https://t.co/9TG5xgTS56

— Michael Novakhov (@mikenov) June 3, 2024

By Jon Miltimore

My wife and I are in the process of finishing Shōgun, the new FX miniseries on Hulu based on James Clavell’s 1975 book.

Shōgun was one of the first books that truly captivated me. I read it for the first time when I was 13 years old, and couldn’t put it down.

Set in the early 17th century, Shōgun tells the story of an English pilot—John Blackthorne, a character based on William Adams, an actual English sailor—who is stranded in Feudal Japan when his ship, the Erasmus, runs aground. The plot follows Blackthorne’s experiences in “the Japans” as he becomes embroiled in the political intrigue and the power struggles of rival warlords fighting for dominance over Japan following the death of the Taikō. (The Taiko is based on Toyotomi Hideyoshi(1537–1598), “the Great Unifier of Japan.”)

Hulu’s adaptation of Clavell’s bestselling book is not the first. A miniseries starring Richard Chamberlain as Blackthorne was released in 1980 and became the second-highest-rated miniseries (behind Roots) ever at the time, attracting some 120 million viewers.

The success of the original miniseries set a rather high bar for the latest adaptation of Shōgun, but FX has not disappointed. The series has proven a hit with critics and general audiences alike, scoring 99% and 90%, respectively, on Rotten Tomatoes.

Audiences are right to be impressed. The 2024 adaptation is so good that it just might be superior to the 1980 version (which benefited from the participation of Clavell, who died in 1994).

The latest Shōgun is less grand in scope than the previous one, but it’s also less daunting. The characters are more relatable, and less archetypal. Cosmo Jarvis’s Blackthorne is strong, capable, and savvy, but he’s more human than Chamberlain’s Blackthorne.

One of the greatest strengths of the show is that it takes viewers to an alien land completely different from anything they’ve ever experienced, and the writers make it clear that life in early 17th-century Japan was not for the faint of heart.

Though the Japanese were more advanced than Westerners in some ways, in other ways they were more brutal and barbaric than the European “barbarians” (their term for the English and Portuguese) living among them. We see this early in the show when one of Blackthorne’s shipmates is boiled alive for no apparent reason, and when a villager is beheaded on the spot for not showing the proper respect to Omi, the samurai lord of the village.

All of this should prompt viewers to ask important questions: What makes a society good? What makes it just? Where should power lie?

Though Feudal Japan is not without its charms, we see that there is something not quite right about its political structure. Even those who have power, like samurai and daimyos, are at the mercy of those who have more of it. It’s Game of Thrones but in the Orient; and the powerful have little respect for the individual.

Blackthorne learns this early in the show. After wrecking the Erasmus off the coast of a small fishing village, he and his men are thrown into a pit. When he’s brought outside the pit, he begins to make demands to the samurai who rules the village, Omi. To demonstrate that Blackthorne has no power in Japan and no business making demands, Omi has Blackthorne held down. He then proceeds to urinate on the English navigator.

Things don’t end there, of course. Blackthorne is taken to Osaka where he meets the powerful Lord Toranaga, whom Blackthorne helps escape.

In Episode 4, Blackthorne returns to the fishing village, where he once again meets Omi. This time, however, Blackthorne is hatamoto, an honor he received from Toranaga. He’s also armed with a pair of mean-looking pistols he was able to retrieve from his ship.

Omi doesn’t like any of this. And in one of the best scenes of the show, the samurai tells Blackthorne’s Japanese interpreter that he must turn his pistols over.

MARIKO: “Omi-Sama insists it is forbidden to bring your weapons today.”

BLACKTHORNE: “Nonsense, your people bring swords wherever they go.”

MARIKO: “He says guns are different. You must turn them over.”

Blackthorne refuses, prompting Omi to take a step toward Blackthorne to confiscate the guns. Blackthorne cocks them and points them right at Omi’s head.

“For some reason, I just can’t shake the memory of our first meeting,” he tells Mariko.

The takeaway is clear. Now armed again with his pistols, and bestowed with samurai standing, Blackthorne has no intention of being powerless ever again.

There’s a lesson here. Firearms empower individuals. They offer protection against the tyrants (big and small) who would rule others.

This is why we have a Second Amendment. Our natural and constitutionally-protected right to bear arms has nothing to do with hunting. It’s to protect us from tyranny.

“To disarm the people… [i]s the most effectual way to enslave them,” George Mason said during Constitutional Debates in 1788.

Writing nearly a half-century later, the famous jurist Joseph Story (1812–1845) elaborated on this point:

The right of the citizens to keep and bear arms has justly been considered, as the palladium of the liberties of a republic; since it offers a strong moral check against the usurpation and arbitrary power of rulers; and will generally, even if these are successful in the first instance, enable the people to resist and triumph over them.

