# Distributed Hydrogen Production via Steam Methane Reforming

Distributed production of hydrogen from natural gas utilizes small scale
steam methane reforming technology. The advantages of distributed
hydrogen production are the production unit can be located at the
consumer refueling site, the unit capacity can be tailored to the site's
fueling requirements, and this approach eliminates the need for an
extensive hydrogen delivery infrastructure. This process may be the most
viable for introducing hydrogen as an energy carrier since it requires
less capital investment for the smaller hydrogen volumes needed
initially in the transition phase of the hydrogen economy.

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  -------------------- ------------ ------------ ------------- -------------
  **Well-to-Wheels                                             
  Energy and                                                   
  Greenhouse Gas                                               
  Emissions Data**                                             

                       **Current    **Current    **Current     **Future
                       (2005)       (2005)       (2005)        (2015)
                       Gasoline ICE Gasoline     Distributed   Distributed
                       Vehicle**    Hybrid       SMR - FCV**   SMR - FCV**
                                    Electric                   
                                    Vehicle**                  

  **Well-to-Wheels     5,900        4,200        3,700         2,800
  Total Energy Use                                             
  (Btu/mile)**                                                 

  **Well-to-Wheels     5,300        3,800        40            40
  Petroleum Energy Use                                         
  (Btu/mile)**                                                 

  **Well-to-Wheels     470          340          260           200
  Greenhouse Gas                                               
  Emissions (g/mile)**                                         

  **Cost of Hydrogen                             3.10          2.00
  (\$/gge,                                                     
  Delivered)**                                                 
  -------------------- ------------ ------------ ------------- -------------

> **Notes: Distributed Hydrogen Production via Steam Methane Reforming**

1.  Source: Well-to-wheels energy, petroleum and greenhouse gas
    emissions information from the Argonne National Laboratory GREET
    model, Version 1.7. Well-to-wheels values represent primary fuel
    production, electricity production, hydrogen production, hydrogen
    compression, and hydrogen dispensing. Fossil resource exploration
    and equipment manufacture is not included.

2.  Source: Cost, resource requirements, energy requirements, all fuel
    and feedstock energy contents, and efficiency values for the
    Current (2005) case is from the H2A model cases modified to reflect
    the Department of Energy's Hydrogen Fuel Cells, and Infrastructure
    Technologies Program 2005 cost goals as of November 2005. Capacity
    of plant represented here is 1,500 kg/day.

3.  Source: Cost, resource requirements, energy requirements, all fuel
    and feedstock energy contents, and efficiency values for the
    Future (2015) case is from the H2A model cases modified to reflect
    the Department of Energy's Hydrogen Fuel Cells, and Infrastructure
    Technologies Program 2015 cost goals as of November 2005.

4.  Basis is 1 kg of hydrogen, dispensed from filling station for 5,000
    psi fills. A kg of hydrogen contains approximately the same amount
    of energy as one gallon of gasoline, or one gallon of gasoline
    equivalent (gge).

5.  Diagram is for future (2015) case, showing feedstock and energy
    consumption levels required to meet technology cost goals. Flows in
    diagram represent direct energy and emissions between production and
    dispensing, and are not based on well-to-wheels calculations.

6.  Costs include hydrogen production, compression, storage, and
    dispensing to vehicle. Cost assumes that small-scale steam methane
    reforming technology is added to an existing fueling station.

7.  Efficiency results are presented in terms of lower heating value
    (LHV) of hydrogen.

8.  The efficiency of the electric forecourt compressor, which raises
    the pressure of gaseous hydrogen for 5,000 psi fills, is 94%.

9.  The operating capacity factor of the forecourt station is 70%. This
    value accounts for on-stream availability as well as consumer demand
    variations between week days/weekends and winter/summer.

10. Natural gas feedstock prices are based on the 2015 projections for
    industrial natural gas by the Department of Energy's Energy
    Information Administration Annual Energy Outlook 2005 High A case.
    Prices shown in table are in 2005 \$. Feedstock is inflated at
    1.9%/year for the 20 year operating life of the plant.

11. Electricity is consumed by the process for production and
    compression operations. Electricity prices are based on the 2015
    projections for commercial-rate electricity by the Department of
    Energy's Energy Information Administration Annual Energy Outlook
    2005 High A case. Prices shown in table are in 2005 \$. Electricity
    is inflated at 1.9%/year for the 20 year operating life of the
    plant.

