dynamic combustion chamber

H I G H LY C O N F I D E N T I A L . D O N O T D I S T R I B U T E . H T I | 1

Dynamic Combustion Chamber


3 EXECUTIVE SUMMARY

4 PROBLEM

4 The problem with GHG Emissions

5 The problem with fossil fuel boiler inefficiency

6 SOLUTION

7 How does the DCCTM work?

8 Fuel Efficiency

10 Efficiency Trail 11 Applications

12 Form Factors

13 BALANCE OF PLANT

13 Differences relative to Fossil Fuel Boilers

14 Electrolyzers

15 H2/O2 Storage

15 Genset

16 Alternate Sources of H2

17 COMPETITIVE LANDSCAPE

17 DCCTM relative efficiency

18 Coal-fired boilers

18 Natural Gas boilers

19 Electric boilers

19 Biomass boilers

19 Comparative Economics and Emissions

20 OPERATION AND REGULATION

20 Operational Performance

21 Regulatory drivers

22 Maintenance

23 Safety and permitting

TABLE OF CONTENTS

H I G H LY C O N F I D E N T I A L . D O N O T D I S T R I B U T E .


Dynamic Combustion ChamberA HYDROGEN TECHNOLOGIES, INC. PRODUCT

There are two fundamental issues with traditional fossil-fuel boiler systems used in commercial, industrial, and power end-markets (“CI&P”). First, the greenhouse gasses (“GHG” such as CO2, NOx, and SOx) from these coal, natural gas, diesel, and oil-fired systems contribute heavily to the world’s ever increasing GHG emissions profile. And second, the current installed base of CI&P boilers are largely aged and inefficient — with efficiencies as low as 50% on 40+ year old equipment. Meanwhile, new product offerings fail to fully address the inherent inefficiencies, cost and emissions related issues.

We developed the DCCTM from a clean sheet of paper to be the boiler of the future. It maximizes thermal efficiency, minimizes operating headaches, and emits absolutely no greenhouse gasses or other pollutants.

By combining pure Hydrogen and Oxygen gas in an exothermic reaction, the DCCTM achieves previously unattainable fuel efficiencies in the range of 95-98%. It is a closed loop system with no smokestack that is free of all current air and emission regulations.

This adds up to a boiler that produces high quality process steam at prices that already compete with best-in-class natural gas boilers. We make no assumptions of speculative future technology which may or may not become reality. This white paper was written to give customers and partners of HTI a look behind the curtain at the first-principles physics that govern the DCCTM’s performance, and the economics it enables.

EXECUTIVE SUMMARY


Are boiler emissions really a big-picture climate change risk?

Burning coal, natural gas, diesel or fuel oil for everyday thermal needs (hot water, space heating, industrial steam, and power processes) accounts for over 20% of all global greenhouse gasses emitted each year. As developed economies and industrial geographies like India, China and Southeast Asia grow their means of production, there will be an ever increasing call on fossil fuel-based boilers. Meanwhile, the underlying CI&P boiler market is slated to grow between 5-7% per annum over the next 10 years. Despite net zero sustainability goals front and center for global political bodies, Fortune 1000 corporations, and asset managers alike, there remains little progress in solving the issues of GHG emissions related to our thermal energy needs.

Undercomprehended by most of the energy consumer public, steam is a pervasive energy medium in Commercial & Industrial applications (not to mention electricity production). For example, 37% of the fossil fuels burned by U.S. industry alone are burned to produce steam. All major industrial energy users devote significant proportions of their fossil fuel consumption to steam production: 57% for Food Processing, 81% for Pulp & Paper, 42% for Chemicals, 23% for Petroleum Refining to mention a few. Eliminating emissions related to our thermalenergy needs is critical to our global net zero goals. For example: a single 1MWe coal-fired boiler (running at 100% capacity) produces the same emissions as 5,000 passenger vehicles per year.

Source: GrandView Market Research, 2020

PROBLEM:GHG Emissions



PROBLEM: Efficiencies

How do traditional systems lose efficiency?