Shōgun shows just how important a firearm can be when it comes to protecting one’s rights and human dignity. Blackthorne might have had hatamoto status during his second encounter with Omi, but it was his two pistols that really made the difference (watch the scene below).

Shōgun is a good reminder that the sole moral purpose of government is to protect our individual rights, not to trample them, as it often does.

• About the author: Jonathan Miltimore is the Senior Creative Strategist of FEE.org at the Foundation for Economic Education.
• Source: This article was published by FEE

Russia faces fresh allegations of flooding Libyan markets with counterfeit banknotes in another bid to further destabilize the country. The Kremlin has a documented history of sending counterfeit currency to Libyan National Army (LNA) leader Field Marshal Khalifa Haftar.

The Central Bank of Libya (CBL) announced in April that it began withdrawing the first and second prints of 50-dinar (just more than $10) banknotes from circulation after officials discovered counterfeit prints.

Russia is accused of printing the fake money at a farm on the outskirts of Benghazi, Haftar’s base. Russia’s Wagner Group of mercenaries, now known as the Africa Corps, supports the LNA.

The CBL asked banks in Libya and their branches to allow the public to present the banknotes and deposit them in their accounts. It urged banks to exercise due diligence to prevent counterfeit currency from being passed and it published a presentation that showed the minute differences between legitimate and counterfeit 50-dinar prints.

The country is divided between Haftar’s government in Benghazi and Libya’s internationally recognized Government of National Accord (GNA) in Tripoli, which Haftar is attempting to overthrow.

Jalel Harchaoui, an associate fellow at the Royal United Services Institute, said Haftar has intensified efforts to strengthen his ties with the Kremlin since August 2023.

“It’s important to emphasize that Russia’s assistance to Haftar rarely comes without financial demands,” Harchaoui told The New Arab. “Haftar is always required to cover the expenses incurred by the Russians active on Libyan soil — in military and other domains.”

A $150 million dispute between Haftar and Wagner emerged in 2020 after a contract between the parties ended. Haftar was accused of not paying the group after the combined forces lost seven cities over a 24-hour stretch in 2019, the year the warlord launched a sustained assault on Tripoli that ultimately failed.

At the time, Wagner was bringing “fighters — not so experienced — from Syria, Belarus and Serbia,” a military source close to Haftar said in a report by the Arabic Post news website.

In September 2019, five months into Haftar’s attack on Tripoli, Malta officials intercepted a shipment of Russian-made dinars en route to Haftar. Nearly 4.5 billion dinars were shipped from Russia to the eastern port city of Tobruk in the first half of 2019, coinciding with the start of the Tripoli war, Reuters reported. Another billion dinars was delivered to the east in 2016, according to the Libya Herald.

Legitimate Libyan dinars issued by the GNA in Tripoli are printed in the United Kingdom. Joint Stock Company Goznak, a Russian state-owned company, printed the illegitimate bills seized in 2019 and 2020.

As with the current crop of counterfeit cash, the previous fake Libyan dinar bills looked almost identical to official bills. By some estimates Haftar’s government flooded the country with nearly 12 billion Russian-made dinars between 2015 and 2020.

The fake bank notes were used to pay Haftar’s fighters and were found all over the country. They fueled inflation, drove down the value of the dinar, and undermined the official currency supplied by the central bank in Tripoli, according to Libyan economic analyst Mukhtar Al Jadeed.

The primary purpose of the counterfeit currency was to “fund the war on Tripoli,” Al Jadeed told Al-Jazeera.

Officials intercepted a shipment of $1.1 billion in fake dinars bound for Haftar in Malta in the spring of 2020.

By Steven Curtis and Peter D. Rocha

The Department of Defense (DOD) needs a new approach to electrical grid infrastructure to maintain security and access to operational energy. Recent natural disasters and cyber attacks have exposed the vulnerability of the current system, posing threats to military operational readiness. Strategic military facilities currently acquire most of their electric power directly from the national grid, which is increasingly vulnerable to failures. The problems experienced to date could be exponentially worse if targeted by a sophisticated adversary with advanced offensive cyber capabilities, such as Russia or China. Simultaneously, the growth of renewables and increased DOD demand for carbon-free energy create challenges and opportunities for operational energy. To date, only a small fraction of work has been done to create a system for DOD energy that is robust, responsive, and reliable.

A Defense Energy Architecture (DEA) should address these issues by providing a comprehensive approach to microgrid implementation for defense installations and deployable energy capabilities. A DEA would simultaneously deliver increased infrastructure security and carbon-free energy with an advanced microgrid system based on small modular reactor (SMR) nuclear power and renewables, such as wind and solar, when they are available. A DEA should also emphasize the development of energy storage applications beyond batteries, specifically hydrogen. A fully integrated system of baseload (that is, on all the time) electricity production, renewables, and energy storage is necessary to maximize the benefits to DOD in both permanent installation and expeditionary environments. The focus of a DEA should be on efficient resources based on the requirements of each base in which the microgrids would be employed.

