Unlocking New Zealand’s Biomethane Potential

BIOMETHANE VALUE CHAIN

Executive Summary

Anaerobic
Digestion

Unlocking New Zealand’s Biomethane Potential

Landfill
Gas

Digestate

Pretreatment

Natural gas is a key component of New
Zealand’s energy system; it provides heating tohomes, businesses and powers a large partof our industry. As well as being used forheat, methane is an important feedstock
for some of New Zealand’s largest chemical
processing operations.
Natural gas is both a fossil fuel and greenhouse gas. If New Zealandwishes to fully decarbonise its energy sector then a transition awayfrom natural gas to lower emitting gases will be an essential step.
As discussed in the Climate Change Commission’s (CCC) final advice
report, low emission gases may have a part to play in New Zealand’s

A popular low emission gas overseas that has seen little interest to
date in New Zealand is biomethane; a renewable green methane
substitute produced by biologically digesting organic wastematerials and upgrading the gas produced. It is chemically identicalto natural gas, but over the full biomethane value chain it prevents
up to 95% of associated carbon emissions.
This study, conducted by Beca, Firstgas Group, Fonterra and
EECA, explores the potential presented by biomethane in New
Zealand. While this report is not a response to the CCC, we believe
it outlines a potential pathway and the high level economics
required to evaluate the part biomethane could play in New
Zealand’s energy transition.

Biogas tobiomethaneprocessing

Biofertiliser use on
agricultural landdecarbonisation. The CCC have indicated that the economics andfeasibility of these technologies in a New Zealand context are notwell understood, and more work is required to evaluate what role
they may be able to play.

Food grade CO²

Collection oforganic waste

Industry

Natural gas
network

Industrial
effluent

Municipal
Organic waste

Municipal
Wastewater

ManureCrop Residue

Residential &rial
commercausers

Why Biomethane?

Unlocking New Zealand’s Biomethane Potential

Biogas

Production and utilisation of biomethane via digestion of organic wastes and processing the raw
biogas creates benefits for gas users, waste generators, asset owners, their communities
and the environment.
Diverting organic wastes from landfills or other end locations
to anaerobic digestion decreases associated biogenic
emissions for that waste by up to 95%. The methane
captured from the waste being processed in an anaerobic
digester can then be treated and used to offset fossil fuelconsumption, which more than doubles the
carbon savings.
A positive upside for boiler operators is the chance to use
upgraded biomethane as a drop-in replacement for their natural
gas with none of the emissions. This provides an invaluable
opportunity to decarbonise their energy use without needing to
make any changes to their onsite assets.
Key differentiators between biogas and biomethane generationand other popular renewable fuel sources is the creation ofother valuable by-products through the biomethane value
chain. The creation of valuable products like digestate andgreen CO² bolster the financial and environmental
benefits of biomethane production, and combined withthe capture of biogenic emissions more than double thetotal emissions avoided throughout the product lifecycle.

“The methane captured fromthe waste being processed in
an anaerobic digester can thenbe treated and used to offset
fossil fuel consumption, whichmore than doubles the
carbon savings”.

Biogas and Biomethane:

Technologies and
Use Internationally

Biomethane

CO²
Digestate
Organic Waste

CARBONBALANCEAD Plant

CAPTURED BIOGENICWASTE EMISSIONS

Biomethane Plant

FarmlandEMISSIONS FROMPROCESSING WASTE

CARBON SEQUESTEREDBY DIGESTATE

Homes

Industry

CARBON SAVED
USING GREEN CO ²

CARBON SAVED BY
USING RENEWABLE
BIOMETHANE FUELTOTALEMISSIONS
Total
Emissions

EMISSIONS
Total
avoidedEmissions
EMISSIONSAVOIDED

19x Total
EmissionsBiogas can be created by anaerobic digestionof many types of high-energy organic wastes,such as:• Food wastes;• Animal manures;• Wastewater treatment sludges;• Crop residues; and• Industrial effluents with lots of		 dissolved organic material.

Biogas can also be collected from landfills that receive organic
wastes – this gas is very similar to biogas but contains othercontaminants from non-organic material in the landfills. One ofthe differences between biogas creation via anaerobic digestion(AD) and collection of landfill gas is the creation of a solid

residue called digestate, a processed and inert material
that can be used as a fertiliser supplement.
After biogas has been created, it can either be used for directenergy or cleaned and refined into biomethane. This process
enables the gas to be injected into natural gas networks,transported and used as a direct substitute for naturalgas.
Internationally, biogas and biomethane have been
identified as key mechanisms for decarbonisation andenergy independency in a number of countries. Denmark
is currently using biomethane to supply 20% of its naturalgas grid, with a goal to completely displace its fossil-methane
consumption with biomethane by 2050. Other countries arealso committing to legally-binding biomethane grid injection
targets, like France which in 2015 set a target to rapidly expand
its biomethane production and reach 10% biomethane in its
grid by 2030
Commercially, biomethane is becoming an important part ofthe development strategies for many large international oil
and gas companies. Companies like Total and Chevron areinvesting in biomethane projects to support developmentof new biofuel technologies and enable a transition togreener fuels.

Category

The Size of The Biogas
Prize in New Zealand

Municipal Waste

Industrial Wastewater**

We have reviewed available quantities of feedstocks in New
Zealand to understand the maximum achievable biogas
generation with existing waste streams.

Agricultural Waste

The only key feedstock popular overseas that we did not consider a large contributor to
New Zealand’s possible biomethane future is the use of purpose-grown biomass or energy
crops for biogas generation, as energy crops are not an established agricultural productin New Zealand and are unlikely to take off in New Zealand given our already highlyproductive agricultural sector occupying the majority of available land for energy crops.

Feedstock Type

Biogas Potential (PJ/year)

Municipal Wastewater solids

0.6 to 0.9

Source-Segregated Food Waste

1.5

Dairy

1.1 to 1.9

Meat

0.7

Pulp and Paper

0.6

Dairy Manure

6.8

Pig Manure

0.4

Poultry Manure

1.3

Crop Residue

1.4 to 2.9
Total

Landfill Gas

12.6 to 16.9 PJ

Existing Landfill Gas Capture3
15.6 to 19.9 PJ

Total

Our estimates indicate that implementation of wide-scale anaerobic digestion in New
Zealand could produce between 13 and 17 PJ of biogas energy per year, as well as large
quantities of CO² and digestate as valuable by-products. This estimate excludes current
biogas generation via landfills (around 3 PJ), which may decrease over time as a result of
diverting food waste to AD facilities.

These figures are based on a set of assumptions around achievable collection of different feedstocks in a New Zealandcontext, typical conversion rates and technical limitations on processing different waste streams.

The most significant sources of biogas identified in our analysis were Dairy
Manure (5-6.8 PJ), Dairy and Meat Industry Effluents (2.6 PJ) and SourceSegregated Food Waste (1.5 PJ).

Implementation of Biomethane+ Uptake Towards 2050

Achievable Today

Less Favourable orMore Competition

Vision to 2050

Landfill Gas

0.36

1.44

2.52

Crop Residues

0.145

0.87

1.45
2.56

Biomethane Potential Over Time
Industrial Effluent

0.48

Today in New Zealand biogas andbiomethane are not part of the main
zero-carbon energy conversation, andthis has meant that biogas has beenchampioned by only a few privatecompanies and experts in the field.
To date, the majority of New Zealand’s biogas generation
has been from wastewater treatment plants (WWTPs),a few private companies like Fonterra (at their Tirau andDarfield sites), small piggeries and from landfill gas capture
operations. None of these operations currently upgrade theirbiogas to biomethane.
Our analysis shows that digestion plants producing
biomethane can become profitable today if supported
by charging a gate fee for reception of wastes as well
as also selling CO² and digestate as a by-product.

We estimate that a biomethane sale price similar to current
natural gas prices could allow up to 1.6 PJ to be made using
readily available feedstocks.
A further 5.6 PJ would become available in coming decades as
natural gas prices increase above $35 /GJ, driven by Emissions
Trading Scheme (ETS) price rises and natural gas scarcity.
Out to 2050, 13 PJ could become available as hard-to-utilise
feedstocks like animal manure and crop residue, which don’t
stack up economically today, become viable at biomethane
prices of $50-60 /GJ. These high prices help to provide
revenue for new plants that cannot charge a gate fee or
maximise their digestate value.
Separate from these totals, large percentages of our identified
feedstocks can be used for small-scale biogas generation forheating or Combined Heat and Power (CHP). Small-scale onfarm digesters or digesters at small industrial sites can still be
used to reduce emissions and create clean energy at scales
where biomethane creation and injection to the natural gas
pipeline is too difficult.

Biomethane Yield Potential (PJ)

14

1.6

Achievable Today

Less Favourable orMore Competition

Vision to 2050

Food Waste

0.6

0.9

1.2

Solids

0

0.69

0.84

Animal Manure

0

1.676

4.396

Available Biomethane
at $50-60/GJ

12

10

8

Available Biomethane
at $35-40/GJ

6

4

Readily - Available
Biomethane

2

2

2020

Animal Manure

2030

WWTP Solids

Food Waste

2050

2040

Industrial Effluent

Crop Residues

Landfill Gas

Barriers to Maximising
Biomethane and How They
Can be Overcome
Biogas and biomethane are well-establishedoverseas, but the technology has not experienced
the same success in New Zealand.
New Zealand’s low landfill taxes mean that it is easier and moreconvenient to simply send organic waste to landfill, whereas overseas
high landfill taxes, bans on organic materials to landfill and moreregenerative and circular approaches to waste management havecreated demand for alternative technologies like anaerobic
digestion. Promotion of more circular economies for all kinds ofwaste in New Zealand would create a more sustainable approach
to waste management and allow a more regenerative economy todevelop. Coordinating separate waste collection for suitable organic
wastes can also be a logistical barrier to building the case for a largescale plant, especially if the individual wastes are all different
in composition.

“Promotion of more circular
economies for all kinds of waste
in New Zealand would create amore sustainable approach towaste management and allow amore regenerative economy
to develop.”
One of the key differences between New Zealand and othercountries overseas is the lack of green gas and high-quality digestatecertification systems locally. Overseas, companies can sell thebiomethane they generate as a premium product, supported by
the trading of green gas credits which can benefit purchasers
in their emissions reporting etc. Additionally, digestate created byprocessing clean organic wastes can be certified and sold as a fertiliser
supplement for use in agriculture. In particular, digestate represents
a large value stream that should be monetised, but requires support
to realise its full value and address the barriers affecting its uptake in
New Zealand. If not enabled, the loss of potential revenue fromdigestate can significantly affect the profitability of biogas andbiomethane generation.
These two schemes support additional revenue generation of biogas
and biomethane plants, boosting profitability and returns for investors,
and also create additional ways for these plants to support New
Zealand’s other primary industries. It is promising to see Certified
Energy and the Bioenergy Association’s recent steps to publish draft
proposals for these schemes in recent months, and suggests thisbarrier may be removed in the near future.
Financially, countries that have experienced the fastest and mosttransformative uptakes in biogas and biomethane production havebeen supported by central government via green investment schemes,
guaranteed Feed-In Tariffs and further taxes on top of ETS schemes
for producers of fossil fuels/heavy emitters of GHGs. This helps makealternative biofuels more cost-comparative with incumbent fossil
fuels in the early stages of investment, as markets develop and adjust
to these new fuels and particularly other by-products of bilop
igas andbiomethane processing.

Collaboration is Key:
Next Steps Towards a
Zero Carbon FutureThis study has demonstrated that biogas andbiomethane are significant, untappedenergy resources in New Zealand, and havethe potential to play a significant role in the
decarbonisation of New Zealand’s natural
gas network.
Using existing and available organic wastes in New Zealand, up
to 7-8% of New Zealand’s natural gas demand could be
met with biomethane which would reduce New Zealand’s
annual emissions by 2%. Biomethane can perform just as well as
alternatives to traditional natural gas like hydrogen and electricity toprovide heat and can also be used as a chemical replacement for fossil
methane feedstocks to chemical processes.
Successful uptake of biomethane in New Zealand will not happen
overnight, and will require cooperation across industries, communities
and both the private and public sector to reach its full potential.
We are excited about the role that biogas and biomethane canplay in New Zealand’s energy transition, and continuing theconversations generated by this study.

Contents
Executive Summary ................................................................................................ ii
Acknowledgements ................................................................................................. 2
Acronyms and Units ................................................................................................ 3
Introduction to Biogas and Biomethane ......................................................... 6
1.1

What is Biogas? ............................................................................................................................... 6

1.2

How is Biogas Produced? ................................................................................................................ 6

1.3

What is Biomethane? ....................................................................................................................... 7

1.4

Other Products from Anaerobic Digestion and Biomethane Processing ......................................... 7

1.5

Benefits of Biogas and Biomethane Production .............................................................................. 8

Biogas and Biomethane on the World Stage .................................................. 9
2.1

Germany .......................................................................................................................................... 9

2.2

United States ................................................................................................................................. 10

2.3

France ............................................................................................................................................ 12

2.4

Italy ................................................................................................................................................ 14

2.5

United Kingdom ............................................................................................................................. 15

2.6

Denmark ........................................................................................................................................ 17

2.7

Sweden .......................................................................................................................................... 19

2.8

Australia ......................................................................................................................................... 21

2.9

Rural Biogas in Developing Countries ........................................................................................... 22

2.10 Key Learnings and Success Factors for New Zealand ................................................................. 23

Biogas and Biomethane in New Zealand Today ........................................... 25
3.1

History of Biogas and Biomethane in New Zealand ...................................................................... 25

3.2

Snapshot of Current Biogas and Biomethane in New Zealand ..................................................... 25

Availability of Feedstocks in New Zealand ................................................... 28
4.1

Municipal Wastewater Treatment Sludge ...................................................................................... 29

4.2

Source-segregated Food Waste .................................................................................................... 29

4.3

Crop Residue and Manure ............................................................................................................. 30

4.4

Industrial Wastewater .................................................................................................................... 30

4.5

Forestry Waste .............................................................................................................................. 31

4.6

Conclusions ................................................................................................................................... 31

4.7

Limitations and Conflicts of Feedstock Use ................................................................................... 32

Biogas and Biomethane Processing ............................................................. 33
5.1

Feedstocks to Biogas .................................................................................................................... 33

5.2

Typical Anaerobic Digestion Processes + Costs ........................................................................... 37

5.3

Biogas to Biomethane Processing ................................................................................................. 41

5.4

Transporting and Using the Gas .................................................................................................... 46

5.5

Carbon Emissions from Biogas and Biomethane vs Regular Material Disposal Pathways .......... 48

5.6

Biomethane in areas without a Reticulated Gas Network ............................................................. 50

Digestate Production....................................................................................... 51
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S

6.1

Introduction .................................................................................................................................... 51

6.2

Digestate Potential in New Zealand .............................................................................................. 51

6.3

Processing of Digestate ................................................................................................................. 52

6.4

Digestate Use in New Zealand ...................................................................................................... 53

Case Studies: Biogas and Biomethane in the Waikato ............................... 54
7.1

Case Study 1: Municipal Food Waste Processing Plant ............................................................... 54

7.2

Case Study 2: Dairy Manure Processing Plant ............................................................................. 58

7.3

Case Study Conclusions ................................................................................................................ 61

What is the Realistic Potential of Biomethane in New Zealand? ................ 64
8.1

Scenario 1: Biomethane Injection Achievable Today .................................................................... 65

8.2

Scenario 2: Biomethane Potential Achievable Tomorrow (2040) .................................................. 66

8.3

Scenario 3: Biomethane Injection Achievable by 2050 ................................................................. 69

8.4

Notes on All Scenarios .................................................................................................................. 71

8.5

What are the Benefits? .................................................................................................................. 73

Unlocking New Zealand’s Biogas/ Biomethane Potential ........................... 76
9.1

Regulatory and Policy Barriers ...................................................................................................... 76

9.2

Technical Barriers .......................................................................................................................... 77

9.3

Economic Factors .......................................................................................................................... 79

Conclusions and Closing Remarks ............................................................... 81
A1. Types of Feedstocks and Volumes ................................................................ 83
A2. Digestate production ....................................................................................... 89
A3. Feedstocks to Biogas Process....................................................................... 92
A4. Choosing a Biogas Processing Operation for your Feedstock ................ 100
A5. Biogas to Biomethane Processing .............................................................. 106
A6. Biomethane in Areas without a Reticulated Gas Network ......................... 120
Bibliography.……………………………………………………………………………122
Figure 1: Biogas Plant in Denmark (Biogas Go Global, 2018) ........................................................................ 18
Figure 2: Nature Energy Process Diagram...................................................................................................... 19
Figure 3: Household-scale Biogas Units in Developing Countries (Renewable Energy Agency, 2017) ......... 22
Figure 4: Snapshot of biogas in New Zealand today ....................................................................................... 26
Figure 5: Fonterra's Tirau Anaerobic Lagoon Digestion Plant ........................................................................ 27
Figure 6: Simplified diagram of the main stages of methane-yielding anaerobic digestion (Mes et al., 2003) 33
Figure 7: Digester Classifications by Total Solids % (Van et al., 2020) .......................................................... 36
Figure 8: Capital cost ($NZD) vs biogas plant capacity (Nm³/h) for dry digestors, single-stage fully mixed
reactors and multi-stage fully mixed reactors .................................................................................................. 38
Figure 9: Typical biomethane upgrading process ........................................................................................... 42
Figure 10: Emissions impacts of diverting organic waste from landfill or other disposal pathways ................ 48

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Figure 11: The role of digestate in closing the carbon cycle ........................................................................... 51
Figure 12: Simplified overviewed of digestate processing steps ..................................................................... 52
Figure 13: 2050 Biomethane Potential in New Zealand across three scenarios ............................................. 64
Figure 14: Biomethane Generation Prediction out to 2050 ............................................................................. 71
Figure 15: Effect of Temperature of Growth Rates of Methanogenic Organisms (Singh, Jain, and Singh2017) ................................................................................................................................................................ 92
Figure 16: Effect of pH on Cumulative Methane Production (Liu et al. 2008) ................................................. 93
Figure 17: Typical biomethane upgrading process ....................................................................................... 106
Figure 18: PSA sieve pressurization (UNIDO & German Biogas Association, 2017) ................................... 110
Figure 19: Scrubbing technologies schematic (UNIDO & German Biogas Association, 2017) .................... 111
Figure 20: Membrane Separation Fundamental (Pentair Haffmans) ............................................................ 112
Figure 21: Network operator equipment ownership models .......................................................................... 117

Table 1: Summary of available biogas feedstocks in New Zealand ................................................................ 28
Table 2: Summary of Biogas Potential from Municipal Wastewater Solids in New Zealand .......................... 29
Table 3: Summary of Biogas Potential from Organic Waste in New Zealand ................................................. 29
Table 4: Summary of Biogas Potential from Crop Residue and Manure in New Zealand .............................. 30
Table 5: Summary of Biogas Potential from Industrial Wastewater in New Zealand ...................................... 30
Table 6: Feedstocks to Biogas Process Variables and Additives ................................................................... 34
Table 7: Pre-Treatment Methods for Feedstocks ............................................................................................ 35
Table 8: Comparison of Digestion Processes ................................................................................................. 36
Table 9: Standard Digester Technology/Configuration by Feedstock Source Type and Volume ................... 37
Table 10: Methane and carbon dioxide content (% by volume) of landfill gas and biogas from anaerobic
digestion .......................................................................................................................................................... 41
Table 11: Contaminants in raw landfill gas, biogas from AD, and limits for reticulated gas in NZ .................. 42
Table 12: Pre-treatment Summary .................................................................................................................. 44
Table 13: Biogas to Biomethane Processing Technologies ............................................................................ 44
Table 14: Network Injection Equipment Summary .......................................................................................... 45
Table 15: Biogas Upgrading Cost Matrix ($NZD) ............................................................................................ 46
Table 16: Additional Costs ............................................................................................................................... 46
Table 17: Maximum theoretical production of digestate from available agricultural feedstocks in New Zealand......................................................................................................................................................................... 52
Table 18: Case Study 1 Summary ................................................................................................................... 54
Table 19: Case Study 1 - Annual Operational Costs ....................................................................................... 55
Table 20: Case Study 1 - Annual Revenue Streams ....................................................................................... 56

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Sensitivity:l Genera

Table 21: Case Study 2 - Emissions Summary ............................................................................................... 56
Table 22: Case Study 2 Summary ................................................................................................................... 58
Table 23: Case Study 2 - Operational Costs ................................................................................................... 59
Table 24: Case Study 2 - Revenue Streams ................................................................................................... 60
Table 25: Case Study 2 - Emissions Summary ............................................................................................... 60
Table 26: Summary of three scenarios: achievable today, achievable tomorrow, achievable by 2050 .......... 64
Table 27: Summary of Scenario 1 ................................................................................................................... 65
Table 28: Quantification of Scenario 1 and Assumptions ................................................................................ 65
Table 29: Summary of Scenario 2 ................................................................................................................... 67
Table 30: Quantification of Scenario 2 and Assumptions ................................................................................ 67
Table 31: Summary of Scenario 3 ................................................................................................................... 69
Table 32: Quantification of Scenario 3 and Assumptions ................................................................................ 69
Table 33: Animal Manure Figures by Livestock Type ..................................................................................... 85
Table 34: Standard Digester Technology/Configuration by Feedstock Source Type and Volume ............... 101
Table 35: Methane and carbon dioxide content (% by volume) of landfill gas and biogas from anaerobic
digestion ........................................................................................................................................................ 106
Table 36: Contaminants in raw landfill gas, biogas from AD, and limits for reticulated gas in NZ ................ 107
Table 37: Acceptable levels of H2S by end-use ............................................................................................ 108
Table 38: Pre-treatment Summary . (Sun et al., 2015a) ............................................................................... 109
Table 39: Biogas Upgrading Equipment Comparison ................................................................................... 113
Table 40: Biogas to Biomethane Scales........................................................................................................ 116
Table 41: Biogas Upgrading Cost Matrix ($NZD) .......................................................................................... 118

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Biogas and Biomethane in NZ - Unlocking New Zealand's Renewable Natural Gas Potential | 2939894-1559009345-106 |1/07/2021 | 1

| Acknowledgements |Acknowledgements
Beca would first like to thank and acknowledge the study partners, all responsible for providing technical andfinancial support to this report. The three study partners and their representatives are below:•••

The Energy Efficiency and Conservation Authority (EECA); who provided co-funding for the study.
Firstgas Group; represented on the study governance board by Angela Ogier and Tony Vranjes
Fonterra; represented on the study governance board by Tony Oosten.

We would like to acknowledge the key authors of the study, responsible for technical research and analysis
that contributed to this report:•••

Jack Timings, Eleanor Grant, Claudia Hopkins and Sara Louise Williams from Beca
Jesse Shepherd and David Innes from Firstgas Group
Lion NZ Ltd, for providing expertise on biogas and anaerobic digestion as a Technical Study Partner

We would also like to acknowledge our technical partners who provided their technical knowledge andexpertise to the study team:•••Senior Technical Staff from Beca, Firstgas Group, Fonterra and Wood Group for their input andexpertise
Insa Errey from Curios Ltd for providing technical guidance and verification on anaerobic digestion
processes,
Richard Bartlett from Biogrid Consulting Ltd for providing technical guidance on biogas processing andbiomethane production.

Special thanks also to Hans Henrik Dahl Andersen from Nature Energy, for providing support and context
about Nature Energy’s operations in Denmark and France
Finally, we express our gratitude to industry stakeholders and members of the Bioenergy Association of New
Zealand who provided feedback and review of the study, especially Brian Cox and Alzbeta Bouskova for
their efforts coordinating their wider review.

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| Acronyms and Units |Acronyms and Units
AD = Anaerobic Digestion
BIP = Biomethane Injection PointCAPEX = Capital Expenditure
CBG = Compressed Biogas
CH4 = Methane
CHP = Combined Heat and Power
CNG = Compressed Natural Gas
CO2 = Carbon Dioxide
CO2e = Carbon Dioxide-equivalent (referring to Greenhouse gases in terms of their GWP)
COD = Chemical Oxygen Demand
CV = Calorific Value
EJ = Exajoules (1x1018 Joules)
EPA = Environmental Protection Agency
EROI = Energy Return on Investment
ETS = Emissions Trading Scheme
EU = European Union
EV = Electric Vehicle
FIT = Feed-In Tariff
GHG = Greenhouse Gas(es)GJ = Gigajoule (1x109 Joules)
GWh = Gigawatt hours (1x109 Watt hours)
GWP = Global Warming Potential
H2S = Hydrogen Sulfide
Ha = hectare
kW = Kilowatt (1x103 Watts)
kWh = Kilowatt hours (1x103 Watt hours)
kt = kiloton
LCOE = Levelised Cost of Energy
LFGR = Landfill Gas Recovery
LNG = Liquified Natural Gas
LPG = Liquified Petroleum Gas
MAC = Marginal Abatement Cost (Undiscounted)
MSW = Municipal Solid Waste
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| Acronyms and Units |MW = Megawatt (1x106 Watts)
MWh = Megawatt hours (1x106 Watt hours)
Nm3 = Normal cubic metres (i.e. at standard conditions)
NPV = Net Present ValueODM = Organic Dry MatterOECD = Organisation for Economic Co-operation and Development
OLR = Organic Loading Rate
PAS = Publicly Available Standard
PJ = Petajoules (1x1015 Joules)
ppm = Parts per Million
RNG = Renewable Natural Gas
SO2 = Sulphur Dioxidet = Metric Tonnes
TS = Total Solids
TJ = Terajoules (1x1012 Joules)
TWh = Terawatt hours (1x1012 Watt hours)
VAT = Value-added Tax
VFA = Volatile Fatty Acids
WACC = Weighted Average Cost of Capital
WWTP = Wastewater Treatment Plant

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| Context |Context
Biogas is a renewable, reliable and local source of energy. Overseas, the biogas industry provides analternative route for the treatment of organic waste while supporting the development of local economies andproviding clean energy to millions of people. Biogas can also be refined into biomethane by removing
contaminants and impurities, which makes it a direct substitute for natural gas allowing for injection into
existing pipeline systems with the only required modification being the tap-in point which supports a greater
variety of gas end-users. Globally, worldwide biogas production is estimated to be equal to around 2 EJ (or2,011 PJ), with total potential being equal to fifteen times this amount (30 EJ).
In New Zealand, biogas is an established industry with significant unrealised potential; only 3.5 PJ of biogas
is collected and utilised from landfills, wastewater treatment facilities industrial manufacturing sites acrossthe country annually. In 2020 New Zealand’s first commercial anaerobic digestion plant for sourcesegregated food waste was announced in Reporoa which will divert an estimate 75,000 t of food waste fromlandfill annually, and generate around 0.3 PJ of biogas alone.
Most of the OECD leads New Zealand in terms of biogas and biomethane generation. Most parts of New
Zealand still dispose of most of their organic wastes to landfill which leads to large volumes of fugitive
emissions. The non-circular, non-regenerative approaches to managing these waste streams contribute tosome of the largest measured GHG sources in New Zealand.
Additionally, while New Zealand may have one of the most renewable electricity networks in the world, in
terms of gross energy potential New Zealand uses more natural gas than electricity per annum, including
non-energy uses of natural gas e.g. as a chemical feedstock.
This report stems from a shared interest of multiple organisations to evaluate the potential contribution of
biogas and biomethane to decarbonising our primary energy by supplementing fossil methane with biogas.
The study partners realise the complexities of these opportunities and believe that this report is the first stepto quantifying the opportunities presented by biogas/biomethane technologies.
The preparation of this report employed a variety of approaches, including:••Engagement with New Zealand biogas industry stakeholders: potential generators, distributors andusers, to gain insight into how a market for biomethane and other anaerobic digestion products could
develop in New Zealand and support decarbonisation of the natural gas network
Review of academic literature and technical reports on the development and implementation on biogas
and biomethane technology around the world, and opportunities for New Zealand based on thesefindings.

This report is not intended for use as a policy document or official directive to industry stakeholders; it isintended to demonstrate the potential and benefits of biogas and biomethane in New Zealand and highlightthe key enablers and barriers to the continued growth and development of biogas and biomethane as a low
emissions fuel source and the success of this technology in New Zealand between now and 2050.

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| Introduction to Biogas and Biomethane |1Introduction to Biogas and Biomethane

1.1 What is Biogas?
Biogas is an energy-rich mixture of gases produced as biological materials are broken down by bacteria in
the absence of air or oxygen. Previously called ‘marsh gas’, it was discovered and analysed in the 1800’s byscientists investigating the sources of flammable gases emitted from swamps.
Some speculate that biogas produced in covered marshes and swamps may have been the source ofancient myths and legends such as dragons and will-o-the-wisps. The biogas emitted from undergroundwould occasionally ignite after mixing with air, producing short-lived flickering flames.
The main gaseous components of biogas are methane (CH4) which makes up 60-70% of the gas, carbon
dioxide (CO2) which usually accounts for 25-35% of the biogas produced, and the remainder being water
vapour and impurities e.g., nitrogen or hydrogen sulphide, depending on feedstock and digester design.
Biogas was discovered, produced and utilized as a source of heat and lighting long before petrochemicalmethane. Biogas from processing of sewage sludge was used for street lighting in Exeter, England as earlyas 1896.
Biogas produced from many different sources has been a key energy source for both developing anddeveloped countries for over 100 years. Rural communities in developing countries utilize biogas produced
from animal manure and crop residues to provide a reliable supply of gas for heating and cooking, even inlocations far from anything resembling a national or regional gas supply network.
In developed countries around the world, biogas generated in large-scale digestion plants or from landfills
provides a source of energy for electrical generation, process heat and transportation.

1.2 How is Biogas Produced?
Biogas production is a biological process where carbohydrates, proteins and fats in organic material are
consumed and broken down in a series of stages by bacteria. This process involves several different
bacteria working in series to convert the material step-by-step, all in the absence of oxygen.
Inside an anaerobic digester, long-chain organic molecules are broken down into their simple repeating
monomer units before conversion into Volatile Fatty Acids or VFAs. Then, the VFAs are split into acetic acid,carbon dioxide and hydrogen before being recombined into methane.
As the organic material is decomposed in the digester by the bacteria, biogas is produced and continuallydrawn off from the digester. Generally, the gas is cleaned to remove any dangerous or volatile chemicals
before being burned to create heat or electricity or flared.
1.2.1 Biogas Feedstocks
There are several different materials used today to produce biogas at scale. The main sources of biogas
processing feedstock material are:
•
•
•
•
•

Animal/Livestock Manure
Wastewater Treatment Sludge
Industrial Effluent/Wastewater
Food Waste
Energy Crops or Crop Residues

All these materials are processed slightly differently, but the key biological steps are the same. In manycases, biogas may be a by-product of a plant’s primary objective which is waste processing and treatment.

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| Introduction to Biogas and Biomethane |Some organic materials cannot be converted easily into biogas including wood or other materials with highamounts of lignin. Lignin is a complex organic molecule that is not easily broken down by the bacteria
responsible for creating biogas, and feedstocks that have high amounts of lignin need large amounts ofenergy-intensive pre-treatment to process.

1.3 What is Biomethane?
Biomethane (or Renewable Natural Gas [RNG]) is the name given to concentrated methane derived frombiogas or landfill gas. Chemically, it is undistinguishable from natural gas extracted from natural gas fields
and is a direct substitute, meeting the AS/NZS 5442 specifications.
Compared to biogas, biomethane has many properties that make it much more useful than unrefined biogas:
•

•

•

•

Higher energy content – after the non-combustible components of biogas have been removed,
biomethane contains much more energy per volume/weight. This enables it to burn hotter and enable
more energy to be stored in smaller tanks or vessels.
Less corrosive – depending on the feedstock being processed, biogas can often have high levels of H2Sor hydrogen sulfide. This chemical can cause corrosion and damage to mechanical equipment, and large
amounts of H2S can be deadly. By treating the biogas to remove this contaminant, the risk to operatorsand equipment where the gas is transported, stored and used is decreased.
Better compressibility – As well as removing non-combustibles and H2S, the removal of other gas
components with different boiling points means that biomethane can be compressed and stored at highpressure or even as a liquid much more readily than biogas. This enables it to be economicallytransported via pipeline at high pressure and used in applications like transportation fuels.
Dehumidification – With the dewpoint sufficiently reduced water vapor is less likely to condense insidepipelines, tanks and components, this also lowers the possibility of freezing during winter conditions.

While biogas must be handled and processed in specialized equipment, biomethane can be easily integrated
with existing assets used to transport and use natural gas. Cleaned or scrubbed biogas can have some of
the above advantages which makes it more useful than raw biogas, but it is not able to be injected andtransported in natural gas networks (see Section 5.3)

1.4 Other Products from Anaerobic Digestion and Biomethane Processing
1.4.1 Digestate
Anaerobic digestion of organic feedstocks is primarily a process designed to break down organic material
and remove the volatile organic components of said material. As organic material is decomposed to create
biogas, the feed material becomes a nutrient-rich and biologically-inert material which can be used as afertiliser. Digestate produced from some organic wastes cannot be used as a fertiliser on land used for
agriculture in some countries (see Section 6.2), especially if the material is from WWTPs.
Both solid and liquid digestate can be used as an organic replacement or supplement to chemical fertilisers,
boosting crop growth and remediating marginal land into fertile and nutrient-rich soils. Depending on theprocessing arrangement and physical qualities of the incoming organic waste, solid and liquid digestate will
be produced in different ratios and qualities.
Some countries have legislation that allow for certification of digestate produced from anaerobic digestion ofa given quality, which allows the digestate to be certified as a bio-fertiliser and sold as a competitor tochemical fertilisers on the open market. In other countries, biogas plants processing manures and crops willoften have agreements with their organic waste suppliers to return digestate in exchange for organic wastematerials to feed the plants.

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| Introduction to Biogas and Biomethane |1.4.2 Carbon Dioxide
After raw biogas is produced, the removal of contaminant gases to produce biomethane can create some
additional value streams. Liquid CO2 for example, is a very valuable revenue stream for a plant equippedwith the right technology to collect and compress CO2 of sufficient quality.
Some technologies for biomethane refining like Cryogenic Separation (see Section 5.3.4) allow biogenic
food-grade CO2 production, which is carbon-neutral.
Smaller biogas processing operations that do not have the scale to economically produce biomethane will
instead burn their biogas to create electricity or heat, and the high CO2 fraction in the gases produced after
combustion makes it possible to use this gas to feed greenhouses.

1.5 Benefits of Biogas and Biomethane Production
Utilising organic wastes and using them to create a renewable energy source in New Zealand would have awide range of environmental, social and economic benefits. The below are all observations from the use of
biogas technology internationally.
1.5.1 Economic Benefits• Creation of valuable products from current wastes• Decreased asset modifications on behalf of natural gas users switching from natural gas to biomethane
to decarbonise their operations• Continued use of natural gas distribution assets and appliances• Renewable Energy storage is an intrinsic benefit of biomethane delivered via existing natural gas
distribution assets.

1.5.2 Social Benefits• Job creation in construction and operation of these new processing facilities across numerous dispersed
locations, both urban and rural.
• Creation of Circular, self-sustaining economies• Opportunities to utilise transferrable skills from industries at risk of closing e.g. oil and gas industry• Energy supply to consumers protected as fossil fuels phased out• Less land required for new landfills or landfill expansions – Food waste contributes to 17% of waste sent
to landfill in New Zealand alone (Ministry for the Environment, 2011)

1.5.3 Environmental Benefits• By displacing natural gas consumption, biomethane greatly reduces the carbon emissions associatedwith process heat, electricity generation, residential/commercial space heating & chemical feedstock
utilisation.
• Less organic material sent to landfill, and less biogenic methane emissions from landfill• Better management and reduction of volatile organics in industrial waste streams, improving water
quality• Reduction in agricultural emissions by utilisation of collectible manure• Digestate product creation and use– Less required synthetic fertiliser– Improves soil health– Potential for carbon sequestration in soil
– As a result of the above, improved waterways

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| Biogas and Biomethane on the World Stage |2

Biogas and Biomethane on the World Stage

Internationally, biogas and biomethane production provides over 2,011 PJ of energy annually which is used
for electricity and heat generation and as a vehicle fuel. According to the IEA, this is predicted to increase to9,260 PJ by 2040 – a 360% increase over the next two decades (IEA, 2020b).
By 2040, over half of the biogas produced internationally is expected to be converted into biomethane andused as a natural gas substitute (IEA, 2020a). This will require not only a massive uptake in biogas
generation, but the conversion of many existing biogas production facilities to biomethane upgrading plants.
Internationally, several countries are leading the uptake of biogas and biomethane production – the drivers ofthese countries to adopt biogas and biomethane, and the mechanisms they are using to drive this change
are explored in the section below.

2.1 Germany
Germany is the clear leader in global biogas/biomethane production, representing more than 50% of
production in the EU (Banja et al., 2019). There are more than 9500 biogas plants in Germany which
generate a total of 30.1 TWh of electricity and 5.4 PJ of biomethane as an end product (Budde & Newman,
2019; Decorte et al., 2020). Assuming a 40% conversion from raw energy to electricity, this represents over
300 PJ of raw biogas. In comparison, Germany used 3,105 PJ of natural gas in 2020, so the energy suppliedby biogas is equal to around 10% of the energy Germany gets from natural gas (Appunn et al., 2020).
The majority of biogas in Germany is generated from the anaerobic digestion of energy crops and biowaste.
Over 1.26 million hectares of land (10.7% of Germany's total arable land) were used for the cultivation of
biogas feedstock crops in 2015 (German Biogas Assocation, 2021). A total of 17.5% of Germany's total
arable land is used for the cultivation for biogas and biodiesel crops (Federal Agency for Nature
Conservation, 2016). This has led to conflict between the agricultural industry and biogas producers
regarding best uses of land.
Germany also produces biogas from other sources of organic waste materials like manure (around a quarterof all livestock manure in Germany is digested), source segregated organic waste and industrial effluents likespent grain, pulp from juices and dairy waste.

