Name:

Title:

Company:

Sign Date:

Name:

Title:

Company:

Sign Date:

Permitted Facility Representative / Date Testing Company Representative / Date

Final Test Report 

for

/ /

Based on information and belief formed 

after reasonable inquiry, I certify that the 

statements and information in this test 

report are true, accurate, and complete.

I have reviewed all testing details and 

results in this test report and hereby 

certify that the test report is authentic 

and accurate.

Monday, January 31, 2011 Page 1 of 14
Facility Information:

Optim Energy LP, Twin Oaks

13065 Plant Road

Bremond TX 76229

Contact: Eddy Young

Phone: (254) 746-7604

Fax: (254) 746-7159

Email: eddy.young@optimenergy.com

Testing Company:

METCO Environmental

3226 Commander Dr.

Carrollton TX 75006

Contact: Ned Shappley

Phone: 972-931-7127

Fax: 931-931-8398

Email: shappley@metcoenv.com

Air Permit Number:

17294

Permitted Source ID/Name:

EPN 1 - 1 Unit Number 1

Permitted Maximum Process Rate:

N/A

Max. Normal Operation Process Rate:

N/A

Target Process Test Rate

N/A

Description of the source (including control equipment). Please see the attachments for source or

 process flow diagram:

Twin Oaks (TO) is a two-unit 305MW, lignite-fired plant completed in 1991. The plant utilizes circulating fluidized 

bed (CFB) technology to produce electricity with minimum emissions. Each of the CFB boilers is rated at 1,025,254 

pounds of steam per hour at 1815 psia and 1005 degrees F. The boilers are controlled circulation reheat units with 

three 50% capacity KSB wet stator boiler circulating pumps. Each unit has two 60% capacity primary and secondary 

air fans to provide combustion air. Two 60% capacity variable speed induced draft fans pull flue gas from the fabric 

filter system and discharge to the 330-foot concrete stack for each unit. 

Each boiler has four refractory-lined cyclones arranged in parallel between the combustor and the convective 

backpass. Particulates collected in the cyclones drop into standpipes and are conveyed through fluidized loop seals 

back to the combustor. A portion of the solids passing through the loop seals is drawn off through Spiess valves to 

the fluidized bed heat exchangers (FBHE’s) on each boiler. The FBHE’s are water cooled bubbling bed units 

fluidized with high-pressure blowers. On each boiler, the front FBHE contains the finishing superheater and 

evaporator sections while the rear FBHE contains the middle temperature superheater and finishing reheater 

assemblies. 

Each unit has one steam turbine designed to produce a gross output of 160,082 kw at 2.5 inches of mercury (absolute) 

back pressure and rated conditions of 1,025,000 lbs. /hr. of steam at 1815 psia and 1005 degrees F. The steam 

turbines are also designed to operate at 5% overpressure with a maximum steam flow of 1,100,000 lbs. /hr. However, 

the maximum steam flow rating is reached at approximately 2.5% overpressure at high back pressures of 

approximately 3.5 in. Hg. High-pressure feedwater heater shell safety valve settings also limit operations to the 2.5% 

overpressure condition. 

Industry/SCC/NAIS 221112 AFS #: 483956E002 FRS #: 110015666144

SCC / Description 10100318 External Combustion Boilers - Electric Generation - Lignite - Atmospheric 

Fluidized Bed Combustion - Circulating Bed 

The following state and federal regulations that apply to the proposed testing:

Monday, January 31, 2011 Page 2 of 14
The condensate feedwater circuit on each unit is equipped with two 100% capacity variable speed condensate pumps, 

two 60% capacity variable speed boiler feed pumps, three low-pressure heaters, one deaerating heater, and two high 

pressure feedwater heaters. Each unit has a five-cell concrete cooling tower (10 deg. F. design wet-bulb approach) 

with two 100% capacity circulating water pumps. The plant has three ground water wells with a capacity of 2,500 

gpm each. The plant also has a 16.5 million gallon storage pond that can supply make-up water requirements for 4 1⁄2 

days. 