The dual problem related to inefficient boilers results not only in harmful GHG emissions in the form of waste heat and gas, but in an increase in total cost. The inability to design efficient, closed-loop boiler systems with carbonless molecules greatly increases the amount of carbon emitting fuel input for the same amount of useful energy increasing one’s total cost of energy production and carbon footprint.

In addition to fossil fuel-based boilers, the market has produced alternative zero emission boilers. However, these alternatives (like ‘Hydrogen-Ready’ boilers and Electric Boilers) are fraught with their own challenges around reliability, O&M and total cost and total emissions profile.

The majority of natural gas boilers can already accept a fuel mix at sub 20% pure Hydrogen. Further, many large boiler manufacturers are already marketing dual-fuel or 100% H2 boilers for residential and limited commercial applications. However, all of these designs burn H2 in the presence of air, which generates emissions which must be vented via a smokestack. The existence of this smokestack is responsible for efficiency losses and GHG emissions which cannot be designed around.

Smokestacks can also be eliminated with pure electric boilers, but there are some fundamental issues with this approach. These include but are not limited to 1) grid/regulatory acceptance of high-output transformers 2) fouling of internal electrical components shortens service life and reduces uptime 3) water purity must be upgraded in order to reduce said fouling 4) availability of peak power requirements and related peak demand charges. For all of these reasons and more, industrial boilers unilaterally employ hydrocarbon fuels instead of electrons to do their work.

PROBLEM


Even in H2 Ready or very efficient natural gas boilers, fuel is combined with outside air, necessitating a smokestake. That smokestack has a fundamental negative effect on efficiency which cannot be designed around.


The Dynamic Combustion Chamber (DCCTM) is the only zero-emissions closed-loop Hydrogen boiler. This approach produces clean “process steam” without generating any air pollutants. It does not require a smokestack or any other energy dissipating exhaust, and is nearly 30% more efficient in fuel usage than a conventional steam boiler.

SOLUTION:The clean H2 steam DCCTM boiler is a unique zero-emissions hydrogen boiler — a bold step in the evolution of hydrogen technology

H T I | 6H I G H LY C O N F I D E N T I A L . D O N O T D I S T R I B U T E .


WHAT IS THE PROCESS?

From a first-principles perspective, the DCCTM is the most efficient way to convert H2 and O2 into high-temperature steam.

Instead of burning H2 in the presence of air, the DCCTM’s scalable process is based on combining pure H2 and pure O2 to form water molecules and heat. The DCCTM combustion produces an exothermic reaction between H2 and O2 that releases 61,000 BTUs (heat index) per pound of H2, compared to 12,000 BTUs per pound of coal.

This combination, in the presence of a spark, immediately flashes into superheated steam in a high-temperature reaction that reaches 5,080 degrees F or 2,804 degrees C creating a mild vacuum owing to the condensing characteristic of the chemical reaction. When the superheated steam encounters the boiler tubes, it effectively transfers heat to the boiler shell to create cycle steam for useful work.

Critically, hydrogen burns in the ultraviolet range with little to no radiant heat, compared to typical fossil fuel-based combustion processes. These conventional systems utilize the flame (burning in the infrared) and hot gasses to transfer the energy to cycle steam and then exit back to the atmosphere via a smokestack. No matter how well engineered, the physics of this design lose valuable energy and emit heavily regulated CO2, NOx, and SOx.

SOLUTION

The chemical reaction which occurs in the DCCTM fully captures the total heat of steam. This allows the greatest amount of heat to be retained in the combustion of H2 and O2.



The energy content of calorific value is the same as the heat of combustion, and can be calculated from thermodynamic values, or measured in a device called a calorimeter. The equation governing that analysis is as follows:

Q= mCp∆T

Where Q= energy (expressed as heat) ∆T = change in temperature (in °C)m = mass of water (in g)Cp = specific heat capacity (4.18 J/g°C for water).