DOD needs to advance microgrid systems for several reasons. First, DOD has energy assurance and resilience needs that significantly exceed most civilian requirements, and it therefore requires a separate system for energy production and storage. Second, as one of the largest single energy consumers in the world, DOD has the scale to create a market demand signal strong enough to encourage private investment and drive down hardware costs. Finally, with suitable guidance, DOD could move quickly to reach net-zero carbon goals for energy production.

The defense grid system and energy production mechanisms must improve to increase resilience to natural disasters and terrorist attacks on the national grid and integrate clean energy improvements in a cogent manner. This article defines the concept of a Defense Energy Architecture that may guide the construction of microgrid systems to supply desired energy production while supporting energy independence, security, resiliency, and affordable power. We further recommend that DOD integrate emerging energy concepts, in both garrison and expeditionary environments. Advances in modern energy technologies provide many opportunities for DOD to modernize, increasing security and operational capabilities.

DOD Reliance on the National Electric Grid System and Vulnerabilities

The national grid was designed with one purpose: to deliver electric power from the source of production to end users. However, at the time of its creation, there was little thought given to things such as redundancy in natural disasters and certainly none given to potential problems that could not be imagined at the time, such as cyber attacks and electromagnetic pulse (EMP) weapons. For the security of the Nation, DOD must ensure that it has continuous access to energy, making the entire defense system more robust and able to withstand the emerging threats of 21st-century warfare.

America’s electrical grid is the system that powers the garrison operations of DOD and provides a platform for the application of military power worldwide. For decades, the reliability of the grid system was such that the military was confident that when electricity was needed, it would be there. However, this basic assumption is being questioned as the national grid ages, shows vulnerabilities, and grapples with the challenges of incorporating distributed electricity-generating sources like solar and wind energy.1 These shortcomings—coupled with the realization that the existing system is vulnerable to disruptions from incidents both natural (hurricanes and solar flares) and man-made (cyber attacks and EMPs)—call for more direct control by DOD of energy production systems.

However, rather than simply moving ahead with its current course, DOD should embrace best-in-class technologies to ensure that it is moving forward with the best solutions. Moreover, the system needs to be flexible enough to incorporate new technologies as they evolve to ensure that best-in-class remedies are delivered to address the changing nature of power generation and increasingly sophisticated potential attacks on critical infrastructure.

The current grid system struggles to deal with vulnerabilities that could disrupt power and harm American security, including potential attacks by foreign adversaries or terrorists. For many, Superstorm Sandy in 2012 was a wakeup call—it demonstrated a potential for widespread damage that could affect the national electrical grid, leaving 8.5 million people without power across 21 states.2 However, to those watching closely, Sandy was not an anomalous event but rather more of a culmination of a long-term trend that has revealed how susceptible the grid is to disruption from severe weather, including wildfires and extreme temperatures.3 The potential for disruptive events seems to be increasing.

As devastating as these natural events have been, many national security experts predict that damage from man-made attacks could be multiple times worse. The insurance company Lloyd’s of London has modeled a plausible scenario in which a cyber attack on the Eastern Interconnection, which services approximately half of the United States, could leave large areas—including dozens of military installations—without power for days.4 This is not a distant theoretical scenario: Russia has already demonstrated the ability to successfully attack electrical grid infrastructure in Ukraine, and China is believed to have similar offensive cyber capabilities.5 Additionally, the ransomware attacks on Colonial Pipeline in 2021 demonstrated that criminal organizations and other nonstate actors also possess the tools to sow chaos in American energy infrastructure.6 The national grid is susceptible to large-scale disruption, whether from devastating natural weather events, military attacks from near-peer competitors, or terrorists or international crime syndicates. Therefore, response readiness largely depends on a secure supply of electricity from the main grid.

We know that the military is susceptible to the same threats that menace civilian energy infrastructure. In recent years, weather events have disrupted energy service to military installations, such as Tyndall Air Force Base during Hurricane Michael in 2019 and Joint Base San Antonio–Lackland and others during the winter storms of February 2021.7 While the effect on operations was relatively minor in these instances, it does not take much to imagine that targeted attacks on military infrastructure could be orders of magnitude more harmful and severely impact readiness. DOD recognizes this possibility and has conducted a series of exercises to better understand “the growing threat associated with natural or nefarious events . . . such as missions being separated from access to the national grid.”8 The effects from such events could have major consequences on the military’s ability to respond rapidly to crises.

Defense Energy Architecture

The goal of a DEA is to ensure that the advancement of microgrids for DOD use is comprehensive and standardized. A microgrid can be defined as “a local energy grid with control capability, which means it can disconnect from the traditional grid and operate autonomously.”9 For our purposes, we believe this encompasses both energy generation and storage. Defining the concept must not only focus on near-term needs, but also keep options open for future adaptations. It is beyond the scope of this article to prescribe what a fully functional standard for a DEA would look like. However, we can outline key principles that must be addressed to answer the challenges that face the future of DOD energy systems. The following should be considered as the essential tasks for a DEA to address the emerging energy needs:

• provide carbon- and pollution-free energy and baseload power as much as possible
• provide continuous energy on demand
• provide defense against attacks and resilience in the case of natural disasters
• provide expeditionary capability.