Lignite from the Walnut Creek mine is delivered by truck from the mine, located a few miles from the plant to a 

delivery hopper at the plant or to an adjacent lignite storage pile. Ownership of the lignite transfers to TO just past 

the delivery hopper. From the hopper, lignite can be conveyed directly to the plant, placed in a covered 25,000 ton 

live storage building, or conveyed to a dead storage area. Approximately four days of lignite is typically maintained 

in the covered storage that is served by a Krupp stacker-reclaimer. A covered dead storage area of 25,000 tons was 

added in August, 2008. Crushed lignite is transported via conveyors to four 250-ton coal silos per unit which 

provides approximately four hours of fuel at full load. 

Natural gas from a 24 inch high pressure pipeline located approximately 5 1⁄2 miles from the plant is supplied to the 

plant via a 16 inch pipeline owned by TO. The capacity of the pipeline is 150MMCFD to the plant which should 

provide enough fuel for full load operation. 

Limestone, which is used to reduce emissions of sulfur dioxide (S02), is currently delivered by truck from local 

suppliers. A rail spur into the plant is also available for limestone delivery. Limestone is transported to the top of the 

pulverizers by variable speed feeders. Pulverized limestone is stored in two storage silos for each unit. 

Limestone kiln dust (LKD), which is also used to reduce emissions of sulfur dioxide (SO2), is currently delivered by 

pneumatic truck from local suppliers. LKD is transported to one silo per unit via blowers. The material is blown into 

the boiler on each corner near the fuel injection ports.

Anhydrous ammonia, which is used to reduce emissions of nitrogen oxides (NOx), is currently delivered by truck 

from local suppliers. The ammonia is stored in two 12,000 gallon tanks. It is distributed into 16 injection lances per 

unit (4 per cyclone inlet). 

Part of the secondary air is routed to 18 Rotating Opposed Fire Air (ROFA) nozzles to mix combustion gases. ROFA 

improves the removal efficiency of SO2 and NOx by generating a turbulent cyclonic effect in the boiler. 

The plant produces approximately 300,000 tons per year of fly ash and 100,000 tons per year of bed ash. Headwaters 

(ISG) market the ash for TOP. The CFB ash that is produced from burning Texas lignite is not the typical class F ash 

produced by other lignite fired plants in the state. Because of the limestone injection, the ash properties are changed 

so much that the ash is classified “Class C modified” and is marketed as soil stabilization material. 

Each hydrogen-cooled generator (rated at 194MVA and 18kV) is connected to a step-up transformer (18/345kV) 

which is connected to the transmission system through two switchyard breakers. Either of these two breakers must be 

used to synchronize the unit. Each step-up transformer also has a motor operated disconnect switch within the 

switchyard, which cannot be used for synchronization but may be used to isolate the unit for maintenance. A double 

circuit 345 kV transmission line connects the plant switchyard to the Texas Utilities Twin Oak substation, located 

approximately 18 miles from the plant. This transmission system gives the plant a total transmission capacity of 

1,200 MW at an N-1 condition (one circuit out of service).

Sampling Location Information:

Test Parameter Information:

Location

Round

Duct

Diam.

Distance from 

upstream dist.

Distance from

downstream dist.

Number of

Traverse Ports

Equiv. 

Diam

Min.Travers 

Points

Rect. Duct 

Length /Width

Stack Exit 144 0 0 144 2328 1164 4 12

Target

Parameter 

Test

Method

Number of

Test Runs

Test Run

Duration

Sample 

Location Points Comments

Monday, January 31, 2011 Page 3 of 14
The following describes any modifications and/or deviations to the applicable test 

methods. If alternative methods were requested, see the attachments for documentation 

of request AND approval, including dates.

