Hydragas Energy Limited is a Canadian company. We develop projects extracting unusual renewable energy plays, where we find gas in deep water. Our Series-A funding for projects in Africa back on track after the time of COVID-19. We are progressing to Series-A funding close after delays due to the pandemic. Vancouver, Canada, is our home base but we have offices in Africa.
Our funding plan is to develop a full-scale demo extraction plant for Lake Kivu in advance of a series of commercial projects. The innovative technology has already been proven in an in situ pilot program, in this one of Africa’s Great Lakes. Our next steps after full-scale performance tests, a demo project, are to fund and advance the construction of commercial production stages.
Hydragas Energy innovated its extraction technology to produce methane dissolved at depth in Lake Kivu at a commercial scale. No other open water bodies can yet produce renewable natural gas in this way. It is unique.
In the future, we see more massive potential to harvest methane from gas hydrates or other oceanic deposits. Among these, the most urgent need is recovering methane released from Arctic permafrost. We know there are reports of it happening in vast offshore areas off Siberia and Canada’s far north. There, with a massive surge in methane emissions, one can see a sense of helplessness in finding solutions to address the problem. The scale of the problem has been estimated at over 5000 times the size and impact of Lake Kivu’s gas.
Methane hydrates, another form more strongly held in deep water, may make up half the world’s available hydrocarbon reserves. To achieve hydrate harvesting in the solid form, we need to scale our gas recovery system design and add a mining component. But we still see ours as a simpler way to harvest hydrates than the many failed attempts with conventional deep sea O&G equipment. These deep-sea drill-rig methods can hardly be economical, being high capital and short-term, low yield.
More interesting for Hydragas is the current source of emissions in the Arctic. Submerged permafrost deposits buried in hundreds of metres of water will be more practical to recover with Hydragas IP. It will be another debate as to whether we are extracting renewable energy, as the age of the methane is younger than fossil methane but older than Kivu methane.
Unlike methane hydrates, permafrost methane more easily seeps out as it is not bound in the hydrate’s ice-like clathrate. The extent of the resources is assumed to be several orders of magnitude larger than Lake Kivu’s resource. The seeps are not capturable by known methods, especially conventional oil and gas drilling. Their lack of confinement in a sedimentary formation makes them prone to escape too easily.
In addition to open water bodies, deep aquifers also trap vast amounts of methane formed with coal. Methane is found in coal-seam gas (CSG) deposits and exists in vast quantities in Queensland and New South Wales, Australia. Harvesting this methane from aquifers with our equipment is a simple, small-footprint, down-hole process. It is achieved without most of the controversial downsides of current methods used for CSG. In other words, most methane-bearing water sources will be amenable. All can be put into production with versions of Hydragas’s technology. We aim to develop each of these added methods in the future, as R&D funding allows.
Methane needs high pressure to dissolve and remain trapped in solution. So as a result, methane can remain fully dissolved in water deeper than 150 m. Significantly, Lake Kivu is 486 m deep. It is because high pressure is needed to compensate for methane’s low solubility. So here we can find methane in extensive deep water traps. Similarly, we can even find large reserves trapped in permanent ice.
Trapped methane in hydrates represents the world’s largest energy reserve. Firstly, it is helpful that is a low-carbon resource. Secondly, it is a significant, but untapped hydrocarbon resource. So it has all the attributes of a major new energy supply. But it hasn’t become that yet, due to a lack of know-how and experience. So it is here that Hydragas can help define methane’s long-term role as a leading global, renewable energy provider. Here, its contribution will be through its know-how and experience.
Philip Morkel founded Hydragas Energy originally as a technology developer and licensor. Our company is therefore positioned as a leading gas recovery innovator and solutions provider. We will deploy this capability by developing large-scale methane gas extraction facilities at amenable sites. In this pursuit, Hydragas will undertake to build and operate these plants. We will operate them, producing pipeline gas and gas for power generation.
Power production will be the anchor off-taker and economic value driver. Pipeline gas usage will grow organically due to the timeline of gas transmission projects, complementing electrical power to domestic, commercial, and industrial users. We describe in this post the impact of the project in the region. This is the region of Lake Kivu in DRC and Rwanda. The desired balance is to provide a lower overall cost of energy for all socio-economic strata. Gas and hydropower from the lake will supply them for 50 years and more.