The resulting energy value divided by grams of fuel burned gives the energy content (in J/g). The combustion process generates water vapor and certain techniques may be used to recover the quantity of heat contained in this water vapor by condensing it.

• Higher heating Value (= Gross Calorific Value -GCV = Higher Heating Value -HHV) -the water of combustion is entirely condensed and the heat contained in the water vapor is recovered

• Lower heating Value (= Net Calorific Value -NCV= Lower Heating Value -LHV) -the products of combustion contains the water vapor and the heat in the water vapor is not recovered

SOLUTION

H T I | 8

This table gives the gross and net heating value of fossil fuels as well as some alternative bio-based fuels.

FUEL EFFICIENCY


The graph above is called the DCCTM Stretch. It represents visually the effects of eliminating a conventional smokestack. The thermal condensing technology allows for the process to fully capture the total heat of the steam, not lose it to the atmosphere. All of the hydrogen and oxygen used in the HTI System is condensed back to water and recycled back into fuel for the process again.

Heat of the Liquid+ Latent Heat of Vaporization= Total Heat of the Steam

Total Heat of the Steam (MJ / KG)(Heat of liquid + Latent Heat of Vaporization)

DC

CTM S

TRETC

H

US

EFUL W

OR

K

2,804º

25º

TE

MP

ER

AT

UR

E (

CE

LS

IUS

)

LHV

119

.96

LHV

141

.80

No Smokestack Results in 15% More Efficiency


SOLUTION

The full capture of the latent heat of water vaporization in combustion products allows for the greatest amount of heat retained in the combustion reaction of hydrogen and oxygen. This natural phenomenon results in the maximum combustion energy for hydrogen retained for useful work (known as Higher Heating Value [HHV]), versus a more

standard atmospheric (i.e. using air) combustion process exhibited by conventional technology, which is limited to Lower Heating Value (LHV). The DCCTM extracts on average up to 15.4% more useful energy from hydrogen combustion in the presence of pure oxygen.

H I G H LY C O N F I D E N T I A L . D O N O T D I S T R I B U T E . H T I | 1 0

HTI DCCTM

Efficiency TrailRenewable Energy into Electrolyzer

Energy out of Electrolyzerinto DCCTM

Steam Energy out of DCCTM

Direct Use

Steam Energy out of DCCTM

Including Steam Turbine Loss

Additional Electric energy out of Turbine Generator

Total End Use Energy(Steam or Steam + Power)Available to User

(for a representative hour of operation)

PERCENTAGE

ELEC TRIC UTILIT Y P OWER INTO THE SYSTEM IN KWH

GJ/HR

(for a representative hour of operation)

PERCENTAGE

GJ/HR - STEAM

20.48 17.41 16.65

16.49 3.57 20.06

16.65

20.48 17.41 16.65

5,689

ELEC TRIC UTILIT Y P OWER INTO THE SYSTEM IN KWH

5,689

85%

85%

81.28% 81.3%

81.28% 80.5% 17.4% 97.9%

Electrolyzer

Proton OnSite -

Nel M Series

RENEWABLE ENERGY SOURCEDCC

GJ/hr

GJ/hr

GJ/hr

GJ/hr

GJ/hr

Kg/hr Steam

Kg/hr Steam

kWh

16.65

16.65

16.49

3.57

20.06

6,000

1,000

6,000

TOTAL ENERGY

TOTAL ENERGY OPT

ION

#1

OPT

ION

#2

Turbine/

Generator

e- (optional)

STEAM ONLY

17.414 GJ/hr123 Kg/hr H2

20.48 GJ/hr

OPTION #1 - STEAM ONLY

OPTION #2 - COMBINED HEAT AND POWER (CHP)

SOLUTION

EFFICIENCY TRAILS



High quality clean process steam is largely consumed and utilized in Commercial, Industrial and Power end-market applications. Commercial applications and markets are primarily focused on steam boilers for space heat, hot water, Combined Heat and Power and Combined Cooling, Heat and Power applications. Industrial applications are primarily focused on high-quality process steam related to Food and Beverage, Chemical & Petrochemical Processing, Textiles, Pulp & Paper, Metals & Mining among other large consumers of heat and steam. For example, steam plays an integral role in Food and Beverage processing including sterilization, disinfecting, pasteurization, reducing microbiological bacteria, cooking, curing and drying.

