TECHNICAL SUPPORT DOCUMENT FOR
HYDROGEN PRODUCTION: PROPOSED RULE
FOR MANDATORY REPORTING OF
GREENHOUSE GASES
Office of Air and Radiation
U.S. Environmental Protection Agency
August 5th 2008
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1. Source Description
In 2007, roughly 9 million metric tons per year of hydrogen was produced in the U.S.1 in a
variety of ways. This production results in about 60 million metric tons of CC>2 emissions each
year. Table HI provides estimates of U.S. hydrogen production for the various business sectors.
Merchant hydrogen is consumed at sites other than where it is produced. Captive hydrogen (e.g.,
hydrogen produced at oil refineries, ammonia, and methanol plants) is consumed at the site
where it is produced. This technical support document assumes that CC>2 emissions associated
with captive hydrogen production facilities are included as part of the GHG emissions from the
industry producing those other chemical products (e.g., ammonia, petroleum products, and
methanol), and therefore this document is focused on merchant hydrogen production.
Table HI. Estimated Hydrogen Production by Business Sector
Business Sector
Merchant hydrogen
Oil refineries
Ammonia plants
Methanol plants
Chlorine plants
Other
Total
Annual Hydrogen Production
(million metric tons per year)
2.0
2.6
2.1
1.5
0.4
0.3
8.9
Estimated CO2 Emissions (million metric tons per
year)
17
-25
18
None
None
< 1
-60
At present, merchant hydrogen is produced commercially primarily from natural gas, but also
from naphtha and coal2. In 2003, The Innovation Group3 reported U.S. merchant hydrogen
production capacity to be 1.5 million metric tons per year. This same report forecast a 10%
annual growth rate for merchant hydrogen production from 2003 to 2006. EPA assumed 8%
annual growth rate from 2003 to 2007 to arrive at an estimate of 2.0 million metric tons per year
for merchant production in 2007. The estimated CC>2 emissions shown in the right column is
calculated using the ratio of 8.62 tons of CC>2 emissions per ton of hydrogen production based on
a 2001NREL report4.
Oil refineries mainly use steam methane reforming for hydrogen production, but they also use
steam naphtha reforming when naphtha is available at less cost. Steam naphtha reforming
1 U. S. DOE - Fossil Energy. Today's Hydrogen Production Industry.
http://www.fossil.energv.gov/programs/fuels/hvdrogen/currenttechnologv.html.
'N
S. Czernik, R. French, C. Feik, andE. Chornet(2001). Production of Hydrogen from Biomass-Derived Liquids. Proceedings
of the 2001 DOE Hydrogen Program Review, NREL/CP-570-30535.
http://wwwl.eere.energv.gov/hvdrogenandfuelcells/pdfs/30535i.pdf National Renewable Energy Laboratory, Golden, CO.
http://www.the-innovation-group.com/chemprofile.htm, dated February 24, 2003.
Spath, P. L. and M. K. Mann. Life Cycle Assessment of Hydrogen Production via Natural Gas Steam Reforming. Report No.
NREL/TP-570-27637, National Renewable Energy Laboratory, Golden, CO, February 2001.
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produces roughly 10.5 tons of CC>2 per ton of H2. In 2003, The Innovation Group5 reported the
total captive hydrogen production capacity at 145 locations to be 2,995 million standard cubic
feet (scf) per day, which translated to an annual capacity of 2.6 million metric tons per year.
This same report did not anticipate a growth rate for captive hydrogen production from 2003 to
2006. The proportions of natural gas and naphtha reforming vary from year to year; assuming an
equal split, CO2 emissions from oil refineries due to hydrogen production is around 25 million
metric tons per year.
Ammonia plants use steam methane reforming to produce hydrogen as an intermediate. U.S.
ammonia production is currently about 12 million metric tons per year, which requires the
production of 2.1 (12 million metric tons x 3.02 g per mole of Ha / 17.02 g per mole of NHa)
million metric tons of hydrogen per year. Assuming 8.62 tons of CC>2 emissions per ton of
hydrogen as above, the corresponding CC>2 emissions are 18 million metric tons per year.
Methanol plants also use steam methane reforming to produce hydrogen as an intermediate, but,
unlike ammonia plants, the carbon leaves the methanol plant bound in the methanol. U.S.
hydrogen production at methanol plants is currently about 1.5 million metric tons per year, with
no CC>2 emissions.
Chlorine is produced by electrolysis of sodium chloride brine, which results in production of
sodium hydroxide, chlorine, and hydrogen. U.S. production of chlorine results in the production
of about 0.4 million metric tons of hydrogen, but no CC>2. Some of this hydrogen may simply be
released to the atmosphere.
The "Other" category is primarily electrolysis, but it may include petrochemical plants which use
dehydrogenation (a catalytic process to form organic compounds with hydrogen as a byproduct
but not CC>2) or coal (or petroleum coke) gasification to produce hydrogen. The "Other"
category may also include various small plants using steam reforming, partial oxidation, or auto-
thermal reforming of natural gas, ethane, propane, and liquid hydrocarbon fuels to produce
hydrogen.
Table H2 groups hydrogen production processes by development stage and CO2 emissions,
including those hydrogen production methods under development by the U.S. Department of
Energy and other organizations. These processes include a wide range of technologies to
produce hydrogen economically from a variety of resources in environmentally friendly ways6.
About 95% of all hydrogen (not just merchant hydrogen) produced in the U.S. today is made
from natural gas via steam methane reforming7. Numerous other processes are used to produce
the other 5% of hydrogen produced in the U.S. today. Some of these other processes do not
produce GHG emissions8.
5 http://www.the-irmovation-group.com/chemprofile.htm, dated February 24, 2003.
6 U.S. DOE Hydrogen Program (2006). Hydrogen Production Fact Sheet. October.
http://wwwl.eere.energy.gov/hvdrogenandfuelcells/pdfs/doe_h2jroduction.pdf. Washington, DC.
' U.S. DOE - Energy Efficiency and Renewable Energy Hydrogen, Fuel Cells, and Infrastructure Technology Program, Natural
Gas Reforming, http://wwwl.eere.energv.gov/hvdrogenandfuelcells/production/natural_gas.html/. Washington, DC.
8 U.S. DOE Hydrogen Program (2007). Hydrogen and Our Energy Future. Report No. DOE/EE-0320.
http://wwwl.eere.energy. gov/hvdrogenandfuelcells/pdfs/hvdrogenenergvfuture_web.pdf
Washington, DC.