NA

Target

Parameter 

Test

Method

Number of

Test Runs

Test Run

Duration

Sample 

Location Points Comments

Stack Exit Carbon Monoxide Method 10 3 120 0

Total organic compounds 

(TOC) as Propane

Stack Exit Method 25A 3 120 0

Stack Exit O2 Method 3A O2 3 120 0

Stack Exit Co2 Method 3A CO2 3 120 0

Monday, January 31, 2011 Page 4 of 14
Sampling / Stack Data Results Summary

Location Stack Exit - Method 10

Average

Run Number 1 2 3

Test Date 4/27/2010 4/27/2010 4/27/2010

Run Start Time 9:15:00 AM 12:15:00 

PM

3:05:00 PM

Run Finish Time 11:29:00 AM 2:31:00 PM 5:24:00 PM

Carbon Dioxide, % 14.11 13.99 14.09 14.063

Oxygen, % 5.44 5.09 5.42 5.317

Dry Volumetric Flow Rate, dry scfm 395682 402127 400662 399,490.333

F-Factor, dscfm/MMBtu @ %O2 9860 9860 9860 9,860.000

Moisture, % 13.04 13.83 13.33 13.400

Fuel Type Coal - 

Lignite

Coal - 

Lignite

Coal - 

Lignite

Fw 11950 11950 11950 11,950.000

Fc 1910 1910 1910 1,910.000

Location Stack Exit - Method 25A

Average

Run Number

Test Date

Run Start Time

Run Finish Time

Carbon Dioxide, %

Oxygen, %

Dry Volumetric Flow Rate, dry scfm

F-Factor, dscfm/MMBtu @ %O2

Moisture, %

Fuel Type

Fw

Fc

Monday, January 31, 2011 Page 5 of 14
Location Stack Exit - Method 3A CO2

Average

Run Number

Test Date

Run Start Time

Run Finish Time

Carbon Dioxide, %

Oxygen, %

Dry Volumetric Flow Rate, dry scfm

F-Factor, dscfm/MMBtu @ %O2

Moisture, %

Fuel Type

Fw

Fc

Location Stack Exit - Method 3A O2

Average

Run Number

Test Date

Run Start Time

Run Finish Time

Carbon Dioxide, %

Oxygen, %

Dry Volumetric Flow Rate, dry scfm

F-Factor, dscfm/MMBtu @ %O2

Moisture, %

Fuel Type

Fw

Fc

Monday, January 31, 2011 Page 6 of 14
Emissions Summary

Process Run Data

Location: Stack Exit - Method 10

Compound: Carbon Monoxide

Average

Run 1 2 3

Elb/hr 1.58E+01 1.53E+01 1.56E+01 15.567

lb/mmBtuO2 8.85E-03 8.29E-03 8.64E-03 0.009

ppm 9.13E+00 8.75E+00 8.93E+00 8.937

ppm@7%O2 8.21E+00 7.69E+00 8.02E+00 7.973

Location: Stack Exit - Method 25A

Compound: Total organic compounds (TOC) as 

Average

Run 1 2 3

Elb/hr 2.51E-01 9.55E-02 4.12E-01 0.253