Within the Power and Utility space, the DCCTM can be combined with a turbine genset for Combined Heat and Power applications. It can also be used as part of a microgrid, building or district energy system, or in a remote, unconnected location. Combined with electrolysis, gas storage, and a turbine, the DCCTM can have significant advantages over other energy generation alternatives. Hydrogen’s ability to be a store of energy and be separate (via storage) from the DCCTM system allows customers to take advantage of favorable power pricing during off-peak hours or when renewable power sources generate excess power supply to produce the hydrogen and oxygen input fuel – creating a favorable economic proposition.

SOLUTION

Figure 1A Schematic of the Dynamic Combustion Chamber

Safety

Steam for Heat & Power

Superheated Stream(Red)

Burner

Condensing Tubes(Vacuum Inducing)

Low Temperature/Pressure Steam

Recycled Water Back to Electrolyzer

Oxygen Storage

Hydrogen Storage

Electrolyzer

Renewable Power


APPLICATIONS

A Schematic of the Dynamic Combustion ChamberTM



SIZING, INPUTS, AND OUTPUTS

The DCCTM comes in three sizes: 500 kilowatts, 1 megawatt, and 5 megawatts. All of them operate up to 40 bar and up to 400°C. For larger steam or power applications, the DCCTM can be set in series or customized for larger output.

SOLUTION

1) DCCTM3000

a) 731 x 466 x 662cm footprint

b) Produces 3,000 kg/hr steam

i) Equivalent to 250hp

ii) Equivalent to 10.6 mmbtu/hr

iii) Equivalent to 6,600 lb/hr steam

c) Consumes 62 kg/hr Hydrogen

d) Capable of driving a turbine genset up to 500 KWe

2) DCCTM6000




ii) Equivalent to 21.2 mmbtu/hr



d) Capable of driving a turbine genset up to 1 MWe

3. DCCTM28000




ii) Equivalent to 106 mmbtu/hr



d) Capable of driving a Siemens SST-110 turbine genset up to 5 MWe



Fossil fuel boilers require additional plant components downstream of the boiler (scrubbers, exhaust systems, etc) and are simple upstream of the boiler (hookups to municipal natural gas sources). The DCCTM does not have any emissions to handle, but must generate its own fuel resulting in a unique

balance of plant. A typical energy solution setup is represented in the process flow diagram below and can be customized based on a variety of factors including: averaged daily run-time of steam applications, daily power pricing related to peak, off-peak and peak shaving demands.

BALANCE OF PLANT



Electrolyzer

a) Because the DCCTM burns O2 and H2 in their stoichiometric ratio, an electrolyzer is the most convenient way to produce both of those molecules.Depending on the grid electricity feedstock, this electrolysis process can produce completely green H2.

b) HTI has relationships with leading Electrolyzer manufacturers to provide electrolyzers for DCCTM installations. These electrolyzers can be sized up and down depending on the customer’s priorities.

i) A priority on time-shifting renewable energy or using off-peak power would indicate a larger electrolyzer operating less frequently.

ii) A priority on low capital expenditure would indicate a smaller electrolyzer operating round-the-clock at increased average operating costs.

iii) Note that in order to operate the electrolyzer only half the day to take advantage of off-peak power, the size will need to be doubled relative to the daily Hydrogen requirements of the boiler.

