial 

contract with growers to chip their orchard removal material. The contract is 

written prior to the job and establishes a tentative agreement, which includes an 

estimated cost for the removal, chipping and transportation 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 chipping orchard removals can vary 

due to the presiding condition of each contract that 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 plant, the biomass operators 

pay the chipper around $34.00 per BDT. Considering the availability of 

agricultural, forestry, and urban residues, it is relatively more affordable to accept 

urban residues at the biomass power plants. The Figure 7-2, diagrams the 

movement of money through a SJVAB biomass market. 
San Joaquin Valley Unified Air Pollution Control District 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 of 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 considerable price difference between 

the cost of urban fuels and agricultural fuels. Data throughout the state shows an 

average price difference of about $12 per BDT of fuel between urban fuel and 

agricultural fuel. Figure 7-3 diagrams the price difference between biomass fuel 

markets, showing a consistent gap between agricultural fuel and urban fuel. 
San Joaquin Valley Unified Air Pollution Control District 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 Category 

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

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: Update 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 illustrated by the Figure 7-4. 

Figure 7-4 California Biomass Fuels Market by Type of Fuel 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

-

500

1,000

1,500

2,000

2,500

3,000

thousand 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: Update of the California Biomass Database, report of the 

Green Power Institute, December 2006. 
San Joaquin Valley Unified Air Pollution Control District 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 Anticipate? 

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

Basin 
San Joaquin Valley Unified Air Pollution Control District 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 may possibly be prohibited from 

further open burning activities, three of those crops would most likely be sent to 

biomass facilities as an alternative to open burning. The three crops include fig 

orchard removal, <20 acre orchard removal reduced to <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 open burning. 

For purposes of this analysis, staff reviewed a three-year history of each crop 

and activities with those crops using the best available information from the 

District Smoke Management System (SMS). The reviewed information included 

the acreage and tonnage of material open burned. Staff averaged the three-year 

data to create an outlook as to crop and burn activities. Staff assumes the threeyear average to be indicative of future activities. 

Fig Orchard Removal 

Staff is recommending that fig orchard removals would be prohibited from open 

burning acreage greater than 15 acres. Staff assumes that the total annual 

tonnage of material previously burned at amounts greater than 15 acres will be 

sent to biomass facilities as fuel. 

The trend for the burning of fig orchard removal material appears to be from 

November through June in the North SJVAB and November through March in the 

Central SJVAB. There is no data indicating fig orchard removal burning in the 

South SJVAB for the three years averaged for this analysis. The Central SJVAB 

region peaked for fig orchard removal tons burned in 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 orchard removal material occurs in the 

late summer months and early fall months of July through 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 District 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 Distribution 

Average Monthly Fig Orchard Removal Burn Tons per 

Region (2007-2009)

0

200

400

600

800

1000

1200

1400

January

February

March

April

May

June

July

August

September

October

November

December

Month

Burn Tons

Central Valley 

North Valley 

To further analyze the quantity and location of fig orchard removal material 

burned the chart below illustrates the monthly average 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 tons 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

February

March

April

May

June

July

August

September

October

November

December

Month

Burn Tons

Fresno County 

Madera County 

Merced County 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

 Revised July 21, 2010 

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Final Staff Report and 

Recommendations on Agricultural Burning

For purposes of this analysis, staff assumes the fig 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 from the three years (2007-2009) 

to determine the average number of burns greater than 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 removal material that would be 

forwarded to the biomass plants per year for the entire SJVAB. 

<20 Acre Orchard Removal 

Staff analyzed the average monthly burning of <20 acre orchard removals to 

illustrate a comprehensive look at this crop category. The burning trends were 

calculated using a three-year average of the best available information from the 

District SMS. The trend for the burning of <20 acre orchard removal appears to 

occur throughout the year, through out the SJVAB with 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 material burned. The South 

SJVAB region peaks for <20 acre orchard removal burning in the month of 

October at 4,331 tons of material burned. While the North SJVAB peaks in 

December 3,531 tons of material burned. Figure 7-8 illustrates the average 

monthly <20 acre orchard removal burn ton distribution by region of the SJVAB. 