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Table H2. Hydrogen Production Methods
Development Stage
Without CO2 Emissions
With CO2 Emissions
Current
Electrolysis of water;
Chlorine production;
Dehydrogenation of organic
compounds (including
catalytic reforming of
naphthas and naphthenes)
• Steam methane reforming;
• Steam naphtha reforming;
• Coal gasification;
• Petroleum coke gasification
Under Development
Biomass gasification;
Reforming of renewable
liquid biofuels (e.g., ethanol,
bio-oils);
Nuclear high-temperature
electrolysis;
High-temperature
thermochemical water
splitting;
Photo-biological water
splitting;
Photo-electro-chemical water
splitting
Partial oxidation of methane and other
hydrocarbon gases;
Partial oxidation of naphtha and other
hydrocarbon liquids;
Autothermal reforming of gas and liquid
hydrocarbons
Merchant hydrogen is primarily sold to refineries and chemical plants9. Including captive and
other hydrogen production, hydrogen is mostly used for industrial applications such as petroleum
refining, treating metals, and food processing (See Table H3 for additional applications and
uses). According to a 2001 NREL report10, "Hydrogen is used in a number of industrial
applications, with today's largest consumers being ammonia production facilities (40.3%), oil
refineries (37.3%), and methanol production facilities (10.0%). Its main use as a fuel is in the
NASA space program, where liquid hydrogen is a rocket fuel and hydrogen fuel cells power
onboard electrical systems." The Innovation Group (2003) provides a more recent but different
breakout11 of hydrogen applications:
• Petroleum refining (66.8%)
• Petrochemicals (26.2%)
• Other (7%) -- includes metals (2.7%), electronics (1.5%), government (NASA) (1.2%),
edible fats and oils (0.7%), float glass (0.3%), utility power generation (0.2%),
miscellaneous (0.4%)
Table H3. Hydrogen Applications and Uses
Application
Uses
y U.S. DOE-Fossil Energy (2008). Today's Hydrogen Production Industry.
http://www.fossil.energv.gov/programs/fuels/hvdrogen/currenttechnologv.html. Washington, DC.
Spath, P. L. and M. K. Mann. Life Cycle Assessment of Hydrogen Production via Natural Gas Steam Reforming. Report
No. NREL/TP-570-27637, National Renewable Energy Laboratory, Golden, CO, February 2001.
http://www.the-innovation-group.com/chemprofile.htm, dated February 24, 2003.
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Metals
Chemicals,
Pharmaceuticals and
Petroleum
Glass and Ceramics
Food and Beverages
Electronics
Miscellaneous
Hydrogen is mixed with inert gases to obtain a reducing atmosphere, which is
required for many applications in the metallurgical industry, such as heat treating
steel and welding. It is often used in annealing stainless steel alloys, magnetic steel
alloys, sintering and copper brazing.
Hydrogen can be produced by dissociation of ammonia at about 1800T with the
aid of a catalyst - which results in a mix of 75% hydrogen and 25% mononuclear
nitrogen (N rather than N2). The mix is used as a protective atmosphere for
applications such as brazing or bright annealing.
Hydrogen is used in large quantities as a raw material in the chemical synthesis of
ammonia, methanol, hydrogen peroxide, polymers, and solvents.
In refineries, it is used to remove the sulfur and nitrogen that is contained in crude
oil. Hydrogen is catalytically combined with various intermediate processing
streams and is used, in conjunction with catalytic cracking operations, to convert
heavy and unsaturated compounds to lighter and more stable compounds.
The pharmaceutical industry uses hydrogen to manufacture vitamins and other
pharmaceutical products.
Large quantities of hydrogen are used to purify gases (e.g. argon) that contain trace
amounts of oxygen, using catalytic combination of the oxygen and hydrogen
followed by removal of the resulting water.
In float glass manufacturing, hydrogen is required to prevent oxidation of the large
tin bath.
It is used to hydrogenate unsaturated fatty acids in animal and vegetable oils,
producing solid fats for margarine and other food products.
Hydrogen is used as a carrier gas for such active trace elements as arsine and
phospine, in the manufacture of semi-conducting layers in integrated circuits.
Generators in large power facilities are often cooled with hydrogen, since the gas
processes high thermal conductivity and offers low friction resistance.
Liquid hydrogen is used as a rocket fuel.
The nuclear fuel industry uses hydrogen as a protective atmosphere in the
fabrication of fuel rods.
Source: Universal Industrial Gases, Inc. (2008). Hydrogen (H^ Properties, Uses, Applications, Hydrogen Gas and
Liquid Hydrogen, http://www.uigi.com/hydrogen.html. Easton, PA.
Instead of releasing the carbon dioxide generated by steam methane reforming to the atmosphere,
a portion of it may be captured and diverted to other industrial uses. Common uses of the
captured and diverted carbon dioxide include:
• Pure CC>2 used for the carbonation of beverages;
• Pure CC>2 used to produce dry ice;
• Pure CC>2 used as a fire extinguishing agent, refrigerant, or laboratory gas; and
• Pure CC>2 used for grain disinfestation.
a. Total Emissions (based on Inventory)
Table H4 lists the U.S. inventory of 73 active liquid and gaseous merchant hydrogen production
facilities in 2003 from The Innovation Group data12, along with 4 more facilities listed as
planned for new construction in the 2004-2006 timeframe. The Innovation Group reported the
merchant hydrogen facility capacity data in thousand standard cubic feet (scf) per day.
12 http://www.the-irmovation-group.com/chemprofile.htm, dated 2003 (Four Canadian facilities were removed from the original
list)
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Additional merchant hydrogen production facilities or additional production capacity may have
been constructed since, but more recent data are not available.
Table H4. Merchant Hydrogen Production Facilities in the U.S.
Producer
Merchant Cryogenic Liquid Hydrogen
Facility 1
Facility 2
Facility 3
Facility 4
Facility 5.
Facility 6
Facility 7
Total Merchant Cryogenic Liquid
Merchant Compressed Hydrogen Gas
Facility 8.
Facility 9
Facility 10
Facility 1 1
Facility 12
Facility 13
Facility 14
Facility 14a
Facility 14b
Facility 14c
Facility 15
Facility 16
Facility 17
Facility 18
Facility 19
Facility 20
Facility 21
Facility 22
Facility 23
Facility 24
Facility 25
Facility 26
Facility 27
Facility 28
Facility 29
Facility 29a
Facility 29b.
H2 Facility
Capacity
(thousand scf
per day)
26,800
11,500
2,300
11,500
11,500
15,000
8,500
87,100
830
15,000
7
50
165
200
50,000
700
1,000
1,800
100,000
2,300
1,500
750
960
125,000
750
60,000
40,000
100,000
3,600
750
160,000
n.a.
35,000
H2 Facility
Capacity
(metric
tons/yr)
23,645
10,146
2,029
10,146
10,146
13,234
7,499
76,847
732
13,234
6
44
146
176
44,115
618
882
1,588
88,229
2,029
1,323
662
847
110,286
662
52,937
35,292
88,229
3,176
662
141,166
n.a.
30,880
CO2
Emissions at
Full Facility
Capacity"
(metric
tons/yr)
203,850
87,473
17,495
87,473
87,473
114,095
64,654
6,313
114,095
53
380
1,255
1,521
380,318
5,324
7,606
13,691
760,635
17,495
11,410
5,705
7,302
950,794
5,705
456,381
304,254
760,635
27,383
5,705
1,217,017
n.a.
266,222
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Facility 29c
Facility 29d
Facility 29e
Facility 30
Facility 30a
Facility 3 Ob
Facility 30c
Facility 30d
Facility 30e
Facility 31
Facility 32
Facility 33
Facility 34
Facility 35
Facility 36
Facility 37
Facility 38
Facility 39
Facility 40
Facility 41
Facility 42
Facility 43
Facility 44
Facility 45
Facility 46
Facility 47
Facility 48
Facility 49
Facility 50
Facility 51
Facility 52
Facility 53
Facility 54
Facility 55
Facility 56
Facility 57
Facility 58
Facility 59
Facility 60
Facility 61
Facility 62
Facility 63
Facility 64
Facility 65
Facility 65a
Facility 65b
Facility 65c
Facility 65d
100,000
30,000
21,000
12,000
27,000
52,000
29,000
80,000
n.a.
1,080
n.a.