Provide Carbon and Pollution-Free Energy

In recent years, DOD has increasingly focused on the potential threats posed by climate change. An example of this is the Army Climate Strategy, which set goals for 100 percent carbon- and pollution-free electricity for Army installations by 2030.10 Given this policy priority, we believe a DEA should follow the same path. The current focus for the source of this energy is renewables, primarily solar and wind. However, wind and solar power suffer from the fact that they are intermittent (they supply energy only about 30 percent of the time, and wind is not predictable). This creates reliance on fossil fuel–based electrical plants to meet operational demands for energy, which not only runs counter to low carbon goals but also maintains the vulnerable linkage to the main grid.

An ideal solution to this intermittency problem is to use small modular reactors (SMRs) to integrate baseload nuclear energy as the carbon-free backup for solar and wind. In 2021, 60 percent of the electricity generated in the United States came from natural gas and coal.11 So when renewables are not available in the desired amount, DOD and other electricity consumers plug into a system that generates over half its power from carbon-producing and -polluting resources. Instead of backing up renewables with fossil fuels, SMRs can assure that clean energy is available on demand. This shift would allow DOD to phase out fossil fuels in the energy mix over time. Each individual installation could be configured to maximize the natural resources available—for example, relying more on wind for installations on the Great Plains. Once the optimal mix of renewables is designed, SMRs would be deployed to make up the balance. The units are modular and can be added to provide more energy. This would enable DOD installations to sever themselves completely from the national grid over time and achieve clean energy goals.

Provide Continuous Energy on Demand

A second aspect of a DEA is to ensure the availability of continuous operational energy. Again, the intermittent nature of renewables causes issues with instantaneous accessibility to energy. For an organization with 24/7 operational needs, this would not do. Much of the DOD focus thus far has been to look at battery storage to preserve the electricity generated by solar and wind sources.12 However, lithium-ion batteries, which are the current state of the art, are best suited for intra-day storage, as their ability to store energy competitively is capped at around 8 hours.13 In a normal operating environment, this is possibly adequate since it provides overnight storage and dispersion when demand for electricity is low. However, in a crisis scenario when high energy loads are present around the clock, this may lead to shortfalls. In addition, if a natural disaster took solar and wind capabilities offline, battery storage capability would be diminished rapidly after only a few hours. Therefore, a truly independent microgrid system should have autonomous power that could be provided in the case of a prolonged interruption.

While SMRs are ideal for providing continuous energy, a microgrid system should have backup power available in case the unit does need to go offline for any period. As stated, batteries have limited ability to provide anything beyond intra-day energy storage, which itself is a system vulnerability. Hydrogen has much greater capability to integrate with a microgrid system to meet energy storage needs. Hydrogen can be produced by splitting water molecules (H20) into their component parts of H2 and elemental oxygen. When this is done with renewable electricity, the resulting hydrogen is carbon-free or “green.” Once hydrogen is formed, it can store energy indefinitely.14 Therefore, H2 could maximize the total amount of energy produced by renewables.15

Furthermore, hydrogen can be produced by nuclear power, so it is also carbon-free and can store an almost unlimited amount of energy. Infrastructure investments would be required to store the hydrogen in a safe manner, but this is currently done globally in many industries that use hydrogen. If the SMR ever went down, hydrogen could provide a long-term bridge of operational energy until the issue was resolved. Though currently less efficient for short-duration storage than batteries, the flexibility that hydrogen provides in a microgrid system makes it extremely valuable for energy assurance. In fact, coupling hydrogen with battery storage may provide the most overall benefit for the entire system.

Provide Security and Resiliency

A third requirement for a microgrid system for defense use is the ability to safeguard it from potential attacks. We have noted that one of the vulnerabilities of the current grid is susceptibility to cyber attacks. The nature of warfare is constantly evolving. A World War I–era general transported to the 21st century would barely recognize how warfare is conducted in the age of long-range missiles, precision-guided munitions, and stealth bombers. It is not difficult to believe that future warfare may become as unrecognizable to us, since the main contested spaces in the future might not be air, land, and sea but space and cyberspace.