 

Figure 7-8 Average <20 Acre Orchard Removal Burn Distribution 

Average Monthly "<20 Acre Orchard Removal" Burn 

Tons by Region (2007-2009) 

0

1000

2000

3000

4000

5000

6000

7000

January 

February 

March 

April

May 

June

July 

August

September

October

November

December

Month 

Burn Tons

Central Valley 

North Valley 

South Valley 
San Joaquin Valley Unified Air Pollution Control District 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 feasible to reduce burning of orchard 

removals from <20 acres to <15 acres. Staff determined 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 acres to 20 acres. Staff did 

this by reviewing the SMS database for approved burn sizes and quantities for a 

three year average from 2007-2009. 

For purposes of this analysis, staff assumes the crops that were burned that 

were greater than 15 acres in size would continue to burn in the future, but at 15 

acres. Staff subtracted the 15 acres from each approved 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 would have been for 50 acres 

would be allowed to burn 15 acres in the future, leaving a difference of 35 acres 

that would no longer be allowed to burn and would be 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 average. 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 entire SJVAB. 

Citrus Orchard Removal 

Staff analyzed the average monthly burning of citrus orchard removals to 

illustrate a comprehensive look at this crop category. The burning trends were 

calculated using a three-year average of the best available 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 orchard 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 District 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 Burn Distribution 

Average Monthly Citrus Orchard Removal Burn Tons by Region 

(2007-2009) 

0

1000

2000

3000

4000

5000

6000

7000

January 

February 

March 

April

May 

June

July

August

September

October

November

December

Month

Burn Tons

Central Valley 

South Valley 

7.2.2 Could the Current Biomass Power Plants Physically 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 between 1,409,360 and 

1,909,141 bone dry tons (BDT’s) per year1

. 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 Biomass heat content 

value of 0.008805 MMBtu/lbm Higher Heating Value (HHV). The value 

is based on ultimate analysis from 1999 source testing (page 47 in a 

technical support document submitted with project S-1010053). Using 

the 1999 ultimate analysis, nitrogen was lower, heat 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 the 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 District 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 value is based on 

heat content values reported in the Phyllis database, the United States 

Department of Energy, Energy Efficiency and Renewable Energy 

(DOE/EERE) feedstock database, and selected literature sources. 

District staff acknowledges that the use of difference heat content values will 

result in differences, particularly when fuel rate capacity is calculated. The 

following table illustrates the calculations used to determine the lower and upper 

bound capacities of the facilities based. 

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

Power Lower Bound Upper Bound 

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 1999 source testing. Using the 1999 ultimate analysis, nitrogen was lower, heating value of the fuel was 

higher. This results in considerably less fuel being consumed with a higher yield of air flow. 

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

For purposes of determining if the biomass power plants have the capacity to 

accept the additional agricultural materials that would be generated by the 

prohibition of open burning of specific crops, District staff analyzed the 

agricultural material increase by region of the SJVAB rather than by county. To 

analyze if the biomass power plants have the capacity to accept the additional 

agricultural material, staff made the following assumptions: 

1. The average monthly burn tons per region (2007-2009) will remain 

constant in future years. 

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

each month. 
San Joaquin Valley Unified Air Pollution Control District 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 biomass 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 facilities have been operating 

at 590,401 BDT/yr. If the Central SJVAB biomass plants 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 ability 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 agricultural materials accepted and 

burned instead of increasing overall consumption and energy production. 

Data presented in Table 7-7 indicates that the biomass 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 facilities 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 biomass 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 per month. Another option for 

biomass power plants would be to increase the percentage of agricultural 

materials accepted and burned instead of increasing overall consumption and 

energy production. 

Data presented in Table 7-7 indicates that the biomass 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 facilities 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 biomass 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 per month. Another option for 

biomass power plants would be to increase the percentage of agricultural 

materials accepted and burned instead of increasing overall consumption and 

energy production. 