BALANCE OF PLANT

Figure 2Use of the DCC™ in an Energy Storage and Combines Heat and Power Configuration

Dynamic Combustion Chamber

Building

Turbine Generator

High Value Peak Power

Heater

(or other winter load)Fre

ezer

Ref

rig

era

tor

Chi

ller

Chiller(or other summer load)

Low Pressure Steam

Water

Electrolyzer(converts the water into gas)

Low Value Off-Peak Power

Renewable Energy

Solar Wind Hydro

OxygenCompressor

HydrogenCompressor

OxygenStorage

HydrogenStorage

H2 Fueling Station for Automobiles

Use of the DCCTM in an Energy Storage and Combines Heat and Power Configuration


H2 & O2 Storage

a) Due to the physical characteristics of the H2 molecule, challenges arise in storage or transportation. H2 is extremely small, and can rather quickly embrittle materials not designed for its containment. This small size also promotes leakage under high pressure containment. Finally, the extremely high specific energy of H2 is coupled with quite low volumetric energy density. This means comparatively more tanking is required than with traditional fossil fuels.

b) The first step in storing both H2 and O2 is compression. This can be done at low pressures 200-250 bar, medium pressures 300-350 bar, or pressures as high as 700 bar (10,000 psi).

i) Because of the nature of this boiler application, storage at pressures higher than necessary will be a net energy loss. Energy from compression is not returned into the system.ii) Higher stages of compression require energy which increases logarithmically, not linearly. As such, when storage volume permits, minimal compression should be used. The price to purchase additional low pressure storage will quickly break even under the reduced operating expenditures of higher stage compression.

c) Tanks for storage of H2 and O2 are different, but well established. Storage costs starting at $1,000 per kg are industry standard for medium tankage and can be expected to drop with scale.

i) Sufficient tankage must be coupled with the abovementioned electrolyzer upsizing strategy in order to time-shift renewables or take advantage of off-peak power pricing.ii) A minimum of one hour of buffering regardless of 24/7 electrolyzer operation should be considered mandatory. For the 1MW DCCTM, that would be roughly $100,000 USD in H2 tankage and half that price for O2.

Genset

a) While not an essential part of the DCCTM balance of plant, there are applications where the steam genset should be considered.

b) The highly energetic process steam is perfectly capable of turning a turbine genset before being distributed for applications elsewhere.

i) This combination increases the closed-system DCCTM efficiency from 95% to 98% because of net energy loss throughout a steam system. Long steam pipes have inherent transmission losses due to heat sink effect. Using a portion of the energy up front to turn the turbine results in a relatively lower amount of efficiency lost.

c) In cases where electricity is not used to generate Hydrogen for the DCCTM, such as using a steam methane reformer or waste Hydrogen to feed the DCCTM, this turbine can provide power as part of a CHP, or combined heat and power, system.

i) Even in cases where electricity is used to generate H2, such as with an electrolyzer, the turbine can be used to time-shift the cost of electricity from peak to off-peak hours.

BALANCE OF PLANT

Liquefaction to produce liquid Hydrogen is often touted as a solution to the difficulty of wrangling highly compressed H2. The expense of chilling H2 to -260C (compared to only -160C for Liquid Natural Gas) is several times that of compressing H2 even to 10,000 PSI as required by the best FCEVs. While high pressure tankage is no longer required after liquefaction, leakage can be as high as 2% per day and "energy of cold" is generally not recaptured on gassification.


The DCCTM is agnostic as to the source of its feedstock gasses. In areas with fewer concerns about air emissions, the H2 can be sourced from Steam Methane Reforming or Pyrolysis, while the O2 can be sourced from air separation units. Note that no matter where the H2 comes from, no matter if it’s a green electrolyzer, blue pyrolyzer, or grey SMR unit without carbon capture, the boiler itself will remain zero emissions.

If available locally through a pipeline, H2 can be served that way and buffered through minimal on-site storage. This will become increasingly common in Europe. In worst case scenarios, H2 and O2 can be electrolyzed off-site and moved in modular containers to the boiler site. One good use-case for this approach is Alaska’s Chugach region, where heating demand is high and power is $.65/kWh.