13,000
1,500
1,080
150
190
120
7
500
400
1,500
35,000
35,000
10,000
80,000
290
720
290
n.a.
3,000
430
290
6,000
1,440
1,920
95,000
126,000
3,980
760
35,000
1,920
4,800
40,000
25,000
29,000
75,400
88,229
26,469
18,528
10,587
23,822
45,879
25,586
70,583
n.a.
953
n.a.
11,470
1,323
953
132
168
106
6
441
353
1,323
30,880
30,880
8,823
70,583
256
635
256
n.a.
2,647
379
256
5,294
1,270
1,694
83,818
111,169
3,512
671
30,880
1,694
4,235
35,292
22,057
25,586
66,525
760,635
228,191
159,733
91,276
205,372
395,530
220,584
608,508
n.a.
8,215
n.a.
98,883
11,410
8,215
1,141
1,445
913
53
3,803
3,043
11,410
266,222
266,222
76,064
608,508
2,206
5,477
2,206
n.a.
22,819
3,271
2,206
45,638
10,953
14,604
722,604
958,401
30,273
5,781
266,222
14,604
36,510
304,254
190,159
220,584
573,519
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Facility 65eb
Facility 66
Facility 67
Facility 68
Total Merchant Compressed Gas
Total Merchant Product
200,000
200
n.a.
32,400
1,914,729
2,001,829
176,458
176
n.a.
28,586
1,689,347
1,766,194
1,521,271
1,521
n.a.
246,446
14,564,106
15,226,620
a Includes both process and combustion related emissions estimated based on production capacity (i.e., facilities are
assumed to operate at full production capacity).
b New construction planned in 2003 for the 2004-2006 timeframe.
Source of Capacity Data: The Innovation Group (2003). Hydrogen. http://www.the-innovation-
group. com/chemprofile.htm. Morristown, NJ.
Annual merchant hydrogen facility production capacity in metric tons per year were calculated
assuming 365 days of operation per year, 2,205 pounds per metric ton, and a standard density of
hydrogen of 0.00533 Ib/scf.
Annual CC>2 emissions at full facility capacity (in metric tons per year) were calculated from
annual merchant hydrogen facility capacity using the process and combustion CO2-to-H2 mass
ratio of 8.62. Table H5 lists the analysis steps used to determine the CC>2 emissions from
merchant steam methane reforming based on an NREL report by Spath and Mann13. Essentially
all merchant hydrogen produced in the U.S. today is made from natural gas via steam methane
reforming14. Spath and Mann describe a typical, large steam methane reforming facility in terms
of hydrogen capacity and natural gas consumption. Note that their CO2-to-H2 molar ratio of
0.395 is not equal to the ideal molar ratio for steam methane reforming of 0.25. The ratio is
higher because not all of the available hydrogen is captured in the product stream. Some of the
hydrogen and some unused methane are included in the tail gas, partly to provide heat to the
boiler/reformer unit.
Table H5. Analysis of COi Emissions from Steam Methane Reforming Merchant
Hydrogen Production Facilities
Parameter
NREL hydrogen facility capacity
NREL facility natural gas
consumption (process and
combustion)
Conversion scf per Nm3
Density of H2
NREL facility capacity
Specific gravity of natural gas
Density of natural gas
Natural gas heat content (HHV)
Value
1.5
435
37.23
0.00533
135.0
0.60
0.045
1,029
Comments
million Nm3 of H2/day
Mg/day = metric ton/day
scf/Nm3 (standard is 60 °F at 30 in. Hg) (Normal is 0°C
at!01.325N/m3)
Ib/scf (calculated at standard conditions)
Calculated in metric ton/day
Chemical Engineer's Handbook, 5th Ed., Table 9-15,
typical value
Ib/scf (calculated using air density of 0.075 Ib/scf)
Btu/scf (from U.S. Inventory)
13 Spath, P. L., and M. K. Mann (2001). Life Cycle Assessment of Hydrogen Production via Natural Gas Steam
Reforming. Report No. NREL/TP-570-27637, National Renewable Energy Laboratory, Golden, CO, February.
14 U.S. DOE - Energy Efficiency and Renewable Energy Hydrogen, Fuel Cells, and Infrastructure Technology Program, Natural
Gas Reforming, http://wwwl.eere.energv.gov/hvdrogenandfuelcells/production/natural_gas.html/. Washington, DC.
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NREL facility natural gas
consumption (process and
combustion)
GHG Emission Factors (process
and combustion)
Process and combustion CO2
emissions from NREL facility
Mass ratio of process and
combustion CO2 to H2 at NREL
facility
Molar ratio of process and
combustion CO2 to H2 at NREL
facility
21,933
0.05306
1,164
8.62
0.395
MMBtu/day (calculated)
metric tons CO2 / MMBtu (from U.S. Inventory)
metric tons CO2/day (calculated)
Calculated, including both process and combustion
emissions
Calculated using 2.016 g/mole H2 and 44.01 g/mole CO2
b. Types of Emissions to Be Reported
The Total National Emissions estimates reported here include a mix of process and combustion
emissions. Figure HI is the block flow diagram for steam methane reforming without CC>2
removal, and Figure H2 is the block flow diagram for steam methane reforming with CC>2
capture by an amine process. Natural gas is used as the feedstock as well as a supplementary
fuel to the steam boiler. Once the feedstock passes through a reactor bed to remove sulfur
compounds, steam methane reforming consists of three steps15:
• Reformation of the feedstock to obtain a synthesis gas using high temperature steam
supplied by burning tail gas from the hydrogen purification step;
• Using a water-gas shift reaction to form hydrogen and carbon dioxide from the carbon
monoxide produced in the first step; and
• Pressure swing absorption to produce nearly pure hydrogen and a tail gas containing carbon
dioxide, hydrogen, methane, carbon monoxide, water vapor, and other minor components.
Stack
Natural Gas
65 5 MMscfd
Sylfur
Gyard
I
Reformer/
Boiler
i j
-+
Shift
Reactor
s\
\
PSA
i
H2
41 S TPD
->QO £«!.
346 psia
>
Water
Source: National Energy Technology Center16
Figure HI. Block Flow Diagram for Steam Reforming of Natural Gas
U.S. Hydrogen Association fact sheet, http://nationalhvdrogenassociation.org/general/factSheetjroduction.pdf.
16 Klett, M. G., J. S. White, R. L. Schoff, and T. L. Buchanan (2002). Hydrogen Production Facilities Facility Performance
and Cost Comparisons. Parson Infrastructure and Technology Group, Final Report under Contract No. DE-AM26-99FT40465
between Concurrent Technologies Corporation and the National Energy Technology Center. Golden, CO, March.
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1
, 2,603 TPD
'took >99%C02
20.5 psia
ICQ,
Sulfur ^^^ Reformer! Shift Amine ^^^^^
Natural Gas Guartl Btjlter Reactw fteR ~~^
ee 3 f^ft -f j
^ , j
n
H2
PSA — *>
41 S TPD
vwf <;«,
3*S psia
Water ^
Source: National Energy Technology Center17
Figure H2. Block Flow Diagram for Steam Reforming of Natural Gas for COi Removal
i) Process Emissions
For steam methane reforming, the basic chemical reactions in the steam reformer and the water-
gas shift reactor are:
CH4 + H2O -> CO + 3H2
CO + H2O -> CO2 + H2
These reactions result in a molar ratio of CO2 to H2 of 0.25. However, in an actual steam
methane reforming process, the tail gas from the pressure swing absorption stage includes
unreacted methane and some hydrogen. These fuel gases are used to fire the boiler in the
reformer/boiler unit. According to the NREL report18, the molar ratio of CO2 to H2 product for
typical steam methane reforming is 0.395.