lb/mmBtuO2 1.41E-04 5.16E-05 2.28E-04 0.000

ppm 9.24E-02 3.46E-02 1.50E-01 0.092

ppm@7%O2 8.31E-02 3.04E-02 1.35E-01 0.083

Monday, January 31, 2011 Page 7 of 14
Process Run Data

Run Name Value UOM Comments

Target

Value

1 Lignite Burned 136.3 Tons 0

2 Lignite Burned 0 Tons 0

3 Lignite Burned 0 Tons 0

1 Average Heat Input 1794.6 MMBtu/hr 0

2 Average Heat Input 0 MMBtu/hr 0

3 Average Heat Input 0 MMBtu/hr 0

1 Steam Output 1089 1000 lb steam/hr 0

2 Steam Output 0 1000 lb steam/hr 0

3 Steam Output 0 1000 lb steam/hr 0

1 Flue Gas Flow Rate 395682 0

1 Flue Gas Oxygen Content 5.44 % 0

1 Flue Gas Carbon Dioxide Content 14.11 % 0

1 Flue Gas Moisture Content 13.04 % 0

1 Flue Gas Sampling Point Temperature 341 Deg F 0

1 Flue Gas Pressure 0.984 atm 0

1 Standard Pressure 1 atm 0

1 Standard Temperature 68 Deg F 0

1 Unit Gross Electrical Output 172.9 Mwe 0

1 Unit Net Electric Generation 153.5 MWh 0

4 Lignite Burned 136.9 Tons 0 Run 2 Unit 1

4 Average Heat Input 1803 MMBtu/hr 0

4 Steam Output 1097.4 1000 lb steam/hr 0

4 Flue Gas Flow Rate 402127 0

4 Flue Gas Oxygen Content 5.09 % 0

4 Flue Gas Carbon Dioxide Content 13.99 % 0

4 Flue Gas Moisture Content 13.83 % 0

4 Flue Gas Sampling Point Temperature 348 Deg F 0

4 Flue Gas Pressure 0.98 atm 0

4 Standard Pressure 1 atm 0

4 Standard Temperature 68 Deg F 0

4 Unit Gross Electrical Output 174 Mwe 0

4 Unit Net Electric Generation 155.1 MWh 0

5 Lignite Burned 134.3 Tons 0 Run 3 Unit 1

Monday, January 31, 2011 Page 8 of 14
APCD Run Data

Process Lab Run Data

5 Average Heat Input 1768.3 MMBtu/hr 0

5 Steam Output 1097.5 1000 lb steam/hr 0

5 Flue Gas Flow Rate 400662 0

5 Flue Gas Oxygen Content 5.42 % 0

5 Flue Gas Carbon Dioxide Content 14.09 % 0

5 Flue Gas Moisture Content 13.33 % 0

5 Flue Gas Sampling Point Temperature 344 Deg F 0

5 Flue Gas Pressure 0.983 atm 0

5 Standard Pressure 1 atm 0

5 Standard Temperature 68 Deg F 0

5 Unit Gross Electrical Output 174 Mwe 0

5 Unit Net Electric Generation 155.1 MWh 0

Run Name Value UOM Comments

Target

Value

1 DRY LIMESTONE INJECTION 0 0

1 BAGHOUSE 0 0

1 NSCR (NON-SELECTIVE CATALYTIC 

REDUCTION)