Industry experts recognize our IP and system design capability. They are a technological and solutions breakthrough. Hydragas is therefore a primary enabler of gas-harvesting from water. It has capabilities and plant design well in advance of its peers. The advantages come from extracting gas with the highest recovery and lowest cost of production. Its plant design enables full compliance with the MPs. It also tops all technical performance indices. So it can therefore lead the way for Lake Kivu’s optimal development.
For the lake, we have identified the key needs to align our design objectives with the Management Prescriptions. This approach has thus allowed us to develop fully compliant designs. Achieving this compliance allows us to optimize methane-from-water recovery solutions from each stratum of the resource.
The design principle is the same for any similar resources. In this case, we plan to put them into production with design-build extraction plants. With this, we can achieve economic gas production for any resource of the type. We can deliver high investment returns with this capability. They provide leading environmental and social benefits to host countries. Our gas plants also deliver category-leading net energy yields. In time, Hydragas can dominate such niche markets for reliable, lowest-cost energy to users.
The Rwanda government has been engaging qualified investors. The World Bank has recommended a competitive bidding process for concessions, based on power pricing and other criteria. The process is to be managed through the country utility (REG-EDCL) and the Rwanda Development Board (RDB). They need to boost gas production from Lake Kivu, where output lags behind their long-term power planning.
KivuWatt’s has been a troublesome project. It was expensive and took seven years to build and commission. Symbion/Shema is building a second unit that was scheduled for testing 15 MW capacity in June 2021. But with the same technology and low recovery, it will be a steep climb to economic success. Shema has to address the key safety requirements during the ESIA stage to keep the lake safe.
The DRC has been slower to develop its more open opportunities, but this is changing rapidly. Private developers bid to acquire concessions and team with solution providers, most of which lacked the key competencies. Bid documents lacked clarity on the access to the resources and agreements required. Their programs were to harvest the shared 2.2 tcf renewable resource in 50 years, starting in 2009, again in 2014, and once again in 2023. So far only 5% of the potential output is producing gas, and that is only in Rwandan waters.
The countries committed to developing capacity equally in 2009, on both sides of the lake, in compliance with the rules. To date, capacity-building has lagged, due largely to failures to develop capable and appropriate technology and design. Hydragas is uniquely fully compliant with the rules. It has the technology, know-how, and ready-to-build design to achieve the two governments’ plans. However, access to the resources remains a political process.
To take our proposed next step, we require a $36 m investment in fund-raising. This funding is needed now to secure the government’s go-ahead to build a demonstration project, producing 5 MW of clean, renewable power. Hydragas’s 2024 funding program is therefore engaging some Canadian government agencies to secure initial investment funds.
Our investment program proposes to raise Series-B equity investment of $36 million from private investors such as carbon traders. We will then proceed to complete the installation of our demo project. Our plan would complete commissioning within 15 months of the funding close. Next, we will certify proof of performance by having the underwater plumes of re-injection water traced for compliance with the Management Prescription rules, a test that no other operator has completed successfully. We should have the requisite data and analysis after running the demonstration plant for to 3-6 months. We expect to keep the initial demo plant running for many years as a research platform. It can provide 5MW of power at a commercially solid rate of return.
Hydragas will follow this demo plant with a Series-B fund-raise. This will be for the first 50 MW commercial plant. With secured rights, we plan to build further projects sized for 50 -100 MW. We plan to have these going into production every 18 to 24 months, subject to demand. The projects have the potential to produce a total of 600 MW in Rwanda and DRC. However, actual power output will depend on how the output is split between power generation and pipeline gas supply.
The selection of power plant equipment governs output. The gas-fired plant allows choice between gas engines (44-46% efficient) and the higher-cost CCGT (60-62% efficiency). So total output and capital cost will vary, depending on power plant selections. However, we expect any configuration to yield high economic returns, with high confidence.
The financial models of the demo and commercial projects demonstrate strong net revenues. Until we know the value and saleability of carbon, carbon offset sales are not factored into the model. It is difficult to assess how the values may be achievable, but we can expect to begin more rapid acceleration in the years before 2030. Despite that, models also show rapid build-up of positive cash flow from the project series.
Hydragas’ development plan has four commercial projects in operation by 2030. Net revenues will approach $300 M annually within eight years if carbon offsets are approaching projected pricing. So with high available free cash flow, further capital projects can be funded with cash-reserves and debt.