For steam reforming of other gas and liquid hydrocarbons (including naphtha), the three process
steps are the same as for steam methane reforming: reformer/boiler, water-gas shift, and
pressure-swing absorption. Steam reforming of a generalized hydrocarbon and the water-gas
shift reaction are:
CnH2n+m + n H2O -> n CO + (2n+m/2) H2
CO + H2O -> CO2 + H2
These ideal reactions result in a molar ratio of CO2 to H2 of l/(3n + m/2) and a mass ratio of CO2
to H2 of 44.01/2.016/(3n + m/2).
17 Klett, M. G., J. S. White, R. L. Schoff, and T. L. Buchanan (2002). Hydrogen Production Facilities Facility Performance
and Cost Comparisons. Parson Infrastructure and Technology Group, Final Report under Contract No. DE-AM26-99FT40465
between Concurrent Technologies Corporation and the National Energy Technology Center. Golden, CO, March.
1 ° Spath, P. L. and M. K. Mann (2001). Life Cycle Assessment of Hydrogen Production via Natural Gas Steam Reforming,
Report No. NREL/TP-570-27637, National Renewable Energy Laboratory, Golden, CO, February 2001-
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Partial oxidation can be carried out non-catalytically or catalytically (autothermal reaction).
Partial oxidation is preferred when the raw material is a heavier fraction of petroleum while
steam reforming is more convenient for lighter ones. In the partial oxidation process, air is used
as oxidant and the use of air results in nitrogen being mixed with the hydrogen produced,
reducing the partial pressure of the hydrogen entering the pressure swing absorption unit. Partial
oxidation is accomplished by reacting a fuel with a restricted amount of oxygen:
CnH2n+m + n/2 O2 -> n CO + (n+m/2) H2
CO + H2O -> CO2 + H2
These reactions take advantage of oxygen having a greater affinity for carbon than for hydrogen.
These ideal reactions result in a molar ratio of CO2 to H2 of l/(2n + m/2), and a mass ratio of
CO2 to H2 of 44.01/2.016/(2n + m/2).
For coal gasification, the process steps are:
• Air separation unit (to separate the oxygen from the air);
• Coal gasifier to produce raw synthetic gas;
• Steam mixer (to add process steam);
• Water-gas shift converter;
• Water removal;
• Amine unit (to remove sulfur compounds);
• Pressure swing absorption unit (to produce hydrogen and a tail gas); and
• Combustion of tail gas to make process steam.
The coal gasification reactions are roughly equivalent to:
CHn + !/2 O2 + m H2O -» m CO2 + (m+n/2) H2 + (1-m) CO + other species
Where "n" is typically around 0.819 and "m" is almost but less than one, depending on the
success of the water-gas shift converter. These ideal reactions result in a molar ratio of CO2 to
H2 of m/(m+n/2), and a mass ratio of CO2 to H2 of 44.01/2.016*m/(m+n/2).
ii) Combustion Emissions
In steam methane reforming using natural gas, almost all of the natural gas is used as feedstock
(resulting in process CO2 emissions). The plants are designed to allow the tail gas to make steam
and maintain the temperature of the reformer/boiler unit. However, a small portion of the natural
gas is used during plant startup to preheat the reformer/boiler unit and during normal plant
operations to supplement the heat provided by the tail gas as needed to maintain the proper
temperature of the reformer/boiler unit (resulting in minor combustion CO2 emissions). The
process and combustion emissions go up the same stack from the boiler/reformer unit. Since the
19 U.S. DOE Hydrogen Program (2007). Hydrogen and Our Energy Future. Report No. DOE/EE-0320.
http://wwwl.eere.energy. gov/hvdrogenandfuelcells/pdfs/hvdrogenenergvfuture_web.pdf.
Washington, DC.
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emissions are predominately process emissions and because the natural gas combustion products
are emitted from the same stack, EPA has treated all the emissions as process emissions.
2. Options for Reporting Threshold
The requirements of other emissions reporting programs were reviewed and the results are
summarized below (see Table H6). The reporting programs reviewed included:
• 2006 IPCC guidelines20
• API Compendium21
• Department of Energy 1605(b) Voluntary Reporting Program22
• California Mandatory GHG Reporting Program - Initial Statement of Reasons - 10/16/07
version with 12/06/07 updates23
• New Mexico Green House Gas Mandatory Emissions Inventory (finalized 1/3/08)24
• European Union Emissions Trading System (EU-ETS)25
Table H6. Thresholds for Other Reporting Programs
2006 IPCC guidelines
API Compendium
Department of Energy 1605(b)
Voluntary Reporting Program
California Mandatory GHG Reporting
Program - Initial Statement of Reasons
- 10/16/07 version with 12/06/07
updates
New Mexico Green House Gas
Mandatory Emissions Inventory
(finalized 1/3/08)
European Union Emissions Trading
System (EU-ETS)
CO2 Threshold Level
(Metric Tons CO2e/year)
N/A
None
No minimum
Facility CO2 emissions from
combination of stationary
combustion and process sources >
25,000 metric tons per year
Simplified documentation for CO2
emissions <5% of facility GHG
emissions (CO2 equivalent)
N/A
H2 Production Capacity
(Tons H2/year)
Not mentioned
Not mentioned
Not mentioned
Not mentioned
Not mentioned
Not mentioned
20 IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas Inventories
Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buenida, K. Miwa, T Ngara, and K. Tanabe
(eds.). Hayama, Kanagawa, Japan.
API Compendium (2004). Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry.
http://www.api.org/ehs/climate/response/index.cfm. Washington, DC, February.
22 DOE (2007). Guidelines for Voluntary Greenhouse Gas Reporting. Department of Energy 1605(b) Voluntary Reporting
Program, 10 CFRPart 300, PJN 1901-AB11. http://www.eia.doe.gov/oiaf/1605/aboutcurrent.html. Washington, DC, April.
23 CARB (2007). Mandatory Greenhouse Gas Emissions Reporting. California Environmental Protection Agency Air
Resources Board, Initial Statement of Reasons - 10/16/07 version with 12/06/07 updates.
http://www.arb.ca.gov/cc/reporting/ghg-rep/ghg-rep.htm, Sacramento, California.
24 New Mexico (2008). Green House Gas Mandatory Emissions Inventory (finalized 1/3/08). New Mexico Environment
Department Air Quality Bureau, http://www.nmenv. state.nm.us/aqb/ghg/ghgrr_index.html. Santa Fe, NM.
25 EU-ETS (2005). Guide on Monitoring and Reporting. European Union (EU) Emissions Trading Scheme (ETS) Manual No.
1, Version 1.0. http://www.euets.net/. Uden, The Netherlands, October.
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Most of these protocols have no reporting threshold, or simplified reporting requirements for
CC>2 emissions below 5% of the facility total GHG emissions (CC>2 equivalent). The California
threshold is for merchant hydrogen production facilities that emit greater than 25,000 metric tons
per year of CC>2 from the combination of stationary combustion and process sources. If
California facility operations result in emissions of less than 20,000 metric tons per year of CC>2
for three consecutive years, then the operator is exempt from reporting until the emissions
exceeds 25,000 metric tons per year of CC>2. This threshold is based on actual emissions and not
on the facility capacity.