2.1.1 How Germany Became a World-leading Producer
A major contributor to the proliferation of biogas for electrical generation in Germany was the Renewables
Energy Act of 2004, which provided biogas generators a financial benefit based on the net amount ofelectricity their plants produced (Fulton et al., 2012). In 2015, these tariffs provided 6.2 billion euros to biogas
plants across Germany, at an average of $300 NZD/MWh(Geerolf, 2018).

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| Biogas and Biomethane on the World Stage |However, in 2014 it was announced that the tariffs would be restructured resulting in less guaranteed
incentives for biogas plants primarily fed by energy crops, but maintain current incentives for plants fed bywaste materials. This led to a decrease in the construction of new biogas plants.
At the same time, the changing incentives in Germany have led to an uptake of biomethane production. In
2018, Germany produced 36 PJ of biomethane from 213 biomethane production facilities, although the
majority of this biomethane was still converted into electricity (Regatrace, 2020). The removal of historictariffs for maximising biogas production and implementation of new tariffs for electricity generation via
biomethane and grid injection has caused many new biogas projects to be cancelled and existing plants tochange the way they operate. As subsidies continue to change, it is expected that existing biogas CHP
plants will continue to transition to biomethane production and then grid injection if they have the scale to doso.
2.1.2 Biomethane Exports in Germany
Germany is a net exporter of biomethane, producing around 36 PJ of biomethane per year and exporting an
average of 0.5 PJ per year (Decorte et al., 2020). The end destination of this biomethane is commonly
countries like Sweden where incentives are geared towards using biofuels instead of towards generation.
For more info on Sweden’s biomethane consumption, see Section 2.7.
2.1.3 How Biogas fits in to the Overall Energy Strategy
Expanding renewable electricity, including power from biogas CHP plants, has been a very strong focus of
the German government for some time. One of the strongest motivators for the expansion of renewableelectrical generation has been the planned decommissioning of the country’s remaining nuclear power plants
by 2022. In contrast to countries like France, Germany does not see the continuation of its nuclear reactors
as a suitable mechanism to achieve energy independence and decrease emissions associated with its
energy consumption.

2.2 United States
The United States produce approximately 163 PJ of biogas annually (IEA, 2020a). There are four main
sources of biogas used to produce biomethane or Renewable Natural Gas (RNG) in the United States:
municipal solid waste (MSW) landfills, anaerobic digestion at WWTPs, anaerobic digestion at livestock farms
and anaerobic digestion at stand-alone organic waste management operations (United States Environmental
Protection Agency, 2020).
In 2019, approximately 5% of the energy generated in the United States was derived from biofuels andwastes, this corresponds to 1260 TWh or 4,540 PJ.
As of February 2020, across all feedstocks, there are over 100 operational RNG facilities, with an additional
40 under construction in North America (United States Environmental Protection Agency, 2020). In addition,
the United States currently have 2,200 operating biogas systems across all 50 states and have the potential
to add over 13,500 new systems (Environmental and Energy Study Institute, 2017). RNG could replace up to
10 percent of the natural gas used in the United States (Environmental and Energy Study Institute, 2017).

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| Biogas and Biomethane on the World Stage |2.2.1 Biogas and Biomethane Feedstocks in the United States• Food Waste: In 2010, the United States produced approximately 66.5 million tonnes of food waste,
primarily from the residential and commercial food sectors. Anaerobic digestion of 100 tonnes of foodwaste per day can generate enough energy to power 800 to 1,400 homes each year, so if this entire
feedstock was utilised this would power 1.4-2.7 million homes (Environmental and Energy Study
Institute, 2017).
• Landfill Gas: Landfill gas (LFG) generates in the United States about 17 TWh of electricity per year and98 billion cubic feet of gas, which is distributed via natural gas pipelines or directly to end-users eachyear (Environmental and Energy Study Institute, 2017).
• Livestock waste: The United States Environmental Protection Agency have estimated a potential for
8,241 livestock biogas systems based on livestock numbers and the amount of recoverable manure
available. This could generate over 13 TWh each year (Environmental and Energy Study Institute, 2017).
• Wastewater Treatment: Many WWTPs already have on-site anaerobic digesters, however, much of thisbiogas is flared due to not having the equipment to use the biogas produced. This is largely due to mostof these anaerobic digesters never being installed with the intention to recover the biogas produced, it
was only considered as a by-product. Around 860 of the 1,269 WWTPs using an anaerobic digester use
their biogas produced. WWTPs equipped anaerobic digestors treat over 19 million litres of wastewater
per day. If all 1,269 sites were installed with an energy recovery facility, this could reduce annual CO2
emissions by 2.3 million metric tonnes (Environmental and Energy Study Institute, 2017).
• Crop Residue: The United States have an estimated 104 million tons of crop residues available for sale.
Crop residue contains a high lignin content which is difficult to break down via anaerobic digestion.
Therefore, crop residue tends to be co-digested with other organic waste (Environmental and Energy
Study Institute, 2017).
2.2.2 Commercial Developments in the United States
In October of 2020, Chevron USA and Brightmark formed a joint venture, Brightmark RNG Holdings to own,
operate and sell biomethane from dairy digestion plants across the United States (Bioenergy Insight
Magazine, 2020).
This strategic decision from Chevron represents a growing interest from energy companies around the globe
to diversify and develop new low-carbon technologies and leverage the experience and technical skills in
fast-developing sustainable energy technology providers like Brightmark.
Anaergia is a company with staff based in North America, Europe, Africa and Asia. In January of 2021, it
announced that in partnership with Universal Waste Systems Inc. it will construct a new organic waste
digestion plant in Los Angeles capable of receiving up to 300 t of organic material per day in support ofCalifornia’s organic waste reduction targets.

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| Biogas and Biomethane on the World Stage |the facility will reduce California’s emissions by 70,000 tCO2e and produce up to 300 TJ of biomethane per
year (Anaergia, 2021).
Both of these examples show a growing appetite for both energy companies and waste managementcompanies in the United States to diversify and invest in biogas and biomethane technology as a way tocreate valuable by-products from their wastes and decrease their carbon emissions.
2.2.3 Incentives in the United States
There are a few incentives (both federal and state specific) in the United States to encourage the use of
RNG as transportation fuel. These include tradeable credits knows as Renewable Identification Numbers(RINs), and programs such as Renewable Fuel Standard (RFS), The Rural Energy for America Program(REAP), Landfill Methane Outreach Program (LMOP), and Municipal Natural Gas Fleet Conversion (UnitedStates Environmental Protection Agency, 2020). However, the incentives and subsidies for RNG projects
appear to be less in comparison to its European counterparts. California has the largest incentives for use ofbiomethane as a transport fuel, and many biomethane projects in other states sell their credits to gas users
in California to achieve best returns for their plant.

2.3 France
2.3.1 Production Capacity & Feedstocks
As of 2019, France produces approximately 6.6 PJ of biogas per year (Frédéric Simon, 2019). France
produced 2.6 TWh of electricity from biogas in 2019, accounting for approximately 0.45% of France’s total
electricity production (Heiberger & Holland, 2019). Since biomethane was granted access to the national gridin 2011, growth in production has been considerable. In response to France’s set biomethane target for
29 PJ biomethane production by 2023, the number of biomethane plants has increased from seven in 2015
to 107 in 2019 (Decorte et al., 2020).
As of December 2019, there were a total of 860 biogas plants operating in France. 123 of these plants
injected 4.4 PJ of biomethane into French distribution networks. By the end of 2019, there were 738 biogas
units producing electricity and heat, accounting for 86% of all biogas plants in France (Biogas World, 2020).

Biogas and biomethane in France is predominantly produced from waste and agricultural, industrial or
municipal by-products (Biogas World, 2020). In 2017, 75% of biogas generated in France came from landfill
gas capture (Geerolf, 2018). Today the majority of biogas plants use agricultural feedstocks such as manure,agriculture residues and wastewater sludge from the regions the plants are located in (Biogas World, 2020).

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| Biogas and Biomethane on the World Stage |2.3.2 Local Schemes and Policy
There are many schemes, policies and incentives set up by the French government and local authorities
which have helped to facilitate France’s growth in biogas and biomethane production in recent years. An
overview of some of the key schemes and policies is given below.
•

•

•

•
•

France has an energy efficiency bonus system, which is determined by the overall efficiency of thebiogas plant. Plants with an overall efficiency (including utilised electrical and thermal generation) of atleast 40% are eligible for a bonus. The highest bonus requires an overall efficiency of at least 70%(Ecoprog, 2014).
Fixed purchase tariffs give biogas producers certainty that they can sell their product at a fixed price for a
fixed time. Different fixed purchase tariffs apply for biomethane injected into the national grid and forelectricity produced from biogas. Duration of the tariffs is 15 years and 20 years respectively. For
example, the purchase tariff for renewable natural gas plants on 31 December 2018 was between 45 and139 €/MWh of gas produced, depending on the size of the plant. Depending on the type of feedstocks
used, a bonus may be added. This scheme has helped to facilitate growth in electricity production fromcogeneration in agricultural areas (Biogas World, 2020).
Financial incentives are provided through grants and technical aids offered by the French Environment
and Energy Management Agency (ADEME), local authorities, water agencies and others (Biogas World,2020).
Biogas or biomethane mixed with natural gas was exempt from the domestic consumption tax on naturalgas (TICGN) until 1 January 2021 (Biogas World, 2020).
In 2017, the French government also established a tariff rebate of up to 40% on the costs associatedwith connecting biomethane to the French distribution network. Biomethane injection was also permitted
in underground storage locations (Biogas World, 2020).

2.3.3 Commercial Developments in France
In January of 2021, Total announced that it had acquired the French company Fonroche Biogaz, a company
that designs, builds and operates anaerobic digestion facilities in France. Fonroche Biogaz is a large player
in the French biogas industry, with 1.8 PJ of installed production capacity which doubled from 2019 to 2020.
Fonroche Biogaz represents a 10% market share of biogas production in France (Total, 2021).
Total’s President of Gas, Renewables and Power, Phillipe Sauquet, said “In 2020, we stated our intention tocontribute to the development of this sector, which we expect to become more competitive in the next few
years.
“We intend to produce 1.5 terawatt-hours (TWh) [5.4 PJ] of biomethane a year by 2025 and Fonroche
Biogas is therefore the cornerstone of our development in this market.”Previously, Total had established partnerships with biogas company Methanergy and biomethane production
and distribution company Clean Energy.
Through partnerships like these, Total plans to produce 14-20 PJ of biomethane per year across its portfolios(Total, 2021).
Companies like Total investing in bringing this technology to significant national scale is a massive enabler toeffective and timely uptake of this technology in Europe, and the benefits of this investment extend wellbeyond the companies finding this technologies into the surrounding communities and consumers of gas,
fertiliser and other by-products.
2.3.4 FutureFrance’s plans for further development and expansion of biogas and biomethane include:•

The Energy Transition for Green Growth Act, which came into effect August 2015, sets a specific target
for 10% biomethane in the grid by 2030 (Blaisonneau et al., 2017).

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| Biogas and Biomethane on the World Stage |•The Energy Transition Law target of injecting 29 PJ/yr of biomethane into the grid by 2023, including
7.2 PJ/yr for transport purposes (Decorte et al., 2020; Geerolf, 2018). These commitments should see
biogas production in France amounting to 54 PJ per year in 2022, including 4.4 TWh per year ofelectricity, 3.9 TWh per year of heat and 24 PJ year of biomethane (Geerolf, 2018).

Overall, the French government have shown strong support for biogas and biomethane, particularly throughtheir ambitious, legally binding target of 10% biomethane grid-injection by 2030. This has facilitated amomentous uptake of biomethane to date, and the potential for prosperous growth in the future, primarily
through the continued uptake of energy crops and agricultural residues as feedstock.

2.4 Italy
Italy has a population of 60 million people, and its economy is largely based around agriculture, viticulture,horticulture, and production of machinery and vehicles. Natural gas accounted for 45% of Italy’s total
electricity production in 2018. Among renewable sources, hydropower ranked first (16%), followed bybiomass (9%) and solar energy (8.3%) (Statista, 2018). Italy’s bioenergy growth in the last decade has
primarily been focused on the transport sector (Eyl-Mazzega & Mathieu, 2019), resulting in Italy having thelargest EU fleet of vehicles fuelled with biogas. Italy ranks second to Germany in terms of number of biogas
plants in the EU and ranks third in the EU, behind Germany and the UK, in terms of installed electricity
capacity (Benato & Macor, 2019).
Electricity generation in Italy from bioenergy was 19.5 TWh in 2016, making up 18.1% of Italy’s total
renewable production. Biogas plants generated 42.3% of total bioenergy generation (amounting to 84 PJ of
biogas prior to electrical generation), while solid biomass and bioliquids contributed 33.6% and 24.1%,
respectively, to total bioenergy generation (Benato & Macor, 2019).
As of 2016, Italy has 1,995 biogas plants, of which 49.6% use agriculture feedstock (crop residue), 27% use
animal manure, 19.5% use source segregated organic waste and the remaining 3.9% use sludge as
feedstock.
Agriculture is one of Italy’s key economic sectors, which has driven the large uptake of crop residue as
feedstock. It should be noted that Italy has a decentralised biogas sector, with many biogas plants
traditionally being less than 1 MW in capacity. The main reason for this is the “all inclusive” feed-in tariff
introduced by the Italian Government in 2008, which guaranteed 280 €/MWh for biogas plants with an
installed capacity of less than 1 MW (Consorzio Italiano Biogas, 2016). This was the most generous support
available among the EU and boosted the installation of small-scale biogas plants, especially in the
agricultural sector. In 2012, the feed-in tariffs were replaced by less favourable feed-in premiums giving
preference to by-products and farming waste over energy crops, which has led to a stagnation in growth of
biogas production since 2012 (Eyl-Mazzega & Mathieu, 2019).

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| Biogas and Biomethane on the World Stage |2.4.1 Biomethane in Italy
Priorities have shifted to biomethane production. At the start of 2019, Italy had only six biomethane plants, ofwhich three used agricultural feedstocks, two used source segregated organic waste and one used landfill
waste. All six of these plants sold biomethane to vehicle fuel stations and were not connected to the naturalgas grid (Benato & Macor, 2019). The March 2018 Biomethane decree represents a fundamental step for thedevelopment of Italy’s biomethane sector, promoting support for biomethane as biofuel for transport andfacilitating the registration of over 900 preliminary gas grid connection projects (Eyl-Mazzega & Mathieu,2019). As of 2020, there are eight full-scale biomethane plants and fifteen are under construction (Decorte etal., 2020).
The CIB (Consorzio Italiano Biogas) estimates Italy to have a biomethane production potential of
10 billion m³ in 2030. Italy plans to spend 4.7 billion euros from 2018 to 2022 on the production anddistribution of advanced biofuels, including biomethane, to reach the EU energy and climate change goals(Biogas World, 2018).

2.5 United Kingdom
According to the European Biogas Association Statistical Report 2020, the UK has 715 biogas plants, ofwhich 80 are biomethane plants (European Biogas Association, 2021).
Bioenergy and waste contribute 9.2% of the UK’s primary energy, supplying 656 PJ of energy and just over
40% of the total renewable energy in the UK. A large portion of this energy comes from Waste to Energy
generation (IEA, 2021).

2.5.1 Biogas Production in Recent Years
In 2016 the UK has 617 MW of installed biogas capacity (Business Energy, 2017). However, growth inbiogas capacity has since been stalled due to subsidy cuts – mainly a result of concerns over limited
agricultural land for food crops.
Bioenergy contributed about 31 TWh (10%) to the UK’s total power usage in 2017. Of this 31 TWh, UKproduced biogas made up about a third (amounting to around 85 PJ of biogas prior to electrical generation),with the remainder being imported biomass for use at the Drax Power Station converted coal plant.
In 2019 around 3.6 TWh (13 PJ) of biomethane was injected into the national grid (Boykew, 2020),
displacing around 0.6% of natural gas in the UK. This came from just under 90 agricultural biogas plants
injecting biomethane into the UK gas grid (Business Energy, 2017).
In summary, it is evident that there has not been much growth in UK biomethane supply in recent
years. However, the Green Gas Levy and Green Gas Support Scheme (announced in the March 2020
Budget) could potentially provide more momentum in the years to come (more details in policy section).

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| Biogas and Biomethane on the World Stage |According to the ADBA (2020), the UK is currently only generating one fifth of its biomethane potential, but
based on the analysis below its potential could be considerably higher.
2.5.2 Sources of Biogas and Biomethane
Biogas in the UK is mostly produced from landfill gas; compared to Germany where agricultural biogas plants
dominate. This is because in Germany, most biogas plants use specially grown crops, whereas the UK do
not produce the same amount of purpose-grown biogas feedstocks, and purpose-build anaerobic digestion
plants are fed with organic wastes. Landfill gas capture is a more productive source of biogas than anaerobic
digestion in the UK today.
a. Food waste
7.3 million tonnes of household food waste is collected annually in the UK, and 15% is separated andprocessed through anaerobic digestion or composted (Bia, 2020). This suggests there is a large potential forfurther digestion of municipal and commercial food waste, and opportunities for co-digestion with WWTP
sludge.
b. Farm waste
On-farm AD offers biggest potential for growth. To capture and recycle all agricultural waste (manures,
slurries and other forms of waste), it is predicted that the number of on-farm AD plants in the UK will need toincrease from the current 375 to 3200 (an investment of 8.5 billion pounds) (Bia, 2020). UK could feasibly
reach levels of animal manure yield and digestion achieved by Denmark given appropriate policy support(see below).
c. Energy crops
In the UK, 96,000 ha of agricultural land was used to grow crops for bioenergy – just over 1.6% of arable
land. Of this 96,000 ha, 20% was used for biofuel (biodiesel and bioethanol) in the UK road transport market.
The remainder of this land was used for heat and power generation.
••

Maize (67,000ha) is produced primarily for digestion into biogas.
11,000 ha of wheat was produced for production of biofuel (bioethanol). This is significantly lower thanprevious years – likely due to intermittent closures of UK cereal bioethanol plants in 2019

2.5.3 Policy and Incentives
a. Green Gas Levy
The Green Gas Levy (GGL) was announced in the March 2020 Budget. It sets out to fund support forbiomethane injection into the national grid through the Green Gas Support Scheme. The ‘Consultation on a
Green Gas Levy’, released in September 2020, proposes to put a levy on natural gas suppliers to support
biomethane injection into the grid (Department for Business Energy and Industrial Strategy, 2020a). Thislevy will hopefully be used to support schemes like the Green Gas Support Scheme (see below).
b. Green Gas Support Scheme
This proposed scheme acts to accelerate the decarbonization of the UK gas grid through promoting
biomethane injection. Expanded Feed-In Tariffs (FIT) ,funded by the GGL, are the main proposedmechanism to incentivise ongoing production and development of new plants (Department for Business
Energy and Industrial Strategy, 2020b). These have worked well in countries like Denmark and Sweden. The
UK has run a smaller FIT scheme in the past that incentivises the generation of renewable energy by small
scale projects (Bioenergy Insight, 2018). This scheme was introduced in 2010 but ended in 2019. Payments
were made to those who produce and export renewable energy (e.g. hydro, solar, biogas, wind) with acapacity of up to 5 MW (or 2 kW for CHP). It will be interesting to see whether this new phase of incentives
can re-invigorate the growth of biogas in the UK.

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| Biogas and Biomethane on the World Stage |2.6 Denmark
Biogas has been a significant part of Denmark’s energy mix since the 1970s. The two main drivers for the
uptake of this technology in Denmark were the need to develop independent and secure supplies of energy
following the oil crises of the 70’s and 80’s, and a need to reduce pollution, waste and emissions associatedwith its agricultural sector (Danish Energy Agency, 2020). The production of biogas in Denmark has been
rapidly increasing in recent years, reaching a total annual production of 20 PJ in 2020 (Stockler et al., 2020).
In 2012, Denmark formally committed to biogas when it became a political priority and part of the National
Government’s strategy for a fossil-free energy supply by 2050. Feed-in tariffs and investment tax credits
significantly matured the industry, increased the number of large-scale projects and spurred innovation inareas like CO2 recovery, Power2Gas, and nutrient recovery. Denmark’s largest-ever biogas facility iscurrently under construction and will produce 75 million m3 of biogas annually (around 1.5PJ) when
operational (ENDS Waste and Bioenergy, 2021).

2.6.1 Sources of Biogas
More than two-thirds of Denmark’s renewable energy comes from bioenergy. Agriculture is big business inDenmark, and it indirectly helps provide energy too, with manure, animal fats, and straw used as the basis
for biogas and liquid biofuels. Separately from just biogas, many Danish power plants are switching fromcoal generation to biomass (wood pellets, wood chips, or straw), and there are widespread efforts to swap
out traditional fossil fuels with their biofuel equivalents. (Danish Energy Agency, 2020).
The main feedstock utilised for biogas and biomethane production in Denmark is animal manure and otheragricultural by-products. Over 20% of Denmark’s animal manure from its dairy, poultry, pork and fur
industries is collected from barn operations and processed to create biogas, and returned to farmers asprocessed digestate to support agricultural activity (Hermann et al., 2019).
2.6.2 Uses of Biogas
Unlike most other countries profiled in this section, the majority of Denmark’s biogas is not used for electricity
generation or CHP. In fact, less than 40% of biogas created from Denmark’s many digestion plants is used
to generate electricity. The majority of biogas produced in Denmark is refined and scrubbed into biomethane,
which is then injected into Denmark’s national gas grid (Eyl-Mazzega & Mathieu, 2019).
The Danish gas industry predicts that by 2040, the entirety of gas supplied via the national gas grid will bebiomethane (the Danish government however expects this to be by 2050 at the latest). Currently they havepassed the milestone of being 20% renewable at the end of 2020.

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| Biogas and Biomethane on the World Stage |2.6.3 Biogas and Biomethane Snapshot
As of 2018, there were 165 industrial-scale biogas plants operating in Denmark - this includes 51 WWTPs,
four industrial plants, 27 dumpsites, and 83 agricultural plants. That same year, 32 of these plants were
processing biogas into upgraded biomethane (Biogas Go Global, 2020).

In 2021, 48 biogas upgrading plants are connected to the national gas grid, with 8-10 plants currently underconstruction (Ministry of Foreign Affairs of Denmark, 2021a).

Figure 1: Biogas Plant in Denmark (Biogas Go Global, 2018)

2.6.4 Danish Case Study: Nature Energy
Nature Energy is a company based in Denmark that constructs, owns and operates biogas and biomethane
plants. Nature Energy has over 250 employees split across 13 plants in Denmark (11), France (1) and theUnited Kingdom (1). 30% of the biogas generated by Nature Energy is refined and injected into Denmark’snatural gas network.
In 2020, Nature Energy received and processed 5 million tonnes of organic waste (75-80% animal manureand 20-25% household waste etc.) and produced enough energy to heat 71,000 Danish households or
power 10,000 heavy vehicles.

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| Biogas and Biomethane on the World Stage |Figure 2: Nature Energy Process Diagram

A typical biomethane plant in their portfolio would be designed to process 600,000t of organic waste
annually, and produce 22,000,000 Nm3 of biomethane for the grid. The plants are around 6-10 acres in size,and vendors + local stakeholders are offered ownership up to 49%.
Through their partnerships with local farmers, Nature Energy also produces digestate/ natural fertiliserswhich is returned to the farmers in exchange for feed material for the plant. This circular approach produces
a range of benefits for the local community and reduces agricultural emissions and pollution.
At a pilot level, Nature Energy is trialling biological methanization to turn CO 2 generated in its digesters into
additional methane by combining it with green hydrogen produced by renewable energy sources. This
represents a way to utilise surplus electrical generation and store energy in the gas grid, balancing out
supply and demand of renewable energy.
Nature Energy is rapidly expanding; with ten plants in construction (four in Denmark, six in France) as
demand for biomethane grows in Europe.
As well as owning and operating biomethane production facilities, Nature Energy also owns 16 of the 18
biomethane vehicle refuelling stations in Denmark.

2.7 Sweden
Sweden is a unique case study in Europe, being the only country in Europe that consumes more than double
the amount of biomethane it produces annually. In 2018, Sweden imported more than 4 PJ of biomethanefrom Denmark for use within its borders as a transport fuel, which represented about 2/3rds of its overall
biomethane imports (Decorte et al., 2020).
Overall, Sweden produces around 7.3 PJ of biogas per year from 198 biogas plants, with the majority of its
biogas being produced by WWTPs and co-digestion facilities mostly processing food wastes (Ammenberg &Gustafsson, 2020; European Biogas Association, 2018).

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| Biogas and Biomethane on the World Stage |2.7.1 Biogas Feedstocks in Sweden
As far back as the 1930’s Sweden’s WWTPs generated biogas as a by-product of wastewater treatment,
which became a high-value fuel in the 1970’s as oil crises threatened energy supplies globally. Through the1970’s and 1980’s industrial effluent and farm-scale anaerobic systems became more popular, but it wasn’t
until 1990 that codigestion plants for food waste took off. Until 2013, WWTPs were still the dominant sourcesof biogas supported by landfill gas generation, but now 47% of biogas is generated in codigestion facilities(Smart City Sweden, 2020).
2.7.2 Biomethane Use in Sweden
In Sweden, biogas and biomethane make up around 22% of total Energy Gas supply, which overall makes
up 3% of Sweden’s total energy supply. The majority of Sweden’s energy supply comes from Nuclear Power(32%), Oil (24%) and Biofuels (25%).
The majority of Sweden’s biomethane is used as a vehicle fuel (63%), thanks to incentives promoting CNG
vehicles powered by biomethane. These incentives are the reason that biomethane produced in countries
like Denmark ends up being used in Sweden; incentives from production of the product in Country 1 and use
in Country 2 mean that the biomethane is double-incentivised (Klackenberg, 2019).
Today, a large portion of Sweden’s biomethane production is off-grid, or confined to local or reginal markets.
This has led to the creation of many bioenergy hubs, where the end use of the biomethane is often used as avehicle fuel or transported to customers as CNG.
In 2018, Sweden produced and utilised 2.8 million tonnes of digestate from anaerobic digestion plants as
fertiliser in its agriculture industry, around 86% of the total digestate produced. Only 40% of digestate from
WWTPs was utilised in this way, given the additional challenges of processing and pasteurising this waste(Ammenberg & Gustafsson, 2020).
2.7.3 Commercial Developments in Sweden
Recently, on the 27th of April 2021 forest and fibre product manufacturer Stora Enso opened a biogas plantat their Nymölla mill in partnership with Gasum, a Nordic gas producer. This new plant will produce 0.3 PJ
worth of liquified biogas for use as a heavy vehicle fuel, which represents a 90% reduction in the emissionsof fuelled trucks. The plant also returns clean water to the paper mill process (Tenz, 2021).
Gasum has also recently entered into an agreement with Sweden’s largest fuel company Preem to supply
their tankers with a new fuel blend consisting of liquefied natural gas and liquefied biogas. The liquified
biogas is produced in Finland from Industrial effluents and sewage sludge, and locally in Sweden from crop
residues (Helmen & Lidén, 2021).

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| Biogas and Biomethane on the World Stage |2.7.4 Future Biomethane Predictions
Out to 2030, Sweden predicts that its production of biogas will increase from 7.3 PJ to 25 PJ, mainly fromutilisation of new feedstocks including manure and energy crops. Existing production from Food Waste andWWTPs are anticipated to stay static for the near future.
Sweden also anticipates an additional 10 PJ of renewable gas from gasification processes in its grids by
2030.

2.8 Australia
The biogas industry in Australia is not as developed as industries in some of the other countries profiled inthis section, but is steadily growing.
In 2019, Australia produced 16 PJ of biogas, of which 75% came from landfill gas capture (Australian Energy
Statistics, 2020). In 2017 Australia had 242 biogas plants of which around half were landfill gas capture
plants. Half of the gas captured at these plants was not used for energy production and was flared instead.
A report by ENEA Consulting in March 2019 estimated a potential of up to 371 PJ of biogas in Australia,
equal to 9% of Australia’s total energy consumption in 2017.

2.8.1 Biomethane Developments in Australia
In November of 2020, it was announced that Australia’s first biomethane-to-grid plant will be proceeding withsupport from ARENA (Australian Renewable Energy Agency (ARENA), 2020b). Jemena and Sydney Water
are collaborating to upgrade up to 95 TJ of biogas per year into biomethane, which will be injected into
Sydney’s gas network and displace 5,000 tCO2e annually (Mavrokefalidis. Dimitris, 2020). This plant will
eventually be expanded to supply 200 TJ annually.
2.8.2 The Future of Australian Biomethane
The Australian Renewable Energy Agency (ARENA) is currently preparing a Bioenergy Roadmap forAustralia in partnership with ENEA and Deloitte. This will be provided to the Australian Government to inform
policy decisions and investment decisions at a central level (Australian Renewable Energy Agency (ARENA),
2020a) .
A previous ENEA Report highlighted obstacles to achieving maximum biomethane uptake in Australia,
including:••Financial viability of biogas and biomethane projects in current conditions; high initial investments andcomplexity of securing revenue sources are specifically mentioned
The need for more favourable policy conditions

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| Biogas and Biomethane on the World Stage |••The complexity of project development and operation; related to the first point, but inclusive of complex
approval processes facing project proponents
The lack of widespread industry experience in Australia, given the early stage of the industry in Australia.

It is promising to see that some of the recommendations of this report, namely creation of a national
roadmap and strategy for bioenergy and the use of ARENA finding to support biomethane projects, havealready been implemented. It is likely that the next decade will deliver many more biogas and biomethane
projects across Australia.

2.9 Rural Biogas in Developing Countries
In developing countries, household biogas plants are a common feature of rural farming communities.
Without connections to national or regional gas distribution networks, biogas created by processing
agricultural residues and animal manure presents a low-cost method to produce heat and energy for cooking
and lighting etc.
In 2016, China had over 42.6 million small-scale biogas digester units installed in rural areas (Renewable
Energy Agency, 2017). Between 2003 and 2012, total investments in rural biogas production in China
totalled almost $15 billion USD. In 2014, this investment avoided 61 million tonnes of carbon dioxide
emissions.
Biogas produced in household biogas units in China accounted for 1.2% of China’s total energy supply in2014.
India produced 2 million cubic metres of biogas in 2016 from rural installations (Mingyu, 2016) from suchnational programs like the New National Biogas and Organic Manure Programme (NNBOMP) helping
establish small scale rural plants.

Figure 3: Household-scale Biogas Units in Developing Countries (Renewable Energy Agency, 2017)

Uptake of rural biogas systems has been rapid in Asia over the last several decades, with China and India
alone possessing over 95% of all household agricultural biogas units.
Africa is currently trailing behind Asia, but programmes like the Africa Biogas Partnership Programme (SNVWorld, 2021) are assisting the uptake of this technology. Between 2014 and 2019, the programme installed
60,000 biogas units across Burkina Faso, Ethiopia, Kenya, Tanzania and Uganda which resulted in:

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| Biogas and Biomethane on the World Stage |

•
•
•
•
•
•

Access to clean energy for more than 300,000 people (Hivos, 2016b)
Digestate for 300,000 ha of land
A corresponding 20% crop yield increase for this land
Creation of 4200 jobs supporting biogas unit installation and biogas production
Improved health outcomes via displacement of wood-fired cooking indoors
Time savings for residents; “On average, 38,000 women save 2.5 hours daily by no longer collecting
firewood or scrubbing soot from pots”. (Hivos, 2016a)

From the above, we can see the social, environmental and economic impacts of this technology indeveloping and isolated rural communities are significant.
As these rural communities continue to develop, it is likely that smaller family-owned farms will be replacedby large-scale commercial farming operations as is the case in China. This will have impacts on the manure
supplies for many of these installed small biogas units and larger centralised units will become morecommonplace. China, recognising this incoming shift in regional economic development, are modifying theirbiogas support policies to further incentivise medium and large-scale digestion. Whether there will be a way
to utilise the previous investment in small-scale household unit technology in the long-term remains to beseen.

2.10 Key Learnings and Success Factors for New Zealand
It is clear from our profiles of each country above that biogas and biomethane is a mature and rapidlygrowing technology. Especially in recent years, countries overseas with significant natural gas consumption
have been turning to biomethane as a mechanism to help them decarbonise their primary energy supplies.
Countries like Denmark and France are proving that significant displacement of natural gas by biomethane(in the order of 10-20%) is readily achievable today by utilising available feedstocks, and much further
natural gas displacement is achievable with a strategic vision for a decarbonised natural gas network (evenup to 100% in Denmark’s case). It is promising to see both large and small countries utilising this resource,
and it reinforces the idea that New Zealand could be the next country to do so.
Corporate interest in biomethane technology has spiked overseas in recent years; biomethane is becoming a
popular mechanism for oil and gas companies to diversify their energy portfolios and develop moresustainable technologies.
A common factor across all countries with significant biogas and biomethane uptake is the presence ofstrong policy support and financial incentives for renewable energy investment. Policy and financial support
can manifest in several ways, including:
•
•
•
•
•

Restrictions (i.e. bans) or levies on disposing of organic materials in traditional landfills,
Emissions penalties for suppliers and users of fossil fuels,
Capital funding support for renewable energy investments,
Tariffs or credits for generators of renewable energy – especially where biogas or biomethane are used
to support peaking electrical demand
Formal recognition & approval of digestate quality standards (PAS110 or equivalent)

In countries that have made the most of biomethane, policy support for biomethane has been backed up bya renewable energy strategy, usually with the aim of achieving energy-independence.
Tariffs and financial incentives without careful directives have sometimes led to inefficient outcomes in the
countries we have studied. Where policy hasn’t been clearly signalled or policy has been modified/ended
prematurely, investment has declined and/or gone to waste:•

In Germany, where incentives were originally applied on a feedstock processing capacity basis, financial
benefits led to the construction of many large biogas and biodiesel plants fed by energy crops since thisBiogas and Biomethane in NZ - Unlocking New Zealand's Renewable Natural Gas Potential | 2939894-1559009345-106 |1/07/2021 | 23

| Biogas and Biomethane on the World Stage |•feedstock was the easiest to collect at scale. Now, energy crops take up 17.5% of Germany’s arable
land and energy crop production competes with food crop production for farmland. The incentives werere-evaluated in 2014 to incentivise processing of waste material streams rather than energy crops andthis has significantly slowed development of the sector.
In developing parts of China, government-incentivised small-scale household units on family-owned
farms are being abandoned as rural communities are being transformed into productive conglomerate
farms with new centralised biogas plants. To some degree, the original assets are being prematurely
retired and the investment in these small-scale units has gone to waste.

The most successful tariffs in terms of investment efficiency are the feed-in tariffs employed by the likes ofDenmark and the UK. When funding is given out based on quantity of production, plants are incentivised tobe efficient and achieve maximum biogas yield during their full operational life.
To make it easier for developers and investors to acquire funding, these tariffs are usually guaranteed for aset period of time (related to the expected life of the asset). This helps provide confidence that the plant will
generate a fixed revenue for its operating life which significantly supports the economic case for investment.
In countries with an electricity grid with a much lower proportion of renewable electricity to New Zealand,biogas was initially utilised as a mechanism to create green power. Then, as technologies like wind and solar
became favoured options for renewable energy generation, the digestion plants were reconfigured to
produce biomethane instead.
In New Zealand, it is unlikely that we would see the same targeted uptake of biogas production for electricity
generation as seen in countries like Germany, given how renewable our electricity supply is currently. The
NZ government has expressed interest in achieving 100% renewable electricity by 2030, and biogas orbiomethane production could support this by decarbonising gas-fired electricity generation in peak demand
periods.
Another more likely scenario is that large users of natural gas in New Zealand would directly consume
biogas and biomethane to offset their current natural gas or coal thermal generation, either produced onsite
or supplied via a distribution network. Initial targeted uptake would focus on developing anaerobic digestion
plants capable of injecting their biomethane into the existing network infrastructure or directly feed a large
gas user to achieve this outcome.
New Zealand can learn a lot from countries like Sweden and Italy with significant biomethane utilisation anda geographically-dispersed population. In areas without natural gas distribution infrastructure, Sweden still
manages to utilise biomethane as a transport fuel and distribute the biomethane from centralised plants tousers via ‘virtual pipelines’ i.e. CNG trucks. In these countries, a few easily utilised feedstocks were the firstto be developed (food wastes, WWTP sludges) and as the demand for biomethane grew harder-to-utilise
feedstocks became the next in line (animal manures, industrial wastewaters). This model of targeted biogas
and biomethane development could help New Zealand develop its biogas and biomethane capacity at asustainable rate.

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| Biogas and Biomethane in New Zealand Today |3

Biogas and Biomethane in New Zealand Today

3.1 History of Biogas and Biomethane in New Zealand
New Zealand was an early adopter of biogas, after the oil crisis of the mid-1970’s prompted countries aroundthe world to re-evaluate their energy supplies and start looking into ways of achieving local energy security.
As the Ministry of Energy established the New Zealand Energy Research and Development Committee(NZERDC), and New Zealand began supporting widespread CNG vehicles fuelled by the gas reserves in
Taranaki, another parallel development was the implementation of farm-scale bioenergy plants. Farmers
grew rapeseed and canola to produce diesel substitutes, and others digested their crop residues andmanure to create refined biogas as a direct CNG substitute. A standardized farm-scale system for producing,
purifying and compressing biogas was developed by the Ministry of Agriculture to support the development
and implementation of these systems across the country.
By the middle of the following decade, there were sixteen farm-based biogas plants across New Zealand.
New Zealand was a world-leader and early-adopter of biogas processing technology. The success ofagricultural biogas plants here inspired expeditions of researchers, engineers and technicians from countries
like Sweden, Denmark and Germany to visit and examine our plants and try to learn what they could toimplement similar systems at home.
However, in 1984 a change in government policy led to the dissolution of the NZERDC and government
support for CNG/Compressed Biogas (CBG) was discontinued. Coupled with the return to regularity foroil/petrol prices, New Zealand’s agricultural biogas plants gradually closed down (Ministry of Agriculture &Forestry, 2008).
Unlike New Zealand, the countries that sent observers to learn from our technology have continued todevelop their biogas technology and have successfully achieved grid-scale biogas generation. Today, thosevery same countries are leaders in global biogas/biomethane, like New Zealand was in the 1980’s.
The experience left in New Zealand after the closure of our agricultural biogas plants helped develop biogas
generation as an avenue for wastewater solids and sludge treatment, and in 1986 led to the creation of aworld-leading biomethane upgrading technology vendor Greenlane Renewables, which is now based in
Vancouver, Canada (Greenlane Renewables, 2021).