Fig Orchard Removal 

Decreasing allowed open burning of fig orchard removal materials to <15 acres 

would generate an increase of 1,830 tons of agricultural material throughout the 

SJVAB to the biomass plants per year. The following analysis was performed 

assuming the 1,830 tons of agricultural material from 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 assumes the additional tonnage 

would be sent to biomass power plants in the Central and North SJVAB. 

Analysis, as illustrated in Figure 7-6, indicates that 51% of the fig 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 
San Joaquin Valley Unified Air Pollution Control District 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 category. 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 orchard removals to <15 acres 

results in an increase of 933 tons of material to be forwarded to the biomass 

plants in the Central SJVAB per year. Therefore, staff believes the biomass 

facilities have the capacity to accept the additional 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 that 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 distributed throughout the SJVAB 

parallel to the total acreage from this crop category. 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 orchard removals to <15 acres 

results in an increase of 897 tons of material to be forwarded to the biomass 

plants in the North SJVAB per year. Therefore, staff believes the biomass 

facilities have the capacity to accept the additional 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 agricultural 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 SJVAB per year. 

Analysis indicate that 18% of the <20 acre orchard removal burn tons occur in 

the North 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 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 removals 
San Joaquin Valley Unified Air Pollution Control District 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 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 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 believes the biomass power plants 

have the capacity to accept the additional tonnage of agricultural material 

generated by the reduction of allowed burns of orchard 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 would 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 orchard 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 and by 6,442 tons in the 

South SJVAB. This would be an increase that is above and beyond what the 

power plants are currently accepting. 

It is important to note citrus is a unique crop that 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 blended with other biomass fuels in 

ratios up to 25%. 

Additionally, comments from the California Citrus Mutual stated that not all 

biomass facilities accept citrus materials. Staff reviewed quarterly reports 

submitted to the District by the biomass plants, and could only confirm definitively 

that two of the nine biomass plants in the SJVAB accepted citrus wood products 

in the past five years. The California Citrus Mutual comments, mentioned a third 

biomass facility that accepts citrus wood material. Based on this information, 

staff can verify that three biomass facilities accept and use citrus material as 

biomass fuel. One facility is located in each region of the SJVAB. However, 

CBEA has indicated that all 12 biomass power plants have very broad 

acceptance policies for wood fuel, which include citrus orchard and vineyard 

removals. 
San Joaquin Valley Unified Air Pollution Control District 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 definitively verify accepts citrus material. 

In order to analyze a worst case scenario, this analysis is specific to the month of 

August, which is the peak burn month for citrus orchard 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 indicates that the boilers at this facility 

are operational on an average of approximately 25 days per month of the third 

quarter of each year. District staff assumes the average 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 all 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 and availability of the material. 

Using the previously stated assumptions, staff estimates the biomass plant could 

use 4,848 tons of citrus material in the month of August. The five-year historical 

data indicates that this facility accepts an average of 24,265 tons of non-almond 

agricultural orchard material each August. Assuming 15% of that orchard 

material is citrus orchard material, staff would assume 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 increase 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. Each August, the plant has a 

capacity of 4,848 tons of citrus material, and is currently accepting about 3,637 

tons of citrus material resulting in an available capacity 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 removal burning is prohibited. 

According to CBEA, this biomass power plant currently 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 biomass 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 has also indicated that citrus 

handling and grinding practices have changed resulting in a wood product that 

may be used in higher percentages than in past years. For example, Covanta 

Delano alone may now burn up to 100,000 Bone Dry Tons (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 received considerably less than 10,000 

BDTs of citrus in 2009. All of the facilities continue to fall short of their goals for 
San Joaquin Valley Unified Air Pollution Control District 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 operating 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 commitments toward the extensive 

use of agricultural biomass.

7.2.3 Policies for Renewable Energy 

The California Renewable Portfolio Standard (RPS) program was established by 

Senate Bill 1078, effective January 1, 2003. It requires that a retail seller of 

electricity such as Pacific Gas and Electric (PG&E) purchase a certain 

percentage of electricity generated by Eligible Renewable Energy Resources 

(ERR). Each utility is required to increase its total 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 acceleration of this RPS goal to 

reach 20 percent by 2010. This was reiterated again in the Order Instituting 

Rulemaking (R.04-04-026) issued on April 28, 2004, which encouraged the 

utilities to procure cost-effective renewable generation 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, Governor Schwarzenegger 

signed SB 107, which officially accelerates the State’s RPS targets to 20 percent 

by 2010. The bill took effect on January 1, 2007. 