BALANCE OF PLANT

ALTERNATIVE SOURCES OF FUEL


We’ve established that there are no zero-emissions Hydrogen boilers besides HTI’s DCCTM, due to the novel and protected nature of the closed-loop combustion process. However, the DCCTM exists in the broader context of fossil fuel boilers and non-Hydrogen zero-emissions technologies. All cost figures in this section are levelized, to provide an even playing field for comparison. While the DCCTM itself is 95-98% efficient, it exists in a “Hydrogen Cycle” including an electrolyzer in most applications. This H2 Cycle is currently 83% efficient but will rise to 93% efficiency with next-generation electrolyzer technology. Taking into account large investments in balance-of-plant outside the DCCTM, levelized cost of process steam at the IEA standard 6c/kWh is still only $35/Klb*. Factors positively influencing this figure include low O&M expenditure, high inherent uptime, and long lifetime of componentry. At 3c/kWh, which many industrial power purchase agreements can accommodate, that cost of steam drops to ~$18/Klb.

Coal’s resilience as a boiler fuel surprises many outside the industry. Coal boilers aren’t inherently efficient or reliable, and they can be subject to heavy carbon taxation. However, the “mine and burn” nature of the fuel enables extremely low variable operating costs. As carbon taxes grow this decade, new coal boiler construction has nearly evaporated in the developed world, and old coal boilers will increasingly be converted to run natural gas or get decommissioned entirely. As it relates to the DCCTM, the equation governing replacement is a function of emissions regulations and lifecycle. An example coal boiler might produce process steam at $12/Klb with $50/ton carbon taxes, but that cost skyrockets to skyrockets to $26/Klb with Canada’s new $133 tax. This assumes that the given regulatory body hasn’t mandated they be decommissioned by a certain date and/or even allows for the installation of a new coal fueled boiler system. Natural Gas Boilers afford a 25% reduction in greenhouse gas emissions while still ingesting a “zero-process” fuel like coal, and are the current industry

COMPETITIVE LANDSCAPE

https://www.energy.gov/sites/prod/files/2014/05/f15/tech_brief_true_cost.pdf


standard. In particularly strict air districts, NOx emissions standards are circumvented by running multiple sub-50hp boilers in series. Capital costs for installation of a megawatt system (~$600,000 installed) are significantly lower than those required in the DCCTM balance of plant, due to the requirement for gas generation (electrolysis). At a $50/ton carbon tax, best-in-class nat gas boilers can make a pound of process steam at $16/Klb. At $133/ton, that cost rises to almost $25/Klb in parity with current zero-emissions steam from the DCCTM. This too assumes a continued allowance for the use of Natural Gas, which has now been banned from use by 40 cities and municipalities in California already. Seattle, New York, and Denver have banned it in new building construction. Electric boilers at the megawatt scale exist, but are so fraught with operational issues that they are not considered feasible by the majority of the industrial market. The first problem to overcome is the demand charges, grid service fees, and even availability of high-voltage hookups for the transformers required at this scale. If installation is possible, the primary operational concern is the fouling of internal electrical components which shortens service life. To prevent this, water purity must be upgraded and constantly monitored. Even so, periodic de-scaling of the boiler will be required, reducing uptime. Finally, there is no ability outside of massive lithium ion batteries to de-couple an electric boiler from the whims of electric utility pricing. Beyond pricing, simple availability of peak power may result in untenable demand charges.

Should electric boilers still be considered, they produce process steam at $36/Klb at 6c/kWh.Biomass boilers are very interesting for the right geographic location and set of customer priorities. So long as carbon taxes are not applied, and NOx/SOx regulations also inapplicable, biomass boilers can make steam cheaply. In some jurisdictions, the growth of trees for biomass is even considered carbon-negative due to the lifetime carbon consumption of those trees. However, carbon emissions accounting for wood biomass remains suspect, as burning biomass emits more CO2 than fossil fuels per energy unit generated. In these cases, $15/Klb process steam is possible.