A tipping point may have been reached already with advances in the sophistication of offensive cyber capabilities and society’s increasing reliance on digital technology.16 The national electric grid is vulnerable because of age and the threat to the Supervisory Control and Data Acquisition (SCADA) control system from cyber attacks. An additional threat comes from EMP weapons, which deliver a pulse of energy from a nuclear or electromagnetic detonation “that creates a powerful electromagnetic field capable of short-circuiting a wide range of electronic equipment,” including computers and telecommunications equipment.17 The conventional grid is exposed to EMP attacks in the form of high-voltage control cables and transformers that regulate the grid. High-voltage transformers take 2 years to build, and the United States is inadequately stocked with backup transformers. Thus, a large-scale EMP attack could bring down a large section of the grid for an extended time.18

Certainly, military operational readiness would suffer if military installations were still integrated in the national grid at the time of such an attack. Again, this is not a scenario found only in science fiction novels and dystopian Hollywood films. Today, China is already believed to possess super-EMP weapons and to have developed procedures to execute a first strike.19 This rationale is arguably enough for DOD to explore alternative power delivery systems to maintain response capabilities in the event of such an assault.

Fortunately, a microgrid system based on SMR technology has significant defensive advantages to the national grid. First, by definition, a microgrid is a discrete system that provides power locally. An SMR acts as an “island of power,” which decouples from the larger grid and from other military installations, so a successful attack on one installation would be an isolated incident and not a systemic failure. In the case of a cyber attack or EMP detonation on the larger grid infrastructure, a military microgrid would simply not be affected because it is separate from the rest of the system.

Direct cyber attacks on microgrid infrastructure are also possible, but this infrastructure is more resilient because of its independent computer control. We recommend that both buried SMRs and underground power lines are a standard part of a DEA microgrid configuration. By virtue of being below surface, they are less vulnerable to overhead EMP explosions, which is not an option for systems based on solar panels and wind turbines. Increased sophistication and sheer volume of monitoring sensors required on a large grid necessitate the automated monitoring capabilities of a SCADA system. Automation not only provides efficiency of operation but also affords efficiency of disruption if cyber security systems can be breached. A series of smaller grid systems could be better protected individually, thus vastly increasing cyber security.20 Furthermore, the use of hydrogen as an energy storage medium provides a long-term reservoir of energy, and if the SMR were taken offline for a period, a reversible hydrogen stack could return the stored power in the form of electricity, assuming no damage to the transmission infrastructure.

Provide Expeditionary Capability

The fourth concept underpinning the DEA is the idea that any investments in energy production and storage systems should be applicable in expeditionary environments as well as at installations after the strategic systems become mature. The military uses doctrine, organization, training, materiel, leadership, personnel, and facilities (DOTMLPF) to assess organizational systems and the resources required to support those systems. DOD should avoid redundancy of DOTMLPF for separate systems for energy production and delivery in garrison and expeditionary environments. This just represents waste and opportunity cost.

Second, the challenges faced in deployed operations are equally well addressed by the microgrid systems that we advocate. In the wars in Afghanistan and Iraq, powering forward operating bases was one of the most challenging and deadly aspect of the conflicts. Diesel generators and vehicles required constant fueling, which gave the enemy ample opportunity to attack resupply convoys. The Army Environmental Policy Institute calculated that every 39 fuel-resupply missions resulted in a U.S. casualty.21 These are lives that are lost or irreparably changed, and no price tag can be placed on them. Additionally, it has been estimated that the financial cost of delivering fuel to the end user in the operational theater exceeded $400 per gallon.22 Given the personal and fiscal costs that result from current in-theater energy systems, the clear challenge is to develop systems that remove military operations from the “tether of logistics” as much as possible. This would not only save blood and treasure but also enhance operational flexibility of commanders since they would experience more autonomy in deploying forces.

In addition to installation energy systems, SMRs have the potential to act as the centerpiece of deployed energy systems. As DOD better understands the capabilities of mobile reactors, we expect to see the technology migrate further to the tactical level. The Navy is certainly no stranger to small nuclear reactors, as they have been employed in the fleet since the USS Nautilus launched in 1955. Project Pele, conducted by DOD,23 envisions an SMR that can be used at remote operational bases.24 Analysis has shown that SMR technology allows for production units that are small enough to be moved by a heavy truck but are large enough to produce up to 20 megawatts of energy, enough to power an Army division headquarters.25

As discussed, an SMR can be buried underground, making it a hard target in a deployed environment. While SMRs address the need for a forward operating base’s energy, they do not directly address vehicle mobility. However, the electricity from nuclear generation can be used to power electric and hybrid electric vehicles that the U.S. military is already experimenting with.26 As stated, nuclear energy can be used to create hydrogen and other fuels, and higher operating temperatures of SMRs are ideal for producing hydrogen. Because hydrogen is energy-dense, it can extend the operational range of vehicles. In fact, H2 is nearly three times as energy-dense as petroleum diesel, which means less refueling and fewer halts in missions for refueling operations.27 These expanded operational capabilities are simply not available with batteries, which have one-hundredth the energy storage capacity of hydrogen on an equal-weight basis.28 The nuclear-hydrogen synergy could provide all the energy needed for military operations in deployed environments and eliminate the fossil-fuel supply chain altogether.29 We believe a Defense Energy Architecture should unequivocally embrace an SMR-hydrogen system in deployed operations to save lives and resources and increase operational range and flexibility.