According to CBEA, there are current developments in increasing the requirement to 

33%. The Governor’s Executive Order S-21-09, September 2009, directs the ARB, 

under its AB 32 authority, to adopt a regulation consistent with the 33 percent 

renewable energy target established in Executive Order S-14-08 by July 31, 2010. 

The Legislature is also actively pursuing its own 33% 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, biomass, geothermal, ocean, 

small hydro, solar thermal, and solar photovoltaic. Charts on the CPUC website 

indicate that biomass is one of the smallest contributors of ERR utilized by 

electric companies to meet the RPS standards. 
San Joaquin Valley Unified Air Pollution Control District 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 Under Contract 

CPUC.ca.gov. Renewable Energy Capacity Currently Under Contract from Contracts Signed Since 2002, by Type and 

Vintage. 

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

determine the distribution of ERRs in the SJVAB. Biomass power plants make 

up approximately 2% of PG&E’s RPS portfolio. The ERRs contracted with PG&E 

as a larger portion of the RPS portfolio include solar 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 utility 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 the California Public Utilities 

Commission (CPUC) website and found the following facilities have approved 

projects online as a part of the RPS program. Power Purchase Agreement 

(PPA) Contracts that were scheduled to terminate, per contract agreement have 

been extended through additional terms with the utility companies. At the time of 

this report, staff was unable to confirm if the Delano contract has also been 

extended to more terms. 

Renewable Energy Capacity Currently Under Contract from 

Contracts Signed Since 2002, by Type and Vintage (minimum 

MW)

0

1000

2000

3000

4000

5000

6000

7000

8000

wind

biogas

biomass

geothermal

ocean

small hydro

solar thermal

solar photovoltaic

Capacity (MW)

New/Repower/Re-Start

Existing
San Joaquin Valley Unified Air Pollution Control District 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 Contracts 

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 PPAs 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 renewable energy capacity 

currently under contract for Pacific Gas and Electric. Based on information 

presented there it appears to staff that biomass fuel makes up a mere 2% of the 

total capacity of renewable energy capacity currently under contract. Staff chose 

to review PG&E’s information because they are the primary utility company 

purchasing power from the SJVAB’s biomass power plants, as presented in 

Table 7-8 above. Other technologies PG&E have under contract for renewable 

energy include wind, biogas, geothermal, small hydro, solar thermal and solar 

photovoltaic. 

Table 7-9 shows additional information from CBEA for 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 240 MW of renewable 

capacity and are all under contract with California’s investor owned utilities. 
San Joaquin Valley Unified Air Pollution Control District 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 adopted the Districts 2010 

Legislative Platform. On that Legislative Platform are two 2010 Legislative 

Priorities that will affect biomass facilities. These legislative priorities will provide 

policy guidance for legislative action and recognize the unique needs of the 

District during the upcoming legislative session. The District supports legislation 

that will encourage, promote, and facilitate alternative uses for agricultural 

material. 

7.2.5.1 Cost-Effective Alternatives to Agricultural Burning 

The District has been phasing out agricultural burning 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 continue. In implementing the 

latest phase of the CH&SC, District staff has analyzed the amount of agricultural 

material that are currently and has been historically accepted by the biomass 

power plants and other related information. 

District staff released a Draft Feasibility Study on Biomass Incentives in 

December 2008. In that study, District staff analyzed past incentive programs 

and determined that the programs appeared to be cost-effective; however, there 

was no long-term incentive funding available to support this conclusion. 
San Joaquin Valley Unified Air Pollution Control District 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 renewable energy as part of its 

effort to attain air quality standards as expeditiously as possible. When utilized 

properly, biomass to generate energy is a viable alternative to open burning of 

these materials. The District supports policies and initiatives that encourage 

renewable energy and energy efficiency including supporting legislation that 

provides additional biomass capacity utilizing agricultural materials. 