3.2 Snapshot of Current Biogas and Biomethane in New Zealand
New Zealand’s current production of biogas is dominated by three sources: landfill gas recovery (LFGR),
industrial effluent treatment plants and sludge digestion at WWTPs. In 2019, New Zealand produced a totalof 3.5 PJ of energy across eight WWTPs, several industrial effluent treatment plants including Fonterra’s
Tirau and Darfield sites, and thirteen landfills with CHP plants. As context, 3.5 PJ represents half theresidential gas demand in New Zealand (Ministry of Business Innovation and Employment, 2020), so ourcurrent biogas generation is in no way insignificant at a national level.
Today, this gas is generally burned at its source to generate electricity and heat. In some cases, excess heat
and CO2 can be used by nearby agricultural facilities. For example, Redvale landfill sends a portion of thegas and hot water generated by its gas engines to a local greenhouse.
Recently, New Zealand’s first purpose-built biogas plant for source-segregate organic waste was announced
in Reporoa. The first of its kind in New Zealand, it will accept food waste from Auckland City and from local
municipal collections to create carbon-neutral energy and CO2 for a local Turners & Growers plant andproduce digestate from the waste that will be suitable for local agricultural operations. The plant is expected
to be operational in 2022.

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| Biogas and Biomethane in New Zealand Today |Figure 4: Snapshot of biogas in New Zealand today

3.2.1 Landfill Gas Capture
Currently landfill gas capture is the largest source of biogas in New Zealand (around 3 PJ/year) (Wabnitz etal., 2011). In New Zealand 90% of municipal solid waste ends up landfill with some form of gas capture,
where it is left to decompose in sealed landfill cells, and as a result biogas is produced. The biogas produced
from landfills is produced in an uncontrolled process environment over many years. Generally, the quality of
the gas generated is much lower than the quality of gas produced in a purpose-built anaerobic digestion
plant (Bioenergy Association New Zealand, 2019).
Many of the landfills fitted with gas capture technology do not generate energy or electricity from thecaptured gas. Instead, this gas is flared to destroy methane and other harmful gases and reduce the overall
GHG emission potential of the gas. According to recent estimates, 68% of methane generated at landfills
with gas capture technology installed is successfully captured with the remainder escaping to atmosphere(Ministry for the Environment, 2019).
In the landfills where gas is captured, the biogas is generally utilised in CHP plants to generate electricity
and some useful heat.
3.2.2 Municipal Wastewater
The majority of New Zealand is serviced by centralised WWTPs, with the remaining portion on local systems
including septic tanks. Based on WaterNZ data, the total amount of wastewater treated annually isapproximately 450 million m³ per year (Water New Zealand, 2021).

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| Biogas and Biomethane in New Zealand Today |The existing biogas production from sludge digestion in WWTPs in New Zealand is approximately 0.6 PJ.
Most of the existing biogas produced at WWTPs is currently consumed onsite for electricity generation or
combined heat and power units. Grid injection from WWTPs is not feasible unless biogas production
surpasses the onsite plant consumption. Plants overseas have been successful in boosting biogas
production by co-digesting energy crops and food waste with municipal sludge. This approach is currently
being adopted by Palmerston North WWTP
3.2.3 Case Study: Fonterra Tirau Biogas Plant
Fonterra operates one of the largest anaerobic digesters in the southern hemisphere at its Tirau plant. Thisdigestion system generates biogas from whey and other high-Chemical Oxygen Demand (COD) wastewater
streams onsite, which is used to offset the natural gas consumption of the utilities plant. The plant has beenrunning for over two decades and produces around 12 TJ of biogas per year.

Figure 5: Fonterra's Tirau Anaerobic Lagoon Digestion Plant

The sludge produced from Tirau’s anaerobic lagoon is harvested and applied to maize cropping land, as anatural fertiliser supplement. The sludge has high quantities of phosphorous and lime which promote plant
growth.
Fonterra’s Darfield site has a purpose-built hydraulic digester which treats its effluent stream to produce
biogas and remove COD from its wastewater stream.

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| Availability of Feedstocks in New Zealand |4

Availability of Feedstocks in New Zealand

Several sectors generate streams of organic wastes which can become part of New Zealand’s energy mix,
namely the agricultural sector, industrial sector, and municipal sector. Determining the potential for
feedstocks for biogas production in New Zealand requires analysis of available quantity, quality, and locationof the various feedstock streams. As part of our analysis we have reviewed:•••

Factors affecting the quality of feedstock streams include the chemical composition of the feedstock,level of contamination from foreign matter, and seasonality and reliability of the stream.
o Contamination from foreign matter such as glass and plastic in source segregated organic
waste can affect the biological stability of the digester and cause technical issues such as
blockage and build-up of inorganic material.
o Seasonality affects the security of the feedstock stream.
Location of the feedstock stream, which affects transport costs, the potential for co-digestion with otherfeedstocks, and the possibility of injection into the North Island gas grid.
Sites similar to Fonterra Tirau, or the opportunities to co locate business in industrial parks, supporting amore circular economy.

Table 1 summarises the available biogas feedstocks from three key sectors; municipal, industrial, andagriculture, and the total energy these streams could produce assuming 100% of the feedstock isanaerobically digested. This has formed the basis of the uptake scenarios detailed in Section 9.
Table 1: Summary of available biogas feedstocks in New ZealandCategory

Municipal
waste

Industrial
wastewater2

Feedstock Type

Feedstock
Quantity(wet t/year)

Methane Yield(m³ CH4/wet
tonne)

Maximum3
Biogas Potential(PJ/year)

Source-segregatedfood waste

354,000128

1.5

Municipal
wastewater

N/A

N/A

0.60 – 0.871

Dairy

67,400,000

0.50 – 0.84

1.1 – 1.9

Meat

22,000,000

1.0

0.72

Pulp and paper

36,100,000

0.49

0.58

Dairy manure

5,320,00039

5 - 6.8

Pig manure

281,000

39

0.36

Poultry manure

825,000

49

1.3

Crop residue

300,000 –600,000

145

1.4 – 2.9

Agricultural

Total

12.6 – 16.9

Notes:
1. Based on NZ urban population of 5,107,700 and gross gas production of 18-26 L/PE/day (PE = Population
Equivalent)
2. Industrial wastewater quantities have been converted from cubic meters to tonnes at an assumed density of
1.1 t/m³
3. Maximum assumes 100% of the estimated feedstock size is anaerobically digested to produce biogas

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| Availability of Feedstocks in New Zealand |We have not considered the implementation or use of purpose-grown energy crops in our calculations of thetotal biogas potential in New Zealand. This feedstock has been a large part of the uptake of biogas andbiomethane in some overseas countries like Germany. Overseas the growth of energy crops has led toconflicts for land use between biogas producers and agricultural operators. Due to this our analysis has
considered repurposing existing organic wastes only.

Types of Feedstocks and Volumes
4.1 Municipal Wastewater Treatment Sludge
Anaerobic digestion of municipal wastewater solids is an established practice in New Zealand’s larger
WWTPs where biogas is currently used for combined heat and power on-site. Table 2 outlines thegeneration potential from wastewater sludge. Further detail is in Section A1.
Table 2: Summary of Biogas Potential from Municipal Wastewater Solids in New Zealand

Resource

Generation
Potential

Existing
BiogasGeneration

Maximum*
BiogasGeneration

Key Assumptions•

New Zealand’s urban
population (86.6% of
315 to 400 Nm³
the total population
CH4/t Organic(Trading Economics,
Primary Sludge
Dry Matter2019)) was used as a
(ODM)
basis for potential
generation
0.4 to0.6 PJ/year
0.6 to• Gross gas production(consumed
0.87 PJ/year
per capita, assuming
onsite)the wastewater isprocessed in a plant
190 to 240 Nm³
with anaerobic sludge
Secondary Sludge
CH4/t ODM
digestion ranges from18 to 26 L per capita
per day (Bachmann,
2015)*Maximum assumes 100% of the estimated feedstock size is anaerobically digested to produce biogas

4.2 Source-segregated Food Waste
Table 3 outlines the generation potential from municipal, commercial and industrial food waste. Essential tothe uptake of biogas production from this stream is the introduction of segregated food waste collection
schemes across New Zealand. Further detail is in Section A1.
Table 3: Summary of Biogas Potential from Organic Waste in New Zealand

Resource

Maximum*
BiogasGeneration

Key Assumptions•

New Zealanders produce 0.07 tonnes of digestible
municipal solid waste (food waste) per year per capita
Source-Segregated(Reynolds et al., 2016)
1.5 PJ/year
Food Waste• Biogas generation from Food waste is equal toapproximately 128 Nm3/tonne (Al Seadi et al., 2008;
Banks et al., 2018; Jain, 2019)* Maximum assumes 100% of the estimated feedstock size is anaerobically digested to produce biogas

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| Availability of Feedstocks in New Zealand |4.3 Crop Residue and Manure
New Zealand’s large agricultural sector provides several sources of biogas feedstock streams, including
manures from different livestock and crop residue. Table 4 outlines the biogas generation potential fromeach of these sources. Further detail is in Section A1.
Table 4: Summary of Biogas Potential from Crop Residue and Manure in New Zealand

Resource

Feedstock
RecoveryCrop Residue

5 tonnes per
hectare of arable
land

Dairy Manure

10% of total
manure produced(Ministry ofAgriculture &Forestry, 2008)

Maximum*
BiogasGeneration

Key Assumptions•

1.4 – 2.9 PJ/year••

Poultry Manure

100% of total
manure produced

Pig Manure

100% of total
manure produced

5 – 6.8 PJ/year••

22,600,000 chickens in New
Zealand produce 0.1 kg of manure
per day (Ministry of Agriculture &Forestry, 2008)•

233,000 pigs in New Zealandproduce 3.3 kg of manure per day(Ministry of Agriculture & Forestry,
2008)

1.3 PJ/year

0.36 PJ/year

Based on the region of Canterbury
only
30% - 60% of crop residue can besustainably recovered (Jain, 2019)
4,900,000 dairy cattle in New
Zealand each produce 27 - 35 kg ofmanure per day (Ministry ofAgriculture & Forestry, 2008;
Wilcock, 2006)
Only manure from the dairy shed
can be recovered* Maximum assumes 100% of the estimated feedstock size is anaerobically digested to produce biogas

4.4 Industrial Wastewater
Table 5 outlines the maximum biogas generation available from meat, dairy and pulp and paper wastewater.
These values should be evaluated with consideration that most industrial plants will not produce biogas inexcess of their process heat demand. Meat and dairy wastewater have substantial biogas potential due tothe high COD concentrations of these streams, which can be processed in a purpose-built hydraulic reactor.
The COD concentration and subsequent biogas yield of pulp and paper wastewater is too low to makeanaerobic digestion of pulp and paper wastewater a feasible option. Other waste streams and by-products
are generated by the industrial sector, such as food waste from food manufacturers, trade waste, spent grain
and yeast from distilleries and breweries, grease from grease traps and paunch grass from slaughterhouses.
These additional streams have not been quantified.
Table 5: Summary of Biogas Potential from Industrial Wastewater in New ZealandIndustry

Existing
Generation

Maximum*
BiogasGeneration

Key Assumptions•

Meat Processing-

0.72 PJ/year•

Dairy Processing

0.12 PJ**

1.1 –1.9 PJ/year••

20,000,000 m³/year of wastewater with a
COD of approx. 3600 g/m³ (A. Khan et al.,2014; Wabnitz et al., 2011)
Processed in a purpose-built hydraulicreactorBased on Fonterra only
61,000,000 m³/year of wastewater with a
COD of approximately 1800 to 3000g/m³

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| Availability of Feedstocks in New Zealand |Industry

Existing
Generation

Maximum*
BiogasGeneration

Key Assumptions•••
Pulp and Paper
Processing-

0.58 PJ/year••(R. Hamilton et al., 2011; NZ Institute ofChemistry, 2017; Wabnitz et al., 2011)
Processed in a purpose-built hydraulicreactorBased on Kinleith mill only
32,000,000 m³/year of wastewater (OjiFibre Solutions, 2019) with a COD of1760 g/m³
Processed in a purpose-built hydraulicreactorPre-treatment is required for lignocellulosic
material* Maximum assumes 100% of the estimated feedstock size is anaerobically digested to produce biogas** Excludes newly commissioned Darfield site

4.5 Forestry Waste
Biogas from forestry waste has not been quantified as rigorous pre-treatment is required to break down thecomplex structure of lignocellulose found in woody biomass. Established pre-treatment methods do exist, butthese are costly and energy-intensive. Refer to Section A1 for more information.

4.6 Conclusions
The variety of biogas feedstock available in New Zealand illustrates that the solution to expanding on biogas(and subsequently biomethane) production entails the utilisation of all feedstock types, namely livestock
manure, source segregated food waste, municipal wastewater, industrial wastewater and crop residue. New
Zealand is already producing biogas from municipal WWTP sludge, landfill gas recovery, and industrial
wastewater. Livestock manure, crop residue and source-segregated organic waste, which are not currently
an established source of biogas production in New Zealand, have the potential to produce up to 13 PJ of
biogas.
Agriculture, one of New Zealand’s largest sectors, could play a key role in producing scalable biogas andbiomethane. While this feedstock is certainly available at scale, there are logistical challenges associatedwith collection and transportation of the feedstock. Notwithstanding, the distribution of agricultural land isregionally dense. Canterbury has access to approximately 70 percent of New Zealand’s crop residue, while
33 percent of New Zealand’s dairy herds are in the Waikato (Dairy NZ, 2018). Regions like these may besuited for on-site anaerobic digestors for creation of biogas or be suited for focused feedstock collection andtransportation to be converted into biomethane in an opportune location. Industrial wastewater tends to be ata scale that constitutes reuse on site, with anaerobic digestion used as part of the treatment process. The
dairy and meat industries produce wastewater at scale, with high biological loadings and are therefore highly
suited for biogas production. Source segregation of municipal organic waste also presents a considerable
opportunity for biogas production such as at the Reporoa plant due to open in 2022, but there is still room to
expand on the use of this feedstock with the key being the establishment of a standardised organic waste
collection system in New Zealand.

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| Availability of Feedstocks in New Zealand |4.7 Limitations and Conflicts of Feedstock Use
4.7.1 Composting or Other uses for Organic Waste
Home composting and vermicomposting (using worms to digest organic materials) turns food waste andplant waste into a product rich in nutrients that are beneficial to soil. Some individual New Zealanders opt tocompost their kitchen waste themselves, which could divert a portion of municipal organic waste away frombiogas production. However, it is assumed that the uptake of home composting is minimal compared to thetotal volume of organic waste New Zealander’s produce. There are organisations in New Zealand, forexample Living Earth and WeCompost, who collect organic waste to be composted, which is a noteworthymeans of reducing waste to landfill. There has also been an increased uptake in vermicomposting in recent
years. Both of these technologies require much greater areas of land than anaerobic digestion. In 2013,35,196 tonnes of source segregated organic waste was vermicomposted (Quintern & Morley, 2014).
Nonetheless, a vast majority of organic waste still goes to landfill and thus composting and vermicomposting
is not anticipated to significantly conflict with the realistic uptake of organic waste as biogas feedstock.
4.7.2 Landfill Gas Capture vs Source Segregated Collection
Some organic waste streams already produce biogas in New Zealand through collection and disposal in
landfills with landfill gas capture systems installed. Some landfills in New Zealand use the biogas generated
to create heat and power, while others flare the gas to reduce its Global Warming Potential (GWP). Landfill
gas capture systems are on average only 60% efficient and many landfills across New Zealand are close toreaching capacity.
The advantages of anaerobic digestion over landfill gas capture is that it enables more complete capture anduse of the biogas generated, and allows for the production of digestate which is another valuable by-productof the digestion process. However, landfill gas capture is capable of producing biogas from highly
contaminated wastes with only partially digestible contents.
There is already an established roadside waste collection network in New Zealand, whereby waste istransported to landfill via pickup trucks, of which 90% of these landfills are already equipped with gas
recovery (Biogas Association of New Zealand, 2019). Establishing a household collection system whereorganic waste is diverted to a dedicated biogas plant conflicts with these existing practices. Adopting a newcollection system for organic waste will no doubt be a challenging mindset change for New Zealanders.
Therefore, it should be expected that a portion of organic waste will still go to landfill, thus conflicting with its
use as feedstock to biogas plants. Nonetheless, there are strong drivers for making the change.
4.7.3 Manure Fertiliser
While anaerobic digestion has been shown to improve the fertilisation properties of manure (Barłóg et al.,2020; Drosg et al., 2015; Möller & Müller, 2012), its use as a fertiliser via other processes, for example,
composting, presents a conflict of use. The various value-added manure fertilisers on the market should
therefore be kept in mind when considering a realistic uptake of the use of manure as feedstock for biogas
and biomethane production.
4.7.4 Anaerobic Digestion in the Context of the Waste Management Hierarchy
The production of biogas and biomethane relies on the continued creation of organic waste products forcollection and processing. While the creation of digestate to be applied back to land from this waste createsa circular economy for this waste, we should keep in mind that a more effective strategy for reducing theimpacts of waste to our environment is reducing the amount of waste generated in the first place.
Biogas feedstocks like food waste and industrial wastewater are unlikely to disappear , but changing waste
management practices around New Zealand could impact the amount of these feedstocks available.

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| Biogas and Biomethane Processing |5

Biogas and Biomethane Processing

5.1 Feedstocks to Biogas
Biogas is created through the decomposition of organic matter. Micro-organisms digest the organic material
in the absence of oxygen and as a result methane, carbon dioxide and other compounds are produced. The
exact conditions inside the reactor encourage different kinds of bacteria to produce different organic
compounds, and in some cases can inhibit these same bacteria. The key to designing a successful
anaerobic digestion system is understanding how to optimize the conditions in a reactor for the selected
feedstock to enable sustainable, effective, and balanced conversion of organic waste to biogas throughout
each of the key stages of conversion.
There are four main steps in the conversion of organic material to biogas, undertaken by three separatekinds of bacteria. Detailed steps are outlined in Section A3. A simplified diagram is shown in Figure 6:

Figure 6: Simplified diagram of the main stages of methane-yielding anaerobic digestion (Mes et al., 2003)

Each of these different bacteria work at different rates and prefer slightly different conditions to grow andconvert their food into intermediate products for the next group of bacteria (Achinas et al., 2017). The
conditions inside an anaerobic digester are often optimized to try and even out the speed of each reaction
and achieve the highest overall conversion speed, but this is a dynamic exercise. The most important groupof bacteria in terms of methane production, the methanogens, are often the slowest and most sensitive tochanges in digester conditions and commonly deemed the rate limiting step. (Nsair et al., 2020).
Like all biological processes, there are several variables that need to be tightly controlled for these different
bacteria to operate effectively and maintain the balance in the digester.
Before we discuss how these conditions can be optimized in the design of a reactor, let’s review which
conditions and variables affect the digestion process the most (Table 6).

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| Biogas and Biomethane Processing |5.1.1 Process Variables and Additives
Table 6: Feedstocks to Biogas Process Variables and Additives

Variable

Conditions

Temperature

Methane bacteria can be either:• Psychrophilic (10-20°C)• Mesophilic (20-40°C, or 30-38°C with the latter more common)• Thermophilic (50-60°C)
Reaction to produce biogas is exothermic however external heat is usually stillrequired.

pH

Most microorganisms grow best in neutral pH conditions.
pH control can be done in the following ways dependent on reactor design:• Extra buffer capacity• Adjusting or stopping the feed into the reactor• Direct dosing of the reactor with chemicals

Organic Loading
Rate andFeedstock Control

Nutrients

The Organic Loading Rate (OLR) for a digester system is a measure of thedigestible material feed rate, or the feed rate of volatile solid materials
Generally, systems are designed for a set OLR and it is not easy to implement
process changes to boost this figure after an operating scheme has been selected
High C/N (carbon to nitrogen) ratios mean good biogas yields from feeds, and lower
C/N rations mean reduced biogas yields.
Sulphur:• There is a minimum level of sulfur compounds required for the reaction pathway
from organic waste to biogas to proceed• High concentrations of sulfur compounds in solution interfere with themethanogenesis stage of the reaction, preventing maximum conversion
Ammonia• Optimum ammonia levels can keep the reaction chain stable and buffer themethanogenic stage of the reaction• Too much ammonia, especially at pH below 7, can be toxic to bacteria

Further detail on the process variables is in Section A3.
5.1.2 How to Choose a Plant for your Feedstock
At scale, there are only a handful of different processing arrangements widely used to create biogas fromorganic waste. This is because these designs have proven to be the most efficient and the most costeffective after years of operation in overseas markets. Over the past 30 years, plant designs have been
continually refined and developed to provide the most effective biogas conversion for every dollar spent.
Consideration of the most desirable processing arrangement, includes the following factors:••••

Types of feedstocks available
Available land or cost of land
Access to markets for energy products and digestion by-products
Acceptable level of technical complexity.

Types of feedstock include:••••

Industrial effluent
Energy crops
Animal manure
Energy crops

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| Biogas and Biomethane Processing |The factors that influence the way the processing scheme is designed, and the decisions that investors andoperators of anaerobic digestion facilities make at the start of any project to ensure that a best-fit installationis achieved will be reviewed.
5.1.3 Pre-treatment Methods for Feedstocks
Wet digestion systems will often require extensive pre-treatment of feedstocks to prepare them for mixing
and processing in the anaerobic digester (Ariunbaatar et al., 2014). Table 7 outlines the broad categories offeedstock pre-treatment. Further detail on the pre-treatments is in Section A3.
Table 7: Pre-Treatment Methods for Feedstocks

Treatment
Preparing Feedstocks for
Digestiona. Mechanical PreTreatment
Optimising Feedstocks for
Digestion:a. Thermal Pre-Treatment

b. Chemical or Biological
Pre-Treatmentc. Electrical Pre-Treatment

d. Pasteurisation

Objective/Process
Pre-treatment to make organic wastes suitable for biological digestion –removing impurities and processibility••

Usually first stage of pre-treatment
Physically screen the feedstock for non-organics or impurities andthen physically re-size solid feedstocks
Pre-treatment prior to digestion to make it easier to process into methaneby the bacterial cultures inside the reactors••

In feedstocks that contain biomass with resistant/complex cellstructures or quantities of lignin, thermal pre-treatment can assist
acidogenic bacteria in decomposing feedstocks by breaking up
molecular structures before the feedstock enters the digester
Use of chemical reagents to break up cellular structures and reducethe downstream work for the anaerobic digester

Two main types:• Microwave treatment (where feedstocks are exposed to microwave
radiation)• Ultrasound treatment (where feedstocks are exposed to highfrequency vibrations)• Removes any possible biological contaminants from feedstocks
before passing them into a digester• Usually involves elevating the feed material to a set temperature andkeeping the temperature stable for a set period of time
• The higher the temperature, the shorter the holding duration (Wood
Environment & Infrastructure Solutions UK Limited, 2019).

5.1.4 Designing the Best Digestion Process
Conversion of organic material into biogas can be done in a number of ways, and there are many ways toconfigure a biogas plant to process organic materials. For maximum yield and plant utilization, the key is todesign the biogas plant around the type of organic waste it will be processing. Then, depending on scalerequired and acceptable operational complexity, the plant can be tweaked and adjusted to be economicallyand practically successful.

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| Biogas and Biomethane Processing |Figure 7: Digester Classifications by Total Solids % (Van et al., 2020)

Table 8 briefly compares the different digestion processes. Further detail is in Section A3.
Table 8: Comparison of Digestion Processes

Process
Dry vs Wet Digestion• Used when TS% >20
Dry AD
Technologies • Occurs in plug flow systems or batch-type reactors• More labour-intensive than wet digestion as feedstocks cannot be easily pumped
and are often manually moved usually via front end loader• Three categories;
Wet ADo Suspended Solid digestion (where 15% > TS >5%) (common forTechnologies
wastewater treatment sludge and food waste where there is a lot ofsuspended organic matter) oro Attached Medium digestion (TS <5%) (predominantly liquid organics
streams)o High-rate Hydraulic digestion (TS <1%) used when organic material ismostly in dissolved state• Involves a much higher amount of fluid entering and leaving digester (comparedwith dry)• Feedstock can be treated like a liquid allowing for more autonomous control andprocessing
Batch vs Continuous Digestion• For high solids feedstocks (TS > 30%)
Batch
• Low-CAPEX alternative to a fully mixed reactor system or plug flow reactor• Must be initialized with a sample of bacteria from a completed batch• Processor easy to construct and operate• Requires more space than continuous• When feedstock is low in solids content (TS <15%)
Continuous• Suspended organic matter is circulated and mixed with bacteria to achieve a moreor-less homogenous solution• Continual supply or organic material into reactor
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| Biogas and Biomethane Processing |Process• Biogas/digestate is continually harvested from the reactor• Always maintains a level of the required bacteria
Thermophilic vs Mesophilic Digestion• Thermophilic digesters can produce much larger yields of biogas and process
Thermophillic
more organic material than mesophilic digesters with similar volumes (Bekkering etal., 2010)• Requires more energy than mesophilic process to maintain the higher digester
temperature, which creates a larger parasitic load on energy produced from biogas
production• More susceptible to temperature swing upsets than mesophilic digesters• Lower yields of biogas than thermophilic
Mesophillic• Can’t process as much organic material as thermophilic digesters• Less susceptible to temperature swing upsets than thermophilic digesters
Single-Stage vs Multi-Stage• Simpler processing arrangement where all four reaction steps proceed in the same
Single-Stageconditions• Less capital intensive, but reaction proceeds overall at a slower speed• Larger equipment needed to facilitate longer residence times• Require more upfront costs and smarter plant control to operate efficiently
Multi-Stage
compared to single stage• Multiple unit operations i.e. there are multiple digestion stages for the feedstock• Allows stage of the reaction to proceed at optimized rates and decreases theoverall retention times of the feedstock which decreases the total installed volumeof the digester(s) (McConville et al., 2020).
• This in turn reduces the footprint of the AD plant and can be installed in smaller
land space.
.

5.2 Typical Anaerobic Digestion Processes + Costs
Table 9 summarises the best-fit standardised processing configuration for all feedstock sources. Further
detail on the sources and their properties is in Section A4.
Table 9: Standard Digester Technology/Configuration by Feedstock Source Type and Volume

Feedstock

Technology Choice
Small (<5,000 t/year)

Medium (<25,000 t/year)

Large (>30,000 t/year)

WWTP
SludgeSingle-stage fully-mixed
digesterSingle-stage fully-mixed
digester

Multi-stage fully-mixed
digester

AnimalManureFarm-scale anaerobic
lagoon or PFR digester

Single-stage fully-mixed
digester or continuous dry
reactorMulti-stage fully-mixed
digesterFood Waste

Dry batch reactor

Single-stage fully-mixed
digester or multiple dry batchdigesters

Multi-stage fully-mixed
digester

Crop Silage

Dry batch reactor

Single-stage fully-mixed
digester or multiple dry batchdigesters

Multi-stage fully-mixed
digester or large-scale dry
batch reactors

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| Biogas and Biomethane Processing |Industrial
Wastewater1

Single-stage small HighRate Hydraulic
Digesters

Single stage High-Rate
Hydraulic Digesters or large
Anaerobic Lagoons

Multi-stage High-Rate
Hydraulic Digesters, or large
Anaerobic Lagoons

5.2.1 Capital Costs

Figure 8: Capital cost ($NZD) vs biogas plant capacity (Nm³/h) for dry digestors, single-stage fully mixed reactors andmulti-stage fully mixed reactors

Figure 8 shows the magnitude of capital costs associated with each main type of digester for solid organic
wastes (Cleanleap, 2013; Moriarty, 2013; SAMCO, 2019; Scion, 2013; Spencer, 2010; Truong et al., 2019).
Please see Section A4 for more information on these estimate ranges.
5.2.2 Operating Costs and Revenue Streams of Biogas Generation
There are many different costs and revenue streams associated with the operation of a biogas production
plant. These can positively or negatively affect the economics of operating the facility and all contribute to thefinancial feasibility of a biogas installation. Below we have identified the main ongoing costs and sources ofrevenue for a biogas installation, and a commentary on how these would be quantified in a New Zealandcontext.
a. Gate Fees and/or Purchasing Feedstocks
Gate fees and similar revenue models are the driving force behind a large number of alternative waste
disposal technologies like Waste to Energy plants in the UK. Collecting payment for accepting andprocessing biogas feedstocks is a great way to generate revenue for some biogas feedstocks, as disposal of
most feedstocks will incur a cost to dispose of via other means e.g. landfilling. Currently in New Zealand,gate fees for landfills can be in the range of $100-$150/ tonne of waste which includes a waste disposal levy.

1
Note: with high-rate hydraulic systems (TS <1-2%), the feed rates in tonnages should be considered thesolids feed rate only – industrial wastewater digestion plants can process millions of tonnes per year of liquid
feed, but average liquid residence times are less than a day.

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| Biogas and Biomethane Processing |New Zealand’s waste disposal levy is being increased gradually from $10 /t to $60 /t by July 2024 (Ministry
for the Environment, 2021).
This revenue stream will not feature as prominently for some feedstocks e.g. manure or crop residue which
are currently left in fields or burned as a waste product. To collect these feedstocks, the biogas plant would
either have to pay for the feedstocks to be supplied or exchange processed digestate for raw biomaterials as
is done in Denmark (Ministry of Foreign Affairs of Denmark, 2021b).
b. Sale of Biogas or Biomethane
The biogas generated by the plant is the primary product of the digester plant. The biogas generated caneither be sold as-is or refined into biomethane for gas grid injection and use.
The average wholesale price for natural gas in New Zealand during 2020 was 2.38 ¢/kWh (excluding GST),
or $6.60 /GJ (Ministry of Business Innovation & Employment, 2021), not including an extra $3 /GJ including
current ETS changes and transmission costs. In future years, it is expected that the realistic sale price forgas could increase well beyond $15-20 /GJ which would help the economics of these installations (Silk et al.,2021).
c. Sale of CHP
In other plants, the biogas generated can be burned for direct generation of electricity and power. In mostmodern biogas CHP engines, around 45% of the energy in the fuel can be converted into electricity (Clarke
Energy, 2021). This can then be supplied to the grid and sold on the spot market, or used to power onsite
equipment like in most of New Zealand’s WWTPs.
The average wholesale spot price for electricity in 2020 was around $0.14/kWh, which after accounting for
efficiency generates $15 per GJ of gas generated. In recent months, average monthly wholesale spot prices
have reached $0.25 /kWh, which would provide $27 per GJ of gas generated (Electricity Authority (Te Mana
Hiko), 2021). The waste heat generated by the engines can also be used for other purposes e.g. hot water
heating for greenhouses.
In New Zealand’s current energy market, electricity generation is currently more profitable than biomethane
production per GJ. However, the electricity spot price market is subject to frequent change and this elevatedprice is unlikely to continue indefinitely, and long term predictions suggest prices of around $80 /MWh are
more realistic, which would equate to a sell price of $8.5 per GJ of gas generated.
d. Sale of Digestate
In some countries with legislation to support the uptake of standards like Publicly Available Standard (PAS)110, digestate produced from an anaerobic digestion facility can be certified and sold as a value-adding
product (Waste & Resources Action Programme (WRAP), 2014). If the digestate is being used to supply
specific nutrients or high-quality material is required, additional processing of the digestate may necessary.
In New Zealand, no such legislation or support for equivalent standards exists currently and the use ofdigestate as a fertiliser will likely be dependent on individual supply agreements (Tinholt, 2019). Biosolids
generated from WWTPs in New Zealand can be used for land rehabilitation after secondary treatment(NPDC use a drying step and sell their biosolids as Bioboost (Bioboost, 2017), HCC supply vermicomposted
digestate from their WWTP for land rehabilitation (Murray, 2017)), but likely there would be no financial
compensation for untreated anaerobic digestate supply given its classification as a waste product currently,
but would avoid the operation paying landfill disposal costs.
Achievable digestate revenues in New Zealand for source-segregated digestion operations are around $20 /t
including transport and spreading costs (Bouskova, 2021). Revenues of $10-$30 /t would generate large
revenue streams for these operations. Sale of certified digestate supported by specifications like TG8 in New
Zealand would enable higher prices to be charged for the material, depending on its composition. Further
analysis should be done to determine achievable premiums for this material.
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| Biogas and Biomethane Processing |e. Sale of Carbon Dioxide
If the decision is made to install an additional CO 2 recovery plant to extract food-grade carbon dioxide forsale, this can add an additional revenue stream to the operation of the plant. Generally, the yield of carbon
dioxide from biogas is around 25-35%.
Food-grade CO2 can be sold for between $200 and $500/tonne based on current industry trends andallowing for distribution costs.
In New Zealand, the majority of our CO2 supply is generated at Refining NZ, located at Marsden Point, andthe domestic market for CO2 is expected to grow in coming years (Underhill, 2018). As Marsden Point plans
to transition towards a smaller operation in coming years, biogenic sources of CO 2 could become valuable.
f. Operations and Maintenance Costs
Operating the anaerobic digestion process and keeping the plant equipment maintained will be an ongoingcost to the plant. Depending on the degree of process automation, operators may be required to handle andtransport feedstocks, adjust digester conditions and handle digestate as well. In a fully automated plant, only
a handful of operators and technicians will be required to control the digestion process and fix any equipment
faults. For most industrial plants of this scale, operational and maintenance costs are equal to 4-6% of theoriginal capital cost per annum (Cleanleap, 2013).
g. Electricity Costs
In general, we would expect most biogas plants to be self-sufficient for electricity and utilise some of thebiogas produced (generally 7-15% (Cleanleap, 2013)) to supply the plant with heat and electrical power, soelectrical costs should be minimal over a year of operation. However, an electrical connection would still be
required for non-production periods and for start-up etc when the plant cannot produce its own energy.
Plants should consider the relative costs of CHP engines and reduction in biogas yields for self-sufficiency vspurchasing grid electricity in a detailed economic analysis.
5.2.3 Other Operational Costs
Some operational costs vary massively across individual installations and can either enable or prohibit
economic operations. These include:•

Energy Requirements – as more automated and efficient processes are pursued to maximise biogas
yield from feedstocks, the amount of energy consumed by the process (heating, electrical power,
mechanical or thermal pre-treatment) compared to the amount of energy generated by biogas can start
to decrease energy yields of the plant.

•

Labour costs – smaller-scale systems with minimum automation require higher degrees of manualintervention to keep the process running successfully. Relatively dry feedstocks rule out the use of pipes
and pumps as transport equipment, in which case bucket loaders/front end loaders will be needed tomove organic material between stockpiles and digesters, which means additional operators and staff. In
this way, upfront capital spend can be the inversely proportional to ongoing operational costs.

•

Chemical Costs – dosing chemicals or enzymes into the process to increase yields of biogas can be asignificant drain on bottom line profit from the sale of biogas products, but some feedstocks may not beable to be processed without them. When assessing a feedstock as an input to a biogas plant, thechemical requirements should be well understood to give an honest reflection of plant profitability. Thiscan also be addressed by mixing feedstocks with complementary properties.

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| Biogas and Biomethane Processing |•Logistical Costs – because the majority of biogas plants utilize waste organic materials, it is necessary tounderstand how/where these waste materials are generated. For feedstocks generated over a wide area
e.g. manure or municipal food waste, understanding how easily these can be collected and transported
to a central processing location is vital. Additionally, once the biogas is generated, consideration of how
this energy can be transported and sold is crucial, as connecting poorly-placed plants to local or nationalenergy infrastructure can be prohibitively expensive (Chen & Liu, 2017; Hengeveld et al., 2020).

5.3 Biogas to Biomethane Processing
Biogas produced from the breakdown of organic materials will contain a variety of components that can bebeneficial or detrimental to further uses. Raw biogas will typically contain methane (CH 4) concentrations
greater than 50mol%, with the remainder being comprised mostly of carbon dioxide (CO 2). The CH4 and CO2
content of raw biogas can be considered as potential value streams for biogas upgrading schemes.
Table 10: Methane and carbon dioxide content (% by volume) of landfill gas and biogas from anaerobic digestion

Component

Landfill Gas(Nyamukamba et al., 2020; Sun etal., 2015)

Biogas from AD% by mol at standard conditions(Al Seadi et al., 2008; Nyamukamba
et al., 2020; Sun et al., 2015)

Methane30-60 mol%

50-90 mol%

Carbon dioxide

15-40 mol%

10-45 mol%

For biogas to be utilised as fuel in reticulated natural gas networks, the calorific value (CV) requires
upgrading to meet the appropriate gas specification. In New Zealand, all reticulated natural gas is required tomeet constituent and Wobbe specifications according to NZS 5442-2008.
5.3.1 Gas Quality
The New Zealand standard “Specification for Reticulated Natural Gas” is NZS 5442: 2008. This specification
states the requirements for the safety and suitability of methane-based gas transported and supplied for use
in natural gas burning appliances and equipment. NZS 5442 Section 1.2.1 states that this specification
applies to biogas production sources that are blended into open access gas systems.
The key requirements for biogas in this specification is the Wobbe Index, which must be between 46 and52 MJ/m3, with a maximum relative density of 0.8. This corresponds to a CV range of 35.2 to 46.5 MJ/m3.
The hydrogen sulphide content must not exceed 5 mg/m3 and the water content must not exceed
100 mg/m3. The oxygen limit is 0.1 mol% with an exception for low and medium pressure networks where
the oxygen limit is 1.0 mol%. Gas must also be free from other contaminants such as particles, heavy metals
and gum forming constituents. Biomethane processing plants are likely to have additional equipment
requirements to maintain oxygen levels below 0.1mol%. Most biomethane processing can typically provide
less than 1mol% oxygen without additional equipment.
Typical biogas sources produce gas which has a CO 2 content of approximately 30-45 mol% and dependingon the biogas feedstock can include a variety of other contaminants. The NZS 5442 specification requires
biogas to biomethane processing to produce a dry gas, where the majority of CO 2 has been removed andany other contaminants such as hydrogen sulphide or Siloxanes have also been thoroughly removed.
The gas distribution or transmission network owner will insist on gas quality monitoring technology as part ofthe biogas processing plant to ensure that the gas specification is constantly met. The equipment design willneed to allow for any “off specification” biomethane to be rejected back to the anaerobic digestion plant or aflare (generally unacceptable).