DOD Role in Advancing Energy Technology

Both SMRs and green hydrogen production can be considered emerging commercial technologies. That is, there are commercial units available, but the industries have not yet scaled to optimize production costs. The general trend in technologies over time is to become smaller and cheaper as the technology evolves. However, this takes place only if demand for the product is such that the product is seen as having long-term profitability, and companies have the incentive to invest in research and development that keeps technology moving forward.

The military operates nearly 800 installations worldwide.30 If even a fraction of these installations were to develop SMR capabilities, it would provide a clear signal to producers and investors. The first SMRs would be much less risky to financiers if they had long-term contracted customers once completed. In fact, the Special Capabilities Office (SCO) within the Office of the Secretary of Defense has already narrowed the selection for the first such SMRs to two commercial designs under Project Pele.31 However, this project cannot be seen as a one-off event if the scale benefits for DOD are to be realized. Project Pele could drive the procurement of the first few units within years and lay out a comprehensive plan for future purchases in the out years. A similar effort to identify promising hydrogen technologies would serve to spur investment and bring down costs for long-term, flexible energy-storage options.

The current moment is favorable for this transition in energy systems. SMR designs are being developed by more than 50 startup companies with private capitalization of greater than $2 billion.32 Instead of paying for the entire technological development cost, the military need only pay for the adaptation to military standards. Based on this, the SCO predicts the initial non-Navy military SMR market will be 300 units and the civilian market 1,000 units.33 The Department of Energy (DOE)’s Office of Nuclear Energy is already collaborating with the SCO to move the project forward and coordinate national laboratory efforts. In fact, the coauthor has personally been involved in extensive meetings at Creech Air Force Base, Nevada, to discuss the possibility of “assured energy” being supplied to the base through a prototype SMR as early as 2030.

Similarly, there is much interest in advancing green hydrogen technology. DOE has launched an initiative called the Hydrogen Shot to reduce the production cost of green hydrogen by 80 percent by 2030.34 Furthermore, the Inflation Reduction Act has announced an investment of up to $8 billion in creating regional hydrogen hubs.35 These programs will stimulate significant private investment as well and help advance the current state of hydrogen technology. DOD can draft off these efforts to ensure that developing hydrogen technologies meet the military specifications of an advanced microgrid system. The earlier the demand signal from the military (vs. DOD hoping for the appropriate solutions to emerge organically), the more likely that customized offerings will be available. DOD can play an important role in providing a market for these emerging technologies.

Conclusion

For the military, energy is the lifeblood to maintain military capabilities. In the event of a large-scale natural disaster or infrastructure attack, the military needs to maintain its own systems to ensure readiness. For these reasons, DOD needs to keep advancing SMR-based microgrid systems with adequate long-term energy storage in the form of hydrogen. For strategic facilities, this would mean that bases control their own destiny without counting on an ever more vulnerable electric grid. With SMR microgrids, military bases can isolate their power supply from the grid when necessary. In fact, during crises, excess power could be supplied to the civilian sector as it is available.

DOD should double down on the current efforts of developing microgrids to increase the resilience of its installations, retain the ability to deploy forces globally when needed, and provide expeditionary power without exposed refueling logistics. The benefits would be multifold. In addition to decreasing vulnerability, DOD adaptation of SMR-based microgrids would allow the military to meet clean energy goals and separate itself from carbon-producing fossil fuels. Increased DOD adaptation would drive demand, resulting in greater competition and lower prices. Furthermore, it would serve as a model to civilian energy planners who could observe the positive outcomes and adapt the technology to civilian requirements.

The military has already determined that SMR microgrids have merit, as evidenced by the maturing of Project Pele. The final solution to base supply of electricity should consider long-term efficiencies to the military of the 21st century. All sources of clean energy integration should be considered on a case-by-case basis to meet the individual needs and priorities of each base mission. Success could drive a successful transition to tactical use of SMR microgrids as well.

The national electric grid is becoming vulnerable because of age and the threat of the SCADA control system being compromised through cyber attacks, EMP disruptions, intermittent power outages, or terrorist threats. Military electric power supply, both strategic and tactical, must adapt to this reality and plan for increased future use of microgrids within a generation in the name of mission assurance. Availability, affordability, and uninterrupted power are the force multiplier requirements governing the transition away from legacy systems toward independent microgrids. It is critical that a transition to a defined Defense Energy Architecture, based on these principles, be developed and implemented soon. 

About the authors: Captain Steven Curtis, USA (Ret.), is a Consultant at the Readiness Resource Group. Colonel Peter D. Rocha, USAR, is a Faculty Instructor at the U.S. Army War College.

Source: This article was published in Joint Force Quarterly 112, which is published by the National Defense University.