However, outside of the pacific Northwest and other highly productive timberlands, accomplishment of $100/ton high-quality biomass is not feasible at scale. Furthermore, biomass boiler life is expected to be shorter than nat gas or DCCTM lifespan. We are confident the H2 cycle equipment will have a 25+ year useful life because the flame (steam only from the H2-O2 exothermic reaction) is the only medium used on the heat transfer surfaces. In contrast, a biomass boiler life is expected to be only 10-15 years, due to the sensitivity of the pressure vessel and other components to contaminated steam. Given progressive air districts’ intolerance of NOx from natural gas boilers, we predict it’s only a matter of time before biomass boilers are subject to the same restrictions, introducing expensive taxes or scrubbing equipment requirements.


At 3c/kWh, a common price for industrial power purchase agreements, the cost of steam from the DCCTM drops to a competitive $18/Klb” even accounting for the levelized cost of expensive electrolyzers.




Comparative Economics vs. Best-In-Class Emission and Zero Emission Boilers

Comparative Emissions Foregone vs. Conventional Boilers

Note: H2 Cycle Solution (3c / kWh + Efficiences) accounts for projected at-volume manufacturing deflation and projected efficiency of Electrolyzer technologies.

Note: CO2 e emission foregone assumes 100% run-time.


The flexibility of steam generator technology has been proven, and its durability tested, for over 200 years. While heat has traditionally been the predominant end product for steam boilers, steam as a motive force to drive turbines and generate power is an underappreciated application. The DCCTM significantly increases the power density of a boiler system while eliminating all combustion products except heat and water.

Steam boilers are known for their ability, with proper maintenance and good chemistry, to perform for decades. In fact, boilers exhibit the longest life cycle of any heat and/or power generating equipment. Utility boilers have been known to operate for more than 50 years. The average coal-fired generating plant in the United States is 42 years old, while the oldest still in service date from the 1940s and early 1950s.

The condensing characteristic of the DCCTM process and the natural vacuum formed from steam condensation within the heat exchanger tubes:

• Acts as a natural process barrier to hydrogen and mitigates the effects of potential hydrogen embrittlement (operating with excess oxygen further ensures a complete reaction and further mitigates the hydrogen embrittlement issue)

• Mitigates conventional boiler failures related to metallurgy issues – there is no outward pressure exerted on the steel and the superheated steam (water) is the only heat mechanism contacting the boiler tubes.

As a result, our DCCTM lacks the traditional major boiler failures related to hydrogen damage and stress corrosion cracking.

OPERATION AND REGULATION



Government and corporates alike are driving to reach near-term 2030 and longer term 2050 GHG emission reduction goals. Concerns regarding GHG emissions and their impact on global warming has prompted the introduction of Government regulations and worldwide Inter-Government coordination (COP21) trying to reduce these harmful emissions.

Fossil fuel boilers are extremely carbon intensive and are nearly ubiquitous in commercial and industrial heating markets where almost 85% of all installed boilers are emitting harmful greenhouse gasses (CO2, NOx or Sox). Corporations looking to net zero goals are increasingly turning to lower and zero emissions boiler systems to meet their objectives.

Over 64 carbon pricing initiatives have been implemented or scheduled. Current and future carbon pricing schemes or tax assumptions are beginning to be included into customer’s techno-economic analysis for their fossil fuel boiler systems. Because boilers are a 20- and 30-year investment decision, forecasting any future carbon price is just as important as what current policies or prices are set. For example, Canada has introduced a phased-in carbon tax, beginning at $50 / ton in 2022, ultimately rising to $133 / ton by 2030. The current price (April 2021) of carbon in EU markets is around $40 / ton. The use of carbon pricing tools provides strong tailwinds to the comparative economics of clean energy technologies including the use of our DCCTM.

More stringent than economic mechanisms, many countries and local jurisdictions are outright banning the sale of new fossil-fuel based boilers. In particular, the United Kingdom and many localities on the West Coast of the United States (California, Washington state, Oregon) have already passed legislation

banning the sale of new fossil fuel boilers in the future. The push to ban traditional boiler competition should lead consumers of heat and steam to zero emissions solutions.