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| Biogas and Biomethane Processing |Biomethane may only be injected into a reticulated gas network if it constantly meets the New Zealand gas
quality standard. This is a legal requirement for the network owner to supply gas to consumers. If the gas
does not meet the specification requirements at any time, then the biomethane injection plant must be
designed to reject and/or recycle the non-compliant gas.
5.3.2 Gas Treatment
There are three steps when upgrading biogas to biomethane and exporting, detailed in Figure 9:•••

Pre-treatment (cleaning)
Biogas to biomethane processing (upgrading)
Network injection

Figure 9: Typical biomethane upgrading process
Depending on the type of feedstock the biogas is produced from, there can be smaller concentrations ofcomponents such as hydrogen sulphide (H2S), silicon organic compounds (siloxanes), oxygen (O 2), water(H2O), ammonia (NH3), Nitrogen (N2) and particulates that are viewed as contaminants to the raw biogas(Sun et al., 2015b). The actual concentration of these contaminants varies depending on the feedstock
quality but are typically viewed as detrimental to downstream equipment.

Table 11: Contaminants in raw landfill gas, biogas from AD, and limits for reticulated gas in NZ

Landfill Gas% by volume atstandard conditions

Biogas from AD% by volume atstandard conditions

Reticulated NG% by volume atstandard
conditions

Nitrogen – atmospheric
N2 is introduced during
AD feeding or landfill
gas extraction

0-15 mol%

0-1 mol%

Not specified

Water vapour – ADprocess is saturated &reactor temps are

1-5 mol%1

Contaminant<0.00001 mol%2
1-5 mol%1

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| Biogas and Biomethane Processing |Contaminant

Landfill Gas% by volume atstandard conditions

Biogas from AD% by volume atstandard conditions

Reticulated NG% by volume atstandard
conditions<2 mol%<2 mol%<1%

typically higher thanambient
Oxygen – atmospheric
O2 is introduced during
AD feeding, H2S control
or landfill gas extraction(low and medium
pressure grids)<0.1%(all other cases)

Ammonia – ADtreatment of feedstocks
with high levels of
nitrogen

0-5 mg/m³0-100 mg/m³

Not specified

Siloxanes – caused by
the digestion of silicone
compounds in landfills
or WWTP sludge

0-50 mg/m³

0-20 mg/m³

Not specified

Hydrogen sulphide –caused by the digestionof sulfide/protein
containing feedstocks

100-10,000 mg/m³0-1000 mg/m³<5 mg/m³

Hydrogen – from thedigestion of sugars &VFA’s

0-3 mol%<1 mol%<0.1 mol%

Total Cl

0-100 mg/m³0-100 mg/m³<25 mg/m³

Volatile Organic
Compounds – typicallyfound in landfill gases<2,000 mg/m3-

Not Specified

Sources(ATSDR, 2001;
Nyamukamba et al.,2020; Sun et al.,2015(Soleilhavoup &DESOTEC, 2020))(Al Seadi et al., 2008;
Nyamukamba et al.,2020; Sun et al., 2015)(Standards New
Zealand, 2008)(WWTP sludge canproduce high levels ofSiloxanes)

1Temperature dependent

2

At standard conditions

5.3.3 Pre-Treatment
A summary of the different pre-treatment options for contaminants is included in Table 12. Further detail of
pre-treatment options is described in Section A5.

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| Biogas and Biomethane Processing |Table 12: Pre-treatment Summary
Impurity

Technology

Outlet levels

Comment

H2 S

Biological desulphurisation< 50 ppm

Most common

Iron Chloride

100 - 150 ppm

Used for high quantities

Impregnated Activated Carbon< 0.1 ppm

Common prior to PSA

Iron Hydroxide or oxide< 1 ppm

Finite regeneration cycles

Sodium hydroxide Scrubbing< 1 ppm

Regeneration not possible

Activated carbon< 0.87 ppm

Carbon unable to regenerate. Sensitive
to humidity

Cooling

26% - 99% removal-27°C to -70°C<1000 ppm

Outlet levels will be dependent oninternal surface area of the desiccant andprocess parameters

Adsorption with Silica Gel or
Aluminium Oxide

Dew Point -10C to -20C

At atmospheric pressure

Absorption with Triethylene
glycol or glycol

Dew Point -5C to -15C

At atmospheric pressure, Regeneration
required to 200C

Siloxanes

O2/N2

Activated carbon
Molecular sieves

Membranes
H2 O. (Sun et al., 2015a)
5.3.4 Biogas to Biomethane Processing / Upgrading
Table 13 gives a brief overview of the major commercial processing technologies used to upgrade raw
biogas to biomethane. The best choice is generally determined by the composition of the raw biogas and thespecific end use requirements for the biomethane. Further detail on these processes is in Section A5.
Table 13: Biogas to Biomethane Processing Technologies

Process

Key Points

Pressure Swing
Adsorption (PSA)••

Water Scrubbing•••
Chemical Scrubbing•

Different sized gas molecules selectively adsorbed to a solid surface at highpressure then released using a reduction in pressure.
Used to upgrade raw biogas by adsorbing other gas molecules like CO 2, N2,
and O2 from the larger methane molecule
Direct contact between the raw biogas and water solvent dissolves CO 2 andother contaminants, such as H2S (up to 0.05%mol), ammonia andparticulates, from the biogas stream
Operating pressure for the process is between 4 – 10 barg
Process takes place in a scrubbing column where water is sprayed
downwards while raw biogas is directed upward
Similar principle as water scrubbing except the solvent is a chemical mixture
which reacts to absorb components from the gas with the solvent
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| Biogas and Biomethane Processing |Process

Key Points

Membrane Scrubbing•

Physical Scrubbing•

Uses selective permeability to separate larger molecules such as methaneand smaller molecules such as CO2, H2S, and O2 (Angelidaki et al., 2018).
Same as pressurised water scrubbing but using organic solvents such as“Selexol” for enhanced selective absorption of CO2

There are other methods to process impurities from biogas such as cryogenic separation, in-situ removal,
biological methods and hydrate separation that have yet to be made readily available to the commercial
market (Sun et al., 2015b). These emerging technologies are not outlined in this study but should beconsidered as part of future biogas production schemes as the technologies evolve and become morecommercially available.
5.3.5 Network Injection Equipment
Once the biogas has had the majority of CO2 and other contaminants removed to upgrade the CV, thebiomethane can be injected into the natural gas network. Like other natural gas producers, the biomethane
producer is required to ensure the biomethane adheres to NZS 5442 prior to network injection. Certain
equipment is required by the network operator to enable biomethane injection into the network. This injection
equipment can be located at the biomethane production facility or at the biomethane injection point (BIP) tothe network. The potential ownership models for this equipment is outlined in Section 3.C.iii.
Table 14 outlines the different types of network injection equipment. Further detail on these processes is in
Section A5.
Table 14: Network Injection Equipment Summary

Network Injection
Equipment

Summary

Gas Chromatograph(GC)•

Gas Enrichment
Pressure Compression
or Regulation

•
•
•
•

Gas Metering•

Gas Odorisation•

Network Isolation
Valve andInterconnection•••

Measures the components of the biomethane and ensures the gas meetsthe specification essential for reticulated customer use
Provides an online measurement of gas quality
Based on composition and Wobbe Index, biomethane can be dosed withpropane to improve energy content for compliance with NZS 5442
Compressors can be controlled to ensure that the maximum allowable
operating pressure (MAOP) of the network is not exceeded
A second stage of pressure regulation such as a pressure relief valve will be
required according to either AS/NZS 2885 or AS/NZS 4645
Accurate metering allows network operators to measure the quantity of gas
entering the network and allocate gas sales to specific producers
As part of the requirements of NZS 5442 for reticulated gas networks,
natural gas must be odorised to be able to identify gas leakage
The recognisable smell is the odorant added to natural gas
To connect a biomethane production facility to an existing network, a BIP will
require interconnection equipment
Depending on the chosen location of the BIP, the equipment required toconnect to the existing network could include modifications to an existing
delivery point

5.3.6 Capital Cost of Biogas Upgrading and Key Cost Drivers
Every biomethane processing scheme will be slightly different; however, most will fit into three categories
according to the source of the biogas feedstock:•

WWTP

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| Biogas and Biomethane Processing |• Landfill• Anaerobic Digestion
Table 15 outlines the capital cost for biogas upgrading. Further detail is in Section A5.
Table 15: Biogas Upgrading Cost Matrix ($NZD)
Biogas Processing Plant Costs

Biomethane Injection Costs

Raw Biogas source
Biogas(Nm3/hr)

40-400400-1000
1000-1500

AD

Landfill

WWTP

1.9M
2.4M 2.9M
3M4.2M~2M
2.49M3.13M
3.22M4.54M~2M
2.47M3.07M
3.17M4.46M

Components
Food
Grade
CO2

Biomethane(Nm3/hr)Compression

Metering &Regulation

Injection
Point

0.5M - 2M

0.3-0.5M

0.5M 1M

Unit

Range

20-2400.7M –
1.4M

200-600
500-900

Table 16: Additional Costs

Additional Requirements$/unitOdorisation$ 100kea.

± 10%Distribution Pipeline$ 300kkm± 20%Transmission Pipeline$ 750kkm± 30%

Gas Chromatograph

$ 80k

ea.

± 10%

Land use

$ 300

m2

± 30%

Telemetry Connection

$ 45k

ea.

± 10%

Compression to IP pressure (19.6barg)$ 0.5M – 2M

ea.

± 50%

References: (Sun et al., 2015a) , (Pentair Haffmans, 2021), (Galileo Technologies, 2020), (Sauer Haug Compressors,2021), (Xebec, 2020), (Firstgas Ltd, 2020a)

5.3.7 Operational Costs for Biomethane Production and CO2 Production
Aside from regular operations and maintenance costs which annually total around 4-6% of the plant’s capitalvalue (citation needed), electrical consumption for biogas upgrading and CO2 separation requires around
0.4 kWh/Nm3 of biomethane produced. At 15c per kWh, this costs 6c per Nm3 of biomethane produced.
Additionally, electrical consumption for CO2 upgrading comes to around 420 kWh per tonne CO2 produced(Jackson & Brodal, 2019). At 15c per kWh, this costs an additional $63 per tonne of CO2 produced.

5.4 Transporting and Using the Gas
During the conceptual phase of a biogas project, the location of the biogas production source needs to beconsidered based on feedstock, but additional consideration for proximity to existing natural gas reticulation
networks is also required. The gas transmission or distribution network operator in the vicinity of a proposed
biogas production site should be consulted early in the conceptual phase of designs. The network operator
can help provide network details to be used by a biogas project developer to consider opportunities andobstacles of a site location. Below are some factors to be considered when locating a BIP:
5.4.1 Network Pressure
The New Zealand gas transmission and distribution systems are operated at very different pressures. Gas
distribution networks are typically lower pressure networks which supply most gas customers. There areseveral operating pressure ranges for distribution networks across the country, the highest pressures for
distribution networks are 19.6 barg, while most networks operate below 10 barg. Distribution networkpressures are location specific and can vary even within a single town. New Zealand gas transmission

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| Biogas and Biomethane Processing |pipelines typically operate at pressures from 20 barg up to 86 barg. Each location specific gas network
operating pressure will define the required biomethane injection pressure.
Raw biogas typically leaves the production process at pressures up to 10 mbarg (Lemmer et al., 2017).
Biogas processing equipment needs to boost the raw biogas to pressures between 4- 20 barg depending on
the biomethane processing elements (UNIDO & German Biogas Association, 2017). Biomethane processing
technologies should achieve outlet pressures suitable for injection into most distribution systems without
additional compression.
Across the country, pressures in gas transmission pipelines vary across different regions. For example, atransmission pipeline near Auckland can operate at pressures between 66 barg and 86 barg, but most gas
producers around Taranaki inject into transmission pipelines that operate between 42 and 48 barg (Firstgas
Ltd, 2020b). If biomethane is to be injected into the transmission system a second stage of gas compression
is required which will add complexity and cost to the biomethane scheme.
5.4.2 Biomethane volume to be injected and Network Capacity
The amount of gas consumed within transmission and distribution networks is metered and understood
through annual network analysis to ensure that minimum pressures are consistently exceeded (Firstgas Ltd,
2020b). The amount of biomethane generated by any proposed scheme and the potential hourly variability ofthis volume is essential when considering potential injection locations for the gas network owners’ system.
Most gas transmission pipelines experience large gas throughput on an hourly basis and most biomethane
plant outputs should be able to be accommodated without the risk of oversupply. However, when connecting
a biomethane plant to a local distribution system, the risk of oversupply can be material. Some distribution
networks may only supply gas to a few customers or there may be defined times when even large numbersof gas consumers have little or no demand for gas (Firstgas Ltd, 2020a). In situations where consistent
volumes of biomethane are injected into a network with little demand, the system pressure may increase to
the point where no further gas can be injected and the biogas plant would be backed out, shut off or diverted
to flare or put into storage at additional cost (but with a better environmental outcome).
It is important to understand the biogas volumes being generated at an hourly level and match this against
the gas being consumed within the gas network system being supplied, to ensure that the gas may beconstantly injected without interruption. Gas transmission networks are typically able to accommodate large
biomethane quantities. Gas distribution networks will require network capacity analysis to prove that an
injection point can accommodate the supply of biomethane.

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| Biogas and Biomethane Processing |5.5 Carbon Emissions from Biogas and Biomethane vs Regular Material
Disposal Pathways
The overall emissions impacts of diverting organic waste from landfill or other disposal pathways for the
purpose of biomethane generation is made up of several connected areas, illustrated in Figure 10:

Figure 10: Emissions impacts of diverting organic waste from landfill or other disposal pathways

5.5.1 Emissions from Processing of Feedstocks
In the processing of feedstocks to biogas in an anaerobic digester a percentage of the biogas generated isassumed to escape to atmosphere, similar to the way that composting operations are treated from anemissions perspective. In MfE’s 2020 emission factor guidance document, there is an emissions factor given
for anaerobic digestion (0.02 kgCO2e/kg) and composting (0.172 kgCO2e/kg) of waste. The factor for
anaerobic digestion assumes an 80% reduction in fugitive methane emissions compared to composting andnone of the nitrate emissions associated with composting.
5.5.2 Emissions from Use of Biogas or Biomethane
In New Zealand, biofuel use is given a blanket emissions factor of 3.42 kgCO 2e /GJ. However, the only
biofuels included in MfE’s current guidance document are biodiesel and bioethanol. CO2 emissions from the
combustion of biofuels are not counted when calculating their emissions factors under the guidance of IPCC,
so these factors only consider other GHG produced via combustion.
In other overseas emissions reporting guidelines e.g. the United States (via EPA guidelines) or the UK (via
the Department of Business, Energy & Industrial Strategy) biogas and biomethane are given a significantly
lower emissions factor (0.106 kgCO2e /GJ per UK guidelines) than liquid biofuels (Department for Business
Energy & Industrial Strategy, 2020). The exclusion of a more specific emissions factor for biogas orbiomethane in New Zealand’s emissions factor guidance documentation is likely because the use of thesefuels at present is limited.

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| Biogas and Biomethane Processing |5.5.3 Transport Emissions from Biogas Feedstock Collection
If the feedstocks for the biogas processing operation are not already being collected and transported to adisposal location, the additional emissions generated by feedstock collection should be considered.
Depending on the type of vehicle, emissions factors can vary between 0.986 kgCO 2e per km for a new diesel
truck with capacity of <20 t, to 0.088 kgCO2e per km for an electric truck with a capacity of <15 t.
5.5.4 Emissions Avoided by Displacing Fossil Fuels/Grid Electricity
If the biogas or biomethane generated is used to offset natural gas or electricity, then we can calculate anemissions abatement by comparing the energy displaced and the relative emissions factors. Natural gas has
an emissions factor of 54 kgCO2e /GJ, and electricity has an emissions factor of 28.2 kgCO2e /GJ which areboth considerably higher than the emissions factor for biomethane. Swapping to biomethane from natural
gas can help reduce stationary energy emissions for a gas user by up to 99.8%.
5.5.5 Emissions Avoided by Capturing Biogenic Methane from Organic Wastes
In New Zealand, most landfills have LFGR installed which means the majority of biogenic methane
generated is destroyed before it escapes to atmosphere. In landfills with LFGR, organic wastes like foodwaste and garden waste have emissions factors of 0.299 kgCO2e/kg and 0.398 kgCO2e/kg respectively.
Without landfill gas capture, these factors increase to 1.125 kgCO2e/kg and 1.5 kgCO2e/kg respectively.
These emissions factors are very high compared to the emissions factor for AD treatment of waste; divertingorganic waste from landfill has a large impact on waste emissions.
The breakdown of captured and spread dairy cattle manure results in 212.6 kgCO2e/head produced perannum (Ministry for the Environment, 2020). Treating and managing this waste via anaerobic digestion
would prevent the release of this carbon.
5.5.6 Emissions Avoided by Displacing Chemical Fertilisers
If the digestate from the digestion process can be used to displace chemical fertilisers, the avoided
emissions should be considered in the overall emissions calculations.
For example, non-urea nitrogen fertilisers produce 5.4 kgCO2e/kg used. Urea fertilisers with urease inhibitors
can decrease the total GHG emissions to 4.86 kgCO2e/kg used. If digestate can be used to reduce the total
amount of chemical fertilisers applied to land, this creates a large net emissions benefit assuming
biodigestate has zero or near-zero emissions. The EPA states that bio fertiliser use can abate up to
30 kgCO2e/tonne used, with an additional 80 kgCO2e/tonne of carbon becoming sequestered in the soil
(EPA USA & Change Division, 2020).
Depending on the ratio of chemical fertiliser displaced vs bio-fertiliser required, the GHG reduction will vary
for a given digestate production volume.

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| Biogas and Biomethane Processing |5.6 Biomethane in areas without a Reticulated Gas Network
For instances where raw feedstock and biogas production facilities are located away from existing pipeline
infrastructure there are still opportunities to use these bioenergy resources. Biogas production facilities awayfrom pipeline infrastructure are found in many countries worldwide. In the case where a direct user of theenergy generated is located nearby and is able to accept untreated biogas as a fuel, it may make sense to
not pursue biomethane generation. However, the flexibility provided by converting the biogas into
biomethane is still worth considering. There are many options to effectively use biomethane in these cases,
this study summarises options that could be valuable opportunities in New Zealand. A summary of theopportunities for biomethane producers includes:
•
•
•
•
•

Construction of dedicated pipelines to connect to existing infrastructure or industrial sites
Compression or liquefaction of biomethane to be transported by tube trailer
Creation of a bioenergy hub to connect multiple biogas producers to a central upgrading plant
Local combined heat and power (CHP) electricity generation
Conversion to hydrogen for transportation

These opportunities are explored in Section A6.

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| Digestate Production |6

Digestate Production

6.1 Introduction
Digestate is the organic matter remaining after anaerobic digestion, which has demonstrated to be aneffective plant fertiliser, rich in both organic matter and nutrients (Aso, 2019; Drosg et al., 2015). Digestate
presents not only a secondary revenue source of biogas production, but also enables the recirculation ofnutrients back to the land, effectively closing the carbon cycle (Figure 11).

Figure 11: The role of digestate in closing the carbon cycle

Digestate is produced from anaerobic digestion of solid material, including animal manure, crop residue,
wastewater sludge and organic household waste. Therefore, the production of digestate will be proportional
to the uptake of solids digestion, primarily manure, crop residue and organic municipal waste. Advantages ofdigestate include the reduced the risk of nitrogen leaching compared to other fertilisers, and an increased
nutrient profile in comparison to untreated manure and crop. Additional technical detail on digestate
properties, processing, application to soil and relevant legislation is in Section A2.

6.2 Digestate Potential in New Zealand
Based on available quantities of agricultural and municipal organic waste feedstock in New Zealand, amaximum of approximately 6 million tonnes of digestate could be produced if all available feedstock isdigested (Table 17). In addition to the feedstocks presented in Table 17, WWTPs produce around
300,000 wet tonnes of biosolids (stabilised sludge) annually, of which 68% is productively used either for
quarry rehabilitation, landfill cover, agricultural land or forestry. Approximately 192,000 wet tonnes (64%) is
produced via anaerobic digestion, which neutralises the pathogens contained in the unprocessed sludge,
allowing for agricultural land application in some instances (Tinholt, 2019). In New Zealand only the highest
grade of biosolids can be used to grow crops for human consumption (Bioenergy Association New Zealand,2021; Ministry for the Environment, 2003).

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| Digestate Production |Table 17: Maximum theoretical production of digestate from available agricultural feedstocks in New ZealandFeedstock Type

Dairy manure
Pig manure
Poultry manure
Crop residue
Source-segregated food waste
Total

Feedstock Quantity(t/year)Digestate Quantity(t/year)5,320,000
281,000
825,000
450,000
354,000
7,230,000

4,470,000
236,000
693,000
378,000
297,000
6,070,000

Notes
1. Numbers are rounded to 3 s.f.
2. Manure feedstock quantities refer to fresh tonnes (no additional water added)
3. Digestate quantities are calculated based on the assumption that 0.84 tonnes of digestate can be produced per
tonne of input (feedstock) material

Whole (unprocessed) digestate is weak in nutrient concentration compared to synthetic fertiliser. To give asense of scale, 430,000 tonnes of nitrogen was applied to New Zealand soils as fertiliser in 2015 (Stats NZ,2015). Available agricultural and municipal organic waste feedstock in New Zealand could produce
6 million tonnes of whole digestate containing 30,000 tonnes of nitrogen. It is therefore not anticipated nor
suggested that digestate could replace chemical synthetic fertiliser. Digestate could, however, be usedconcurrently with synthetic fertiliser in ratios specific to the soils’ physical and chemical properties.

6.3 Processing of Digestate
Direct application of whole (unprocessed) digestate to soil is an inexpensive means of disposing of the
product remaining after anaerobic digestion (Barłóg et al., 2020), while still returning the nutrients to soil.
However, whole digestate can be refined further to significantly increase both nutritional and economic value.
Digestate processing is primarily aimed at volume reduction, which reduces the transport costs, and nutrient
recovery, which diversifies the digestate fertiliser product and ensures adherence to quality obligations, thus
making it a marketable product (Drosg et al., 2015).
Processing implemented must take into consideration whether the value added by decreasing volume andincreasing nutrient density validates the additional energy input and processing costs associated. Figure 12
gives a basic overview of the options for digestate processing. Further detail on solid-liquid separation, liquid
processing and solid processing is described in Section A2.

Figure 12: Simplified overviewed of digestate processing steps

Source: (Drosg et al., 2015)
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| Digestate Production |6.4 Digestate Use in New Zealand
The lack of a clear regulatory framework for the application of digestate on land means there is scarce
utilisation of anaerobic digestion in New Zealand. This presents a barrier to the use of digestate in New
Zealand. A standardised approach across New Zealand and associated quality assurance program would
increase the confidence with which this resource is utilised. Guidelines and standards relating to the use ofdigestate in New Zealand and overseas include:•••

Guidelines for safe application of biosolids to land 2003 (Biosolids Guidelines)
o The intent of the Biosolids Guidelines is to provide national guidance to producers, dischargers andregulators for managing the application of biosolids to land. In the context of these guidelines,
biosolids refers to sewage sludge that have been treated and/or stabilised so that they are able tobe safely and beneficially applied to land (Ministry for the Environment, 2003). Currently, theseguidelines classify digestate as a waste regardless of its source, which means rigorous testing andpermitting is required for high-quality digestate to be used effectively.
Bioenergy Association: The Production and Use as Bio-fertiliser of Digestate Derived from
Source Segregated Organic Waste (Technical Guide 8)
o The intent of the BANZ Technical Guide 8 (TG8) is to encourage the production of high andconsistent quality digestate in New Zealand so that the value of digestate can be realised via saleas certified bio-fertiliser. It focuses on the use of digestate produced from source segregatedorganic waste.
o TG8 provides a framework for AD plant operators to consistently produce quality digestate suitablefor certification and sale as bio-fertiliser. This is an important milestone as if regional councils
choose to recognise TG8 as a certification framework, digestate produced at an AD facility can beapplied on land without the need for the extensive environmental permitting set out in the Biosolids
Guidelines. (Bioenergy Association New Zealand, 2021).
o TG8 specifically excludes digestate from municipal sludge, which is governed by the Biosolids
Guidelines, and animal waste due to risk of disease (Bioenergy Association New Zealand, 2021).
o Sale of certified digestate supported by specifications like TG8 in New Zealand would enablehigher prices to be charged for the material, depending on its composition. Further analysis should
be done to determine achievable premiums for this material.
PAS110: Specification for whole digestate, separated liquor and separated fibre derived from theanaerobic digestion of source-segregated biodegradable materials
o PAS110 is an industry specification, published under license from The British Standards
Institution, for which producers can use to ensure digestate is produced in such a waythat odours, toxic emissions and variance in quality are minimised, and that the digestate produced
is safe and fit for purpose. PAS110 is not in itself a British Standard, but it aims to provide aframework that will enable a specification to be rapidly developed (Waste & Resources Action
Programme (WRAP), 2014). United Kingdom producers can boost the credibility of their digestate
by applying for PAS110 certification (Bioenergy Association New Zealand, 2021).

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| Case Studies: Biogas and Biomethane in the
Waikato |7

Case Studies: Biogas and Biomethane in the Waikato

The Waikato region of New Zealand is a great area to examine the potential use cases and implementation
options for biomethane plants. There are several reasons for this:
•
•
•
•
•

The Waikato is New Zealand’s fourth most populous region, with the city of Hamilton being the home tomore than 176,000 residents
The region is home to many dairy farms, so produces lots of animal manure as a potential feedstock
There are a large number of industrial plants that use natural gas as a fuel for process heat
These same industrial plants often produce high energy effluent streams, which can also be used forbiogas generation
The region is well-connected via the natural gas network and there are many potential locations forinjection.

Below we have examined two possible case studies for biomethane plant implementation. We havereviewed the expected capital costs, operational costs, revenue streams and the impact of plant operation on
carbon emissions.

7.1 Case Study 1: Municipal Food Waste Processing Plant
The city of Hamilton has a population of 176,000 residents. As of 2020, Hamilton City Council has begun asource-segregated food waste collection service through its contractor Envirowaste which collects andtransports a portion of this material for composting at the Hampton Downs landfill. Based on the feedstocks
analysis food waste collection in Hamilton could generate up to 12,300 t of food waste per year alone.
While composting is a better use of this material than landfilling, there are a number of additional advantages
that anaerobic digestion could provide if employed instead:••••

Reduced biogenic emissions from processing of this waste
Creation of biogas/biomethane as an additional revenue stream
Less land required for processing of food waste (up to ten times less land requirement).
Less manual handling challenges compared to composting.
Table 18: Case Study 1 Summary

Case Study 1: Municipal Food Waste Processing Plant
Feedstock

12,300 t of source-segregated food waste

Biomethane Generation

1.9 million Nm3 per year (57,000GJ)Other Products Generated

1,800 t of Carbon Dioxide
10,500 t of digestate material

Capital Cost

$22M NZD

Emissions Avoided

7,000 t CO2e per year

LCOE for breakeven NPV$5 / GJLCOE for 10-year payback$21 /GJ

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| Case Studies: Biogas and Biomethane in the
Waikato |7.1.1 Biogas Generation and Plant Sizing
Processing 12,300 t of food waste per year would produce 360 Nm3 of biogas per hour, so this would beconsidered a medium sized installation. At this size, the capital costs can vary based on the requirement forparticular processing requirements e.g. depending on the quality of the food waste it may be more expensive
to pre-screen for a continuous fully mixed digester, and it may make sense to use a dry batch digester
system.
The cost of a standard fully-mixed digester would range between $12 million and $16 million while a drydigestion facility could cost between $12 million and $23 million. The best choice would depend on
operational complexity of the plant and appetite for manual handling.
7.1.2 Biomethane Processing, Grid Connection and CO2 Generation Costs
The capital cost to take the raw biogas from this digester and upgrade it into biomethane ready for injection
into the transmission pipeline would come to around $4.5 million (including $2.4M for biomethane processing
and $2.1M for injection infrastructure). Assuming this plant can be positioned close to the transmission
pipeline no costs are included for additional pipework.
A food grade CO2 recovery plant would cost an additional $1 million.
7.1.3 Operational Costs
Based on a total capital cost of $16.2M + $4.5M + $1M = $22 million dollars, the annual operations andmaintenance costs for this plant are assumed to be $1M.
As this waste is currently collected and transported to Hampton Downs for disposal, we can assume that any
extra costs associated with collecting and transporting this waste to a new digestion facility are negligible.
Electrical consumption for biogas upgrading requires around 0.4 kWh/Nm3 of biomethane produced, or
600,000 kWh per year. At 15c per kWh, this costs an additional $90,000 per year.
Additionally, electrical consumption for CO2 upgrading comes to around 420 kWh per tonne CO2 produced(Jackson & Brodal, 2019), or 760,000 kWh per year. At 15c per kWh, this costs an additional $113,000 per
year.
Table 19: Case Study 1 - Annual Operational Costs

Case Study 1: Annual Operational Costs

Basis

Operations and Maintenance$1M

Section 5.2.2

Electricity – biogas upgrading$90,000

Refer above

Electricity – CO2 upgrading$113,000

Refer above

Total$1,203,000

7.1.4 Revenue Streams
Because this plant is accepting material that would otherwise be landfilled or sent to some other kind ofwaste treatment centre, the plant will be able to charge a gate fee for acceptance of food waste. Assuming$120/t can be charged based on general industry practise, this generates the plant $1,480,000 per year. If
this project can successfully redirect material from landfill, the plant may be eligible for a portion of revenue
that the local council would have needed to pay due to the ETS scheme. Based on the current ETS price,
this could generate up to an additional $10 /t of waste diverted, or an additional $123,000.
Annually the plant would produce around 3.1 million Nm3 of biogas, including 1.9 million Nm3 of biomethane
after processing and 900,000 Nm3 of carbon dioxide.
Generally plants of this size will consume about 20% of the total energy generated via the digestion process
for onsite use for powering equipment and controlling process temperatures. This leaves us with 1.5

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| Case Studies: Biogas and Biomethane in the
Waikato |million Nm3/year of biomethane, or 59,000GJ. At a current wholesale price of $10 /GJ, this generates$590,000. However, new commercial arrangements are seeing gas prices of $15-$20 /GJ. Assuming thatgas prices will reach upwards of $15 /GJ in coming years this would generate $885,000. The carbon dioxide
generated is equal to 1800 t, which could be sold for around $500,000.
Assuming the incoming food waste is around 20% TS the plant would produce around 5,000 t/yr of solid
digestate material with a similar moisture quantity, as well as 5800 t/yr of liquid digestate. Although current
legislation does not make the sale of this product viable in current markets, we should assume that thesevalue-add products (solid and liquid) can be sold for around $20 /t which would generate $216,000.
Table 20: Case Study 1 - Annual Revenue Streams

Case Study 1: Annual Revenue

Basis

Gate fees$1,480,000

Section 5.2.2

Council – ETS$123,000

Section 5.2.2

Biomethane sale$885,000

Section 5.2.2

CO2 sale$500,000

Section 5.2.2

Digestate sale$216,000

Section 5.2.2

Total$3,204,000

7.1.5 Carbon Emissions Savingsa. Emissions from Waste Capture and Processing
If the entirety of this feed material is being diverted from landfill for digestion, the net carbon saving (including
avoided emissions from landfilling – emissions from digestion of the same material) is equal to 3,430 tCO2e
per year. If the material is being diverted from composting instead, the total avoided emissions are equal to1,870 tCO2e per year. The residual emissions from digestion are 246 tCO2e per year.
b. Emissions from Use of Gas Products
When the biomethane is used after being transported through the natural gas network, it displaces regularnatural gas so there is a net emissions saving. If we use the default emissions factor for biofuels in New
Zealand’s emissions guidance document the carbon abated is equal to 3,000 tCO2e per year. Residual
emissions from use of this fuel is equal to 205 tCO2e per year, but this could be lower if a proper biomethane
emissions factor is introduced. Producing 1,800 t of green CO2 for use instead of petrochemical carbon
dioxide saves an additional 1,800 tCO2e per year.
c. Emissions Savings from Use of Digestate
The EPA states that bio-fertilisers can abate 30 kg of CO2 emissions per tonne used, so if we also include
the emissions potential of the digestate produced we can abate an additional 324 tCO2e per year.
d. Emissions Summary
The total emissions produced by the operation come to 451 tCO2e per year (not including feedstocktransport emissions), but the use of anaerobic digestion can directly abate 7000-8600 tCO2e per year.
Table 21: Case Study 2 - Emissions Summary

Case Study 1

Emissions (tCO2e/year)

Basis

Emissions from digestion

246

Section 5.5.1

Emissions from burning biomethane

205

5.5.2

Total emissions produced

451

Avoided emissions from landfilling

3,430 – 1,870

5.5.5

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| Case Studies: Biogas and Biomethane in the
Waikato |Displacement of natural gas

3,000

5.5.4

Emissions abated from digestate

324

5.5.6

Emissions abated from green CO2

1,800

Total emissions abated

6,694 – 8,554

7.1.6 Financial Summary: NPV and LCOE
We have assumed the following metrics for the project:••••

Economic life of 30 years
Weighted Average Cost of Capital (WACC) is 5%
Tax Rate: 28%
Depreciation rate: 16%

Considering the total Capital Cost of the facility ($21.7 million) and the overall Operational Revenue($1,997,000), the project has the following financial results:•••

Net Present Value (NPV): $5.1 million – with the combined sales of biomethane, CO2, digestate andcharging a gate fee for processing the food waste, the project achieves a payback period of 12 years.
Levelised Cost of Energy (LCOE): $5 /GJ – at this price for biomethane, the facility breaks even over its
lifetime, and for $21 /GJ the project achieves a 10-year payback.
Marginal Abatement Cost (MAC): $-32 /tCO2e – over the lifetime of the project, the total cost of abatingeach tonne of carbon saved in the operations of this facility is far less than the current cost of carbon,
demonstrating that this plant is an effective mechanism for reducing emissions.
For a buyer of biomethane produced by this facility via the grid, based on the breakeven LCOE of $5 /GJ
and the carbon abated by substitution of fossil gas alone, switching from fossil gas to biomethane has a
MAC of $-14 /tCO2e. To achieve 10-year payback with a biomethane sale price of $21 /GJ, switching tobiomethane has a MAC of $77 /tCO2e.

The above figures demonstrate that by maximising the value of all revenue streams (including gate fees),
these facilities can become profitable and competitive economically, as well as being extremely effective
mechanisms for reducing carbon emissions.
7.1.7 Sensitivity Analysis – Digestate Costs, Operational Costs, Gate Fees, Capital Costs
a. Gate Fees
The gate fees are by far the largest revenue stream for the project, providing 50% of the revenue generation.
If gate fees are unable to be charged for the incoming material, the project has an NPV of -$12.1M anddoesn’t not pay itself back over its lifetime. The biomethane would have to be sold for $48 /GJ to achieve a
10-year payback without generating revenue from this source.
As the landfill levy increases out to 2026, an additional $40/t could be charged for reception of this waste. A
gate fee of $160/t would make the facility achieve a 10-year payback with an NPV of $10.4M.
b. Digestate Pricing
If the digestate is unable to be sold, the facility has an NPV of $2.8M and a payback period of 13 years. The
biomethane would have to be sold for $27 /GJ to achieve a 10-year payback.
At a cost of $40 /t, the facility has an NPV of $7.5M and achieves an 11-year payback. The biomethane
would have to be sold for $17 /GJ to achieve a 10-year payback.
c. Operational Costs
If the operational costs of the plant increase by 50%, assuming all other factors stay the same, the NPV of
the facility goes to -$1.4M and the facility achieves a 16 year payback. Gas would have to be sold for

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| Case Studies: Biogas and Biomethane in the
Waikato |$31 /GJ to achieve a 10-year payback. This could be a result of high screening requirements etc.
Increasing operational costs by 25%, the NPV becomes $1.9M and the facility pays itself off in 14 years.
d. Capital Cost
If the Capital Cost for the plant increased by 25%, the NPV would become $1M and the payback period
would increase to 14 years. A gas price of $30 /GJ would generate a 10-year payback.

7.2 Case Study 2: Dairy Manure Processing Plant
Hamilton is one of New Zealand’s most productive dairy regions, with a large number of dairy farms andcattle. There are over 3700 dairy herds, with a median size of 365 cows. In total, there are over 1.37 million
milking cows in the Waikato region. The average farm size of 127 ha means there are around 2.9 cows per
hectare used for dairy land.
A medium-sized manure-fed anaerobic digester requires around 50,000 t/y of manure. Each dairy cow
produces around 978 kg of collectible manure (from the milking shed) per year, which means feedstock fromaround 140 herds would need to be collected to achieve the scale needed. These farms would be likely to be
spread over 17,780 ha, or a 13km x 14km area.
Collection and processing this manure would result in positive outcomes for farmers and communities in theregion, including:•••

Reduced agricultural emissions from manure breakdown
Creation of biogas/biomethane as an additional revenue stream
Upgraded and processed manure digestate being returned to farms in the area, for use in agriculturaloperations.