The European Union Emissions Trading System (EU-ETS) covers the following sectors: electric
power, oil refineries, coke ovens, metal ore and steel, cement kilns, glass, ceramics, and paper
and pulp, but not hydrogen production. The thresholds vary by sector and are expressed in terms
of production. For example, the threshold for combustion for energy production is 20 MW,
which roughly corresponds to 100,000 metric tons of CC>2 per year. This threshold is based on
facility capacity (20 MW) and not on actual facility emissions.
Depending upon the facility, a considerable difference may exist between actual and potential
capacity to emit. However, most industrial facilities operate at least 90% of the available 8,760
hours in a year (6 weeks of down time per year, at most), and operate at near full capacity during
those hours, implying emissions that are at least 75% of operating at full capacity for 8,760 hours
per year.
a. Options Considered
Four options for reporting emissions thresholds were considered for the reporting of CC>2
emissions from merchant hydrogen production facilities: 1,000 metric tons, 10,000 metric tons,
25,000 metric tons, and 100,000 metric tons of process CC>2 emissions per year per facility
(including the minor combustion emissions). Table H7 compares the effect of the threshold on
reported emissions and number of reporting facilities in the U.S. For example, a threshold of
25,000 metric tons per year captures over 98% of CC>2 emissions from merchant hydrogen
production facilities. For reference, the hydrogen production capacities corresponding to the
CC>2 thresholds are listed (assuming steam methane reforming), based on the calculation methods
discussed in Section la.
Table H7. Effect of Threshold on Reported Emissions from Merchant Hydrogen
Production Facilities in the U.S.
CO2
Threshold
Level
(Metric Tons
CO2e/year)
100,000
25,000
10,000
1,000
No threshold
H2
Production
Capacity
(Tons
H2/year)
11,600
2,900
1,160
116
0
Emissions Covered
Tons
CO2e/year
14,251,265
14,984,365
15,130,255
15,225,220
15,226,620
Percent
93.6%
98.4%
99.4%
100.0%
100.0%
Entities Covered
Number
30
41
51
73
77
Percent
39%
53%
66%
95%
100%
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Capacity thresholds need to be provided.
b. Emissions and Facilities Covered per Option
Table H8 lists the incremental emissions and facilities as the threshold decreases. For example, a
threshold of 25,000 metric tons per year captures 4.8% more CC>2 emissions from merchant
hydrogen production facilities than a threshold of 100,000 tons and includes 11 more facilities.
As before, the hydrogen production capacities corresponding to the CC>2 thresholds are listed
(assuming steam methane reforming), based on the calculation methods discussed in Section la.
Table H8. Effect of Threshold on Reported Emissions from Merchant Hydrogen
Production Facilities in the U.S.
CO2
Threshold
Level
(Metric Tons
CO2e/year)
100,000
25,000
10,000
1,000
No threshold
H2
Production
Capacity
(Tons
H2/year)
11,600
2,900
1,160
116
0
Emissions Covered
Tons
CO2e/year
14,251,265
733,100
145,890
94,965
1,400
Percent
93.6%
4.8%
1.0%
0.6%
0.0%
Entities Covered
Number
30
11
10
22
4
Percent
39%
14%
13%
29%
5%
3. Options for Monitoring Methods
a. Existing Relevant Reporting Programs/Methodologies
Monitoring methods required by the emissions reporting programs listed above were reviewed.
These methods all coalesced around variants of two methods: direct measurement of CC>2
emissions by continuous emissions monitoring system (CEMS), and the fuel and feedstock mass
balance method. The CEMS method follows 40CFR Part 60 or 40CFR Part 75 Appendix F. The
CEMS method employs instrument packages which continuously monitor stack flow rates and
concentrations of selected gas species and particulate matter. The data is transferred to a data
acquisition system that interprets the data and produces emissions reports on demand. Such
systems are commonly used to measure NOX emissions.
b. Monitoring Methods Considered
i) Option 1: Direct Measurement (Annual Reporting)
An unknown number of merchant hydrogen production facilities currently employ direct
measurement of emissions by continuous emissions monitoring system (CEMS). CEMS
equipment may have been installed for other purposes, such as measuring NOX emissions, but
rarely for CC>2 emissions. At plants with existing CEMS equipment for measuring emissions
other than CC>2, a CEMS retrofit (e.g., to measure CC>2 concentration and stack flow rate) would
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be required to allow the CEMS equipment to measure CC>2 emissions. For plants with no
existing CEMS equipment, a complete set of CEMS components (e.g., CC>2 gas monitor,
volumetric flow monitor, data loggers or programmable logic controllers (PLCs), data
acquisition and handling system (DAHS), and power and signal cables in conduits) would need
to be installed on every stack at the merchant hydrogen production facility. In most cases,
process CC>2 emissions are emitted via the same stack as combustion emissions. Where process
or combustion CC>2 emissions are emitted via secondary stacks or vents, additional CEMS
components will be needed.
Elements of a CEMS include a platform and sample probe within the stack to withdraw a sample
of the stack gas, an analyzer to measure the concentration of the GHG (e.g., CO2) in the stack
gas, and a flow meter within the stack to measure the flow rate of the stack gas. The emissions
are calculated from the concentration of GHGs in the stack gas and the flow rate of the stack gas.
The CEMS continuously withdraws and analyzes a sample of the stack gas and continuously
measures the GHG concentration and flow rate of the stack gas.
For direct measurement using stack testing, sampling equipment would be periodically brought
to the site and installed temporarily in the stack to withdraw a sample of the stack gas and
measure the flow rate of the stack gas. Similar to CEMS, for stack testing the emissions are
calculated from the concentration of GHGs in the stack gas and the flow rate of the stack gas.
The difference between stack testing and continuous monitoring is that the CEMS data provide a
continuous measurement of the emissions while a stack test provides a periodic measurement of
the emissions.
Owners and operators of facilities should assess whether CEMS or stack testing is the most
economical method for direct measurement given the configuration of their facility operations.
ii) Option 2: Hybrid (Annual Reporting)
This hybrid method combines direct measurement by CEMS, where CEMS components are
currently employed for other purposes, and the fuel and feedstock mass balance approach at
facilities where CEMS not currently employed or at facilities where combustion or process CC>2
emissions are emitted via secondary stacks or vents.
The fuel and feedstock mass balance method entails measurements of the quantity and carbon
content of all fuel and feedstock delivered to the facility and of all products leaving the facility,
with the assumption that all the carbon entering the facility in both the fuel and feedstock is
converted to CC>2. To handle cases where a fraction of the carbon dioxide is diverted, the mass
balance methodology includes a term to account for the diverted carbon dioxide to another
industry to avoid the possibility of double counting these emissions. It is expected that the other
industry will account for the carbon dioxide released to the atmosphere from their facility or
from their products (e.g., dry ice or carbonated beverages).