California has the most stringent air emissions standards in the nation, and the fifth largest economy in the world. It is also the only state that can write its own air pollution related laws and standards. When the Clean Air Act passed, Congress required the Environmental Protection Agency to grant California an exemption, since the state was already developing innovative laws and standards to address the state’s major air pollution issues. The DCCTM when operating with pure hydrogen and oxygen is completely emissions-free, releasing only heat and water through its combustion process. As such, it is fully endorsed by the largest air district in California, the San Joaquin Valley Unified Air Pollution Control District*.

By contrast, even the cleanest natural gas boilers face an impending regulatory crackdown in California. All boilers over 20 MMBTu/hr must comply with a 5 ppm NOx limit by 2023*. It is worth noting that Hydrogen-enabled boilers operating without a closed loop system will still trip this NOx limit, leaving industrial consumers to choose between electric boilers or HTI’s DCCTM solution.

California is not alone in the growing push to mandate new-construction boiler emissions standards. Between the Biden administration’s climate priorities*, the ambitious Paris Climate Accords*, and the typical regulatory fallout from follow-on states* after California innovates, we believe restrictions on boiler emissions will only grow.

May 14, 2020 EPA Approved San Joaquin Valley Unified Air Pollution Control District. https://www.epa.gov/sips-ca/epa-approved-san-joaquin-valley-unified-air-district-regulations-california-sip

NOx limit by 2023: https://www.nationwideboiler.com/boiler-blog/understanding-air-permitting-for-boilers-in-california.html

Biden climate plan: https://www.washingtonpost.com/climate-environment/2021/04/20/biden-climate-change/

Paris: https://unfccc.int/process-and-meetings/the-paris-agreement/the-paris-agreement

Follow-on states: https://news.climate.columbia.edu/2020/09/28/californias-continuing-climate-leadership/

REGULATORY DRIVERS



Boiler operations start with managing water quality. The DCCTM uses hot water not only for work but also as fuel. Whether the hot water or steam is generated in the shell of the boiler or the tubes of the boiler the quality of the water needs to be maintained to prevent deposition of calcium and magnesium allowing for under deposit corrosion and premature failure of the boiler.

High pressure boilers may use the same types of chemistry or use oxygen to control the potential

for corrosion. Whatever the requirements of the customer for their desired process the chemistry plan and execution needs to be an important piece of maintaining boiler integrity.

Corrosion coupons can be used to measure corrosion rates of metals. Annual OSHA pressure vessel inspections required by law and administered by our insurance carrier will provide qualitative information regarding boiler integrity and safety.

MAINTENANCE




SAFETY AND PERMITTING

Permitting is always site-specific. However, there are several globally applicable elements worth mentioning. The DCCTM itself is small, comparable to or smaller than best-in-class natural gas boilers. The larger electrolysis equipment, if necessary to produce Hydrogen and Oxygen, can be located separately, easing form-factor constraints. Storage, if applicable, can be located with the electrolyzer or further in a third location connected via pipeline. Hydrogen regulations are evolving, but the FCEV industry is illustrative of what can be expected for stationary applications. Drivers of Toyota Mirais, for example, sit directly atop 10,000 psi H2 storage tanks in an application where impacts are possible. There is no reason to believe H2 storage will not be permitted below structures, so long as sufficient separation from O2 is allowed (separate tankage).

The DCCTM has no potential to emit, eliminating the need for air permitting. Locations like California will also require additional permitting such as the California Environmental Quality Act (CEQA). Additional safety needs may need to be addressed because hydrogen is considered an acutely hazardous material due to its flammability. Hazardous Materials Management Plans (HMMP) must be part of an onsite consequences plan while those facilities under Federal Law that store 10,000 lbs or more of hydrogen must also develop a Risk Management Plan (RMP). These plans must follow Process Safety Management (PSM 29 CFR1910.119) and have a Risk Management Plan (RMP40 CFR68).

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CEQA: https://opr.ca.gov/ceqa/


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