Notes

1 Brian Warshay, “Upgrading the Grid: How to Modernize America’s Electrical Infrastructure,” Foreign Affairs, March/April 2015.

2 Stephen Lacey, “Resiliency: How Superstorm Sandy Changed America’s Grid,” Green Tech Media, June 10, 2014, https://www.greentechmedia.com/articles/featured/resiliency-how-superstorm-sandy-changed-americas-grid.

3 Ibid.

4 Robert K. Knake, A Cyberattack on the U.S. Power Grid (New York: Council on Foreign Relations, April 2017), https://www.cfr.org/report/cyberattack-us-power-grid.

5 Daniel R. Coats, Worldwide Threat Assessment of the U.S. Intelligence Community (Washington, DC: Director of National Intelligence, January 29, 2019), https://www.dni.gov/files/ODNI/documents/2019-ATA-SFR—SSCI.pdf.

6 David E. Sanger, Clifford Krauss, and Nicole Perlroth, “Cyberattack Forces a Shutdown of a Top U.S. Pipeline,” New York Times, May 8, 2021, https://www.nytimes.com/2021/05/08/us/politics/cyberattack-colonial-pipeline.html.

7 Rose L. Thayer, “Winter Weather Causes More Than a Dozen Military Bases to Close,” Stars and Stripes, February 16, 2021, https://www.stripes.com/theaters/us/winter-weather-causes-more-than-a-dozen-military-bases-to-close-1.662417.

8 Rachel S. Cohen, “DOD’s ‘Black-Start’ Exercises Explore What Happens When Utilities Go Dark,” Air & Space Forces Magazine, October 17, 2019, https://www.airforcemag.com/dods-black-start-exercises-explore-what-happens-when-utilities-go-dark/.

9 Allison Lantero, “How Microgrids Work,” Breaking Energy, July 20, 2015, https://breakingenergy.com/2015/07/20/how-microgrids-work-2/.

10 Department of the Army, Office of the Assistant Secretary of the Army for Installations, Energy, and Environment, United States Army Climate Strategy(Washington, DC: Headquarters Department of the Army, February 2022), https://www.army.mil/e2/downloads/rv7/about/2022_army_climate_strategy.pdf.

11 “Electricity Explained: Electricity Generation, Capacity, and Sales in the United States,” U.S. Energy Information Agency, June 30, 2023, https://www.eia.gov/energyexplained/electricity/electricity-in-the-us-generation-capacity-and-sales.php.

12 National Renewable Energy Lab (NREL), “‘Fort Renewable’ Shows Benefits of Batteries and Microgrids for Military and Beyond,” NREL, July 27, 2021, https://www.nrel.gov/news/program/2021/fort-renewable-shows-benefits-of-batteries-and-microgrids-for-military-and-beyond.html.

13 Jonathan Spencer Jones, “The Different Types of Energy Storage and Their Opportunities,” Smart Energy International, May 14, 2021, https://www.smart-energy.com/storage/the-different-types-of-energy-storage-and-their-opportunities/.

14 Mark Newton, “Is Hydrogen Storage the Future of Renewable Energy?” Reset, June 27, 2022, https://en.reset.org/is-hydrogen-storage-the-future-of-renewable-energy/.

15 NREL, “Answer to Energy Storage Problem Could Be Hydrogen,” NREL, June 25, 2020, https://www.nrel.gov/news/program/2020/answer-to-energy-storage-problem-could-be-hydrogen.html.

16 Peter Yeung, “Why Cyber Attacks Will Define 21st-Century Warfare,” Raconteur, August 26, 2021, https://www.raconteur.net/technology/why-cyber-attacks-will-define-21st-century-warfare.

17 Washington State Department of Health, “Electromagnetic Pulse (EMP),” Fact Sheet 320-090, September 2003, 3, https://doh.wa.gov/sites/default/files/legacy/Documents/Pubs/320-090_elecpuls_fs.pdf.

18 James Conca, “China Has ‘First-Strike’ Capability to Melt U.S. Power Grid With Electromagnetic Pulse Weapon,” Forbes, June 25, 2020.

19 Ibid.

20 Terrorism and the Electric Power Delivery System (Washington, DC: National Academies Press, 2012), https://nap.nationalacademies.org/catalog/12050/terrorism-and-the-electric-power-delivery-system.

21 David S. Eady et al., Sustain the Mission Project: Casualty Factors for Fuel and Water Resupply Convoys (Arlington, VA: Army Environmental Policy Institute, September 2009), 14, https://apps.dtic.mil/sti/pdfs/ADB356341.pdf.

22 Adam Tiffen, “Going Green on the Battlefield Saves Lives,” War on the Rocks, May 22, 2014, https://warontherocks.com/2014/05/going-green-on-the-battlefield-saves-lives/.

23 “Project Pele: Mobile Nuclear Reactor,” Office of the Under Secretary of Defense for Research and Engineering, n.d., https://www.cto.mil/pele_eis/.