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The calculation methodology for process related CC>2 emissions in metric tons per year is
expressed as (Source: New Mexico Green House Gas Mandatory Emissions Inventory (finalized
1/3/08)26):
n
CO2 = 2 ((FSR x CF) - S) x 3.664 x metric ton/1000 kg
0
Where:
CC>2 = emissions of CC>2 (metric tons/yr)
FSR = fuel and feedstock supply rate (kg/day)
CF = carbon fraction in feedstock (kg C/kg feed stock)
S = carbon fraction diverted and accounted for elsewhere (kg C/day)
3.664 = 44.01/12.01 = conversion factor (carbon to carbon dioxide)
n = days of operation
The "S" term is included to avoid double counting of some CC>2 process emissions associated
with hydrogen production. For example, the CC>2 may be diverted for such uses as fire
extinguishers. This "S" term would be non-zero in situations where CC>2 is delivered off-site
and where CC>2 emissions are accounted for using other methodologies in the regulations.
Including the "S" term provides net emissions. For gross emissions, where CO2 sent offsite is
accounted for separately, this term is removed.
This calculation methodology is equally applicable to steam methane reforming, steam reforming
of other gas and liquid hydrocarbons, partial oxidation of liquid hydrocarbons, and coal
gasification. The feedstock supply rate in all cases is currently measured for financial
accounting purposes (e.g., using a conventional gas meter).
The carbon fraction in the fuel/feedstock may be provided as part of an ultimate analysis
performed by the supplier (e.g., the local gas utility in the case of natural gas feedstock). If the
fuel/feedstock supplier does not provide the gas composition or ultimate analysis data, the
facility would be required to perform an ultimate analysis of the fuel/feedstock on a regular
basis. Any of various appropriate ASTM standard test methods would be applied, such as
D1945 Standard Test Method for Analysis of Natural Gas by Gas Chromatography and D3176
Standard Practice for Ultimate Analysis of Coal and Coke27. Applicable test methods need to be
determined.
Similarly, the carbon fraction diverted and sold to others is currently measured for financial
accounting purposes in terms of flow rate and composition. That is, if the facility sells CC>2 over
the fence, then the quantity of CC>2 sold will always be known as part of the sales transaction.
Normally the carbon fraction diverted is 99+% pure carbon dioxide, implying 12.01 kg of carbon
per 44.01 kg of CC>2 sold, as measured by a CC>2 flow meter.
26 New Mexico (2008). Green House Gas Mandatory Emissions Inventory § 95114 (finalized 1/3/08). NewMexico
Environment Department Air Quality Bureau. http://www.nmenv.state.nm.us/aqb/ghg/ghgrr_index.html. Santa Fe, NM.
27 ASTM (2008). ASTM Standards Source (Online and CD-ROM): Petroleum Collection.
http://www.astm.org/CDSTAGE/Petro/TOC.htm. West Conshohocken, PA.
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iii) Option 3: Simplified Emissions Calculation (Annual Reporting)
For the simplified emissions calculation method, the process and combustion related GHG
emissions are based on the hydrogen production and a constant facility-specific proportionality
factor, following IPCC Tier 1 guidelines28. The proportionality factor is based on historical data
for the plant's consumption of fuel and feedstock and the plant's hydrogen production, assuming
that the carbon content of the natural gas or other fuel/feedstock remains constant over time.
This method was used to calculate CO2 emissions in Section l.a and for the threshold analysis as
described in Section 2.a. This method has increased uncertainty but a relatively low incremental
cost for implementation.
This IPCC Tier 1 method uses hydrogen production to derive emissions as follows:
EC02 = HP x FR x CCF x COF x 44.01/12.01 - Rc02
Where:
Eco2 = emissions of CC>2 (metric tons/yr)
HP = hydrogen production (metric tons/yr)
FR = feedstock requirement per unit of output (tons of feedstock per ton of hydrogen)
CCF = carbon content factor of feedstock (weight fraction of carbon in feedstock)
COF = carbon oxidation factor of feedstock (fraction)
Rco2 = CO2 recovered for other uses (metric tons/yr)
Hydrogen production, emission factors, and CO2 recovered for other uses will be obtained from
plant statistics. When a deduction is made for CO2 recovered for other uses, it is good practice
to ensure that ultimate emissions are included elsewhere in the inventory. If data are not
available, it is good practice to assume that CO2 recovered is zero.
4. Procedures for Estimating Missing Data
For the feedstock mass balance method, the likelihood of there being missing data for the option
is small, since the natural gas meter and CO2 meter data are needed for financial accounting
purposes. If the local gas utility fails to provide the gas composition data, an interpolation of
data from adjacent months should provide better than 1% accuracy for carbon content.
Estimating CO2 emissions from merchant hydrogen production data is a possibility, but only for
backup purposes, since the ratio of CO2 emissions to hydrogen production will vary somewhat
from month to month. While valid under certain circumstances, this method would require
significant modification and additional measurements to assure its applicability under operational
scenarios commonly employed in merchant hydrogen production facilities.
CEMS Data
28 IPCC (2006). 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas Inventories
Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buenida, K. Miwa, T Ngara, and K. Tanabe
(eds.). http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.html. Hayama, Kanagawa, Japan.
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Procedures for management of missing data are established under Part 75 (Acid Rain Program.)
These procedures would be applicable to direct measurement using CEMS for merchant
hydrogen production, and are summarized in this section.
For options involving direct measurement of CC>2 flow rates or direct measurement of CC>2
emissions using CEMS, Part 75 establishes procedures for management of missing data.
Procedures for management of missing data are described in Part 75.35(a), (b), and (d). In
general, missing data from operation of the CEMS may be replaced with substitute data to
determine the CC>2 flow rates or CC>2 emissions during the period in which CEMS data are
missing.
Under Part 75.35(a), the owner or operator of a unit with a CC>2 continuous emission monitoring
system for determining CC>2 mass emissions in accordance with Part 75.10 (or an O2 monitor that
is used to determine CC>2 concentration in accordance with appendix F to this part) shall
substitute for missing CC>2 pollutant concentration data using the procedures of paragraphs (b)
and (d) of this section. Subpart (b) covers operation of the system during the first 720 quality-
assured operation hours for the CEMS. Subpart (d) covers operation of the system after the first
720 quality-assured operating hours are completed.
Under Part 75.35(b), during the first 720 quality assured monitor operating hours following
initial certification at a particular unit or stack location (i.e., the date and time at which quality
assured data begins to be recorded by a CEMS at that location), or (when implementing these
procedures for a previously certified CC>2 monitoring system) during the 720 quality assured
monitor operating hours preceding implementation of the standard missing data procedures in
paragraph (d) of this section, the owner or operator shall provide substitute CC>2 pollutant
concentration data or substitute CC>2 data for raw material input determination, as applicable,
according to the procedures in Part 75.3 l(b).
Under Part 75.35(d), upon completion of 720 quality assured monitor operating hours using the
initial missing data procedures of Part 75.31(b), the owner or operator shall provide substitute
data for CC>2 concentration or substitute CC>2 data for raw material input determination, as
applicable, in accordance with the procedures in Part 75.33(b) except that the term " CC>2
concentration" shall apply rather than "862 concentration," the term "CO2 pollutant
concentration monitor" or "CO2 diluent monitor" shall apply rather than "862 pollutant
concentration monitor," and the term "maximum potential CC>2 concentration, as defined in
section 2.1.3.1 of appendix A to this part" shall apply, rather than "maximum potential SC>2
concentration."
Stack Testing Data
For options involving direct measurement of CC>2 flow rates or direct measurement of CC>2
emissions using stack testing, "missing data" is not generally anticipated. Stack testing
conducted for the purposes of compliance determination is subject to quality assurance
guidelines and data quality objectives established by the U.S. EPA, including the Clean Air Act
National Stack Testing Guidance published in 2005 (US EPA 2005). The 2005 EPA Guidance
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Document indicates that stack tests should be conducted in accordance with a pre-approved site-
specific test plan to ensure that a complete and representative test is conducted. Results of stack
tests that do not meet pre-established quality assurance guidelines and data quality objectives
would generally not be acceptable for use in emissions reporting, and any such stack test would
need to be re-conducted to obtain acceptable data.