Table 22: Case Study 2 Summary

Case Study 2: Dairy Manure Processing Plant
Feedstock50,000 t of dairy cattle manure

Biomethane Generation

2.4 million Nm3 per year (72,000 GJ)

Other Products Generated

2,300 t of Carbon Dioxide
45,000 t of digestate material

Capital Cost

$26M NZD

Emissions Avoided

18,300 t CO2e per year

LCOE for breakeven NPV$27 / GJLCOE for 10-year payback$50 /GJ

7.2.1 Biogas Generation and Plant Sizing
Processing 50,000 t of animal manure per year would produce 450 Nm3 of biogas per hour, so this would beconsidered a small-to-medium sized installation. At this size, a fully mixed digester is the best choice.
The cost of a standard fully-mixed digester would range between $15 million and $20 million. Depending onland availability, an anaerobic pond/lagoon could also be considered and would cost a similar amount basedon UK case studies.
7.2.2 Biomethane Processing, Grid Connection and CO2 Generation Costs
The capital cost to take the raw biogas from this digester and upgrade it into biomethane ready for injection
into the transmission pipeline would come to around $4.2 million (including $2.4M for biomethane processing

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| Case Studies: Biogas and Biomethane in the
Waikato |and $1.8M for injection infrastructure). Assuming this plant can be positioned close to the transmission
pipeline no costs are included for additional pipework.
A CO2 recovery plant would cost an additional $1 million.
7.2.3 Operational Costs
Based on a total capital cost of $20.3M + $4.2M + $1M = $26 million dollars, the annual operations andmaintenance costs for this plant are assumed to be $1.2 million.
Collection of 50,000 t of waste annually would involve transporting around 140 t of manure per day.
Assuming each delivery would consist of around 20 t of material and involve travelling around 20 km (bothways), the total daily logistics operation would involve travel of 140km. Assuming an average speed of
20 km/h allowing for pickup and delivery of material, this requires 14 h of truck operation per day. Over thecourse of the year, this adds up to 5,110 h of transportation effort. At an assumed cost of $120 /h including
labour, equipment, fuel and all other externalities, this logistics operation would cost $610,000 per year.
These truck movements can also be used to return digestate to the farms so we will assume there are no
extra truck movements needed for this.
Electrical consumption for biogas upgrading and CO2 separation requires around 0.4 kWh/Nm3 ofbiomethane produced, or 760,000 kWh per year. At 15c per kWh, this costs an additional $114,000 per year.
Additionally, electrical consumption for CO2 upgrading comes to around 420 kWh per tonne CO2 produced(Jackson & Brodal, 2019), or 970,000 kWh per year. At 15c per kWh, this costs an additional $145,000 per
year.
Table 23: Case Study 2 - Operational Costs

Case Study 2: Annual Operational Costs

Basis

Operations and Maintenance$1,200,000

Section 5.2.2

Transport and Logistics$610,000

Refer above

Electricity – biogas upgrading$114,000

Refer above

Electricity – CO2 upgrading$145,000

Refer above

Total$2,069,000

7.2.4 Revenue Streams
Because this material is not currently being collected and disposed of, there is no additional revenue fromgate fees. We should assume that the farmers will not charge a fee for collection.
Annually the plant would produce around 3.9 million Nm3 of biogas, including 2.4 million Nm3 of biomethane
after processing and 1.2 million Nm3 of carbon dioxide.
Generally, plants of this size will consume about 20% of the total energy generated via the digestion process
for onsite use for powering equipment and controlling process temperatures. This leaves us with
1.9 million Nm3/year of sellable biomethane or 74,000 GJ. At a current wholesale price of $10 /GJ, thisgenerates $740,000. However, new commercial arrangements are seeing gas prices of $15-$20 /GJ.
Assuming that gas prices will reach upwards of $15 /GJ in coming years this would generate $1.1M per year.
The carbon dioxide generated is equal to 2300 t, which could be sold for around $580,000.
Assuming the incoming manure is around 15% TS the plant would produce around 15,000 t/yr of solid
digestate material with a similar moisture quantity, as well as 30,000 t/yr of liquid digestate. Since theprocessed manure is being returned to farmers that supplied the material for use as value-added products
we could assume a small fee is charged for processing and upgrading this material, around $10 /t. This
would generate $450,000 annually for the plant. This will depend on the specific installation.

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| Case Studies: Biogas and Biomethane in the
Waikato |Table 24: Case Study 2 - Revenue Streams

Case Study 2: Annual Revenue Streams

Basis

Biomethane sale

$1.1M

Section 5.2.2

CO2 sale$585,000

Section 5.2.2

Digestate sale

$450,000

Section 5.2.2

Total$2,135,000

7.2.5 Carbon Emissions Savingsa. Emissions from Waste Capture and Processing
The net carbon saving from preventing the release of emissions from manure on land is equal to10,900 tCO2e per year. The residual emissions from digestion of the material is equal to 1,000 tCO2e per
year. However, since biogenic emissions are not currently included in the ETS there is no revenue stream
associated with this emissions avoidance. This may change in future years.
Assuming a conservative price of $10/ tCO2e for on-farm emissions, in the future this could add a new $109K
revenue stream for the plant (not included in financial analysis).
b. Emissions from Additional Transportation
Emissions from collection of the feedstock come to 50 tCO2e per year, based on 51,100 km of transit in a
20 t diesel truck.
c. Emissions from Use of Gas Products
When the biomethane is used after being transported through the natural gas network, it displaces regularnatural gas so there is a net emissions saving. If we use the default emissions factor for biofuels in New
Zealand’s emissions guidance document the carbon abated is equal to 3,750 tCO2e per year. Residual
emissions from use of this fuel is equal to 250 tCO2e per year, but this could be lower if a proper biomethane
emissions factor is introduced. The emissions abated by capturing and selling an additional 2,300 t of green
carbon dioxide saves an additional 2,300 tCO2e per year.
d. Emissions Savings from Use of Digestate
The EPA states that bio-fertilisers can abate 30 kg of CO2 emissions per tonne used, so if we also include
the emissions potential of the digestate produced we can abate an additional 1350 tCO2e per year.
e. Emissions Summary
The total emissions produced by the operation come to 1,300 tCO2e per year, but the use of anaerobic
digestion can directly abate 18,300 tCO2e per year. The total lifecycle emissions abated by this project would
be equal 550,000 tCO2e.
Table 25: Case Study 2 - Emissions Summary

Case Study 2

Emissions (tCO2e/year)

SourceEmissions from digestion

1,000

Section 5.5.1

Emissions from transport

50

Section 5.5.3

Emissions from burning biomethane

250

Section 5.5.2

Total emissions produced

1,300

Avoided emissions from manure

10,900Section 5.5.5

Displacement of natural gas

3,750

Section 5.5.4

Emissions abated from digestate

1,350

Section 5.5.6

Emissions abated from green CO2

2,300

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| Case Studies: Biogas and Biomethane in the
Waikato |Total emissions abated

18,3007.2.6 Financial Summary: NPV, LCOE
We have assumed the following metrics for the project:••••

Economic life of 30 years
Weighted Average Cost of Capital (WACC) is 5%
Tax Rate: 28%
Depreciation rate: 16%

Considering the total Capital Cost of the facility ($26 million) and the overall Operational Revenue($120,000), the project has the following financial results:•••

Net Present Value (NPV): -$18 million – the facility does not generate enough revenue from the
combination of biomethane, CO2 and digestate sale to become profitable over its lifetime. The lack ofany gate fee or profit from feedstock collection and requirement for additional logistical effort means thatthe facility does not make a large enough profit to become financially beneficial.
Levelised cost of Energy (LCOE): $27 /GJ – for this price of energy, the facility breaks even over its
lifetime assisted by the sale of CO2 and digestate. For $50 /GJ, the project achieves a ten-year paybackwith all other costs the same.
Marginal Abatement Cost (MAC): $33 /tCO2e – over the lifetime of the project, the total cost of abatingeach tonne of carbon saved in the operations of this facility is less than the expected price of carbon in
coming years.
For a buyer of biomethane produced by this facility via the grid, based on the breakeven LCOE of$27 /GJ and the carbon abated by substitution of fossil gas alone, switching from fossil gas tobiomethane has a MAC of $120 /tCO2e. To achieve 10-year payback with a biomethane sale price of$50 /GJ, switching to biomethane has a MAC of $284 /tCO2e.

7.2.7 Sensitivity Analysis – Digestate Costs, Operational Costs, Gate Fees, Capital Costs
a. Digestate Pricing
If the digestate is unable to be sold, the facility has an NPV of -$22.9M and also does not generate a profit.
The biomethane would have to be sold for $56 /GJ to achieve a 10-year payback.
At a cost of $40 /t, the facility has an NPV of -$3.4M and achieves an 18-year payback. To achieve a tenyear payback, a gas price of $32 /GJ is required.
b. Operational Costs
If the operational costs of the plant increase by 25%, assuming all other factors stay the same, the NPV of
the facility goes to -$23.5M and the facility does not pay itself back over its lifetime. Gas would have to be
sold for $57 /GJ to achieve a 10-year payback.
Decreasing operational costs by 25% the NPV remains negative (-$12.6M) but the project does still not pay
itself back over its lifetime. Gas would have to be sold for $43 /GJ to achieve a 10-year payback.
c. Capital Cost
If the Capital Cost for the plant increased by 25%, the NPV would become -$22.8M and the facility does not
pay itself back over its lifetime. A gas price of $59 /GJ would generate a 10-year payback.

7.3 Case Study Conclusions
The types of biomethane installations we have explored in our case studies present quite different results.
While the Waikato Food Waste plant (Case Study 1) presents some promising financial indicators, utilisation

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| Case Studies: Biogas and Biomethane in the
Waikato |of animal manures (Case Study 2) appears to be much more challenging.
A few factors that have contributed to the outcomes above worth discussing in more detail are below.
Biomethane: The primary product of these plants. On its own, achievable revenues from biomethane
production cannot provide enough revenue to justify initial investment.
CO2: A secondary product from biomethane production. In the plants we have reviewed, CO2 production can
increase revenue by around 50% and abate 60% the carbon emissions abated by biomethane. For a small
amount of additional capital investment, CO2 production can greatly improve the operational feasibility of theplant.
Digestate: As discussed in Section 6, digestate is a valuable by-product of anaerobic digestion, andoperators should aim to maximise the value of this revenue stream when constructing a biogas/biomethane
plant. Revenues from this stream can add an additional 40% of the revenue generated by biomethane andimprove operational profitability.
Gate Fees: Only some types of feedstocks will allow generation of a gate fee for the reception andprocessing of organic wastes. Gate fees can greatly improve the financial viability of the plant. For
feedstocks not actively collected and disposed of for a fee (i.e. animal manures, crop residues), it is harder tojustify this revenue stream.
Waste Collection & Logistics: In our examples, the process of collecting and transporting biogas feedstock
materials varies significantly in terms of additional complexity from the base case scenario. While Case
Study 1 re-purposed organic wastes already being collected for centralised processing, Case Study 2 wasbased on a feedstock that otherwise had no real drivers for collection and processing which provided
additional complications. Case Study 2 was much more of a deviation from current organic waste
management strategies than Case Study 1, and the financial indicators reflected this.
7.3.1 Review of LCOE and MAC Figures
Case Study 1 breaks even over its lifetime with a green gas price of $5 /GJ, and a 10-year payback with agreen gas price of $21 /GJ. Based on this pricing, the project is financially viable to implement in the near
future.
Case Study 2 only breaks even over its lifetime with a green gas price of $27/GJ, and a 10-year paybackwith a gas price of $50 /GJ. Based on this pricing, the project is not financially viable in current conditions but
could become viable with green gas certification providing a cost premium, and increasing prices of natural
gas out towards 2050.
At breakeven biomethane sale prices, users of fossil gas could purchase biomethane through the natural gas
grid to greatly reduce the carbon emissions associated with their use of fossil fuels, without requiring them toinvest in onsite capital upgrades. The MACs associated with this kind of conversion for Case Studies 1 and 2
respectively are $-14 /tCO2e and $120 /tCO2e, which even for Case Study is comparable to MACs foralternative fuel switching opportunities e.g. biomass boiler upgrades or electric boilers.
The numbers above stress that while not all potential biomethane projects in New Zealand may make sensestrictly financially today, in terms of a decarbonisation strategy for high-to-medium temperature process heat
especially biomethane can be an effective investment opportunity.
7.3.2 Producing Biogas instead of Biomethane
If the biomethane plant in Case Study 1 was able to be constructed near a connection point to the electricity
grid, or near a large heat user, then using the generated biogas directly should be a consideration.
A biogas plant of the same size, without the biomethane upgrading equipment and CO2 recovery plant,
would cost $16.2M instead of $21.7M. Some initial investment would be required to purchase biogas engines

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| Case Studies: Biogas and Biomethane in the
Waikato |and provide a HV connection, or retrofit local natural gas boilers to accept biogas, which would need to beconsidered in upfront costs.
Depending on the quality and energy content of the biogas produced, the acceptable price for biogas as a
product may be lower than the achievable sale price for biomethane. Electricity generation could potentiallybe scheduled to take advantage of market sport prices and could generate similar revenues to biomethane(upwards of $15 /GJ of biogas generated), especially if a use could be found nearby for the heat generated.
See Section 5.2.2 for more details.
The absence of a biomethane/CO2 recovery plant would decrease electrical and operational requirements forthe plant, but also not allow carbon dioxide to be sold which would have a negative impact on ongoing
operational costs.
All of the above should be factored into decisions when designing the facility.

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| What is the Realistic Potential of Biomethane in
New Zealand? |8

What is the Realistic Potential of Biomethane in New Zealand?

When considering the learnings from previous sections, including:•••

Available feedstocks and the ways they can be collected and processed,
Available technologies best suited to processing different kinds of materials,
The interactions between different uses of organic material, and other barriers to achieving 100% yield of
the identified biomethane,

What can we expect New Zealand’s biomethane future to look like with different levels of uptake based on
current feasibility and economics and future drivers for change, and what are benefits associated withdifferent levels of uptake?
Table 26: Summary of three scenarios: achievable today, achievable tomorrow, achievable by 2050

Scenario

Biomethane
Potential (PJ)

% of 2020
Natural Gas
Consumption

Total CO2
Emission
Reductions

CO2 Emission
Reductions as% of NZ 2020
emissionsIndicative
BiomethanePrice Required($/GJ)

Achievable
Today

1.6

1%

184 ktCO2e

0.2%

$20

Achievable
Tomorrow

7.2

4%848 ktCO2e

1%$35-40

Achievable
by 205013

7.2%

1,540 ktCO2e

2%$50-$60

Figure 13: 2050 Biomethane Potential in New Zealand across three scenarios

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| What is the Realistic Potential of Biomethane in
New Zealand? |8.1 Scenario 1: Biomethane Injection Achievable Today
Based on the analysis in this report, New Zealand is ready to realise some of its biomethane potential today,and plant can become economic with gas prices we are currently observing/ are predicted to occur in thenext ten years.
The base building blocks for this case study are:•••Source-segregated organic wastes in the North Island,
High-energy industrial effluent streams at plants with existing WWTPs
A portion of New Zealand’s existing landfill gas generation.

Table 27: Summary of Scenario 1

Scenario

Biomethane
Potential (PJ)

% of Natural Gas
Consumption

Total CO2
Emissions

Achievable
Today

1.6

1%

10 ktCO2e

Total CO2
Emission
Reductions
184 ktCO2e

Indicative $/GJ
Required$20

Refer to Table 28 for a full description of the assumption made for the creation of this Scenario:
Table 28: Quantification of Scenario 1 and Assumptions

Biomethane Potential Achievable Today
Feedstock

Scenario Assumptions

Scenario Notes

Biomethane
Potential (2030)

AnimalManureAssume none collected forbiomethane processing, and are
better utilised for CHP or non-AD
use if collected.

Feedstocks are not economical tocollect and process in current market.

0

WWTP
Solids0%; assume biogas is better used
onsite for electricity generation

Current systems better used tocontinue generating electricity until
premium for biomethane increases
and grid electricity becomes 100%
renewable

0

Food
Waste

40% of maximum value; foodwaste and processing operations
make sense economically in the
NI today. Boosted by sale of CO2
and digestate and gate fees

Councils generally moving in the
direction of source-segregated foodwaste collections, so reasonable toassume that all of this collectedmaterial could be used for biomethane
production.

0.6

Industrial
Effluent

Only for high-quality waste
streams with existing natural gas
connections (assume 15%)

Waste streams identified haveprocessable COD content, biogas andbiomethane could become an
important method for industrial plants
to decarbonise. Most of this gas would
be consumed onsite.

0.5

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| What is the Realistic Potential of Biomethane in
New Zealand? |Biomethane Potential Achievable Today
Feedstock

Scenario Assumptions

Scenario Notes

Crop
Residues

5%; use small portion of crop
residues in NI to boost biogas
yields in codigestion plants e.g.
WWTPs and food digesters

Likely that source-specific biomethane
conversion of Canterbury crop
residues is possible either locally or via
transport to NI grid, rest of feedstock
may have to be co-digested

0.1

Landfill
Gas

Assume 10% of LFG is generated
near a natural gas grid + could beturned into biomethane insteadof burned for electricity.

LFGR systems are expensive tomaintain and capturing + selling
biomethane + trading green gas credits
are good ways to offset emissions.

0.4

Total Biomethane Potential:

Biomethane
Potential (2030)

1.6 PJ

According to our predictions, almost 2 PJ of biomethane are able to be generated and used with relative
ease in New Zealand today. This biomethane would reduce New Zealand’s gross emission by 184 kt ofcarbon, around 0.2% of our annual emissions (Ministry for the Environment, 2020).
The other benefits of this case include:••

the creation of 48,400 tonnes of green CO2, which could supply the majority of New Zealand’s current
market for high-quality CO2, which is expected to grow significantly (Underhill, 2018)
production of 110,000 tonnes of high-quality digestate from food waste digestion

The key challenges/enablers to achieving this scenario include:••

Generating buy-in from industry, farmers, local councils, and waste management/treatment to support
the development of this technology across the country and support collaborative projects between
stakeholders
Promoting anaerobic digestion as a frontrunner in alternative disposal mechanisms for organic wastes.

Without these assumptions, it is unlikely that this scenario could be achieved:•••

Policy support is implemented for biomethane upgrading installations, focusing on using existing biogas
generation installations for the production of the more valuable refined product.
Biomethane becomes distinguishable as a premium product from fossil methane, as an emissions-freeprocess heat fuel and a renewable source of baseload electricity generation via a green gas certification
schemeDigestate becomes an additional revenue stream for biogas plants which help cover initial investment
costs.

8.2 Scenario 2: Biomethane Potential Achievable Tomorrow (2040)
Over and above the immediately available biomethane in New Zealand, there is a second portion of theavailable biomethane that we believe will be able to be utilised as gas prices rise due to the combined effectsof rising ETS prices and increasing scarcity of natural gas.
According to the Climate Change Commission’s predictions for New Zealand’s carbon price, the ETS could
increase in value to over $200 per tonne by 2035 (Silk et al., 2021). This will almost double the current costof natural gas for consumers without taking into account the effect of reduced production as predicted by
MBIE (Ministry of Business Innovation and Employment, 2020).

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| What is the Realistic Potential of Biomethane in
New Zealand? |At these elevated prices, the use of additional organic waste streams for biomethane production is avaluable proposition to support gas users as they transition to low carbon operations.
The base building blocks for this case study are:•••Source-segregated organic wastes in the South Island,
WWTPs selling biomethane to the grid and using renewable grid electricity instead of consuming theirown biogas
A portion of isolated diary manure and crop residue used for biomethane generation in large farms witheasy grid access.

Table 29: Summary of Scenario 2

Scenario

Biomethane
Potential (PJ)

% of Natural Gas
Consumption

Total CO2
Emissions

Achievable
Tomorrow

7.2

4%

50 ktCO2e

Total CO2
Emission
Reduction
848 ktCO2e

Indicative$/GJ
Required$35-40

Refer to Table 30 for a full description of the assumption made for the creation of this Scenario:
Table 30: Quantification of Scenario 2 and Assumptions

Biomethane Potential Achievable Tomorrow
Feedstock

Scenario Assumptions

Scenario Notes

Biomethane
Potential (2040) (PJ)

AnimalManure5% of dairy scoped (from dairy
clusters only), 10% of chicken
manure (all still collected), 10% of
piggery waste (some processed,
rest spread on fields as iscurrently practised)Best use of most manures would still
be onsite use of biogas, and only
particular installations on large farms
would make sense supported byhigher prices of gas.

1.7

WWTP
Solids30%; with higher gas prices,plants can export theirbiomethane and purchaseelectricity to run their plants
insteadHighly dependent on connection costs
and relative electricity supplies.
However, as grid becomes more
renewable the carbon offsetting
potential of biomethane sale would
become more favourable.

0.7

Food
Waste

60% of max value, allowing for
majority of NI municipal
collections integrated withbiomethane operations and somestrategically placed SI digestion
plants able to supply biomethane
to industrial users

This approach in the SI copies
successes of Swedish model, where
biomethane can be generated andused without large grid infrastructure.
Building plants make economic sense ifbuyers for biomethane can be found.

0.9

Industrial
Effluent

Only plants with existing natural
gas connections implement
technology (50%) - 50% of dairy,
60% of meatworks, all P&P plants
use gasPlants without gas connections may
find it hard to sell back the gas to the
grid.

1.6

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| What is the Realistic Potential of Biomethane in
New Zealand? |Biomethane Potential Achievable Tomorrow
Feedstock

Scenario Assumptions

Scenario Notes

Crop
Residues

30%; partial collection of NI andSI residues for biomethane
generation in areas of process
heat demand e.g. dairy plants in
Canterbury.

Enabled by strong need for
decarbonisation for gas/LPG users in
SI. Majority of material still hard toutilise. Possible to co-digest thisfeedstock with other sources as abooster

0.9

Landfill
Gas

Assume 40% could be utilisedwith higher gas prices andconversion of truck fleets to run
on biomethane etc., or othercouncil infrastructures being
supplied with biomethane as agreen fuel.

As incentives/gas prices increase, thisexisting resource can be better
utilised. Likely that the majority oflandfills with gas capture remain notavailable, due to either spatial location
to grid or low gas production.

1.4

Total

Biomethane
Potential (2040) (PJ)

7.2 PJ

According to our predictions, more than 7 PJ of biomethane becomes achievable as economic factors
change and low emissions fuels become priced as preferred alternatives. This biomethane would reduce
New Zealand’s gross emission by 850 kt of carbon, around 1% of our annual emissions (Ministry for theEnvironment, 2020).
The other benefits of this case include:••

the creation of 220,000 tonnes of green CO2, enough to provide New Zealand’s predicted requirements
and potentially allow for extra CO2 for export or CCS
production of 330,000 tonnes of high-quality digestate from food waste and crop residue, and 1 million
tonnes from manure digestion

The key challenges/enablers to achieving this scenario include:•••

Generating buy-in from industry, farmers, local councils and waste management/treatment to support thedevelopment of this technology across the country
Convincing dairy farmers and crop farmers in particular to recover manure and crop silage forprocessing, given that these materials are generally viewed as low-value waste streams. Focus can be
put on farmers where recovery operations can be implemented with relative ease, and farms where
exercise would be too difficult can be excluded
Promoting anaerobic digestion as a frontrunner in alternative disposal mechanisms for organic wastes.

Without these assumptions, it is unlikely that this scenario could be achieved:
•
•
•

•

Policy support is implemented for anaerobic digestion and other kinds of organic waste treatment,
guided by additional advantage of biomethane production from AD becoming a valuable differentiator
Policy support is implemented for biomethane upgrading installations, focusing on using existing biogas
generation installations for the production of the more valuable refined product.
Biomethane becomes a highly valued commodity in the near future and distinguishable as a premium
product from fossil methane, as an emissions-free process heat fuel and a renewable source ofbaseload electricity generation as the ETS price increases
Digestate becomes an additional revenue stream for biogas plants which help cover initial investment
costs
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| What is the Realistic Potential of Biomethane in
New Zealand? |8.3 Scenario 3: Biomethane Injection Achievable by 2050
Out as far as 2050, it is hard to predict the sort of market changes that will occur in the energy market.
Based on our feedstock quantification and case studies, large-scale digestion of animal manures is thelargest single available biogas/biomethane feedstock in the country and it requires a biomethane price of$50-60 /GJ to become economically viable.
At gas prices in this range, it is likely that other sources of biogas used predominantly for electricalgeneration or heat (e.g. landfill gases) or non-utilised sources of biogas (e.g. industrial effluent producers inareas without natural gas infrastructure) will be incentivised to convert to biomethane production as energy
prices reach this height.
Reaching this point would put New Zealand on par with countries like Sweden and the United Kingdom
which have already capitalised on easily attainable biomethane feedstocks and are looking to morechallenging feedstocks to reach higher yields.
Table 31: Summary of Scenario 3
Scenario

Biomethane
Potential (PJ)

% of Natural Gas
Consumption

Total CO2
Emissions

Total CO2
Emission
Reduction

Indicative $/GJ
RequiredAchievable
by 205013

7.2%

90 ktCO2e

1,540 ktCO2e$50-$60

Refer to Table 32 for a full description of the assumption made for the creation of this Scenario:
Table 32: Quantification of Scenario 3 and Assumptions

Vision to 2050
Feedstock

Scenario Assumptions

Scenario Notes

Biomethane
Potential (2050) (PJ)

AnimalManure50% of dairy waste (from dairy
clusters in the NI), 60% of chicken
manure (allowing for nonbiomethane alternate end uses),
60% of piggery waste.

More limited collection andcentralised processing of dairy and pig
wastes; portion of chicken waste
retained for existing fertiliser market

4.4

WWTP
Solids80% of un-utilised potential
realised by conversion of plants
with AD to produce grid-injectedbiomethane in the NI andbiomethane as a vehicle
fuel/process heat fuel in the SI

Conversion to AD still makes economic
sense for most plants, but someparticular installations may be limited
by upstream processes.

0.9

Food
Waste

80% of max value; assume an evenlarger portion of SI food waste canbe utilised to produce green fuelThis approach in the SI copies
successes of Swedish model, where
biomethane can be generated andused without large grid infrastructure.
Building plants make economic sense ifbuyers for biomethane can be found.

1.2

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| What is the Realistic Potential of Biomethane in
New Zealand? |Vision to 2050
Feedstock

Scenario Assumptions

Scenario Notes

Industrial
Effluent

80% of high energy effluent
streams can be utilised to help
industrial plants produce their own
process heat and sell excess fuels
to the grid in times of low use.

With larger push for industry to
decarbonise out to 2050, and limit ofavailable fuels for process heat, highenergy effluents represent a readilyavailable path for decarbonisation.

2.6

Crop
Residues

50%; larger collection of NI and SI
residues for biomethane
generation in areas of process heat
demand e.g. dairy plants in
Canterbury driven by requirement
for green fuels

Enabled by strong need for
decarbonisation for gas/LPG users in
SI. Possible to co-digest this feedstockwith other sources as a booster, or
generated in bioenergy hubs.

1.5

Landfill
Gas

Assume 70% of this gas can be
captured, allowing for highutilisation of this gas but taking into
account decreased landfill gas
generation due to diversion oforganic waste from landfill

Uptake of food waste digestion andmore circular organic waste handlingstrategies will limit this source of
biogas/biomethane going forward

2.5

Total:

Biomethane
Potential (2050) (PJ)

13 PJ

According to our predictions, more than 13 PJ of biomethane could become achievable in the long term as
ETS prices and natural gas scarcity combine to produce high biomethane prices. This quantity ofbiomethane would reduce New Zealand’s gross emission by 1,540 kt of carbon, around 2% of our annual
emissions (Ministry for the Environment, 2020).
The other benefits of this case include:••

the creation of 400,000 tonnes of green CO2, which opens up the possibility of large-scale CO2 exportingor sequestration as well as fulfilling New Zealand’s domestic demand
production of 490,000 tonnes of high-quality digestate from food waste and crop residue, and 2.7 million
tonnes from manure digestion

The key challenges/enablers to achieving this scenario include:•••

Generating buy-in from industry, farmers, local councils, and waste management/treatment to support
the development of this technology across the country
Convincing dairy farmers and crop farmers in particular to recover manure and crop silage forprocessing, given that these materials are generally viewed as low-value waste streams
Promoting adoption of anaerobic digestion processing over other kinds of equivalent waste treatment
options e.g. landfilling, composting, waste incineration, cheaper methods of wastewater treatment. Need
overwhelming favouring of anaerobic digestion to achieve specified yields.

Without these assumptions, it is unlikely that this scenario could be achieved:

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| What is the Realistic Potential of Biomethane in
New Zealand? |

•

•

•

Strong policy support is implemented for anaerobic digestion over other kinds of organic waste
treatment, guided by additional advantage of biomethane production from AD becoming a valuable
differentiator
Biomethane becomes a highly valued commodity in the near future and distinguishable as a premium
product from fossil methane, as an emissions-free process heat fuel and a renewable source ofbaseload electricity generation, as an emissions-free process heat fuel and a renewable source ofbaseload electricity generation as the ETS price increases
Digestate becomes an additional revenue stream for biogas plants which help cover initial investment
costs.

Figure 14: Biomethane Generation Prediction out to 2050

8.4 Notes on All Scenarios
8.4.1 Particularly Challenging Feedstocks to Utilise for Grid Injection
Because of its geographical location, crop residue is a particularly challenging feedstock to utilise effectively
as feedstock for grid injection. In New Zealand, 70% of all crop residue is generated in the Canterbury
region, far from the HP reticulated gas network in the North Island.
In our uptake scenarios, we have assumed only a maximum of 50% of the identified feedstock can beutilised, which consists of a portion of residues generated in the South Island and most of the available
residue generated in the North Island.
Residues generated in the South Island could be used for grid injection by digesting and processing thecrops in Canterbury, and transporting compressed biomethane to the North Island for injection by CNG
trucks or ships via “virtual pipelines”. That being said, it is likely that costs and associated transport
emissions generated from moving gaseous biomethane between islands would erode the possible benefits
without additional processing to convert it into liquified-biomethane (bio-LNG).

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| What is the Realistic Potential of Biomethane in
New Zealand? |Another pathway would be for bioenergy plants to be co-located with large users of process heat in theSouth Island e.g. dairy plants or abattoirs, helping them offset their fossil fuel consumption. Crop residues
from the North Island can of course be used just as easily as animal manure from the North Island.
8.4.2 Other Uses of Biogas and Biomethane
The figures presented in our Uptake Scenarios are estimates of the biomethane generation and/or grid
injection potential in each scenario only, and does not provide estimates for biogas generation and local use.
In situations where centralised collection and processing of organic wastes at the scale needed to achieverequired economic scale for biomethane production is not possible, other options include:••

Using the biogas onsite directly for heat
Using biogas CHP units to generate electricity

The advantages of these two systems are that they can be employed at much smaller scale and withrelatively low capital investment, especially in the case that the gas is already being collected at a landfill or
anaerobic lagoon. The disadvantages are that the CO2 revenue stream cannot be realised, and that without
additional scrubbing and processing the biogas can only be used in specialised equipment and is moredifficult to transport. However, in smaller operations and in situations where heat or electricity is morevaluable than gas these may be the favoured options.
It is worth noting that the use of CHP engines to create electricity needs to consider additional costs ofconnecting to electrical networks if the electricity cannot be used locally, as this cost can be prohibitive.
Biomethane can also be compressed and bottled for use as a vehicle fuel or as an LPG substitute (note: thiswould involve asset retrofitting to correct for differences in energy density) in areas without a natural gas
reticulation network, in a similar fashion to the bioenergy facilities dotted around Sweden.
8.4.3 Key Conflict in Biomethane Sources – Landfill Gas vs Biogas
One of the main conflicts we note in terms of feedstock use is the commercial conflict between landfill gas
generators, and developers looking to install anaerobic digestion plants for processing of Source-SegregatedMunicipal Food Wastes.
As food waste collections begin diverting food wastes from landfills, the landfill gas generation capacity of
our landfills will begin to decrease over time. Residual food wastes and other kinds of organic wastes notsuited for anaerobic digestion facilities will still end up in landfills, so their gas generation potential will not
disappear entirely, but this represents a loss in electrical generation capacity for incumbent waste
management firms.
The advantages of anaerobic digestion over landfill gas generation are:•••Creation of digestate by-productMore complete biogenic methane recovery
Less land use required

However, landfill gas generation has advantages of its own:
• Able to accept highly contaminated wastes• Less operational complexity.
Because landfill cells take 3-4 years to start producing landfill gas and remain productive for 6-10 years, thedrop-off in landfill gas generation will trail the increase food waste digestion gas production by roughly adecade. This has been factored into our projections for landfill gas generation in all scenarios.

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| What is the Realistic Potential of Biomethane in
New Zealand? |8.4.4 Co-digestion: Advantages and Disadvantages
Co-digestion (the digestion of different kinds of feedstock sources at the same time) is a techniquecommonly used at large-scale digesters that require a large amount of incoming feed material to keep theplant operating. Designing a large plant to process a mix of feedstocks is advantageous if the plant is too big
for a single dedicated source of organic materials. When high-energy feedstocks (e.g. crop silage or foodwaste) are combined in small quantities with low-energy feedstocks (e.g. WWTP sludge or animal manure),
the biogas generation can speed up significantly and some studies have shown this can lead to improved
yields too!
There are two main disadvantages of a codigestion system. Firstly, having to design a digester to handle
feed with variable make-up and changing nutrient content is that the digester cannot be optimised based ontight material specifications. Digesters processing very consistent incoming feeds can be finely tuned andcan operate for long periods of time without intervention. Feed composition changes can affect operatingyields as the biological cultures adjust to their new environment.
Secondly, if feedstock like crop silage or food waste are co-digested with WWTP sludge the presence of
pathogens and human waste materials in the sludge means the digestate from the plant is considered lower
quality and cannot be used as a fertiliser. Co-digestion of small quantities of food waste or crop silage with
WWTP sludge could be considered to boost biomethane yields from existing biogas plants, but separate
digestion is preferable if a reasonable quantity of the high energy feedstock is preferable.
For this reason, in our scenarios we have elected to nominate the majority of feedstock use will be inpurpose-build digesters, and unless grid-scale use of a particular feedstock is not deemed reasonable wehave avoided building up scenarios based on assuming a portion of the feedstock is available for codigestion.
In this way, the biomethane figures in the tables above represent the portion of available energy we think
could be utilised as a renewable methane substitute, rather than the total energy contribution of biogas andbiomethane towards New Zealand’s zero-carbon energy future.

8.5 What are the Benefits?
There are a number of benefits associated with maximising the production of biomethane in New Zealand,
across environmental, social and economic dimensions. We touched on some of these benefits in the
Introduction section, but let’s expand on how a maximised biomethane uptake between now and 2050 would
impact different groups:
8.5.1 Benefits of Biomethane to Natural Gas Users
Biomethane or Renewable Natural gas production allows a simple decarbonisation roadmap for gas-fuelled
operations. By switching to a chemically-identical, biologically-sourced substitute for natural gas theemissions associated with this gas use are dramatically decreased. It is also possible to decrease emission
gradually over time as the percentage of renewable gases feeding chemical or heating infrastructure
increases over time.
In addition, the emissions associated with gas use are decreased without high abatement costs for theusers. The same assets and equipment can be used if natural gas users switch to biomethane instead ofswitching to alternative fuels like biomass or electric element boilers.
As an example of this, biomass boiler fuel switching installations for gas users generally cost around $2M ininitial capital per MW installed capacity, with Marginal Abatement Costs of around $80-110 /tonne of CO2
abated due to their high operational and maintenance costs. Based on our first case study, biomethane
plants generally have much higher upfront capital costs than this (around $10M /MW installed capacity), but

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| What is the Realistic Potential of Biomethane in
New Zealand? |have much lower Marginal Abatement Costs (around $-14 /tonne of CO2 abated) because of the additional
revenue streams the anaerobic digestion and biomethane processing operations create, which allow morecompetitive energy prices. Biomethane plants charging gate fees and selling CO2 and digestate as byproducts can end up generating revenue in contrast to biomass boilers which generate a loss over time.
As well as users that need gas for heat and power generation, there are industries in New Zealand that use
methane as an input to their chemical manufacturing processes. Biomethane and other RNG sources could
support the continuation and decarbonisation strategies of existing industries that have the most future
uncertainty around continuation of New Zealand natural gas supplies.
8.5.2 Benefits of Biomethane to Biomethane Generators
While individual generators of biogas may not have a natural use for the energy they generate, a biomethane
economy integrated into existing natural gas networks would provide a larger, more flexible market for
production allowing more consistent production and a steadier demand. Biomethane is a more flexible
resource than regular biogas, and less specialised equipment is needed to handle the gas which means alarger potential customer base for producers.
Biogas and biomethane generation from a company or council’s organic waste is a powerful mechanism tohelp them reduce emissions, as well as turn waste products into additional revenue streams.
8.5.3 Benefits of Biomethane to Distributors
New Zealand (especially the North Island) has considerable transmission and distribution infrastructure used
to transport natural gas from the Taranaki to gas users all over the North Island. Current natural gas
production in New Zealand is expected to decrease yearly until 2050 when it is expected to reach close to
zero. As a result, these assets will need to be retired much earlier than intended. Tied to this, there are still
gas users that will need to continue using natural gas right up until 2050 as they figure out how to transition
away from fossil fuels, and as users drop off the network operational and maintenance costs will become
more and more expensive for remaining operators and users. Biogas could continue to be transported
through the natural gas network if it is modified to transport hydrogen in the future.
In addition, the development of a biomethane economy will create opportunities for the transition of workers
experienced in New Zealand’s oil and gas sector to new roles in bioenergy.
8.5.4 Benefits of Diverting Organic Wastes to Anaerobic Digestion/Biomethane Plants
Capacity for alternate organic waste disposal created by a thriving biomethane industry diverts material fromlandfills and slows demand for additional landfilling space. Additionally, the GHG emissions generated by theprocess of converting organic material into biogas and biomethane are much lower than the emissions
produced by the eventual degradation of organic material in a landfill.
The creation of an industry that uses a waste product to generate energy and valuable by-products is much
more sustainable and circular in nature than traditional waste management strategies in use around New
Zealand.
8.5.5 Benefits of Other Biomethane Products
Of the by-products produced from biomethane production, the two most valuable are carbon dioxide (CO 2)
and bio fertiliser.
Most CO2 consumed as a product in New Zealand is generated by petrochemical processing e.g. the refiningof crude oils into petroleum fuels. Carbon dioxide captured and refined from biogas presents a sustainable
alternative to fossil fuel-based CO2. Additionally, biomethane producers in Europe are developing processing
technology to combine green hydrogen with CO2 from biogas plants to create additional renewable methane.
This is easier to store, transport and use than pure hydrogen.