7.2.6 New Facilities 

There are currently four biomass facilities undergoing the permitting process 

through the District. These biomass facilities are mentioned in this report for 

purposes of completeness of the report. The four potential facilities are spread 

throughout the SJVAB as illustrated in the maps presented 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 revealed that the facility has no 

intention to accept agricultural materials from orchard removals or prunings. 

According to CBEA, there are additional Greenfield or new biomass plants under 

development, which includes San Joaquin Solar/Thermal Biomass, Modesto 

Bioenergy, and Buena Vista Biomass Power. These plants could require an 

additional 800,000 to 1,000,000 BDTs of wood fuel resources 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 convert to 100%. CBEA 

indicated that the three plants are Millenium Mt. Poso, Stockton AP Cogen, and 

POSDEF. Staff researched the District database and confirmed that the Air 

Products plant has applied for an ATC to install and operate an ag derived 

biomass fuel handling system with a max amount of biomass to be received of 

300 tons per day. According to CBEA, most of the fuel used in the three facilities 

mentioned above will be agricultural waste from the SJVAB. 

At this time, staff will not include these facilities 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 burning 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 agricultural offsets. However, there are 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

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7-44 Chapter 7: Biomass Power Plants 

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Recommendations on Agricultural Burning

no long-term federal or state funding commitments for the biomass facilities in 

the SJVAB. 

District staff found that there are no long-term federal or state funding 

commitments for biomass power plants in place at this time. Staff was 

successful in identifying one short-term federal program that is currently in place, 

one short-term state-funding program that is currently 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 Renewable Electricity Production 

Tax Credit (PTC). The PTC is a federal corporate tax credit that provides a perkilowatt-hour (kWh) tax credit for electricity generated 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 periods and the in-service deadline 

to qualify for the tax credit is set to expire on December 31, 2013. 

The applicable sectors for the PTC tax credit are commercial 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 available 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 recent 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 amount 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 federal tax credits, grants, taxexempt financing, or subsidized energy financing. Table 7-10 outlines two of the 

most important characteristics of the tax credit: the 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 for 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) Open-loop biomass, geothermal, 

small irrigation hydro, landfill gas and municipal solid waste combustion facilities 

placed into service after October 22, 2004, and before enactment of the Energy 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

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7-45 Chapter 7: Biomass Power Plants 

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Policy Act of 2005, on August 8, 2005, are only eligible for the credit for a fiveyear period. (2) Open-loop biomass facilities placed in service before October 

22, 2004, are eligible for a five-year period beginning 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) has developed and currently 

administers renewable energy incentive programs, and the ERFP is one of 

several program elements within the renewable energy incentives program. 

The ERFP was implemented to allocate state funds to increase the 

competitiveness of existing in-state renewable generating facilities and to help 

achieve the California Renewable Portfolio Standard’s (RPS) goal of 20% of 

retail electricity generated from renewables by 2010. 

ERFP eligible technologies include solid-fuel biomass, solar thermal electric, and 

wind power. Facilities must have commenced commercial operations as a 

renewable energy facility, consistent with the requirements 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 refers to the ability of these 

facilities to continue operation without public funding by no later than December 

31, 2011. 

To qualify for ERFP funding, a facility’s electrical generation must satisfy the 

following criteria: 

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

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

• The energy must not receive monthly energy payments at a price equal to or 

greater than the applicable target price as determined 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 within the state or near the state’s 

border with its first point of interconnection to the transmission systems within the 

state. The facility must not be owned by an electrical 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 District May 20, 2010 

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The existing renewable facilities are considered for incentives by the ERFP 

based on individual need and market price. Facilities 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 market price of energy of a facility 

drops below the target price, then the CEC will incentivize the facility for each 

kilowatt-hour generated up to a maximum incentive cap. 