0 0

Run Name Value UOM Comments

1 Fuel Higher Heating Value 9164 Btu/lb

1 Fuel Moisture 29.19 %

1 Fuel Mercury Content 0.27 ppm

1 Fuel Cadmium Content 0.4 ppm

1 Fuel Nickel Content 10 ppm

1 Fuel Arsenic Content 2 ppm

1 Fuel Chromium Content 17 ppm

1 Fuel Beryllium Content 1.5 ppm

1 Fuel Lead Content 7 ppm

1 Fuel Manganese Content 163 ppm

1 Fuel Chlorine Content 41 ppm

1 Fuel Fluorine Content 77 ppm

2 Fuel Higher Heating Value 9454 Btu/lb

2 Fuel Moisture 29.39 %

2 Fuel Mercury Content 0.03 ppm

2 Fuel Cadmium Content 0.4 ppm

2 Fuel Nickel Content 11 ppm

Monday, January 31, 2011 Page 9 of 14
2 Fuel Arsenic Content 3 ppm

2 Fuel Chromium Content 19 ppm

2 Fuel Beryllium Content 1.7 ppm

2 Fuel Lead Content 7 ppm

2 Fuel Manganese Content 183 ppm

2 Fuel Chlorine Content 43 ppm

2 Fuel Fluorine Content 83 ppm

3 Fuel Higher Heating Value 9329 Btu/lb

3 Fuel Moisture 29.74 %

3 Fuel Mercury Content 0.24 ppm

3 Fuel Cadmium Content 0.4 ppm

3 Fuel Nickel Content 10 ppm

3 Fuel Arsenic Content 2 ppm

3 Fuel Chromium Content 16 ppm

3 Fuel Beryllium Content 1.5 ppm

3 Fuel Lead Content 6 ppm

3 Fuel Manganese Content 164 ppm

3 Fuel Chlorine Content 38 ppm

3 Fuel Fluorine Content 77 ppm

Monday, January 31, 2011 Page 10 of 14
Sampling / Stack Data Results Detail

Location Stack Exit - Method 10

Average

Run Number 1 2 3

Test Date 4/27/2010 4/27/2010 4/27/2010

Run Start Time 9:15:00 AM 12:15:00 PM 3:05:00 PM

Run Finish Time 11:29:00 AM 2:31:00 PM 5:24:00 PM

Carbon Dioxide, % 14.11 13.99 14.09 14.063

Oxygen, % 5.44 5.09 5.42 5.317

Fuel Factor 1.1 1.13 1.1

Dry Volumetric Flow Rate, dry scfm 395682 402127 400662 399,490.333

F-Factor, dscfm/MMBtu @ %O2 9860 9860 9860 9,860.000

Moisture, % 13.04 13.83 13.33 13.400

Analyzer Make Thermo 

Environmental

hermo 

Environment

al

hermo 

Environmenta

l

Analyzer Model 48C 48C 48C

Analyzer Serial Number 503010324 503010324 503010324 503,010,324

.000

Operating Range 100 100 100 100.000

Operating Units ppm ppm ppm

No. Readings/Avg. 480 480 480 480.000

Calibration Set 1 1 1 1.000

Calibration Pre Zero Cylinder ID N2- ALM 

65384

N2- ALM 

65384

N2- ALM 

65384

Calibration Pre Zero Cylinder Instrument Response 0.32 0.32 0.32 0.320

Calibration Pre Zero Cylinder Bias 0.1 0.1 0.1 0.100

Calibration Pre Zero Cylinder Drift 0 0 0 0.000

Calibration Pre High Cylinder ID CO-ALM 

8696

CO-ALM 

8696

CO-ALM 

8696

Calibration Pre High Cylinder Instrument Response 41.33 41.01 41.22 41.187

Calibration Pre High Cylinder Bias -0.3 -0.64 -0.42 -0.453

Calibration Pre High Cylinder Drift 0 0 0 0.000

Calibration Post Zero Cylinder ID N2- ALM 

65384

N2- ALM 

65384

N2- ALM 

65384

Calibration Post Zero Cylinder Instrument Response 0.32 0.32 0.32 0.320

Calibration Post Zero Cylinder Bias 0.1 0.1 0.1 0.100

Calibration Post Zero Cylinder Drift 0 0 0 0.000

Calibration Post High Cylinder ID CO-ALM 

8696

CO-ALM 

8696

CO-ALM 

8696

Calibration Post High Cylinder Instrument Response 41.01 41.22 41.22 41.150

Calibration Post High Cylinder Bias -0.64 -0.42 -0.42 -0.493

Calibration Post High Cylinder Drift 0.34 0.22 0 0.187

Cavg 9.29 8.9 9.1 9.097

Cavg Units ppmvd ppmvd ppmvd

Cgas 9.1347 8.7493 8.9303 8.938

Cgas Units ppmvd ppmvd ppmvd

Fuel Type Coal - Lignite Coal - 

Lignite

Coal - Lignite

Fw 11950 11950 11950 11,950.000

Fc 1910 1910 1910 1,910.000

Cgasw 0 0 0 0.000

Monday, January 31, 2011 Page 11 of 14
Cgasw Units

Location Stack Exit - Method 25A

Average

Run Number

Test Date

Run Start Time

Run Finish Time

Carbon Dioxide, %

Oxygen, %

Fuel Factor

Dry Volumetric Flow Rate, dry scfm

F-Factor, dscfm/MMBtu @ %O2

Moisture, %

Analyzer Make

Analyzer Model

Analyzer Serial Number

Operating Range

Operating Units

No. Readings/Avg.