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| What is the Realistic Potential of Biomethane in
New Zealand? |Bio-fertiliser and digestate have been successfully used to supplement or altogether replace synthetic
nitrogen fertilisers overseas and help restore soil health. New Zealand's large agricultural sector is highly
dependent on imported phosphorous/nitrates to sustain agricultural yields which:••

Are responsible for a large quantity of emissions due to overseas transport and fugitive nitrate emissions
after application
Contribute to soil degradation and release of stored soil carbon if over-applied, as well as degradation of
fresh water via fertiliser runoff and soil destabilisation.

Bio-fertilisers and other organic fertiliser products could be an important tool for balancing New Zealand'scarbon emissions and reducing our dependence on imported synthetic fertiliser products.

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| Unlocking New Zealand’s Biogas/ Biomethane
Potential |9Unlocking New Zealand’s Biogas/ Biomethane Potential

9.1 Regulatory and Policy Barriers
9.1.1 Policies and Certification Schemes missing to promote and incentivise use of bioenergy and biofertilisers
In our overseas research we mentioned that Germany is a net exporter of biomethane, and most of thisbiomethane ends up in Sweden where it is used as a vehicle fuel. This biomethane is exported to Sweden istransported down the same pipeline connecting Germany and Sweden that contains regular natural gas, andthe attribution of production and use of biomethane between different parties connected by the pipeline isfacilitated by issuing of credits and certificates for this renewable gas.
Companies buying biomethane in Sweden can claim benefits by demonstrating certified biomethanepurchases, which allows German biomethane producers to compete with cheaper petrochemical natural gas
suppliers. It is anticipated that a similar system of certifying biomethane as its own product will be requiredfor organisations to claim potential benefits. Certified Energy, who administers the New Zealand Energy
Certificate System, has recently announced public consultation on establishing a green gas certification
scheme. This will elevate biomethane as a low/no-carbon gas option for sale via the existing natural gas grid.
In a similar way, the production and selling of biodigestate or bio fertiliser in New Zealand is unlikely to
become feasible without its own certification schemes or other method for buyers to have guarantees on
quality of material supplied. New Zealand’s current regulations concerning the possible end uses forbiosolids produced from anaerobic digestion processes will not allow digestate to be certified, marketed andsold as a fertiliser supplement on most agricultural land, and prohibit the use of biosolids on land without
rigorous testing. Adoption of standards similar to the UK’s PAS 110 allows for biosolids to be graded andcertified based on their source and chemical compositions, which then allows them to be sold as an organic
fertiliser supplement. In the absence of support for similar standards in New Zealand, it will be extremely
difficult to differentiate this biodigestate from biowaste and other biosolids as per existing legislativeclassifications, and therefore market and sell this valuable by-product from anaerobic digestion.
The Bioenergy Association has produced a guidance document on this standard, adapting the regulations to
a New Zealand context (see Section 6.4). This may allow easier uptake of a similar standard to PAS 110
locally.
9.1.2 Missing coordination of municipal solid waste collections promoting diversion of organic waste fromlandfills.
Countries such as Norway and Denmark have implemented aggressive policies to prevent the disposal ofdegradable organic waste in landfills, including partial or total bans. In New Zealand, the vast majority of all
food waste from municipal collections (as well as commercial and industrial food waste) is disposed of in
landfill. The majority of this gas is captured, but a large portion of biogenic methane emissions from thedecomposition of this material still escapes to atmosphere.
Some councils are beginning to promote alternative waste disposal pathways for organic material including
Auckland Council, who have awarded EcoGas the contract for collection and processing of Auckland’s foodwaste in the coming years. However, there is a lack of clear policy governing the disposal of this waste at aregional and national level in New Zealand, and it is up to councils to set their own targets and timelines fororganic waste strategies.
As the waste sector is such a large contributor to New Zealand’s overall GHG emissions (4% in 2019)(Ministry for the Environment, 2019), a strategy to mitigate and reduce these emissions will be crucial for
New Zealand to reach its 2050 net zero ambitions. The repurposing of source-segregated waste towards

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| Unlocking New Zealand’s Biogas/ Biomethane
Potential |alternative disposal routes e.g. composting and anaerobic digestion would enable better emissions capture,a reduction in volume sent to landfill per year, and create circular markets for waste streams.
9.1.3 Lack of support to promote wide range of sustainable energy technologies.
New Zealand’s emergence as a world leader in biogas technology in the 1970’s was driven by strong
government support for alternative fuels technology in the wake of a developing economic crisis. Biogas was
put forward as one of many mechanisms to provide security against overseas oil prices and protect local
farmers and rural communities from the effects of market collapse.
However, as the threat passed so did the government support for alternative fuel technologies.
We have demonstrated that biogas and biomethane uptake in European and North American countries has
been supported in almost all cases by local and central government policy. These policies (including feed-in
tariffs, investment grants, organic waste disposal restrictions) are most successful in developing lastingchange when underpinned by a National Energy Strategy with clear long-term objectives. In the absence of
this in overseas countries, policy can lead to unintended outcomes or sub-optimal results e.g. Germany’s
land use conflicts.
With New Zealand needing to create substantial changes to its energy mix and emissions profile to achievezero-carbon by 2050, we expect that New Zealand will need to take advantage of all available technologies,
including biogas and biomethane..

9.2 Technical Barriers
9.2.1 The lack of technical expertise
Despite New-Zealand being an early leader in the production of biogas, anaerobic digestion and biomethaneprocessing is currently not a widely established technology in the New Zealand, which creates a gap incurrent local experience.
As a result, expertise in this field will in turn have to be gained from overseas to re-establish this technology
and supporting amenities such as gas scrubbers and distribution systems. Expertise is required both at theinitial instalment of an anaerobic digestion system, but also over the course of operation of digester, formaintenance and operational support. This could be supported by research and development with tertiary
education organisations and/or other technical research services.
9.2.2 The lack of local equipment vendors and supporting services
Following from the above, the lack of installed and operating biogas plants and biomethane refining facilities
in New Zealand means there will be heavy reliance on overseas equipment vendors and specialists to
support construction and operation of these facilities. In the first instance, the few operating
biogas/biomethane plants will depend heavily on European and American suppliers to design, construct,commission and maintain specialist equipment, and over time this will lead to a local presence as theindustry develops and matures. However, until this critical mass is reached, and key
suppliers/contractors/consultants establish a New Zealand presence, it will be difficult and expensive toengage with these crucial participants in New Zealand’s biogas/biomethane development.
One potential opportunity is the cross-over between biogas and natural gas handling that would enable New
Zealand’s oil and gas industry workforce to help support the development and operation of biomethane
upgrading plants. These technicians and engineers familiar with fossil fuel methane processing andtransportation technology could easily apply their skills to support bioenergy projects.
In the early 2000’s New Zealand was the home to one of the leading global biogas upgrading equipment
suppliers (Greenlane Biogas) which now operates predominantly in the US and EU markets. However, manyof the key engineers and technicians from this company have stayed in New Zealand operating in different

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| Unlocking New Zealand’s Biogas/ Biomethane
Potential |areas of practise. If the industry was to re-establish itself in New Zealand, Greenlane Biogas’ history in New
Zealand could help accelerate the re-establishment process.
9.2.3 The lack of one-size fits all solutions
The anaerobic digestion system, from pre-treatment to gas conditioning, is dictated by the characteristics ofthe feedstock stream(s). In New-Zealand, there is a wide variety of feedstocks available in a range ofdifferent volumes. Co-digestion further diversifies feedstock options. Case by case evaluation of the feedstream is needed for the design of the digestion system, and this makes adoption of the technology more
expensive.
The lack of one-size fits all solutions slows the adoption of the technology in New-Zealand, however, it canalso be viewed as an advantage, as the process is adaptable to many scales and feedstocks increasing theopportunities available.
9.2.4 The lack of supporting infrastructure and logistics networks
The dispersion of feedstock sources and energy users in New Zealand poses logistical challenges.
A significant number of feedstocks are generated by the agricultural sector; however, these feedstocks
require transport over long distances if not processed on farm. Subsequently, digestate requires transport toaccepting agricultural land. The financial cost and environmental cost arising from transport of feedstocks
and digestate should not compromise the economic viability and sustainability of an AD operation. Sufficientstorage of substrate and digestate at the AD site, and well-managed logistics are important to ensure
continued operation. For feedstocks and biogas production too difficult to connect to natural gas distribution
infrastructure, farm or community-based bioenergy hubs could be incentivised to provide both a method of
disposing of feedstocks, a supply of clean energy (for transport, heating, electricity etc.) and digestate byproducts.
The installation of the required infrastructure also affects the rate of adoption in New Zealand
Biomethane having comparable properties to natural gas, much of the natural gas infrastructure such as
pipelines has the potential to be recommissioned for the transport of biomethane. Nonetheless, additional
infrastructure is needed to support a biogas and biomethane network in New-Zealand, including gas
scrubbing and compression sites, grid injection sites, possible bottling sites, storage facilities and waste
segregation and collection sites.
More established biogas/biomethane markets overseas also experience difficulties due to a lack ofinfrastructure to support the growth and diversification of their market. This primarily affects the use of CBG
as a transport fuel, which requires a distribution system. A limited number of refuelling stations inhibits thewidespread use of biogas vehicles, especially civilian cars, which has been the case in countries such as
Sweden and Denmark (Eyl-Mazzega & Mathieu, 2019).
9.2.5 Challenges connecting to & injecting biomethane into existing gas grid infrastructure
The Specification for Reticulated Natural Gas (NZS 5442:2008) states the requirements for methane-basedgas that is transported and supplied for use in natural gas burning appliances. The specification will need tobe reviewed, specifically in regard to the upper oxygen content for biomethane injected into the transmission
grid. AD process and landfill gas typically do contain unavoidable, albeit trace, levels of atmospheric oxygenand nitrogen that require extra gas polishing processes to remove. The additional cost required for gas
polishing should be contrasted against the concerns around pipeline corrosion, modification of Wobbe Index,
and a practical oxygen limit established for biomethane injected into the transmission grid. Biomethane
injected into the local distribution grid has an upper limit of 1%-mol Oxygen, which will not typically require
any further gas polishing process.

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| Unlocking New Zealand’s Biogas/ Biomethane
Potential |9.3 Economic Factors
9.3.1 Perception of Waste as a Low Value Material
In New Zealand, waste management strategies and plans have traditionally not recognised the value of
waste, and as a result landfilling of waste is the default approach taken for most waste streams. This is trueof both contaminated/inert construction wastes as well as high energy wastes and other kinds of wastes thatcan be processed and regenerated i.e. organic wastes and green wastes.
Currently, the levy for sending waste to landfill in New Zealand is $10 NZD/tonne (Ministry for theEnvironment, 2021). This is very conservative when compared to other countries overseas. For example, in
the UK it costs £94.15 ($185.75 NZD) /tonne for standard waste disposal with discounted rates for more inert
materials (UK Government, 2020).
Some developed countries overseas including Denmark, Norway, and Sweden have even gone as far as toban the landfilling of combustible waste. This waste is instead sent to incineration plants to generate heatand electricity. While the levy, introduced in NZ in 2008, is currently used to fund wase minimisation activities
and is confirmed to increase to $60 NZD/tonne by 2024 (Ministry for the Environment, 2021), additional
policy, such as the ban of landfilling combustible waste and higher penalties for landfilling of organic
materials could be considered to further aid decarbonisation.
9.3.2 Low Carbon Price and Carbon Tax as part of ETS (Emissions Trading Scheme)
The NZ ETS puts a price on greenhouse gases and by doing so creates financial incentive for businesses toreduce their emissions and for landowners to plant forests. However, this cost is significantly lower than thatof those globally, and as such, the low-cost nature of the units means that it is not appropriately
disincentivising New Zealand businesses to lower their emissions at present.
The price for the units is based on a supply and demand basis, with the government reducing the number ofavailable units each year. This creates an incentive for emitters to reduce their carbon production as theprice for units increases with demand.
The cost of one unit in NZ is currently $39.20 as of February 2021 (CarbonNews, 2021). This is significantly
lower that the price of carbon in Europe of €40.63 EUR ($68.23 NZD) as of March 2021 (Ember Climate,2021). Furthermore, in order to half their 1990 emissions by 2030 Norway has introduced an additional
carbon tax on top of the EU ETS, raising their costs of emissions per unit to 2,000 Norwegian Crown($333.71 NZD) (Buli & Adomaitis, 2021).
As the ETS price increases in New Zealand, biofuels like biomethane will become more competitive whencompared with fossil fuels like natural gas since biomethane would not require an ETS unit to be paid
associated with its use. This will create more demand for sustainable energy. As reviewed in our Scenarios,
expected ETS price increases will make different kinds of biomethane installations more appealing financiallyin coming decades.
9.3.3 High Upfront Investment Costs of Biogas/Biomethane Plants
Lack of funding opportunities for new renewable energy investment is one of the key economic barriers
preventing businesses from creating and utilising sustainable energy in New Zealand. The high capital costsof these installations can reduce the appeal of these projects to investors without partnering with otherorganisations for capital funding, as observed in overseas examples. Additionally, guaranteed revenue
streams can boost investor confidence which manifest overseas as Feed-In Tariffs, or green gas supply
contracts.

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| Unlocking New Zealand’s Biogas/ Biomethane
Potential |Feed in Tariff (FIT) schemes and subsidies are used overseas to incentivise the generation of renewableenergy. These provide a guaranteed revenue stream for renewable energy investment which helps
companies commit to investing in renewable energy projects.
FITs, like those used in the UK, incentivise the generation of renewable energy through the implementationof small-scale projects. Payments are made to those who export renewable energy, created through the useof solar, wind, or micro CHP, back into the grid (Energy Saving Trust, 2021). Additionally, these tariffs arelocked in for a set time period after project implementation so that project investors can have confidence inongoing revenue generated by their investments. Denmark employs the use of public subsidies to encourage
the production of biogas for electricity, industrial use, transport fuel, and heating (Danish Energy Agency,2021).
The EU has multiple funding options aimed at promoting the development of sustainable energy sources.
These include funding to develop suitable energy, transport and digital infrastructure required for renewablesources, grants for energy research and innovation projects, additional funding to support ‘low carbon
projects’, and policies that make it easier for renewable energy projects to get loans approved. Furthermore,
there is additional support to and grants to help coal-intensive regions transition to a greener economy(European Commission, 2021).

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| Conclusions and Closing Remarks |10 Conclusions and Closing Remarks
This study has demonstrated that biogas and biomethane are robust, well-developed technologies that canbe readily deployed and utilised in New Zealand. This technology has a wide range of benefits; aside fromproviding low-emissions renewable energy, it reduces emissions from organic waste disposal and produces
many valuable by-products.
Based on our findings, enough readily-available organic waste exists in New Zealand today to produce asmuch as 19 PJ of biogas. Some of this material is easier than other types of material to utilise effectively, but
by 2050 we expect that as much as 13 PJ of biogas from anaerobic digestion could be converted into
biomethane per year. This would replace over 7% of our national natural gas consumption and reduce New
Zealand’s gross greenhouse gas emissions by 2% over the total biomethane value chain. These figures are
positive, however there are still many steps to realising this biomethane potential.
Realising this potential will require continued efforts from a number of stakeholders across industry andgovernment to address and remove the key barriers highlighted by this study, as well as further detailed
technical and financial analysis to determine the best installations on a case-by-case basis. As highlighted inthis report, each individual biogas/biomethane installation has its own specific benefits and challenges which
need to be carefully understood to ensure project success.
Another important next step for the implementation of this technology is an assessment of how theopportunity presented by biogas and biomethane fits into New Zealand’s energy transition to Zero Carbon by
2050. Biogas and biomethane, like many other alternative fuels and energy sources, cannot provide all of theanswers to the challenge faced by New Zealand to adopt low emissions fuel sources. But by playing a role
alongside other fuels, biogas and biomethane can provide part of the overall solution.
The recent Climate Change Commission Advice Report highlights the need for an energy strategy including
the range of low-emissions gases available for use in New Zealand. This will be a great opportunity toassess and define the role of biogas and biomethane in our future energy transition.
We look forward to engaging with partners across industry, government, iwi and community stakeholders tocontinue developing and realising the potential of biogas and biomethane in New Zealand.

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| Conclusions and Closing Remarks |A

Appendix A – Additional Technical Material

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| Types of Feedstocks and Volumes |A1.Types of Feedstocks and Volumes
Municipal Wastewater Treatment Sludge
Anaerobic digestion of municipal wastewater solids is an established practice in New Zealand’s larger
WWTPs where biogas is currently used for combined heat and power on-site. Anaerobic digestion is used totreat primary sludge, which has a high content of organic matter and is easily degradable, yielding 315 to
400 Nm³ CH4/t ODM, or secondary sludge which has a lower degradable fraction, yielding
190 to 240 Nm³ CH4/t ODM (Bachmann, 2015). In the absence of accurate municipal wastewater sludge
volumes in New Zealand, to capture the maximum quantity of biogas production obtainable from themunicipal population connected to WWTP, New Zealand’s urban population (86.6% of the total population(Trading Economics, 2019)) was used as a basis. Gross gas production per capita, assuming the wastewater
is processed in a plant with anaerobic sludge digestion ranges from 18 to 26 L per capita per day(Bachmann, 2015). This could yield an estimated total 0.60 to 0.87 PJ of biogas, including current
generation. It should be noted that this is the theoretical maximum production. It may not be economical forsmall WWTPs, especially in remote locations, to anaerobically digest their sludge for biogas production.
Both the quality and the location (in proximity to urban centres) of municipal wastewater sludge lends itself toco-digestion with food or industrial waste (Biogas Association of New Zealand, 2019), which has been shownto increase the biogas yield. Substantial additional biogas production through use of co-digestion would
create excess of the heat and power requirements on-site, creating potential for revenue by resale to thenational gas grid.
The Mangere, Rosedale, Christchurch and Palmerston North WWTP already use anaerobic digestion to
generate biogas for combined heat and power on-site. The Mangere WWTP, New Zealand’s largest WWTP
treating wastewater from about 1 million New Zealanders, has seven mesophilic sludge digestors capable ofproducing 49,000 m³ per day of biogas (the equivalent of about 0.3 PJ of biogas per year). The Rosedale
WWTP produces 10,000 to 12,000 m³/day of biogas (the equivalent of about 0.1 PJ of biogas per year)(Watercare Services Ltd, 2019).
In New Zealand, WWTPs with anaerobic digesters are rarely designed with significant extra capacity but
implementation of recuperative thickening systems and digester optimisation studies have allowed the yieldsof biogas at these plants to increase and free up room for additional feedstocks e.g. Palmerston North City
Council’s WWTP (J. Thiele, 2018). This can also free up room for codigestion of other organic wastes e.g.
food wastes, which would need to be assessed against separate digestion of food wastes only to also
produce a high quality digestate.

Source-Segregated Food Waste
A study conducted in 2011 estimated New Zealanders produce and dispose of 0.07 tonnes of digestible
municipal solid waste (food waste) to landfill per year per capita (Reynolds et al., 2016). This includes
Residential, Commercial and Industrial food wastes, and only captures food that is not home-composted,
used as animal feed, or disposed of in other ways. Based on this figure, it is anticipated that New Zealanders
will produce approximately 354,000 tonnes of digestible waste in 2021, which could yield an estimated
1.5 PJ of biogas. Accessing this feedstock stream is dependent on the disposal method: roadside collection,home composting or to sewage via sink waste disposers and if collected, whether it is source segregated ornot. In New Zealand, 71 source-segregated organic waste disposal sites exist (Ministry for the Environment,
2011).
Currently, 90% of organic waste goes to landfills that are already equipped with gas capture systems (Biogas
Association of New Zealand, 2019). However, biogas captured from these managed landfills can achieve on

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| Types of Feedstocks and Volumes |average only 68% capture, and many of these sites do not use their gas for power generation or heating; it isinstead flared (Biogas Association of New Zealand, 2019).
It is foreseeable that the quantity of organic waste reaching landfill will decrease in the coming years assource-segregated waste collection increases. Currently, landfill emissions make up 4% of New Zealand’s
total GHG emissions (Biogas Association of New Zealand, 2019). While this proportion is not large, there isan opportunity to divert more organic waste from landfill to purpose-built anaerobic digestion facilities as theReporoa biogas plant will soon demonstrate, or for co-digestion with wastewater sludge. As collection ofsource segregated food waste is already occurring, such as in Christchurch for composting, the accessibilityof this stream is high and has prospect to be maximised if source segregated collection increases. This
would require normalisation of organic collection methods across New Zealand and education of the public
on organic and food waste disposal; such has been done with recyclable plastic, metal and glass.
Large quantities of pre-consumer industrial food waste would be easier to utilise in the first instance thanpost-consumer commercial and residential food waste, as this is generally less contaminated and easier toprocess without additional screening equipment (J. Thiele, 2018).

Agricultural Waste
New Zealand’s large agricultural sector provides several opportunities for biogas feedstock streams,
including manures from different livestock and crop residue. Additionally, because the agricultural sector
contributes 48% of the national GHG emissions (Ministry for the Environment, 2019), improvements inagricultural waste management are primarily to meet international targets, providing a driver for the
implementation of anaerobic digesters as a waste management method. While New Zealand’s agricultural
practices do not necessarily lend themselves to the production of biogas, there are nonetheless sizeable
feedstocks streams which are currently not only going unutilized but also cause issues with disposal. For
example, crop residue is often burnt on field which disperses absorbed nutrients in the biomass, and manure
disposal can lead to odour, runoff, groundwater & freshwater eutrophication problems.
Crop Residue
In New Zealand, 70% of arable crops are grown in Canterbury and include a wide range of seed crops andcereal grains. It is common to burn stubble (post-harvest residue not commonly used as food), which isviewed as an effective way to clear straw and other plant material prior to the next crop rotation. Stubble
burning, however, releases 60 to 70% of the carbon, 30 to 90% of the nitrogen and 65 to 81% of the sulphur
contained in the crop residue to the atmosphere (Williams et al., 2013). Burning of crop residue produced
23.4 kt CO2e in 2017 (Ministry for the Environment, 2019). While this is not a significant contributor of GHG
emissions (0.1% of total emissions from the agriculture sector), retrieval of this plant material would
constitute a viable feedstock for biogas production, and an alternative to current stubble burning for clearing
plant material and returning nutrients to the soil via application of the digestate.
The Canterbury region produces approximately 1 million tonnes of crop residue each year (Williams et al.,2013) on approximately 90,000 hectares of arable land (Foundation for Arable Research, 2013). It is notpossible, nor desirable, to remove all crop residue, as the roots of the plants help to maintain soil structure
and carbon content. According to the World Biogas Association (Jain, 2019), 30 to 60% of crop residue canbe sustainably recovered, amounting to an estimated 5 tonnes of recoverable crop residue per hectare ofarable land. In Canterbury, this would yield 1.4 to 2.9 PJ of biogas per year.
Only the region of Canterbury is considered as a primary source of biogas potential; other regions do nothave the same significant, concentrated crop production, although use of crop residue in other areas could
be considered to complement other feedstocks in co-digestion systems. Obstacles to accessibility are
geographical dispersion and ownership of the feedstock being divided between many owners. Crop residue
achieves a high biogas yield; however, lignocellulose requires longer to breakdown, requiring more rigorous

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| Types of Feedstocks and Volumes |pre-treatment or a longer retention time within the digester. Seasonality is also an issue to be considered, as
the majority of crop residues are produced during harvest seasons. Storage of crop residues will need to beconsidered to allow effective use of this resource.
ManureIn New Zealand, accessible manures with significant volumes available are dairy cattle, poultry, and piggery
manure. Beef and sheep livestock numbers are high but retrieval of the manure from these farms is not
feasible due to New Zealand’s high use of pastoral agricultural practices, where manure generation occurs
over a much larger area compared with more common feedlot methods used overseas. Table 33
summarises the key inputs used in determining the biogas production from diary, pig and poultry manure.
Table 33: Animal Manure Figures by Livestock Type

Dairy manure
Pig manure
Poultry manure

Population

Manure(kg/day/head)

Manurerecovery

Total solids% of fresh

4,900,000
233,000
22,615,000

35
3.3
0.1

8.5%
100%
100%

25%
25%
21%

In 2017, emissions from manure management systems totalled approximately 1,597 kt CO2-e (NZ
Greenhouse Gas Inventory, 2019). Most of these emissions come from methane being produced during thestorage and treatment of manure, as well as manure deposited on pasture. Anaerobic lagoons are used forapproximately 7.3% of dairy cattle excrement (Ministry for the Environment, 2019). Gas collected from theselagoons is normally flared, but in a few cases is used in modified diesel generators to produce electricity.
Dairy cattle
Dairy cattle in New Zealand are predominantly pasture-grazed, however there is opportunity for manurecollection from the milking shed, which is estimated to be 10% of the total manure produced by dairy cattle(Ministry of Agriculture & Forestry, 2008). Dairy cattle produce an estimated 27 - 35 kg of manure per day,although this varies depending on the type and quantity of feed consumption (Ministry of Agriculture &Forestry, 2008; Wilcock, 2006). With a milking cattle population in New Zealand of 4.9 million in 2019/20, thisrepresents a sizeable feedstock stream of 5.3 million fresh tonnes per year, equating to 5 - 6.8 PJ per yearof biogas. A range has been provided to encompass the variance in biogas yields reported by the World
Biogas Association and the Ministry for Primary Industries (Jain, 2019; Pratt et al., 2012). Work should beundertaken to develop a New Zealand-specific biogas yield to better reflect current New Zealand farming
practices.
Digestors are economically viable for herds with over 1000 cattle (Rowarth et al., 2015). In New Zealand, theaverage herd size is 440 cattle (New Zealand Dairy Statistics, 2020), which suggests that a centralised
anaerobic digestion plant would be more cost effective for smaller operators. However, geographic dispersalof farms and the nature of manure makes transport difficult. A study conducted in 2006 found that it was still
more economic to transport manure from a 7500-herd size to a centralised anaerobic digestion plant than it
was for the herd to have its own anaerobic digestion unit (Ghafoori & Flynn, 2006). In the North Island,clusters of dairy farms occur in the Taranaki and Waikato regions, which could enable the injection of biogas
from a regional digester into New-Zealand’s gas grid. In the South Island, biomethane could be used directly
to replace coal for process heat in industry or transported via converted LPG networks.
Use of off-paddock infrastructure has increased from an estimated <1% of dairy farms in the 1990s to an
estimated 30% of dairy farms using feed-pads and 25% using stand-off pads in 2017 (Rollo et al., 2017),
which is positive from a manure recovery perspective. With 2022 heralding the inclusion of agriculturalemissions in the Emissions Trading Scheme, New Zealand farms may see an increased incentive to recover

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| Types of Feedstocks and Volumes |manure from existing off-paddock infrastructure (feed-pads, stand-off pads and milking sheds). The
calculated biogas potential has not assumed an increase in off-paddock infrastructure.
Pigs and poultry
Pigs and poultry are mostly farmed in shelters or barns, which allows for a higher fraction of waste to becollected (Ministry of Agriculture & Forestry, 2008). Because waste collection is already occurring, thisresource is relatively accessible, but there is little industry experience using anaerobic digestion, with only
one out of the 93 piggeries in New Zealand, the Lepper Trust Piggery in Taranaki, currently capturing biogas(Taranaki Regional Council, 2016). Poultry farms are clustered around urban centres, increasing local biogas
demand and potential for co-digestion (Ministry of Agriculture & Forestry, 2008).
Broiler chicken manure has a biogas yield of 50 to 100 m³/wet tonne and pig manure has a biogas yield of
40 to 80 m³/wet tonne (Jain, 2019). Assuming all pig and poultry (broiler and laying hens) manure iscollected for digestion, this could yield 1.3 PJ of biogas per year from poultry manure and 0.36 PJ of biogas
per year from pig manure. The collection of animal manure and subsequent uptake in biogas production isdependent on farming practices. With more pig and poultry farmers making the shift to free-range farming
practices, the potential biogas production is expected to decrease.
Variability in quality of feedstock – livestock diet, livestock digestive system, solid content, antibiotic
residueIt should be noted that cows have highly effective digestive systems, resulting in a lower fraction of
biodegradable organic matter available in their manures. Poultry and pigs have a higher biogas yield incomparison due to their poorer digestive systems (Ministry of Agriculture & Forestry, 2008). Poultry manure
also has a favourable carbon to nitrogen ratio. Due to the varied diet of pigs, the manure can be quite
susceptible to changes in composition and result in varied gas composition.
Animal manure is favourable for the growth of anaerobic bacteria with a neutral pH, high buffering capacity
and a wide range of nutrients. Antibiotic residue can reduce the biogas yield by inhibiting the methanogenic
bacteria (D. Hamilton, 2017). Pig and poultry farming tend to use more antibiotics compared to cattle
farming, which is a factor that needs to be considered when designing an anaerobic digestion system. The
presence of inert wood shavings used as bedding in poultry cages and barns also makes digestion lesseffective (Ministry of Agriculture & Forestry, 2008)
Low solid content can inhibit digestion due to the biodegradable components of the animal feed having ahigher presence in the solids of the manure, compared to the water fraction. This can be overcome by goodmanagement or co-digestion with another feedstock. Percentage of dry matter is influenced both by the typeof manure, and the collection method. For example, cow manure is usually hosed down into a sump which
reduces the solid content of the manure (Ministry of Agriculture & Forestry, 2008).

Industrial Wastewater
Overview
The industrial sector uses 6% of New Zealand’s weekly water consumption (MFE, 2010). If wastewater does
not meet local discharge standards, it must undergo treatment, creating the opportunity for anaerobic
digestion on-site. This is especially applicable for producers of large volumes of wastewater with highbiological loadings, such as meat processing plants, dairy processing factories, pulp and paper sites,
distilleries, and breweries. Currently most industrial wastewater treatment is aerobic, releasing emissions,and the few treatment plants using hydraulic or pond anaerobic treatment systems do not all have gas

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| Types of Feedstocks and Volumes |capture systems for biogas reuse. Only 8 industrial WWTPs flare or utilise captured biogas, leaving an
untapped resource of approximately 2.4 to 3.2 PJ per year.
Meat and Dairy
Chemical oxygen demand (COD) is a measure of the amount of oxygen available for consumption inanaerobic conditions, which in turn determines biogas yield. Dairy plants produce wastewater streams fromraw milk, butter, milk powder, cheese and various whey products, which all have varying COD values.
Generally, COD values range from 1,700 g/m³ for milk powder wastewater to 5,000 g/m³ for cheesewastewater (NZ Institute of Chemistry, 2017). Best conversion and treatment of dissolved COD in
wastewater occurs in streams with a COD of >2,000 g/m3. The streams from both meat and dairy processing
plants are subject to seasonality, and variation in volatile solids, pH and chemical composition, dependent on
production regime and processes such as CIP (Beca et al., 2016). This means careful management of thedigester is required.
Meat processing and dairy processing plants commonly employ dissolved air flotation (DAF) tanks to reducethe volatile solid content of wastewater, up to 70% removal (Heubeck & Craggs, 2009). DAF sludge canundergo anaerobic digestion in a solids digestor, which is a different technology to a hydraulic digestor,
which is designed to treat high COD wastewater and cannot be used for solids or sludge.
Fonterra produce approximately 61 million m³ of wastewater per year, which could yield an estimated
1.1 to 1.9 PJ of biogas per year in a purpose build hydraulic digestor (Beca; GHD; Boffa Miskell;, 2020;
Wabnitz et al., 2011). This would predominantly come from the South Auckland-Waikato region and the
Taranaki region (NZ Institute of Chemistry, 2017). Meat processing plants produce approximately
20,000,000 m³ of wastewater per year. The COD of raw wastewater from a typical moderate sized beef
processing plant is estimated to be 3600 g/m³. Anaerobic digestion of meat processing wastewater could
thus yield 0.72 PJ of biogas per year in a purpose built hydraulic digestor.
There are also opportunities (not considered in this section) to separate wastewater streams into high andlow COD concentrations. This could further increase the success of industrial wastewater biogas production
facilities by reducing the bulk volume going through the digestor and allowing for more specialised
processing techniques for the various streams.
Pulp and paper
The pulp and paper industry are another significant user of water. The Kinleith mill in Tokoroa, New
Zealand’s largest mill, produce 32 million m³ of wastewater per year (Oji Fibre Solutions, 2019). The COD ofpulp and paper wastewater is assumed to be 1759 g/m³ (Bantacut & Ardhiansyah, 2018). Based on theseassumptions, pulp and paper wastewater from the Kinleith mill could yield approximately 0.58 PJ per year of
biogas in a high rate liquid digestor.
It is likely that the COD concentration and subsequent biogas yield is too low to make anaerobic digestion of
pulp and paper wastewater a viable option. Furthermore, pre-treatment of pulp and paper wastewater may
be required due to nutrient deficiency, lignocellulosic material and sulphur containing substances which can
result in slower degradation (Al Seadi et al., 2008). A significant amount of fibrous waste is currently being
landfilled, which incentivises the use of anaerobic digestion, but extensive pre-treatment is required andother disposal methods have also been investigated in recent years. Two of New Zealand’s largest paper
mills, Tasman and Kinleith, have implemented vermicomposting (a decomposition process using worms) for
fertiliser application, which has proven successful (Quintern & Morley, 2014).
Other industrial plants
It should be noted that many industrial processing plants do not have on-site WWTPs. In thesecircumstances trade waste is sent to municipal WWTPs. Medium-sized WWTPs in Hawera and Morrinsville

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| Types of Feedstocks and Volumes |receive more than 50% of their discharge flow rate as trade waste. The Mangere WWTP (New Zealand’s
largest), receives approximately 10% of their discharge flow rate as trade waste.
Many additional by-products from industry exist, such as food waste from food manufacturers, trade waste,spent grain and yeast from distilleries and breweries, grease from grease traps and paunch grass fromslaughterhouses. Spent grain from breweries yields 60 to 100 m³ of biogas per tonne of spent grain (with
20% TS content) (Jain, 2019). These streams, while not high enough in volume to constitute having theirown AD plant, make good “booster” feedstocks to complement high volume, low-to-medium yield single
feedstock digestion facilities. For example, animal manure has a low methane yield which benefits from codigestion with oily food residue, fishing industry waste and brewery waste (Al Seadi et al., 2008).

Forestry Waste
According to (Hall & Gifford, 2007) an estimated 250,000 tonnes of forestry residue is harvested every year
in New Zealand. This is only about 7% of total forestry residue available, leaving more than 2 million tonnesof unharvested residue. The present quantity available in the 2020’s will be higher due to the large-scale
planting that took place in the 1990s (Industrial Symbiosis Kawerau, 2012). However, woody biomass, which
is a lignocellulosic biomass, yields only a small amount of biogas if untreated. Lignocellulose, found in cell
plant walls, has a complex structure which is hard to decompose. In forestry residue, cellulose makes up
35 to 50% of its composition. Therefore, pre-treatment of the woody biomass is required before anaerobic
digestion, adding to other costs of the process, such as transportation costs. For this reason, biogas fromforestry residue has not been quantified, although it should be noted that there are well-established pretreatment methods available, which makes use of New Zealand’s forestry residue as a biogas feedstock
certainly possible from a technology perspective. Pine, for example, if pre-treated hydrothermally (at210°C to 215°C) with SO2 as a catalyst, yields 180 m³ of biogas per tonne of volatile solids, which compares
well with other feedstock yields. If untreated, pine only yields 54 m³ of biogas per tonne of volatile solids(Matsakas et al., 2016).

Purpose-grown energy crops
Purpose grown energy crops, which are not currently grown in New Zealand, have proven viable for biogas
production overseas in countries such as Germany where they are supported with subsidies. While crops are
harvested seasonally, a constant supply throughout the year can be maintained by preserving the crop via aprocess called ensiling for use as a feedstock when needed. Ensiling involves chopping then drying the crop,
followed by compressing the crop and covering it to push out the air. Anaerobic fermentation then produces
acidic conditions which preserves the crop for storage. Purpose grown energy crops are advantageous dueto their high biogas yield, ranging from 180 m³/wet tonne to 650 m³/wet tonne, depending on the type of cropand processing conditions (Jain, 2019). Given that purpose grown energy crops are not an existingfeedstock in New Zealand, and growing them at large scale would conflict with the use of arable land for foodcrops, their biomethane potential has not been quantified. However, it should be noted that there is potential
for purpose grown energy crops to be incorporated into New Zealand’s energy mix in the future. For
example, small farms with quantities of manure on the verge of being financially viable may benefit fromgrowing energy crops to boost their biomethane production.

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| Digestate production |A2.Digestate production
Digestate Properties
Digestate is nutrient rich and retains the phosphorous, nitrogen, potassium, sulphur and organic matter
contained in the feedstock digested, enabling the recycling of nutrients back into the soil (Drosg et al., 2015).
As an organic fertiliser, digestate improves the soil’s physical properties, including bulk density, hydraulicconductivity, and moisture retention capacity (Aso, 2019). Digestion also neutralizes pathogens and seeds,
so application of digestate as a soil conditioner inhibits the spread of pathogens and the growth of weeds.
The feedstock material to the AD process dictates the digestate properties, including total solids content, pH,nitrogen and phosphorus content (Drosg et al., 2015). Liquid slurry manure digestion is a wet-state processwith a low total solids (TS) content of 6-12% TS, resulting in a liquid digestate in its unprocessed form.
Digestate can be a stackable solid material when originating from dry state AD. For example AD of fresh
manure (~25% TS) (Jain, 2019), crop residue, energy crops and source segregated organic municipal waste.
The TS content is an important variable, as it dictates the volatile solids content, which can be up to 70% of
total solids. Volatile solids have been shown to improve soil structure through input of inert organic matterand fibres, which contributes to the formation of humus.
The pH value of digestate is typically higher than the pH of the feedstock. For example, digested manure
typically has a pH value ranging from 7.5 to 8.0, compared to undigested manure which has an average pHof 7.5. While an increase in pH positively reduces odour emissions, it also increases the degree of ammonia
volatisation. To manage this, digestate should be immediately incorporated into the soil after application toprevent excess ammonia emissions. If properly managed, digestate has a lower risk of excess ammonia
emissions compared to raw manure due to its superior infiltration speed into soil (Drosg et al., 2015).
Anaerobic digestion degrades the organic nitrogen compounds contained in the feedstock to produce
ammonium, which is readily available for plants to absorb. The ammonium concentration of digestate,normally expressed as a percentage of total nitrogen, is determined by the nitrogen content of the feedstock.
For example, pig slurry has a higher nitrogen content compared to cattle slurry and will thus produce
digestate with a higher ammonium-N content.