U.S. EPA regulations for performance testing under 40 CFR § 63.7(c)(2)(i) state that before
conducting a required performance test, the owner/operator is required to develop a site-specific
test plan and, if required, submit the test plan for approval. The test plan is required to include "a
test program summary, the test schedule, data quality objectives, and both an internal and
external quality assurance (QA) program" to be applied to the stack test. Data quality objectives
are defined under 40 CFR § 63.7(c)(2)(i) as "the pre-test expectations of precision, accuracy, and
completeness of data." Under 40 CFR § 63.7(c)(2)(ii), the internal QA program is required to
include, "at a minimum, the activities planned by routine operators and analysts to provide an
assessment of test data precision; an example of internal QA is the sampling and analysis of
replicate samples." Under 40 CFR § 63.7(c)(2)(iii) the external QA program is required to
include, "at a minimum, application of plans for a test method performance audit (PA) during the
performance test." In addition, according to the 2005 Guidance Document, a site-specific test
plan should generally include chain of custody documentation from sample collection through
laboratory analysis including transport, and should recognize special sample transport, handling,
and analysis instructions necessary for each set of field samples (US EPA 2005).
U.S. EPA anticipates that test plans for stack tests anticipated to be used to obtain data for the
purposes of emissions reporting would be made available to EPA prior to the stack test and that
the results of the stack test would be reviewed against the test plan prior to the data being
deemed acceptable for the purposes of emissions reporting.
5. QA/QC and Verification Requirements
Feedstock Mass Balance Method
For the feedstock mass balance method, QA/QC requirements are established for the utility gas
meter and for the CC>2 meter. If the facility needs to install a dedicated gas meter for their
hydrogen production operation, then they should follow the same QA/QC procedures as the local
gas utility has in place. As for the measurement of the gas composition, the carbon content of
natural gas is always within 1% of one mole of carbon per mole of natural gas. This is a more
critical measurement for determining the heat content of the natural gas than it is for carbon
content. Therefore, the local utility QA/QC requirements should be more than adequate.
Similarly, the CC>2 concentration in the CC>2 stream delivered over the fence is normally 99+%,
implying again that the quality control on the product exceeds the accuracy required for GHG
emissions accounting.
Units using CEMS
For units using CEMS to measure CC>2 flow rates or CC>2 emissions, the equipment should be
tested for accuracy and calibrated as necessary by a certified third party vendor. These
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procedures should be consistent in stringency and data reporting and documentation adequacy
with the QA/QC procedures for CEMS described in Part 75 of the Acid Rain Program.
Equipment Maintenance
For units using flow meters to directly measure the flow rate of fuels, raw materials, products, or
process byproducts, flow meters should be calibrated on a scheduled basis in accordance with
equipment manufacturer specifications and standards. Flow meter calibration is generally
conducted at least annually. A written record of procedures needed to maintain the flow meters
in proper operating condition and a schedule for those procedures should be part of the QAQC
plan for the capture or production unit. Measurement devices used to directly measure the
emissions from equipment (e.g., hand-held devices used to measure fugitive emissions from
valves and flanges) should also be calibrated on a scheduled basis.
An equipment maintenance plan should be developed as part of the QA/QC plan. Elements of a
maintenance plan for equipment include the following:
• Conduct regular maintenance of equipment, e.g. flow meters.
o Keep a written record of procedures needed to maintain the monitoring system in
proper operating condition and a schedule for those procedures;
o Keep a record of all testing, maintenance, or repair activities performed on any
monitoring system or component in a location and format suitable for inspection.
A maintenance log may be used for this purpose. The following records should be
maintained: date, time, and description of any testing, adjustment, repair,
replacement, or preventive maintenance action performed on any monitoring
system and records of any corrective actions associated with a monitor's outage
period. Additionally, any adjustment that recharacterizes a system's ability to
record and report emissions data must be recorded (e.g., changing of flow monitor
or moisture monitoring system polynomial coefficients, K factors or mathematical
algorithms, changing of temperature and pressure coefficients and dilution ratio
settings), and a written explanation of the procedures used to make the
adjustment(s) shall be kept.29
Data Management
QA/QC Plans generally include data management procedures Elements of data management
procedures that are appropriate and could be included in a plan are as follows:
• For measurements of carbon content, assess representativeness of the carbon content
measurement by comparing values received from supplier and/or laboratory analysis with
IPCC default values.
• Conduct third party (off-site) or on-site sampling and analysis of material carbon contents
to verify information provided by suppliers.
29 Part 75, Appendix Bl, Available at http://www.epa.gov/airmarkt/spm/rule/001000000B.htm.
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• Check for temporal consistency in production data, carbon content data, and emission
estimate. If outliers exist, can they be explained by changes in the facility's operations,
etc.?
o A monitoring error is probable if differences between annual data cannot be
explained by:
• Changes in activity levels;
• Changes concerning fuels or input material; or
• Changes concerning the emitting process (e.g. energy efficiency
improvements).30
• Determine the "reasonableness" of the emission estimate by comparing it to previous
year's estimates and relative to national emission estimate for the industry:
o Comparison of data on fuel or input material consumed by specific sources with
fuel or input material purchasing data and data on stock changes,
o Comparison of fuel or input material consumption data with fuel or input material
purchasing data and data on stock changes,
o Comparison of emission factors that have been calculated or obtained from the
fuel or input material supplier, to national or international reference emission
factors of comparable fuels or input materials
o Comparison of emission factors based on fuel analyses to national or international
reference emission factors of comparable fuels, or input materials,
o Comparison of measured and calculated emissions.31
• Maintain data documentation, including comprehensive documentation of data received
through personal communication:
o Check that changes in data or methodology are documented
Calculation checks
Calculation checks should be performed for all reported calculations. Elements of calculation
checks include:
Perform calculation checks by reproducing a representative sample of emissions calculations or
building in automated checks such as computational checks for calculations:
• Check whether emission units, parameters, and conversion factors are appropriately
labeled
• Check if units are properly labeled and correctly carried through from beginning to end of
calculations
• Check that conversion factors are correct
30 Official Journal of the European Union, August 31, 2007. Commission Decision of 18 July 2007, "Establishing guidelines for
the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of
the Council. Available at http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2007:229:0001:0085:EN:PDF.
31 Official Journal of the European Union, August 31, 2007. Commission Decision of 18 July 2007, "Establishing guidelines for
the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of
the Council. Available at http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2007:229:0001:0085:EN:PDF.
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• Check the data processing steps (e.g., equations) in the spreadsheets
• Check that spreadsheet input data and calculated data are clearly differentiated
• Check a representative sample of calculations, by hand or electronically
• Check some calculations with abbreviated calculations (i.e., back of the envelope checks)
• Check the aggregation of data across source categories, business units, etc.
• When methods or data have changed, check consistency of time series inputs and
calculations.32
As part of the data verification requirements, the owner or operator would submit a detailed
explanation of how company records of measurements are used to quantify all sources of carbon
input and output within 7 days of receipt of a written request from EPA or from the applicable
State or local air pollution control agency (the use of electronic mail is acceptable).