Funding tiers for facilities participating in the ERFP have been created and are 

based on the facility’s renewable energy resource type, 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 Funding 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 receiving 

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 receiving 

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 contractual conditions and to account 

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

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Recommendations on Agricultural Burning

Table 7-13 Existing Renewable Facilities Program Target 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 the Renewable Resource 

Trust Fund per Senate Bill 1036. It is estimated that approximately $75 million 

would be allocated to the ERFP by the CEC for calendar 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 promoted 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 agricultural biomass purchased by 

biomass power plants. District staff estimated that 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 increased use of agricultural 

materials for biomass fuel. 

One northern SJVAB biomass power plant, while participating in the BTE 

incentive program, was burning 109,500 tons of agricultural 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 offset requirements of 75-

85,000 tons of agricultural material. The graph below demonstrates this shift 

from the end of the BTE incentive program in 2003 to 2007. At full capacity, this 

biomass power plant could burn up to 115,000 tons of agricultural material 

annually. There is a similar trend seen in a Southern SJVAB power plant that by 

permit is not required to offset emissions. At this facility agricultural material use 

went from 45,000 BDT burned in 2003 down to zero burned in 2008. 

Under the BTE grant program the District saw a significant increase in the 

quantity of agricultural materials burned. Before the program, from 1994-1999, 

an average of 483,000 tons of agricultural materials was burned in the SJVAB. 

In 2000, the average agricultural material use increased to 636,469 tons for the 

year. The second year of the program (2001) showed an even bigger increase in 
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

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agricultural materials burned with an average of 961,247 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 figure 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: Update of the California Biomass 

Database, report of the Green Power Institute, December 2006. 

According to CBEA, the Biomass Crop Assistance Program is also a short term 

incentive program, which was authorized by the 2008 Farm Bill. Under this 

program, owners of all types of agricultural material 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 produce 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 years. 

California Ag Grant Fuel Programs

-

100

200

300

400

500

600

700

800

900

1,000

2000 2001 2002 2003 2004

thousand BDT/year
San Joaquin Valley Unified Air Pollution Control District May 20, 2010 

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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 overview of fuel usage, creates 

uncertainty for staff about biomass operators willingness increase and maintain 

the use of agricultural materials in the future, particularly when the construction 

industry recovers. Although there are regulations and policies in place for 

renewable energy use for the utility companies, there are several other sources 

of renewable energy fuels besides biomass fuel that the utility companies are 

using. Therefore, there is no guarantee that biomass facilities will obtain and 

maintain contracts with utility companies to encourage continued and increased 

use of agricultural materials as a renewable fuel. 

Biomass power plants are unlikely to increase agricultural fuel usage to one 

hundred percent of their fuel usage. Historical data shows that the biomass 

plants accept more than fifty percent of the fuel from urban or other sources 

rather than from agricultural material suppliers. The recent decline in the 

construction industry has limited the amount of urban fuel available from that 

industry and which may explain why biomass facilities 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 the biomass fuel source. 

Renewable energy contracts between the biomass plants and utility companies 

exist but research was only able to find a few of the biomass facilities have such 

contracts. There are several other sources of renewable 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 utilities are meeting this 

requirement with a mix of renewable energies. This makes the possibility of 

increased biomass production to meet increased demand from utilities uncertain, 

at this time. 

There are currently no long-term federal or state funding commitments for 

biomass power plants. There are currently short-term state and federal 

commitments that are scheduled to expire within the next few years. Research 

indicates that the federal Renewable Energy Production Tax Credit program is 

set to expire in 2013, and the state Existing Renewable Facilities Program is set 

to expire in 2011. District staff is unaware of any other Federal or State 

programs currently in place or in the planning stages. Both of these programs 

indirectly subsidize the growers through reduce costs for chipping and hauling 

the agricultural materials instead of open burning. Given the narrow operating 

margin common to agricultural operations, loss of such subsidies could increase 

the removal costs for crops that are currently banned from open burning and 
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those that are being considered for such a prohibition. Therefore, reliance on 

biomass facilities as a primary, long-term alternative method to open burning is 

not possible since there are no long-term federal or state funding commitments 

for the biomass facilities in the SJVAB.