Digestate potential in New Zealand
WWTPs produce around 300,000 wet tonnes of biosolids (stabilised sludge) annually, of which 68% is
productively used either for quarry rehabilitation, landfill cover, agricultural land or forestry. Approximately
192,000 wet tonnes (64%) is produced via anaerobic digestion, which neutralises the pathogens contained in
the unprocessed sludge, allowing for agricultural land application in some instances (Tinholt, 2019). Sourcesegregated organic waste can be used as a feedstock for digestate, however, as per the PAS 110
guidelines, the origin of the waste should be known, and sorting of incoming waste should use reasonableendeavours to remove non-biodegradable packaging (Waste & Resources Action Programme (WRAP),
2014). Source-segregated municipal waste is achievable under local food waste collections schemes. Caremust be taken to ensure that this stream is not contaminated with non-biodegradable material and humanwaste such as nappies. Nonetheless, source segregated organic waste should not be overlooked as it
makes a valuable plant fertiliser. New Zealand’s first large-scale food waste biogas production facility, owned
by EcoGas, is due to open in 2022 and is estimated to produce enough digestate for 2,000 acres of farmland(Sherrard, 2020). Agricultural waste is another potential source of digestate and presents fewer challenges
under the PAS 110 guidelines as it is feasible and possible under current practices to control and know its
origin, thus there is little to no non-biodegradable material present. Manure is already commonly being

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| Digestate production |applied to land, for example, via irrigation. It is advantageous to anaerobically digest manure, as it increases
the presence of readily available plant nutrients, such as ammonium-N, phosphorus and potassium.
The advantages of digestate are realised when its nutrient profile is compared to that of its raw (undigested)
form. This is because digestate has higher proportions of plant-available nutrients compared to untreatedmanure and crop, thereby increasing its fertilizing value (Risberg et al., 2017; Sørensen et al., 2019). For
example, ammonium-N as a percentage of total-N in cattle and pig slurry has been shown to increase 1015% with anaerobic digestion (Risberg et al., 2017). It is therefore beneficial from a nutrient perspective formanure to undergo anaerobic digestion before it is applied to soil.
Nutrient leaching and runoff can occur with both synthetic and organic fertilisers, and both have adverse
effects on the environment. Leaching occurs when dissolved nutrients move beyond the plant root zone,
which can cause harmful contamination of ground water and waterways, and result in poor performance ofthe targeted soil (Fertiliser Association, 2013). An advantage of digestate, however, is it releases nutrient
gradually at a slower rate compared to mineral fertilisers, reducing the risk of nitrogen leaching into water(European Biogas Association, 2015).
Application of digestate to soil
In Europe, the direct application of digestate to land is widely practiced. For example, Germany applies
100% of agricultural digestate to land. Sweden applies almost all except sewage sludge digestate to land.
The vast majority of EU countries do not apply sewage sludge digestate to land (Wood Environment &Infrastructure Solutions UK Limited, 2019). Agricultural digestate is typically used overseas as a soil improver
for use in agriculture, horticulture and in some cases hobby gardening. If the manure feedstock is in slurry
form, it should be expected that the digestate will be liquid, unless it is further processed to separate theliquid from the solids. It is recommended by the European Biogas Association to apply liquid digestate withmachinery that minimizes exposure to air to prevent ammonia volatilization. Trailing hoses, trailing shoes ordirect injection to the topsoil are appropriate methods. The application limit of agricultural digestate varies in
European countries between 10-40 m³/hectare (4-16m³/acre). Further limits are in place for areas vulnerable
to nitrate (Wood Environment & Infrastructure Solutions UK Limited, 2019).
Direct application of digestate to land is the cheapest way of utilising it as fertiliser. Another option is tofurther process it to a value-added, marketable product, to be better suited to the specific needs of farmers.
The digestate processing section below describes the various established digestate processing methods.
As a result of the distribution of agricultural practices across New Zealand, fertiliser demand differs by regionin terms of nutrient type and quantity. For example, dairy pastures use more nitrogen, while sheep and beef
rely more on phosphorous (Fertiliser Association, 2019). The nutrient quantity in digestate is defined by thefeedstock properties and whether it has been processed. In most cases, it is reasonable to assume thatdigestate alone will not fulfil soil nutrient requirements. Furthermore, New Zealand’s fertiliser demand is toohigh for digestate alone to meet. For these reasons, digestate should be considered as a solution tooffsetting a portion New Zealand’s synthetic fertiliser usage, not as a complete replacement. For example,
digestate may be applied to soil and then dosed with synthetic fertiliser to meet the specific nutrient
requirements for the soil and the application. In areas such as the Waikato, Canterbury, Southland andTaranaki regions, digestate application could be dosed with urea to meet higher nitrogen requirements.

Processing of digestate
Solid-liquid separation
The initial treatment of digestate comprises of dewatering, separating the solid and liquid phases of thewhole digestate. This significantly reduces the cost of transportation and is the first step for the further

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| Digestate production |processing of the solid and liquid phase. The most conventional methods for solid-liquid separation are theuse of screw presses and centrifuges (Drosg et al., 2015).
Typically, wet state AD produces digestate with 3-15% TS and dry state AD produces up to 30% TS (Drosg
et al., 2015). Upon solid-liquid separation, up to 90% of the digestate by volume comes out as the liquid
fraction. The liquid fraction contains 2-6% dry matter and most of the soluble nitrogen and potassium
content, which can then be applied directly to land or undergo further processing to enhance its
concentration. The remaining solid fraction, which contains 20-30% TS, retains most of the phosphorous andcan be easily stored or transported (Aso, 2019).
Complete nutrient recovery
Further processing of the solid and liquid fractions generates concentrated products. Drivers for complete
processing include increased marketability, reduction in storage and transportation costs and compliancewith environmental regulations (Aso, 2019).
Solid processing
The solid fraction from solid-liquid separation can be stored or directly applied as fertiliser. However, further
microbial activity and odour emission can still occur. Further processing, via composting or drying, istherefore required to obtain a stable, concentrated and marketable fertiliser product from the solid fraction.
Liquid processing
Further treatment of the liquid fraction can be undertaken to enhance the concentration of the suspended
and dissolved solids. Liquid processing technologies include membrane purification, evaporation, ammonia
stripping, ion exchange and solar drying.
a. Membrane purification
Membrane purification is the only process that can allow direct discharge to receiving waters. Being the mostof expensive and energy intensive of the processing options, it is more suited for the optimisation of largescale processes (Drosg et al., 2015).
b. Evaporation
Evaporation of the liquid fraction requires excess heat from a biogas plant CHP unit. Fibrous material must
be removed beforehand to avoid clogging the heat exchangers. The fertiliser concentrate obtained from
evaporation can have a nitrogen concentration of 8,000 to 10,000 mg/kg, although this is very dependant thefeedstock and liquid inflow concentration. There is the option to follow with reverse osmosis of the remaining
liquid to allow direct discharge to receiving waters (Drosg et al., 2015).
c. Other liquid processing technology
Ammonia stripping, ion exchange and solar drying are other less common methods of concentrating
digestate. Ammonia stripping has the advantage of producing a pure nitrogen product which can be used toenrich other digestate fractions to obtain a standardised nitrogen concentration (Drosg et al., 2015).
In summary, while whole digestate can be directly applied to land without the need for further processing, it
is dilute with respect to nutrients which makes the relative costs of transportation high compared to synthetic
fertiliser. Processing, therefore, is a necessary step for making digestate a marketable product. Large,
centralised biogas plants could find processing to be economical. For smaller plants, it is likely more feasible
to apply whole digestate directly to land because the costs associated with processing are too high.

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| Feedstocks to Biogas Process |A3.Feedstocks to Biogas Process
First, the hydrolysis stage is performed by acidogenic bacteria to break down long-chain proteins,carbohydrates, and lipids into their base constituents. Then, these same bacteria convert the small-chain
compounds into volatile fatty acids or VFAs. Following this, acetogenic bacteria turn VFAs into acetic acidand hydrogen. Finally, the methanogenic bacteria take acetic acid, hydrogen and CO2 and combine them tomake what we call biogas (Gunnerson & Stuckey, 1986; United States Environmental Protection Agency,2020).

Process Variables and Additives
d. TemperatureFirstly, temperature has a huge influence on the speed at which each step in the biogas process canprogress. Generally, the methane producing bacteria can be labelled as either psychrophilic (10-20°C),
mesophilic (20-40°C, or 30-38°C with the latter more common) or thermophilic (50-60°C). Higher
temperatures lead to faster growth of bacteria and therefore mean faster and more effective conversion oforganic waste to biogas per volume (Van et al., 2020). The biological reaction to produce biogas is
exothermic in nature, so the reaction temperature is self-sustaining to some degree. Generally, external heatis still required to maintain heat lost to the external environment.
However, higher temperatures also create more sensitivity to temperature fluctuation. Methanogen bacteria
are sensitive to deviations from their ideal operating temperatures, and swings can slow down or evenentirely halt bacterial growth. Mesophilic bacterial growth can be disrupted by temperature swings as small
as 2°C, and thermophilic bacteria are even more sensitive to thermal disruptions (Bekkering et al., 2010).
Additionally, the higher the operating temperature of the digester the higher the parasitic load resulting inincreased gas production and the ability to maintain digester temperatures. Psychrophilic operations, whileslow and inefficient, are the cheapest to design and run since little external heating and control is needed tokeep the bacteria happy. This is why biogas installations on farms (where space for the effluent pond is not
an issue) are generally not heated (Ministry of Agriculture & Forestry, 2008).
Choosing a design temperature for a reactor requires an assessment of capital impacts (both in terms ofprocess complexity and reactor volumes) and operational impacts (chance of upsets and internal energy
loads). Today, two thirds of large-scale anaerobic digestion plants operate under mesophilic conditions andone third operate under thermophilic conditions (Van et al., 2020).

Figure 15: Effect of Temperature of Growth Rates of Methanogenic Organisms (Singh, Jain, and Singh 2017)

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| Feedstocks to Biogas Process |(Singh et al., 2017)
e. pH
Most microorganisms grow best in neutral pH conditions. Acidic or basic conditions can affect bacterial
growth, either by altering chemical equilibria of reactions or by destroying enzymes (Ariunbaatar et al.,2014).
An intricacy of the anaerobic reactor system is that the pre-cursor reactions leading up to methane
production themselves reduce the pH. As fatty acids and acetate are two of the key intermediary products on
the route to biogas. The presence of carbon dioxide and bicarbonates can buffer pH changes, to an extent. If
the buffering capacity is exceeded, the methanogens are the most affected performance-wise, which leads
to even more acidic compound accumulation (Montgomery & Bochmann, 2014) and the biogas production
can be severely affected. This means that the system may need external adjustment from time to time.
To control pH in a reactor, there are a few options pending digester design:•••

If the feed material can experience pH swings, extra buffer capacity can allow acidic and basic inputs tocancel each other out and not upset the reactor pH balance
In the case of acidic intermediate product build-up, adjusting or stopping the feed into the reactor canallow the methanogenic bacteria extra time to remove acidic compounds from the reactor and restore aneutral pH
Finally, direct dosing of the reactor with chemicals to correct the pH can quickly restore the operating
conditions in the digester

Controlling the pH of the reactor via buffering or chemical additives can have cost impacts (e.g. buffer tanks
and the cost of ongoing chemical consumption), but at the same time having to pause reactor feeds
frequently will impact reactor productivity and biogas yields.

Figure 16: Effect of pH on Cumulative Methane Production (Liuet al. 2008)(Liu et al., 2008)
f. Organic Loading Rate and Feedstock Control
With the Organic Loading Rate (OLR), it is important to understand what sort of organic materials are beingreferred to. Not all organic material can be decomposed in an anaerobic digester – materials with highamounts of lignin for example cannot be digested this way. The OLR for a digester system is a measure of
the digestible material feed rate, or the feed rate of volatile solid materials. This is generally measured

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| Feedstocks to Biogas Process |indirectly by assessing the COD of the feed material. This quantifies the amount of readily oxidizable
material in the material which can be used to predict biogas yields from the feedstock. Generally, systems
are designed for a set OLR and it is not easy to implement process changes to boost this figure after anoperating scheme has been selected.
A more thorough assessment of digestion suitability is a Biomethane Potential (BMP) test, conducted bydigesting a small sample of the substrate in laboratory conditions (Biogas World, 2021a). These can be usedin conjunction with COD values to assess the degradability of fresh feedstock materials and predict biogas
yields.
Another important factor to note is the carbon to nitrogen (C/N) ratio of the incoming organic materials. HighC/N ratios (e.g. manure and agricultural residues, around 25:1) mean good biogas yields from feeds, andlower C/N rations (human waste, around 6:1) mean reduced biogas yields. C/N ratios anywhere from
10:1 to 90:1 are acceptable (especially because not all of the organic material is digestible), but 30:1 is often
considered optimal (Global Methane Initiative, 2016).
Phosphorous content is also important to monitor with Carbon and Nitrogen – Phosphorous supports cell
health and growth (Ghafoori & Flynn, 2006).
Changes in the OLR can affect the balance of bacteria in the digester. A decrease in OLR can starve thebacteria of feed material and affect the balance of different cultures in the digester, where high OLRs canlead to the formation of toxic chemicals (as in the pH section, with an increased growth in acetogen bacteria)
or cause by-product formation (Nsair et al., 2020).
The best way to minimize the potential impacts of changes in OLR is to use a consistent feedstock and levelproduction of biogas as much as possible. However, this is not always possible when designing largecapacity systems requiring co-digestion or variable feedstocks e.g. food waste. Designing a reactor that is
flexible and can cope with variances in OLR and COD over time means sacrificing potential efficiency andbiogas yields but means there will be less operational upsets.
g. Nutrientsi. Sulfur
The concentration of sulfur, sulphates or H2S in an anaerobic digester can greatly impact the production of
biogas. There is a minimum level of sulfur compounds required for the reaction pathway from organic waste
to biogas to proceed, but high concentrations of sulfur compounds in solution interfere with themethanogenesis stage of the reaction, preventing maximum conversion.
High levels of sulfur also lead to high levels of H2S in the collected gas, which can be damaging toequipment designed to burn the gas and must be removed via processing (A. W. Khan & Trottier, 1978) andmust be cleaned from the biogas. The conversion of a high sulfur feedstock to H 2S is the biologicallyfavoured reaction over the conversion to methane (A. W. Khan & Trottier, 1978). High levels of H2S can posea risk to the health and safety of operators and workers in the digester plant, as it is acutely toxic .
That being said, sulfur can also help the digester stay healthy by precipitating out harmful heavy metals,
which can inhibit reactions and kill bacteria.
Understanding how much sulfur the feedstock needs based on optimum methanogenesis conditions andheavy metal presence is essential for optimal gas production, and then adjusting the level via pretreatment
or sulphate dosing to a level that will promote maximum biogas yield.
ii. Ammonia
Ammonia is a naturally-occurring by-product of digestion of high-protein feedstocks. Optimum ammonia
levels can keep the reaction chain stable and buffer the methanogenic stage of the reaction. The presence of
too much ammonia however, especially at pH below 7, can be toxic to bacteria (Gunnerson & Stuckey,1986). Ammonia can be the primary source of nitrogen for digester health.

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| Feedstocks to Biogas Process |As with sulfur, feedstocks that will create high ammonia concentrations can be assessed and steps can betaken to limit excess ammonia production e.g. mixing or buffering with other feedstocks, and ammonia
concentrations can be assessed during reactor operation to enable intervention if necessary.
iii. Siloxanes
Siloxanes are formed via the breakdown of silicon compounds in landfills and WWTP sludges. Siloxanes cancause deposits on pipework and equipment which affect the operation of equipment and need to be removed(Nyamukamba et al., 2020).

Type of Feedstock Available
Different kinds of feedstocks for anaerobic digestion plants can have a wide range of physical and chemical
properties (Bremont et al., 2020). The important properties to understand from the outset, and that ultimately
determine the process configuration are:••

COD or volatile solids %; how much digestible matter is there present in this feedstock?
Total solids content; is the digestible matter in solid form or in solution?

As an example, industrial effluent usually has a moderate COD or concentration of volatile organic material,
but a very low TS. At the other end of the scale, energy crops have very high COD and are largely solid(Blanco-Canqui, 2016). These feedstocks will have to be processed very differently.
There is also the question of co-digestion and how you balance mixed feedstocks. Many biogas installations
find success in combining a large, low biogas-yield stream (e.g. animal manure) with a small stream of highbiogas-yielding feedstock (e.g. energy crops), leading to improved performance (J. H. Thiele, 2010).
Sometimes it does not make sense to compromise the performance of a digester or to spend extra effort
processing an additional feed material to combine streams, but it is very situational.
As well as the above, there are a wide range of other factors that affect how suitable the feedstock will be fordigestion. In the next section we will review some of the most important properties to manage, and different
methods of making feedstocks digestible.

Pre-Treatment Methods for Feedstocks
h. Mechanical Pre-Treatment
Generally, the first stage of feedstock pre-treatment will be physically screening the feedstock for nonorganics or impurities and then physical re-sizing of solid feedstocks. This step serves multiple purposes; it iseffective for removing inorganic materials from streams (within a certain size band) and it decreases the sizeof individual organic waste particulates which improves mixing and flow properties of the slurry and increases
surface area of the feedstock (Pilli et al., 2020).
For a plant processing food waste or energy crops, physical screening is extremely important to remove any
waste incorrectly disposed of e.g. plastics/other non-food waste from bin collections, or items mistakenly
harvested with crops e.g. stones. This can be done with static screens or rotary drums, depending on thefeedstock.
Physical re-sizing is generally done with either mills, screens or a mixture of both. Food waste slurries arenormally screened using screens to remove inclusions larger than 2-5 mm in size. Energy crops, if not
supplied pre-shredded, are then cut, shredded, or milled to break them down into a form that can be mixed
into a slurry.
After the feedstocks are able to be pumped and/or mixed successfully, they can be further refined for better
acceptance into the digester.

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| Feedstocks to Biogas Process |i. Optimising Feedstocks for Digestion – Thermal, Electrical or Chemical Pre-Treatment
The main objective of pre-treating the feedstock prior to digestion is to make it easier to process intomethane by the bacterial cultures inside the reactors. To this end, there are many ways to alter theproperties of the feedstock and prepare the organic material for digestion, including:•••

ThermalChemical/Biological, orElectrical.

Pretreatments discussed in this section are employed to increase methane yields, shorten retention times,
and reduce post-treatment of digestate materials. As these processes can support the hydrolysis stage in thedigestor, reducing longer chain polymers to simpler monomers ready for conversion.
In some cases, a combination of pretreatment operations may be employed to optimize biogas yields e.g.
thermo-chemical pretreatment.
i. Thermal Pre-treatment
In feedstocks that contain organic waste with resistant/complex cell structures or quantities of lignin, thermal
pre-treatment can assist acidogenic bacteria in decomposing feedstocks by breaking up molecular structures
before the feedstock enters the digester (Kamali et al., 2016).
This can be accomplished multiple ways:•••

Feedstocks can be heated or mixed with hot water to increase enzyme activity and allow easierdigestion. This is only effective for some feedstocks (Gunnerson & Stuckey, 1986).
Feedstocks can also be heated to high temperature under pressure and then exposed to low pressure,which causes rapid boiling of the water in the organic material and cavitation/rupturing of cells. This
technique is sometimes referred to as ‘steam explosion treatment’ and is sometimes used in conjunction
with pasteurization (Esposito et al., 2011).
Feedstocks can be extruded through orifices with screws, which shears the material at high pressureand high temperature. This method cannot be used for feedstocks where stones or hard materials may
damage the mechanical components (Pilli et al., 2020).

ii. Chemical or Biological Pre-treatment
If there are reasons why heat and/or pressure cannot effectively alter the properties of the feedstocks,
chemical or biological pre-treatment may be a suitable alternative. Similar to other kinds of pre-treatment
processes, the goal is to use chemical reagents to break up cellular structures and reduce the downstream
work for the anaerobic digester (Xu et al., 2014).
Chemical Pretreatments usually consist of addition of either an acid or an alkali to break down organic
components in the feedstock. Operators must be careful of how pH is then adjusted before the feedstocks
are added into the digester, as residual chemicals may upset the bacterial cultures in the anaerobic system.
In addition, dosing chemicals is another operational cost to consider in the economics of the plant(Srisowmeya et al., 2020).
Biological pre-treatments can accomplish a similar function as chemical pre-treatment by employing bacterial
cultures different to the bacteria used in the anaerobic digestion process, or enzymes, to perform the samework. Some plants compost or aerobically digest feedstocks to ease the initial stages of digestion before
adding organic waste to the anaerobic system. Enzyme application is also effective but can be prohibitively
expensive (Ariunbaatar et al., 2014).
iii. Electrical Pre-treatment

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| Feedstocks to Biogas Process |New-generation pretreatment technologies continue to be developed as operators look for more energyefficient and non-invasive ways to prepare feedstocks for optimal digestion. Advanced treatments include
microwave treatment (where feedstocks are exposed to microwave radiation) or ultrasound (wherefeedstocks are exposed to high-frequency vibrations) are not widespread but may feature more prominently
in future biogas installations as the technology matures (Achinas et al., 2017).
j. Pasteurisation
Especially in feedstocks with high organic content, it is very likely that organic materials will pick up their own
bacteria and other potentially harmful biological material on their way to a digestion facility. Because theconditions in the anaerobic digesters are designed to encourage bacterial growth and maximise proliferationof bacteria etc., it is vital to remove any possible biological contaminants from feedstocks before passing
them into a digester (Swedish Gas Centre, 2012).
Pasteurisation of a feedstock usually involves elevating the feed material to a set temperature and keeping
the temperature stable for a set period of time. The higher the temperature, the shorter the holding duration(Wood Environment & Infrastructure Solutions UK Limited, 2019).
As digestion plants commonly process multiple tons of material in a day, this process consumes large
amounts of energy per batch and is one of the largest heat loads on the digestion system along withmaintaining digester temperature. However, the risk of not pasteurizing a batch properly leading to a digester
failure is significant, so this process should not be skipped if the feedstock carries the risk of contaminants.
Some WWTPs in the UK combine pasteurization and thermal pre-treatment stages to both sterilize solids
and also prepare the feedstocks for digestion (SAMCO, 2019).
Animal manure sources used for local, small-scale biogas production are generally not pasteurized or pretreated, as an exception.

Digestion Processes
k. Dry and Wet AD Technologies
Feedstocks into a digestion process are usually a two-phase mixture of solid organic waste and a fluid
containing dissolved COD. Depending on the proportion of solid to liquid material, the mixture can either beprocessed like a wet solid, a slurry or (more or less) as a liquid stream.
Dry digestion (where TS% >20) can either occur in plug flow systems where solids are continually pushed
through a reactor body and digested, or in batch-type reactors where piles of organic material are depositedin a sealed bunker and left to decompose.
Generally, dry digestion is much more labour-intensive than wet digestion as the feedstocks cannot be
pumped and must be moved/sorted manually for example by front end loader.
Wet digestion can be separated into two categories; suspended solid digestion (where 15% > TS >5%) or
hydraulic digestion (<5%). Suspended solids digestion, where bacteria are mixed into the organic slurry, iscommon for wastewater treatment sludge and food waste where there is a lot of suspended organic matter.
Hydraulic digestion, where bacteria are attached to a medium, is used for predominantly liquid organics
streams like industrial wastewater.
Wet digestion involves a much higher amount of fluid entering and leaving the digester, which can be aconstraint if the plant is not near a ready supply of fresh water or cannot properly filter and dry digested
organic material, especially if the feedstock is dry to start with. However, the feedstock can be processed
and treated like a liquid which allows for more autonomous control and processing.
Of the total installed capacity of biogas plants in Europe, 62% is from dry-type digesters (Van et al., 2020).

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| Feedstocks to Biogas Process |l. Batch vs Continuous
In all applications where the feedstock is low in solids content (TS <15%), the digestion process is usuallycontinuous. Suspended organic matter is circulated and mixed with bacteria to achieve a more-or-lesshomogenous solution, and as biogas is generated additional feed is added.
In high solids feedstocks (TS >30%), a batch process can be used as a low-CAPEX alternative to a fully
mixed reactor system or plug flow reactor. While a continuous reactor has a continual supply of organic
material into a reactor and biogas/digestate is continually harvested from the reactor, a batch system fully
processes a fixed amount of organic waste into biogas and digestate with no other additives or external
inputs (except heating). Batch processes must be initialized with a sample of bacteria from a completed
batch, while a continuous process always maintains a level of the required bacteria (Rocamora et al., 2020).
Batch reactors are popular for energy crop or municipal source segregated food waste feedstocks, and they
are easy to construct and operate. However, they do require more space so are most popular in rural areas.
In a batch process, the four stages of methane generation must occur in series in contrast to a continuous
system where all four stages are proceeding in parallel. This means that the methane production is variable,
and buffering/storage will have to be allowed for. A way around this is to design a plant where multiple batchprocesses are happening at once and the variable flows can be averaged out.
Of the total installed capacity of biogas plants in Europe, 76% is from continuous digesters (Van et al., 2020).

m. Thermophilic vs Mesophilic
Thermophilic digesters have become more popular in large-scale digestion installations in recent years, as
researchers have observed large increases in achievable OLRs with increases in reactor operating
temperatures. Thermophilic digesters can produce much larger yields of biogas and process more organic
material than mesophilic digesters with similar volumes (Bekkering et al., 2010).
The downside of thermophilic digestion is that the process requires more energy to maintain the higher
digester temperature, which creates a larger parasitic load on energy produced from biogas production.
Thermophilic digesters are also more susceptible to temperature swing upsets than mesophilic digesters(Mckendry, 2018).
In short, thermophilic digestion is the most efficient digestion mechanism but it requires more energy andtighter control than mesophilic digestion, so is not suitable for smaller installations where the main function of
the plant is dealing with organic wastes. The only way thermophilic digestion becomes economic is withscale of digestion, a guaranteed market/buyer for the biogas and when available land for the digestion plantis at a premium.
Of the total installed capacity of biogas plants in Europe, 33% is produced in thermophilic digesters.
n. Single Stage vs Multi-StageAs discussed previously, there are four different biological stages in the conversion from organic material tobiogas, undertaken by three different types of bacteria. Each of these bacteria are unique; they operate best
under different conditions and respond to changes in their environment in different ways. The first and laststages in particular, hydrolysis and methanogenesis, have the smallest overlap in efficient environmental
conditions (Van et al., 2020).
In large biogas processing installations, the digestion process can be broken down into multiple unit
operations i.e. there are multiple digestion stages for the feedstock. Commonly, the hydrolysis andacidogenesis stages are separated from the acetogenesis and methanogenesis stages. This allows eachstage of the reaction to proceed at optimized rates and decreases the overall retention times of the feedstock

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| Feedstocks to Biogas Process |which decreases the total installed volume of the digester(s) (McConville et al., 2020). This in turn reduces
the footprint of the AD plant and can be installed in smaller land space.
Multiple stage digestion has not been popular for most of utility-scale anaerobic digestion’s history as it does
require more upfront costs and smarter plant control to operate efficiently. In recent years, a larger proportionof multiple stage systems are being constructed, but only 7% of European installed biogas capacity ismultiple stage (Van et al., 2020).

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| Choosing a Biogas Processing Operation foryour Feedstock |A4.Choosing a Biogas Processing Operation for your Feedstock
Properties of Standard Feedstock Supplies
The five primary feedstocks we have analysed in this report have quite different properties and must bedigested differently in order to achieve the best biogas yield for dollar spent on digester construction andoperation.
Considering the variables discussed previously, here is a brief overview of each target feedstock withrespect to digester selection.
a. Wastewater Treatment Sludge
Due to the degree of pre-processing wastewater treatment sludge receives before it is ready for ananaerobic digester, the properties of this feedstock are reasonably consistent for a given WWTP (Bachmann,2015). Depending on the presence of large individual contributors to individual wastewater treatment
systems e.g. a meatworks or dairy plant connected to the municipal wastewater system, there may be
specific deviations from standard sludge properties for a given plant. However, it is likely the sludge from asingle treatment plant will be consistent throughout the year.
•
•
•
•
•
•
•

Variation in volume of feedstock available (or seasonality): Low variation
Feedstock COD or volatile solids %: 70-80%
Total Solids %: 15%
Expected pH: Neutral
Any required pre-treatment: Pasteurisation and possibly additional thermal pre-treatment
Presence of sulphur, nitrogen, phosphorous, ammonia: Generally suitable
Other contaminants: Siloxanes from wastewater (Li et al., 2019)b. Animal Manure
The properties of animal manure are fairly consistent, depending on the diet of the animals in question. Cow
manure is the least complicated manure source to digest, as manure from chickens and pigs can containhigh levels of chemical contaminants that must be removed from the biogas, requiring additional processing(Sørensen et al., 2019).
•
•
•
•
•
•

Variation in volume of feedstock available (or seasonality): Consistent throughout the year
Feedstock COD or volatile solids %: 75-85%
Total Solids %: 10-20%
Expected pH: Neutral to mildly acidic
Any required pre-treatment: N/A
Presence of sulphur, nitrogen, phosphorous, ammonia: Higher presence of ammonia and sulphates inchicken/pig manure (Risberg et al., 2017)c. Source-Segregated Food Waste
In a large enough collection, properties of the combined feedstock are fairly consistent from day to day. The
biggest challenge in source-segregated food waste is changes in the composition of the feedstock withseasonal variations in available produce. If the plant accepts commercial and industrial food waste as well as
municipal food waste, there may be the occasional large delivery of a single food source which could affectthe consistency of material into the digester.
••••

Variation in volume of feedstock available (or seasonality): Constitution seasonal, volumes consistentFeedstock COD or volatile solids %: 85-90%
Total Solids %: 15-20%
Expected pH: Neutral to mildly acidic

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| Choosing a Biogas Processing Operation foryour Feedstock |••Any required pre-treatment: Screening and pasteurisation
Presence of sulphur, nitrogen, phosphorous, ammonia: Generally suitable

d. Crop Silage
Different types of crops have different properties in terms of biogas yield and ease of digestion. Crop silage
from a single crop source is relatively consistent in terms of feedstock properties, but the amounts of total
feedstock available in a given month are highly variable. During harvest seasons, large quantities offeedstock are collected and ready for digestion. During non-harvest seasons, minimal material is available.
To this end, it is best to either design a modular digester or to incorporate the crop material as a secondary
feed material into digester primarily fed by another feedstock (Möller & Müller, 2012)(Blanco-Canqui, 2016).
•
•
•
•
•
•

Variation in volume of feedstock available (or seasonality): Highly seasonal for singular crop sources.
Feedstock COD or volatile solids %: 85-95%
Total Solids %: 30-60%
Expected pH: Neutral
Any required pre-treatment: Screening and mechanical processing
Presence of sulphur, nitrogen, phosphorous, ammonia: Generally suitable

e. Industrial Wastewater
There are two main challenges with processing industrial wastewater: the presence of highly acidic or highly
basic wastewater streams e.g. caustic from CIP, and the variation/seasonality of wastewater based on
variation/seasonality of the corresponding industrial process. Each industrial wastewater digestion plant will
have to be reasonably bespoke depending on the quality and quantity of wastewater produced (Clarke,2019).
••••••

Variation in volume of feedstock available (or seasonality): Highly variable; depending on process highly
seasonal also
Feedstock COD or volatile solids %: Highly variable
Total Solids %: <5%
Expected pH: Highly variable
Any required pre-treatment: Generally none
Presence of sulphur, nitrogen, phosphorous, ammonia: Highly variable depending on process

Best Digester Configurations for Standard Feedstock Supplies
Based on our assessments of the feedstocks above, the best-fit standardised processing configuration for all
sources above in different quantities is detailed in Table 34.
Table 34: Standard Digester Technology/Configuration by Feedstock Source Type and Volume

Feedstock

Small (<5,000 t/year)

Medium (<25,000 t/year)

Large (>30,000 t/year)

WWTP
SludgeSingle-stage fullymixed digester

Single-stage fully-mixed
digester

Multi-stage fully-mixed
digester

AnimalManureFarm-scale anaerobic
lagoon or PFR
digesterSingle-stage fully-mixed
digester or continuous dry
reactorMulti-stage fully-mixed
digesterFood Waste

Dry batch reactor

Single-stage fully-mixed
digester or multiple dry
batch digesters

Multi-stage fully-mixed
digester

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| Choosing a Biogas Processing Operation foryour Feedstock |Feedstock

Small (<5,000 t/year)

Medium (<25,000 t/year)

Large (>30,000 t/year)

Crop Silage

Dry batch reactor

Single-stage fully-mixed
digester or multiple dry
batch digesters

Multi-stage fully-mixed
digester or large-scale dry
batch reactors

Industrial
Wastewater2

Single-stage small
High-Rate Hydraulic
Digesters

Single stage High-Rate
Hydraulic Digesters or large
Anaerobic Lagoons

Multi-stage High-Rate
Hydraulic Digesters, orlarge Anaerobic Lagoons

a. Farm-scale Anaerobic Lagoon or PFR Digesters
For small-scale manure collections on farms, the best solution is usually a covered lagoon digester or a plug
flow digester, depending on the water content of the feedstock source. Both of these systems are low capitali.e. require minimal capital investment and have little upkeep costs. The gas generated by these small
systems can be scrubbed and compressed for use in heating or power generation or used as a vehicle fuel.
This type of system is recommended for small-scale, isolated sources of manure only.
b. Small Dry Batch Digesters
In small-scale feedstocks with high TS percentages (>30%), dry batch digestion can be a cost-effective way
to process organic waste materials without having to worry about tight process controls or screening/preprocessing feedstocks. After a batch of material is inoculated with bacteria, it is sealed in an airtight cell andleft to decompose, releasing biogas.
This method of digestion is modular and requires little intervention but is more manual and biogas output isless stable than a continuous process. Because these systems can be designed to be small and modular, it
is possible to install them in a variety of locations which can enable the biogas produced to be used in many
applications.
c. Multiple Dry Batch Digesters
If given feedstocks are too dry for Fully-Mixed digesters and there is not a readily available source of water
for dilution, then a modular dry batch digestion system may be a good alternative. By running multiple drydigestion cells in parallel, it is possible to treat more feedstock effectively than a single cell digester and the
combined production of multiple cells evens out variable biogas production seen in single cell systems.
This requires a larger plant than a Fully-Mixed-type system as digestion times are generally longer, and more
space is required for manual materials handling. There are many examples of successful dry multi-reactor
systems overseas producing biogas and processing the gas into biomethane (Rocamora et al., 2020). At thisscale, the dry batch reactor will often include a percolation loop which helps mix and recirculate liquidmaterial in the feed and improve the rate of digestion.
d. Single-stage Fully Mixed Digesters
Single-stage fully-mixed digesters are by far the most popular processing arrangement for medium-sized
sources of organic material with a TS percentage between 10 and 20%. It can also be used to process drier
feedstocks like crop silage, but these require addition of water or waste oils first.
At the scale where this technology is employed overseas, mechanical pre-treatment and pasteurisation
become economically feasible but the volumes do not support multi-stage digestion (Van et al., 2020).
Continuous wet processes like single-stage Fully-Mixed digesters require active process control like heating,gas monitoring, mixing, feedstock screening and buffering as well as gas storage and scrubbing.

2
Note: with high-rate hydraulic systems (TS <1-2%), the feed rates in tonnages should be considered thesolids feed rate only – industrial wastewater digestion plants can process millions of tonnes per year of liquid
feed, but average liquid residence times are less than a day.

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| Choosing a Biogas Processing Operation foryour Feedstock |These systems generally require a centralised collection of feedstock, and at this scale extra investment inbiogas upgrading or biomethane processing equipment becomes viable as observed overseas.
e. Multiple Stage Fully Mixed Digesters
At larger scales, the merits of multiple stage digestion plants start to stack up; faster digestion enabled bystaged digestion units allow faster processing of equivalent feedstock volumes than single-stage processes
which decreases vessel sizing and overall capital/operational costs.
Large multi-stage fully mixed reactors are still relatively new due to the required automation and tighter
process controls required, but they are now the process arrangement of choice for large quantities of wet
feedstocks.
f. Single Stage High-Rate Hydraulic Digesters
Small-scale low TS% digesters are becoming more and more advanced in recent years, with the smallest
available digester units approaching 1 m3 in size. The key operating principle of these kinds of reactors is
separating and processing solid and liquid components at different rates to allow maximum biogas yields.
For low solids feedstocks, reactors that separately circulate liquid and solid feed components deliver the best
overall COD reduction and produce the most biogas. There are many different kinds of liquid digester e.g.
UASB (Upflow anaerobic sludge blanket) , EGSB,(expanded granular sludge blanket) or AF (Anaerobic filter)reactors, and the best choice is generally driven by the qualities of the feedstock as well as appetite for
operational complexity (Clarke, 2019). Each design requires seeding by active granular activated sludges, alimitation to uptake in New Zealand is availability to sludge.
Depending on the site, a small to medium-sized wastewater digestion unit will usually be used to supplement
heat energy used onsite, either dosed into boiler natural gas feeds etc. or to generate small amounts of heator electricity for specific equipment.
Hydraulic reactors require seeding at commissioning to establish a working bacteria population.
g. Multiple Stage High-Rate Hydraulic Digesters
Similarly to single- vs multi-stage Fully-Mixed digesters, higher efficiencies of conversion and optimisation ofindividual conversion stages can become viable as required single reactor sizes increase.
Depending on the site in question and its own energy needs there may be a demand for the biogas produced
onsite, or biomethane production may be a better use of the gas. A primary example of a high rate hydraulicsystem is seen in the IC (internal circulation) design which separates out the pre-acidification stage inincrease methanogen performance and contact time.
h. Large-Scale Anaerobic Lagoons
In the case where a low solids waste stream like dairy runoff from a large farming complex or a large quantityof industrial effluent is produced in an area with lots of space, or if this waste is currently directed to a holding
pool/lagoon-type treatment system, an alternative to high-rate hydraulic digesters could be an anaerobic
lagoon system. These digestion systems require little-to-no interaction and are cheap to install (especially if
the lagoon already exists). Retention times are much higher for this type of system, from 20 to up to
150 days (Moser et al., 2008). This is the current system utilised at the Fonterra Tirau plant discussed
previously.