12. Capital cost of current (2005) and future (2015) cases are \$1.40/kg
    hydrogen and \$0.60/kg hydrogen, respectively.

13. Cost of hydrogen is the minimum required to obtain a 10% internal
    rate of return after taxes on the capital investment.

14. The data relevant to the Distributed SMR technology diagram above is
    provided in the table below.

  --------------------------------- ------------------ ------------------
                                    **Current (2005)   **Future (2015)
                                    Distributed SMR -  Distributed SMR -
                                    FCV**              FCV**

  **Natural Gas Feedstock Price     5.24               5.24
  (\$/million Btu LHV)**                               

  **Natural Gas Feedstock Price     5.15               5.15
  (\$/thousand scf)**                                  

  **Energy in Natural Gas Feedstock 165,000            137,000
  (Btu)**                                              

  **Electricity Price (\$/kWh)**    0.076              0.076

  **Electricity to Process (Btu)**  2000               2000

  **Energy Losses from Process      51,000             23,000
  (Btu)**                                              

  **Pressure of Hydrogen from       300                300
  Production (psi)**                                   

  **Energy Use for Delivery at the  7,200              7,200
  Forecourt (Btu)**                                    

  **Energy Use for Delivery         N/A -- Forecourt   N/A -- Forecourt
  Transport (Btu)**                 Production         Production

  **Hydrogen Dispensing Fill        5,000              5,000
  Pressure (psi)**                                     

  **Plant Gate Energy Use Including 167,000            139,000
  Feedstock (Btu)**                                    

  **Production Process Efficiency** 69%                83%

  **Pathway Efficiency**            66%                79%

  **Greenhouse Gas Emissions from   24                 20
  Production (lb/gge of hydrogen                       
  produced)**                                          
  --------------------------------- ------------------ ------------------

**[Understanding Effects of Feedstock Volatility]{.underline}**

Distributed natural gas/renewable liquid reforming and on-site
electrolysis (promoting renewable electricity) strategies are
advantageous for the transition to the hydrogen economy because they
obviate the need for a new delivery infrastructure. Current delivery
methods (high pressure tube trailers and "liquid" trucks) are very
energy intensive and not cost effective for distances over 100 miles.
The distributed reforming approach is an enabling technology to produce
hydrogen not only from natural gas, but from a portfolio of options such
as methanol, ethanol and other renewable liquids. In a steady state
hydrogen economy, where diverse domestic resources are used, volatility
of hydrogen price should not be an issue. However, natural gas prices
are known to be volatile and this is an important consideration for
planning the transition. The chart below shows this sensitivity:

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For example, using a data point in November 2005 for an industrial
natural gas price of \$12.50 per million Btu, hydrogen would currently
cost \$4.50 per gallon-gasoline-equivalent (gge). This cost is
calculated using the H2A financial model which calculates hydrogen costs
based on the current technology development status. The H2A model is a
cash flow model that allows us to understand the cost of various
hydrogen production and delivery pathways on a consistent basis. This
portfolio analysis tool provides a levelized cost of hydrogen for a
given rate of return (input) and accounts for capital costs,
construction time, taxes, depreciation, O&M, inflation, and feedstock
prices. See <http://www.hydrogen.energy.gov/h2a_analysis.html>. As shown
in the chart below, hydrogen at \$4.50/gge would make hydrogen fuel cell
vehicles competitive on a cents per mile basis with gasoline vehicles
(ICE) at gasoline prices of \$1.90/gge (untaxed) and gasoline
hybrid-electric vehicles at gasoline prices of \$2.70/gge (untaxed).

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The impact of the volatility of natural gas prices will continue to be
evaluated to ensure the viability of this hydrogen production pathway.
Feedstock price volatility will significantly influence investment
decisions.

The chart below shows the major variables that influence natural
gas-based hydrogen costs.

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The pie chart below shows the composition of costs contributing to the
current estimate of producing hydrogen from distributed natural gas.
This estimate is based on the best available research, projected to high
volume, but not yet validated under real-world operating conditions by
the Program's Technology Validation Sub-Program. This estimate is based
on the 2005 EIA High A estimate for natural gas in 2015.

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