Calibration Set

Calibration Pre Zero Cylinder ID

Calibration Pre Zero Cylinder Instrument Response

Calibration Pre Zero Cylinder Bias

Calibration Pre Zero Cylinder Drift

Calibration Pre High Cylinder ID

Calibration Pre High Cylinder Instrument Response

Calibration Pre High Cylinder Bias

Calibration Pre High Cylinder Drift

Calibration Post Zero Cylinder ID

Calibration Post Zero Cylinder Instrument Response

Calibration Post Zero Cylinder Bias

Calibration Post Zero Cylinder Drift

Calibration Post High Cylinder ID

Calibration Post High Cylinder Instrument Response

Calibration Post High Cylinder Bias

Calibration Post High Cylinder Drift

Cavg

Cavg Units

Cgas

Cgas Units

Fuel Type

Fw

Fc

Cgasw

Cgasw Units

Monday, January 31, 2011 Page 12 of 14
Location Stack Exit - Method 3A CO2

Average

Run Number

Test Date

Run Start Time

Run Finish Time

Carbon Dioxide, %

Oxygen, %

Fuel Factor

Dry Volumetric Flow Rate, dry scfm

F-Factor, dscfm/MMBtu @ %O2

Moisture, %

Analyzer Make

Analyzer Model

Analyzer Serial Number

Operating Range

Operating Units

No. Readings/Avg.

Calibration Set

Calibration Pre Zero Cylinder ID

Calibration Pre Zero Cylinder Instrument Response

Calibration Pre Zero Cylinder Bias

Calibration Pre Zero Cylinder Drift

Calibration Pre High Cylinder ID

Calibration Pre High Cylinder Instrument Response

Calibration Pre High Cylinder Bias

Calibration Pre High Cylinder Drift

Calibration Post Zero Cylinder ID

Calibration Post Zero Cylinder Instrument Response

Calibration Post Zero Cylinder Bias

Calibration Post Zero Cylinder Drift

Calibration Post High Cylinder ID

Calibration Post High Cylinder Instrument Response

Calibration Post High Cylinder Bias

Calibration Post High Cylinder Drift

Cavg

Cavg Units

Cgas

Cgas Units

Fuel Type

Fw

Fc

Cgasw

Cgasw Units

Monday, January 31, 2011 Page 13 of 14
Location Stack Exit - Method 3A O2

Average

Run Number

Test Date

Run Start Time

Run Finish Time

Carbon Dioxide, %

Oxygen, %

Fuel Factor

Dry Volumetric Flow Rate, dry scfm

F-Factor, dscfm/MMBtu @ %O2

Moisture, %

Analyzer Make

Analyzer Model

Analyzer Serial Number

Operating Range

Operating Units

No. Readings/Avg.

Calibration Set

Calibration Pre Zero Cylinder ID

Calibration Pre Zero Cylinder Instrument Response

Calibration Pre Zero Cylinder Bias

Calibration Pre Zero Cylinder Drift

Calibration Pre High Cylinder ID

Calibration Pre High Cylinder Instrument Response

Calibration Pre High Cylinder Bias

Calibration Pre High Cylinder Drift

Calibration Post Zero Cylinder ID

Calibration Post Zero Cylinder Instrument Response

Calibration Post Zero Cylinder Bias

Calibration Post Zero Cylinder Drift

Calibration Post High Cylinder ID

Calibration Post High Cylinder Instrument Response

Calibration Post High Cylinder Bias

Calibration Post High Cylinder Drift

Cavg

Cavg Units

Cgas

Cgas Units

Fuel Type

Fw

Fc

Cgasw

Cgasw Units

Monday, January 31, 2011 Page 14 of 14