Capital Costs for Standard Digester Types
The main factors that affect the differences in capital costs for digester construction are:•••Size of the digester. This is determined by the type of digester and the specific operating conditions
Required pre-treatment equipment. This is determined by the physical properties of the incoming
feedstock
Feedstock storage and handling. This is determined by the logistics and collection of feedstock supplies.

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| Choosing a Biogas Processing Operation foryour Feedstock |The most inexpensive plants in terms of capital investment per tonnage of waste processed are dry, singlestage mesophilic digesters. While waste handling and processing are a bit more manual than other options
and production is a bit more variable than other installations, the simplicity and robustness of these plants
make them attractive to small-scale generators.
Capital costs increase when moving to wet/continuous digestion as processing becomes more automatedand feedstocks require dilution/mixing as well as more active control. These plants require more
instrumentation as levels/temperatures and flowrates need to be monitored and managed. The payoff is inlevelling out production, and reducing manual handling (Hengeveld et al., 2020).
Depending on the feedstock, pretreatments can become energy-intensive and require expensive equipment.
Chemical additives or buffering tanks, heat exchangers and boilers for pasteurizing and de-naturing
feedstocks etc. increase operational expenses and affect the proportion of biogas able to be sold rather thanused. However, they can improve the processability of feedstocks and can increase yields to provide
additional revenue in operation.
Moving to multi-stage or thermophilic systems increases capital costs again as the process becomes more
automated and more energy-intensive. The biogas yields and organic loading rates of these plants are miles
above what can be achieved in small-scale dry digestion systems, but only large-scale commercial
generators with large sources of organic waste to process can finance these kinds of projects (Mckendry,
2018).
a. Single-stage Fully Mixed Digesters
Small-to-medium sized Fully-Mixed digesters for manure processing or food waste digestion are more
expensive per unit of feed processed or gas produced than larger installations. At the lower ends of size for
economic grid connection based on overseas case studies, digestion facilities can cost between$35,000 - $45,000 NZD per Nm3/hr installed biogas generation capacity, or between$500 - $800 NZD per tonne of feed material processed per year (Moriarty, 2013; Truong et al., 2019). If
plants are designed to receive material with higher upfront pre-treatment requirements e.g. energy crops,
then investment costs can increase by 20% (Cleanleap, 2013).
At the lower end of the size scale for biogas plants, costs for digestion plant installation can vary significantly.
Depending on the specificities of the feedstock and possible variations in incoming feed material, biogas
plants may need to be designed to be more flexible and therefore more complex than some larger
installations (Truong et al., 2019).
b. Multiple Dry Batch Digesters
As an alternative to Fully Mixed digesters for feedstocks with high solids content, multiple cell dry digester
units can be used but these are generally more expensive to build than fully mixed liquid reactors, with the
majority of capital expenditure going towards concrete structures for the sealed cells (Biogas World, 2021b).
Case studies for medium-sized food waste or manure digestion plants show costs of between$35,000 - $65,000 NZD per Nm3/hr installed biogas generation capacity (Spencer, 2010). The largest dry
digestion facility in the world in San Jose processes 90,000 t of feed material and produces electricity andcompost as valuable products.
c. Multiple Stage Fully Mixed Digesters
Overseas case studies of this technology suggest that as biogas plants increase in size their cost percapacity begins to decrease. Digesters producing between 500 and 1000Nm 3/hr of biogas can cost between$25,000 - $30,000 NZD per Nm3/hr capacity. At higher capacities, this cost can decrease to below$20,000 NZD per Nm3/hr biogas generation capacity (Truong et al., 2019). At larger sizes, economies ofscale can drive down the costs per unit capacity and having a larger feedstock supply with buffering capacity
means that the plant can afford to be less specialised (Mckendry, 2018).

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| Choosing a Biogas Processing Operation foryour Feedstock |Based on the capacity of the upcoming Reporoa biogas plant (75,000 t/year of source-segregated foodwaste) this plant would expect to produce close to 2,000 Nm3/hour. With an expected price tag of$30 million NZD, this plant is being constructed for around $15,000 NZD per Nm3/hr biogas generation
capacity, or $400 NZD/tonne of feed material processed per year (Sherrard, 2020). This lines up withobservations from overseas installations, and provides confidence that these projects can still be completed
in New Zealand for equivalent costs.
d. High-Rate Hydraulic Digesters
Based on estimates from vendors, at grid-scale these types of reactors can be installed for around$27,000 per Nm3/hr capacity (SAMCO, 2019). These digesters are less expensive that other types ofdigesters discussed in this section on a biogas production capacity basis – this is primarily due to the shorter
required retention times and therefore smaller reactors. However, the initial cost to seed the digester could
be significant.

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| Biogas to Biomethane Processing |A5.Biogas to Biomethane Processing
Biogas produced from the breakdown of organic materials will contain a variety of components that can bebeneficial or detrimental to further uses. Raw biogas will typically contain methane (CH4) concentrations
greater than 50 mol%, with the remainder being comprised mostly of carbon dioxide (CO 2). The CH4 andCO2 content of raw biogas can be considered as potential value streams for biogas upgrading schemes.
Table 35: Methane and carbon dioxide content (% by volume) of landfill gas and biogas from anaerobic digestion

Component

Landfill Gas(Nyamukamba et al., 2020; Sun etal., 2015)

Biogas from AD% by volume at standard
conditions(Al Seadi et al., 2008;
Nyamukamba et al., 2020; Sunet al., 2015)

Methane30-60 mol%

50-75 mol%

Carbon dioxide

15-40 mol%

25-45 mol%

For biogas to be utilised as fuel in reticulated natural gas networks, the CV requires upgrading to meet theappropriate gas specification. In New Zealand, all reticulated natural gas is required to meet constituent andWobbe specifications according to NZS 5442-2008. Further details of the requirements of NZS 5442 andtheir influence connecting a biomethane production plant to a reticulated network are outlined in Section 5.4of this report.
There are three steps when upgrading biogas to biomethane and exporting:•••

Pre-treatment (cleaning)
Biogas to biomethane processing (upgrading)
Network injection

Figure 17: Typical biomethane upgrading process

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| Biogas to Biomethane Processing |Depending on the type of feedstock the biogas is produced from, there can be smaller concentrations ofcomponents such as sulphur (S), hydrogen sulphide (H2S), silicon organic compounds (siloxanes), oxygen(O2), water (H2O), ammonia (NH3), Nitrogen (N2) and particulates that are viewed as contaminants to the raw
biogas (Sun et al., 2015b), outlined in Table 36. The actual concentration of these contaminants varies
depending on the feedstock quality but are typically viewed as detrimental to downstream equipment.

Table 36: Contaminants in raw landfill gas, biogas from AD, and limits for reticulated gas in NZ

Landfill Gas% by volume atstandard conditions

Biogas from AD% by volume atstandard conditions

Reticulated NG% by volume atstandard
conditions

Nitrogen – atmospheric
N2 is introduced during
AD feeding or landfill gas
extraction

0-15 mol%

0-1 mol%

Not specified

Water vapour – ADprocess is saturated &reactor temps are typicallyhigher than ambient

1-5 mol%1

Oxygen – atmospheric O2
is introduced during AD
feeding, H2S control orlandfill gas extraction<2 mol%Contaminant<0.00001 mol%2
1-5 mol%1<2 mol%<1%(low and medium
pressure grids)<0.1%(all other cases)

Ammonia – AD treatmentof feedstocks with highlevels of nitrogen

0-5 mg/m³0-100 mg/m³

Not specified

Siloxanes – caused by thedigestion of silicone
compounds in landfills or
WWTP sludge

0-50 mg/m³

0-20 mg/m³

Not specified

Hydrogen sulphide –caused by the digestion of
sulfide/protein containing
feedstocks

100-10,000 mg/m³0-1000 mg/m³<5 mg/m³

Hydrogen – from thedigestion of sugars &VFA’s

0-3 mol%<1 mol%<0.1 mol%

Total Cl

0-100 mg/m³0-100 mg/m³<25 mg/m³

Volatile Organic
Compounds – typicallyfound in landfill gases<2000 mg/m3-

Not Specified

Source(ATSDR, 2001;
Nyamukamba et al.,2020; Sun et al.,2015(Soleilhavoup &DESOTEC, 2020))(Al Seadi et al., 2008;
Nyamukamba et al.,2020; Sun et al., 2015)(Standards New
Zealand, 2008)(WWTP sludge canproduce high levels ofSiloxanes)

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| Biogas to Biomethane Processing |1

Temperature dependent

2

At standard conditions

Sulphur, H2S and NH3 pose a risk to human health and a risk of corrosion to downstream equipment.
Siloxanes also pose a human health risk and can foul combustion equipment (Nyamukamba et al., 2020a).
The water content of raw biogas is dependent on bulk properties i.e. temperature and pressure, but will
typically be saturated at the outlet of any anaerobic process. The moisture content will condense in pipeworkand equipment and cause corrosion and related issues if the condensate is not managed and/or the gas
dehumidified. Due to the inert nature of nitrogen gas any concentration will negatively affect the calorificvalue of the biogas (Angelidaki et al., 2018).
The acceptable levels of the components within the gas stream are determined by the end use of the biogas.
Combined heat and power equipment can accept biogas with higher levels of contaminants than reticulated
gas end uses (Sun et al., 2015b). Both end uses will require some degree of pre-treatment to remove
quantities of moisture, dust, oil and aerosols in the raw biogas prior to or as part of biomethane upgrading.
Acceptable levels of H2S for different end uses is outlined in Table 37.
Table 37: Acceptable levels of H2S by end-use
End UseGas heating boilers
Combined heat and power (CHP)
Fuel Cells
NZ Reticulated Natural Gas

H2S limit (ppm)
<1000
<1000
<1
<4

References
1. (Choudhury et al., 2019)
2. (NZS 5442-2008)

Pre-Treatment
The pressure of raw biogas from an anaerobic digester is typically less than 10 mbarg and requires a blower
close to the source to allow transport to the pre-treatment drier and filter (Lemmer et al., 2017). Raw biogas
leaving the source can be metered & sampled to help determine performance of the biogas production
facility. Blower operation on AD production must be controlled to ensure a vacuum is not created within the
production process. There have been digestion systems designed to operate as much higher pressure, but
this is uncommon at scale (Zhao et al., 2020).
In contrast, blowers used for extraction of landfill gas create a small vacuum to pull gases out of thegathering system (US EPA, 2000).
Once the raw biogas has left the blower the water content is removed by either condensation drying using
cooling, adsorption / desiccant drying, or the relative humidity is reduced by a further increase in pressure.
Levels of ammonia are also removed during drying. Solid particulates and dusts are filtered using
mechanical filters.
Oxygen and nitrogen are typically not present in high concentrations in biogas produced from AD, however,landfill gas can have elevated levels due to air entrainment. O 2 and N2 are not detrimental to combustion,
however, removal for reticulated gas is typically handled during the upgrading process.
H2S can be precipitated to sulphur within the digester using iron ions and processed with the spent digestate.
Depending on concentration at the digester outlet, H2S can be removed by adsorption on activated carbon
filters, scrubbed using water/amines or chemical absorption media such as iron oxides or sodium hydroxides.
(Petersson & Wellinger, 2009). If residual H2S concentrations remain in the separated gas stream postBiogas and Biomethane in NZ - Unlocking New Zealand's Renewable Natural Gas Potential | 2939894-1559009345-106 |1/07/2021 | 108

| Biogas to Biomethane Processing |upgrading; thermal oxidation, activated carbon adsorption or bio-trickling filters can be used to neutralise the
H2S, and thus make it safe, prior to collection/utilisation or discharge to atmosphere of the separated gas
stream. Activated carbon filters also serve to remove siloxanes that are common in gas produced fromlandfill and WWTP (Nyamukamba et al., 2020b).
The level of pre-treatment will depend on the upgrading equipment requirements as some contaminants candamage processing elements. Most types of upgrading equipment can be used for biogas from all types offeedstocks, providing adequate pre-treatment and cleaning equipment is included as part of the design (AlSeadi et al., 2008). A summary of different pre-treatment options for contaminants is included in Table 38.
Table 38: Pre-treatment Summary . (Sun et al., 2015a)
Impurity

Technology

Outlet levels

Comment

H2S

Biological desulphurisation< 50 ppm

Most common

Iron Chloride

100 - 150 ppm

Used for high quantities

Impregnated Activated Carbon< 0.1 ppm

Common prior to PSA

Iron Hydroxide or oxide< 1 ppm

Finite regeneration cycles

Sodium hydroxide Scrubbing< 1 ppm

Regeneration of reagent not possible

Activated carbon< 0.87 ppm

Carbon unable to regenerate. Sensitive
to humidity

Cooling

26% - 99%
removal-27°C to -70°C

Adsorption with Silica Gel or
Aluminium Oxide

Dew Point

at atmospheric pressure

Absorption with Triethylene
glycol or glycol

Dew Point

Siloxanes

O2/N2

Activated carbon
Molecular sieves
Membranes

H2O-10°C to -20°C-5°C to -15°C

at atmospheric pressure, Regeneration
required to 200°C

Biogas to Biomethane Processing / UpgradingThis report focuses on the commercial processing technologies used to upgrade raw biogas to biomethane:
•
•
•
•
•

Pressure Swing Adsorption (PSA)
Water Scrubbing
Physical Scrubbing – Organic Solvents such as ‘Selexol’
Chemical Scrubbing
Membrane Separation

There are other methods to process impurities from biogas such as cryogenic separation, in-situ removal,
biological methods and hydrate separation that have yet to be made readily available to the commercial
market (Angelidaki et al., 2018). These emerging technologies are not outlined in this study but should beconsidered as part of future biogas production schemes as the technologies evolve and become morecommercially available.
Biological hydrogen methanation (BHM) holds the most potential out of the pre-commercial methods andallows for easy integration with any future green hydrogen economy. The method is to inject hydrogen into
the anaerobic digestion process to provide the conditions for the ‘Sabatier’ reaction to be biologicallycatalysed by the specific archaea of Methanothermobacter at elevated reactor temperatures (~60 °C). The
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| Biogas to Biomethane Processing |Sabatier reaction yields methane from hydrogen and carbon dioxide and is endothermic. Deployed at scale
this process can increase methane output from typical anaerobic digestion processes by 70% thereby
reducing, and in some cases eliminating, the requirement for physiochemical biogas upgrading prior tobiomethane injection into reticulated gas networks (Rusmanis et al., 2019).
The synergies possible between BHM and green hydrogen stem from the increased energy density possible(x3) when injected & transported as biomethane instead of hydrogen gas, therefore employing biomethane
as a hydrogen carrier with the added benefit of not having to change gas appliances to be compatible withhydrogen at point of use.
These emerging technologies are not further described in this study but should be considered as part of
future biogas production schemes as the technologies evolve and become more commercially available.
The design of pre-treatment and upgrading equipment are complimentary of each other and depend on theconstituents of the raw biogas. Generally upgrading equipment is chosen during detailed design of thebiogas upgrading scheme. Indicative gas sampling from the biogas production process with the expected
feedstocks is necessary to ensure the cleaning and upgrading equipment are fit for purpose.
All types of commercially available upgrading have been used successfully for different feedstocks.
a. Pressure Swing Adsorption (PSA)
Pressure swing adsorption upgrading is based on the concept of different sized gas molecules being
selectively adsorbed to a solid surface at high pressure, then released using a reduction in pressure. PSA
can be used to upgrade raw biogas by adsorbing other gas molecules like CO 2, N2, and O2 from the larger
methane molecule (Adnan et al., 2019).

.
Figure 18: PSA sieve pressurization (UNIDO & German Biogas Association, 2017)

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| Biogas to Biomethane Processing |The solid material used to adsorb the molecules requires a large surface area, and the adsorption column
can be filled with activated carbon, zeolitic molecular sieves or carbon molecular sieves. The pressure
swings are used to deposit and release the adsorbed molecules, so the batch process has multiple columns
operating at different phases to produce a constant output (UNIDO & German Biogas Association, 2017).
PSA sieves permanently adsorb H2S so pre-treatment must remove this contaminant prior to the process(Adnan et al., 2019). These characteristics allows PSA additional capability to remove inert gases from raw
biogas sources that include higher levels from feedstocks such as WWTP and landfill gas.
b. Water Scrubbing
Water scrubbing is based on the physical solubility of gas components into a solvent solution. The directcontact between the raw biogas and water solvent dissolves CO2 and other contaminants, such as H2S (upto 0.05 %mol), ammonia and particulates, from the biogas stream. The solubility of CO2 in water is improved
at higher pressure, so the operating pressure for the process is between 4 – 10 barg.
The process takes place in a scrubbing column where water is sprayed downwards while raw biogas is
directed upwards. The upgraded biomethane is released from the top of the scrubbing column and the waterwith dissolved CO2 and other components is collected at the bottom of the scrubbing column. The remaining
gas components are removed in a flash column and collected water with dissolved components is sent to a
stripping column.

Figure 19: Scrubbing technologies schematic (UNIDO & German Biogas Association, 2017)
In the stripping column, the water, CO2 and other dissolved components are sprayed downward while air isdirected upwards and the CO2 and other gases are released from the top of the column as exhaust gases,
and the water is collected at the bottom of the column (UNIDO & German Biogas Association, 2017). The
CO2 released from water scrubbing is usually not collected for further use unless an air stripping unit is fitted
to further process CO2 (Sun et al., 2015b).

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| Biogas to Biomethane Processing |c. Physical Scrubbing
Same as pressurised water scrubbing but using organic solvents such as “Selexol” for enhanced selective
absorption of CO2, able to run at lower operating pressures but requiring a heat source for regeneration of
the solvent.
d. Chemical Scrubbing
Chemical scrubbing uses similar principle as water scrubbing except the solvent is a chemical mixture which
reacts to absorb components from the gas with the solvent. The chemical types include monoethanolamine(MEA), diethanolamine (DEA) and methyldiethanolamine (MDEA) mixed with water (UNIDO & German
Biogas Association, 2017). The amine solution reacts selectively with CO 2 and H2S, so the scrubbing
process takes place at lower pressures (Sun et al., 2015b). To strip the CO2 and other components from theamine solution to be reused for further scrubbing requires elevated temperatures between 120 – 160°C(Angelidaki et al., 2018). This upgrading technology typically requires additional pre-treatment to remove
larger proportions of N2 and other inert gases.
e. Membrane Separation
Membrane gas separation uses selective permeability to separate larger molecules such as methane andsmaller molecules such as CO2, H2S, and O2 (Angelidaki et al., 2018). The raw biogas is pressurised and fed
through a membrane designed to allow the smaller gas molecules to permeate faster through themembrane, while the larger molecules are retained in the tube bundle.

Figure 20: Membrane Separation Fundamental (Pentair Haffmans)
The permeation rate of different size molecules through the membrane is a key design parameter that
determines the materials for the membrane. The process requires operating pressures between 7-20barg
and can use multiple passes through membranes to achieve higher methane purity (UNIDO & German
Biogas Association, 2017). Membranes have been used for upgrading for all feedstocks with varying
degrees of pre-treatment equipment
f. Equipment Comparison
The individuality of each biogas production scheme will determine the appropriate technology required for
upgrading. Where a high methane content is required PSA and chemical scrubbing are ideal technologies. In
situations where the raw biogas includes higher concentrations of N2 and O2, then the ability for membrane
and PSA equipment to remove these along with CO2 present them as ideal technologies. For cases where
the output H2S requirement is stringent, then most upgrading technologies will be paired with activatedcarbon filters or iron oxide chemical scrubbers (Sun et al., 2015a).
A comparison of the different biogas upgrading equipment is included in Table 39.

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| Biogas to Biomethane Processing |Table 39: Biogas Upgrading Equipment Comparison
Upgrading TypeOperatingPressure(barg)

OutletPressure(barg)

EnergyRequired(kWhe/m3)

MethanePurity(%)

MethaneSlip (%)

Pre-treatment
Required

Cost

PSA

3 - 104-5

0.15 – 0.35

96 - 98<4

Yes

MediumWater Scrubbing

4 - 10

7 - 100.2 – 0.4

96 - 99<2

Recommended

MediumPhysical Scrubbing

4-8

1-8

0.2 - 0.3
(scrub)<0.2(heat)

96-98

2-4

Recommended

MediumChemicalAbsorption

1-2

4-5

0.1 - 0.3
(scrub)96 - 99

<0.1

Yes

High

96 - 98<0.6

RecommendedHigh

0.5 – 1.0
(heat)
Membrane

7 – 204 - 100.15 – 0.25

References
1.(UNIDO & German Biogas Association, 2017)
2.(Adnan et al., 2019)
3.(Angelidaki et al., 2018)
4.(Sun et al., 2015b)

Network injection equipment
Once the biogas has had the majority of CO2 and other contaminants removed to upgrade the CV, thebiomethane can be injected into the natural gas network. Like other natural gas producers, the biomethane
producer is required to ensure the biomethane adheres to NZS 5442 prior to network injection. Certain
equipment is required by the network operator to enable biomethane injection into the network. This injection
equipment can be located at the biomethane production facility or at the BIP to the network. Packaged
equipment options of Grid Entry Units (GEUs)are available from vendors that perform the following functions.
The potential ownership models for this equipment is outlined in Section 3.C.iii.
a. Gas Chromatograph
Processing equipment may incorporate some fast-acting instrumentation / performance measurement
devices to aid in operation and control of the processing equipment. However, a gas chromatograph (GC) is
required by the network operator to measure the components of the biomethane and ensure the gas meetsthe specification essential for reticulated customer use. A GC will typically be incorporated to provide an
online measurement of gas quality to the network operator gas control for safety and billing purposes.
Should the biomethane go out of specification limits, the network operator will require the BIP to be isolated
from injecting into the network. During the out of specification event the biogas can be reprocessed ordiverted to a flare capable of handling the entire flow of raw & upgraded biogas. This rejection requirement
will be included in the overall equipment design.

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| Biogas to Biomethane Processing |b. Pressure Compression or Regulation
Depending on the outlet pressure of the processing equipment, a second stage of compression may berequired to ensure the biomethane pressure can overcome the network pressure to be injected.
Compressors can be controlled to ensure that the maximum allowable operating pressure (MAOP) of the
network is not exceeded, and a second stage of pressure regulation such as a pressure relief valve will be
required according to either AS/NZS 2885 or AS/NZS 4645.
In instances where the outlet pressure of the processing equipment exceeds the MAOP of the network (suchas injection into some distribution networks), then pressure regulators are required. Each network operator
will have their own regulator equipment specifications that they will provide for the biomethane producer.
c. Wobbe Index Adjustment
To ensure biomethane being supplied into the natural gas network is consistent with energy content
requirements, in-line monitoring of the Wobbe index of the resultant biomethane is required. To ensure an
acceptable gas quality is reached prior to injection, the gas can be dosed with propane to elevate its energy
content (Angelidaki et al., 2018; Energiforsk, 2016)
d. Gas Metering
Each network operator requires accurate gas metering as part of their network injection equipment. Accurate
metering allows network operators to measure the quantity of gas entering the network and allocate gas
sales to specific producers. Each network operator will have their own metering equipment specifications
that they will provide for the biomethane producer.
e. Gas Odorisation
As natural gas does not have any odour, part of the requirements of NZS 5442 for reticulated gas networks
requires natural gas in reticulated networks to be odorised as a safety measure for being able to identify gas
leakage. The recognisable smell is the odorant added to natural gas, which is a mix of 80% tertiary butyl
mercaptan and 20% iso propyl mercaptan (Firstgas Ltd, 2020b). Most transmission pipeline networks in New
Zealand transport odorised gas, but a select few transport unodorised gas.
Most BIPs will likely require odorisation equipment to provide a consistent small percentage of odorant(minimum 3 mg/Nm3) to the gas stream. Odorisation equipment is mostly owned and operated by thetransmission network operator, but some producers own and operate their own odorisation equipment.
f. Network Isolation Valve & Interconnection
To connect a biomethane production facility to an existing network, a BIP will require interconnection
equipment. Depending on the chosen location of the BIP, the equipment required to connect to the existing
network could include modifications to an existing delivery point. Connecting through an existing DP will
involve pipework connections, isolation valves and monitoring equipment to be retrofitted. The network
operator will be able to supply the biomethane producer information on existing assets and advise whether atie -in can be made using an existing DP, or whether a new dedicated tie-in point is required.
A biomethane production facility located away from any existing delivery points will require a dedicateddelivery point or network tie in point. A dedicated tie-in point will require the use of some hot-tap or saddle
tee equipment depending on the network pressure and material. All BIPs require an isolation valve to besafely isolated from the existing network and network operators may require this isolation valve to be
automated for remote operation.
There may be instances where a BIP cannot be located close to a gas network with capacity available, and a
dedicated pipeline may be required to interconnect into the nearest suitable network. The lateral pipeline
construction will depend on the network operating pressure.

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| Biogas to Biomethane Processing |Additional factors to consider
a. Reject CO2 use/quality
Raw biogas typically includes 30-40 mol% CO2 which must be substantially removed during the biomethaneprocessing stage. This means that a substantial quantity of CO 2 will be constantly removed from the gas
stream and there may be opportunities to utilise this gas. The biogenic CO2 gas could be vented to the air,
but this is the least preferable solution. The CO2 can be processed to a certain level and either bottled ortransported for commercial use, such as a commercial greenhouse/plant growing business to enhance thecrop yields.
The waste CO2 could also be further processed and sold as “food grade” CO 2 for many commercial business
opportunities. This is particularly useful in New Zealand currently where there are limited sources of “foodgrade” CO2 from renewable sources. These opportunities should be evaluated to consider the potential value
stream that could be created in the overall biogas processing scheme.
Filtration systems are available to achieve a quality of CO 2 which can be sold to improve the overall viabilityof any potential biogas scheme being considered.
b. Reject Heat use
Gas compression used to increase the biogas pressure for biomethane processing may also be used toincrease the biomethane pressure for injection into the gas reticulation system. If injection is required into thehigh-pressure transmission network, the required compression will generate waste heat in the biomethanegas which must be cooled to meet network temperature limits. This waste heat can be repurposed within the
biogas plant design to be used efficiently to reduce overall plant running costs (i.e. to help provide heat toanaerobic digestion or digestate treatment). The practicality of using the waste heat will depend on eachplant’s specific design and should be considered as part of the initial system design to improve overall plant
efficiency.
c. Redundancy of equipment vs shutdown and recycle
The standard design approach for gas distribution and transmission pressure regulation stations includes
equipment redundancy to operate with a primary regulator stream running and a second stream in standby,
which will automatically take over if needed. This arrangement ensures that gas flows from the station are
uninterrupted, whether due to equipment fault/ failure or during times when maintenance is undertaken.
Duplicate pressure regulation at biomethane injection points may not be required if the overall biogas plant isdesigned to recycle or store significant gas volumes. Gas recycling or rejection would generally be requiredfor biomethane gas that does not meet specification. It will need to be established whether the best
economic decision is to shutdown the gas installation during planned maintenance or equipment fault/failure
and recycle the biomethane, or to provide injection equipment redundancy to allow the biomethane tocontinue to be injected into the gas network during these times.
The gas processing plant and filtration systems will also require periodic maintenance i.e. to change filtration
elements, service rotating equipment, and this system is rarely duplicated. Hence shutdown of this system
for maintenance will require recycling, storage or flaring of biogas.
At large biogas production sites (4,000-16,000 Nm3/hour) multiple biogas upgrading ‘trains’ are typically
deployed in conjunction with raw biogas buffer storage (either integrated into digester volumes or as
standalone storage). This allows for maintenance activities to be conducted on one upgrading train whilst
ramping down organic loading/feeding rates and storing the balance of the biogas not upgraded in the othertrains. This typically allows for a 12-18 hour outage window with minimal flaring of biogas required

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| Biogas to Biomethane Processing |d. Fugitive Methane Emissions - also known as ‘Methane Slip’
All the biogas upgrading technologies described above are affected by the phenomena of methane slip.
When permeating, absorbing or adsorbing contaminants by physical or chemical means, a small but
measurable amount of CH4 is also captured alongside the targeted contaminants. The separated
components continue to the next step of the process which can include venting to atmosphere, adsorption to
media, biological treatment or thermal oxidation. With the exception of thermal oxidation this small amount ofmethane will be eventually vented to atmosphere and become fugitive emissions. There is a great
responsibility placed on designers and operators of biogas upgrading equipment to ensure that methane slip
is measured and minimised so as to not undo the emissions mitigation that anaerobic digestion andbiomethane utilisation provide.

Capital Cost of Biogas Upgrading and Key Cost Drivers
Every biogas production scheme will be slightly different; however, most will fit into three categories
according to their feedstock types:
•
•
•

WWTP
Landfill
Anaerobic Digestion

The expected size of biogas production plants in New Zealand could be further classified into three
production scales outlined in Table 40.
Table 40: Biogas to Biomethane Scales
Scale

Raw Biogas Production(Nm3/hr)Biomethane Production(Nm3/hr)

Energy Produced (MW)Small

40 - 400

20 - 240

0.2 - 2.4

Medium

400 - 1000

200 - 600

2-6

Large

1000 - 1500

500 - 900

5-9Large +

1500+

900+

9+

As part of this research project, manufacturers of packaged biogas to biomethane processing equipment
have been consulted to provide indicative costing for offerings that fit each of these categories. Additional
information has been provided by research team member’s involvement in similar projects. Scales in the
Large+ category may have packaged equipment solutions but may start to approach custom plant design
scales, so have been left out of this study.
Every biogas production and injection ownership scheme may be slightly different, however, for the purposeof this study, there have been ownership demarcations according to 5 schemes, outlined in Figure 21. Theseownership models range from the biogas producer being responsible only to produce raw biogas and the
network operator owning the balance of equipment. Conversely, the biogas producer could choose to own
and operate all equipment up to the interconnection to the gas network. Each ownership scheme will havebenefits and drawbacks dependent on the specific goals of the production and injection scheme.

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| Biogas to Biomethane Processing |Figure 21: Network operator equipment ownership models
As part of this study, best efforts have been made to provide ownership demarcations which coincide witheach stage of the upgrading and injection process. Although this study has suggested ownership models,each biogas project could have an individual ownership and cost model that differs from this study.
To inform this study, costs associated with production equipment are given as ranges of rough orders ofmagnitude costing. Actual equipment and running costs will be heavily dependent on the detailed design ofeach project, and this study does not attempt to quantify these details.

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| Biogas to Biomethane Processing |Table 41: Biogas Upgrading Cost Matrix ($NZD)

OptionBiogas Processing Plant Costs

Biomethane Injection Costs

Raw Biogas source

Components

BiogasAD

LandfillA

40-4001.9 M

400-1000

2.4M - 2.9M

~2M

~2M

2.49M-

2.47M-

3.13M

3.07M

Biomethane

Grade CO2

(Nm3/hr)Metering &Injection

Regulation

Point

0.5M - 2M

0.3-0.5M

0.5M - 1M

N/A

0.3-0.5M

0.3M - 0.5M

0.5M - 2M

0.3-0.5M

0.5M - 1M

N/A

0.3-0.5M

0.3M - 0.5M

N/A

N/A

Compression

20-2400.7M –

200-600

1.4M

transmission

1000-1500

B

Food
WWTP

(Nm3/hr)

3.22M-

3.17M-

4.54M

4.46M

~2M

~2M

2.49M-

2.47M-

3.13M

3.07M

3M-4.2M

40-4001.9M

400-1000

2.4M - 2.9M

500-900

20-2400.7M –

200-600

1.4M

distribution

1000-1500

3.22M-

3.17M-

4.54M

4.46M

3M-4.2M

500-900

40-40020-240C
400-1000

N/A

200-600transmission

1000-1500

500-900

40-40020-240D
400-1000

N/A

200-600

distribution

1000-1500

500-900

40-40020-240E
0.5M - 1M
transmission

400-1000

N/A

200-600

0.3M - 0.5M
distribution

1000-1500

500-900

Add Ons$/unit

Unit

Range

Odorisation$ 100kea.

± 10%Distribution Pipeline$ 300kkm± 20%

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| Biogas to Biomethane Processing |Add Ons$/unit

Unit

Range

Transmission Pipeline$ 750kkm± 30%

Gas Chromatograph

$ 80k

ea.

± 10%

Land use

$ 300

m2

± 30%

Telemetry Connection

$ 45k

ea.

± 10%

Compression to IP pressure (19.6barg)$ 0.5M – 2M

ea.

± 50%

References: (Sun et al., 2015a) , (Pentair Haffmans, 2021), (Galileo Technologies, 2020), (Sauer Haug Compressors,2021), (Xebec, 2020), (Firstgas Ltd, 2020a)

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| Biomethane in Areas without a Reticulated Gas
Network |A6.Biomethane in Areas without a Reticulated Gas Network
In areas without natural gas reticulation systems, the case for production of biomethane may not be the bestuse of generated biogas. Other opportunities for the use of biogas include direct use of the biogas for direct
heating or electrical generation. Both of these options are less capital-intensive than biomethane refining, but
the products generated are lower quality and cannot generate the same revenues. A key challenge is thelack of potential for CO2 generation, which can become a valuable revenue stream for the biomethane
operation.
In the case where a direct user of the energy generated is located nearby and is able to accept untreatedbiogas as a fuel, it may make sense to not pursue biomethane generation. However, the flexibility provided
by converting the biogas into biomethane is still worth considering. Below are some descriptions of ways toutilise biomethane without a distribution network nearby.

Dedicated biomethane pipelines
There are no natural gas reticulation networks on the South Island, so this opportunity does not exist forbiogas producers on the South Island. However, for biogas producers on the North Island, there may be theopportunity to construct a dedicated pipeline to connect to existing pipeline infrastructure. Depending on theproximity to the closest gas network able to accommodate the biomethane flow, there may be theopportunity to construct a small diameter pipeline to interconnect to the networks. The cost of theinterconnection pipeline is likely to prove inhibitive for small producers having to transport long distances tothe existing network. The indicative costs associated with constructing dedicated pipelines are included in
Section 5.3.4. It is likely that a small diameter pipeline would be enough for the flowrates indicated in thisreport for typical biogas production schemes, however, the pipeline construction material and technique will
depend on project specific injection pressures.

Biomethane to Compressed Natural Gas (CNG)
Biogas producers away from pipeline infrastructure can compress the biomethane to allow export using tube
trailers. For CNG, the upgraded biomethane is compressed to pressures greater than 200barg and injected
into transportable tube trailers The CNG market in New Zealand is limited but finds uses in CNG vehicles
and could be transported for reinjection into the natural gas system on the North Island. A major benefit ofbiomethane trucks is that existing diesel trucks can be retrofitted with dual-fuel engines to allow them to run
on biomethane and diesel, which decreases the required capital to decarbonise truck fleets when comparedwith purchasing brand new electric or hydrogen-powered trucks. While CNG trucks may be cheaper to run
and produce less particulates, CNG trucks generally have less range than their diesel equivalents and thereis less infrastructure available to refuel CNG vehicles on long trips (Quartier, 2020). Biomethane vehicles
could be utilised in New Zealand to decarbonise transport in combination with EVs, fuel cell vehicles andbiodiesel, but would need support to work out its strategic place in transport and to what degree we see it
being utilised for the different kinds of vehicles in New Zealand.

Bioenergy hub connecting multiple biogas producers to central upgradingplant
In areas where multiple sources of raw feedstock are available (such as prominent farming areas) there is
the opportunity to produce biogas local to each feedstock and transport clean and dry biogas to a central
hub. The cleaned biogas from multiple sources could be upgraded to biomethane at the central hub using asingle upgrading and compression facility. The bioenergy hub could be used in areas close to infrastructureor areas without pipeline infrastructure to rely on a single CNG plant and tube trailer filling facility. Combining

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| Biomethane in Areas without a Reticulated Gas
Network |multiple biogas streams to utilise a single biomethane upgrading and injection or compression plant would
help reduce the overall unit cost of biomethane.

Local combined heat and power (CHP) electricity generation
There will be instances were raw feedstock and biogas production is unable to be practically upgraded tobiomethane for export by pipeline or tube trailer. However, these valuable renewable biogas resources can
be cleaned and combusted in a gas engine generator to produce electricity. Running a gas generator resultsin waste heat that can be collected for use to improve the efficiency of the conversion process from raw
feedstock to energy. Waste heat can be used to aid raw biogas production, or to provide heat to other facility
uses.

Biomethane conversion to hydrogen
There remains the opportunity to convert biomethane into green hydrogen using steam methane reforming(SMR). Traditional SMR plants have been large capacities to convert fossil based natural gas to hydrogen,however, recent advances have developed SMR plants to produce hydrogen at scales to match biomethane
production schemes (HyGear, 2020). For effective utilization, the hydrogen would likely require compression
to pressures of either 350 barg or 700 barg for transportation and vehicle fuel cell use. As the biomethane
fed into the SMR process is a low carbon or carbon neutral gas, the hydrogen would be considered thesame.

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