Data Verification
As part of the data verification requirements, the owner or operator would submit a detailed
explanation of how company records of measurements are used to quantify all sources of carbon
input and output within 7 days of receipt of a written request from EPA or from the applicable
State or local air pollution control agency (the use of electronic mail is acceptable)
6. Data to Be Reported
a. Description for each method
i) Option 1: Direct Measurement
For options for which the monitoring method is based on direct measurement, either using a
CEMS or through stack testing, the GHG emissions are directly measured at the point of
emission.
a) Continuous Emission Monitoring System (CEMS)
For direct measurement using CEMS, the facility should report the GHG emissions measured by
the CEMS for each monitored emission point and should also report the monitored GHG
concentrations in the stack gas and the monitored stack gas flow rate for each monitored
emission point. These data would illustrate how the monitoring data were used to estimate the
GHG emissions.
The facility should report the following data for direct measurement of emissions using
CEMS:
• The unit ID number (if applicable);
• A code representing the type of unit;
32 U.S. EPA 2007. Climate Leaders, Inventory Guidance, Design Principles Guidance, Chapter 7 "Managing Inventory
Quality". Available at http://www.epa.gov/climateleaders/documents/resources/designj3rinc_ch7.pdf.
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• Maximum product production rate and maximum raw material input rate (in units of
metric tons per hour);
• Each type of raw material used and each type of product produced in the unit during
the report year;
• The calculated CC>2, CH4, and N2O emissions for each type of raw material used and
product produced, expressed in metric tons of each gas and in metric tons of CC^e;
• A code representing the method used to calculate the CC>2 emissions for each type of
raw material used (e.g., part 75, Tier 1, Tier 2, etc.);
• If applicable, a code indicating which one of the monitoring and reporting
methodologies in part 75 of this chapter was used to quantify the CC>2 emissions;
• The calculated CC>2 emissions from sorbent (if any), expressed in metric tons; and
• The total GHG emissions from the unit for the reporting year, i.e., the sum of the
CC>2, CH4, and N2O emissions across all raw material and product types, expressed in
metric tons of CC^e.
b) Stack Testing
For direct measurement using stack testing, the facility should report the GHG emissions
measured during the stack test, the measured GHG concentrations in the stack gas, the monitored
stack gas flow rate fore each monitored emission point, and the time period during which the
stack test was conducted. The facility should also report the process operating conditions (e.g.,
raw material feed rates) during the time period during which the test was conducted.
ii) Option 2: Hybrid
If CEMS data are taken, they will be reported as described above.
If the feedstock mass balance method is used, annual CC>2 emissions will be reported, along with
annual merchant hydrogen production, feedstock type, amount of feedstock used, carbon fraction
in the feedstock, number of plant operating days during the year, amount of carbon-containing
product (e.g., liquid CC>2) diverted, and amount of carbon diverted. If the feedstock mass
balance method is used, the CC>2 data will be reported annually even if the feedstock metering
data and feedstock composition data are recorded more frequently.
iii) Option 3: Simplified Equation
If the simplified equation is used, annual CC>2 emissions will be reported, along with annual
merchant hydrogen production, feedstock type, feedstock requirement per unit of hydrogen
output, weight fraction of carbon in the feedstock, carbon oxidation factor, and amount of CC>2
diverted.
b. Description of additional recordkeeping
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Additional data to be retained onsite (recordkeeping) will include monitoring plan for the
facility, emissions data, emission factors, documentation of calculations, laboratory results,
QA/QC plan, monthly fuel consumptions, specific gravity of feedstock, and purity of CC>2
diverted.
References
API Compendium (2004). Compendium of Greenhouse Gas Emissions Methodologies for the
Oil and Gas Industry, http://www.api.org/ehs/climate/response/index.cfm. Washington, DC,
February.
ASTM (2008). ASTMStandards Source (Online and CD-ROM): Petroleum Collection.
http://www.astm.org/CD ST AGE/Petro/TOC.htm. West Conshohocken, PA.
CARB (2007). Mandatory Greenhouse Gas Emissions Reporting. California Environmental
Protection Agency Air Resources Board, Initial Statement of Reasons - 10/16/07 version with
12/06/07 updates, http://www.arb.ca.gov/cc/reporting/ghg-rep/ghg-rep.htm. Sacramento,
California.
Czernik, S., R. French, C. Feik, and E. Chornet (2001). Production of Hydrogen from Biomass-
Derived Liquids. Proceedings of the 2001 DOE Hydrogen Program Review, NREL/CP-570-
30535. http://wwwl.eere.energy.gov/hydrogenandfuelcells/pdfs/30535i.pdf National
Renewable Energy Laboratory, Golden, CO.
EIA Voluntary Reporting of Greenhouse Gases Program Fuel and Energy Source Codes and
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EU-ETS (2005). Guide on Monitoring and Reporting. European Union (EU) Emissions Trading
Scheme (ETS) Manual No. 1, Version 1.0. http://www.euets.net/. Uden, The Netherlands,
October.
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Greenhouse Gas Inventories Programme, The Intergovernmental Panel on Climate Change, H.S.
Eggleston, L. Buenida, K. Miwa, T Ngara, and K. Tanabe (eds.). http://www.ipcc-
nggip.iges.or.jp/public/2006gl/index.html. Hayama, Kanagawa, Japan.
Klett, M. G., J. S. White, R. L. Schoff, and T. L. Buchanan (2002). Hydrogen Production
Facilities Facility Performance and Cost Comparisons. Parson Infrastructure and Technology
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Technologies Corporation and the National Energy Technology Center. Golden, CO, March.
New Mexico (2008). Green House Gas Mandatory Emissions Inventory (finalized 1/3/08). New
Mexico Environment Department Air Quality Bureau.
http://www.nmenv.state.nm.us/aqb/ghg/ghgrr index.html. Santa Fe, NM.
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Pew Center on Global Climate Change (2005). The European Union Emissions Trading Scheme
(EU-ETS) Insights and Opportunities, Pew Center on Global Climate Change,
www.pewclimate.org/docUploads/EU-ETS White Paper.pdf. Arlington, VA.
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Gas Steam Reforming. Report No. NREL/TP-570-27637, National Renewable Energy
Laboratory. Golden, CO, February.
The Innovation Group (2003). Hydrogen. http://www.the-innovation-
group.com/chemprofile.htm. Morristown, NJ.
U.S. DOE (2007). Guidelines for Voluntary Greenhouse Gas Reporting. Department of Energy
1605(b) Voluntary Reporting Program, 10 CFR Part 300, RIN 1901-AB11.
http://www.eia.doe.gov/oiaf/1605/aboutcurrent.html. Washington, DC, April.
U.S. DOE Hydrogen Program (2006). Hydrogen Production Fact Sheet. October.
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U. S. DOE Hydrogen Program (2007). Hydrogen and Our Energy Future. Report No. DOE/EE-
0320. http://wwwl.eere.energy.gov/hydrogenandfuelcells/pdfs/hydrogenenergyfuture_web.pdf.
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U.S. DOE - Fossil Energy (2008). Today's Hydrogen Production Industry.
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U.S. Hydrogen Association (2008). Hydrogen Production Overview Fact Sheet.
http://nationalhydrogenassociation.org/general/factSheet_production.pdf Washington, DC.
Universal Industrial Gases, Inc. (2008). Hydrogen (H2) Properties, Uses, Applications,
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