24 Jaroslaw Gryz et al., “Mobile Nuclear-Hydrogen Synergy in NATO Operations,” Energies 14, no. 23 (2021), 6, https://www.proquest.com/openview/21c797e164840e6b525ba8343e949115/1?pq-origsite=gscholar&cbl=2032402.

25 Ibid., 7. See also “U.S. Army Signs onto 20 MW Solar Farm, Biggest in Military,” GreenBiz, April 12, 2013, https://www.greenbiz.com/article/us-army-signs-20-mw-solar-farm-biggest-military.

26 Jen Judson, “Oshkosh Unveils Hybrid Electric Joint Light Tactical Vehicle,” Defense News, January 25, 2022, https://www.defensenews.com/land/2022/01/25/oshkosh-unveils-hybrid-electric-joint-light-tactical-vehicle/.

27 Patrick Molloy, “Run on Less With Hydrogen Fuel Cells,” RMI, October 2, 2019, https://rmi.org/run-on-less-with-hydrogen-fuel-cells.

28 Gryz et al., “Mobile Nuclear-Hydrogen Synergy in NATO Operations,” 9.

29 Ibid.

30 David Vine, “Where in the World Is the U.S. Military?” Politico, July/August 2015, https://www.politico.com/magazine/story/2015/06/us-military-bases-around-the-world-119321/.

31 Aaron Mehta, “Pentagon Awards Contracts to Design Mobile Nuclear Reactor,” Defense News, March 9, 2020, https://www.defensenews.com/smr/nuclear-arsenal/2020/03/09/pentagon-to-award-mobile-nuclear-reactor-contracts-this-week/.

32 John Milko, Jackie Kempfer, and Todd Allen, “2019 Advanced Nuclear Map,” Third Way, October 17, 2019, https://www.thirdway.org/graphic/2019-advanced-nuclear-map.

33 Patrick Tucker, “U.S. Military Eyes Tiny Nuclear Reactors for Deployed Troops,” Defense One, January 24, 2019, https://www.defenseone.com/technology/2019/01/us-military-eyes-tiny-nuclear-reactors-deployed-troops/154406/; and author teleconference meeting April 16, 2019, with the National Defense Industrial Association–Las Vegas and the Special Capabilities Office.

34 Department of Energy, “Hydrogen Shot,” Office of Energy Efficiency and Renewable Energy, 2021, https://www.energy.gov/eere/fuelcells/hydrogen-shot.

35 Department of Energy, “Regional Clean Energy Hubs,” Office of Clean Energy Demonstrations, n.d., https://www.energy.gov/oced/regional-clean-hydrogen-hubs.

By C Raja Mohan

The summit meeting between Russian President Vladimir Putin and Chinese leader Xi Jinping in mid-May 2024 in Beijing underlines the growing convergence of strategic interests between two of the world’s most consequential nations in countering the West. The sweeping agenda of bilateral cooperation, from financial to technological and collaboration on regional security-from Ukraine to North Korea outlined by the two leaders demands that Delhi carefully recalibrate its own great power relations and compensate where ever necessary to blunt the negative consequences of the Sino-Russian entente.

Since he took charge of Russia in 2000, Putin has made a sustained effort to expand ties with China even as he explored a modus vivendi with the West. At the turn of the 2000s, a rising China was intensifying interdependence with the United States (US) and Europe, but Beijing found it useful to develop strong ties with Moscow to stabilise its frontiers and strengthen global multipolarity. Since his ascent to the top in 2012, Xi Jinping has sought to reduce dependence on the US, chip away at American US primacy in Asia and double down on a strong partnership with Russia.

As their contradictions with the US began to deepen over the last decade, both Putin and Xi have elevated their bilateral collaboration into a ‘Comprehensive Strategic Partnership of Coordination for a New Era’ in 2019 and professed a high degree of mutual trust. On the eve of his invasion of Ukraine in February 2022, Putin travelled to Beijing to proclaim an “alliance without limits”. Since then, Putin and Xi have surprised Western observers who had been arguing that Russia and China cannot get too close to each other, given the range of their competing regional geopolitical interests and the intensity of their stakes in economic engagement with the West.

It is not that Putin and Xi do not have any differences. As two major powers in a shared neighbourhood with a record of intense bilateral conflict, the interests of Moscow and Beijing are not in absolute alignment. Yet, Putin and Xi have shown that they can put their divergences aside in building a new alliance to resist Western dominance over world affairs.

The latest summit has highlighted their efforts at political coordination and mutual support on their respective national priorities – Ukraine for Russia and Taiwan for China. Putin and Xi also denounced the US’ interventions in Europe and its effort to build new coalitions like the Quadrilateral Security Forum (in which India is a member, including Australia, Japan and the US). They also underlined their commitment to build a ‘multipolar world’ and weaken American global hegemony over international institutions, especially in the domain of finance. If the US has been pressing China to limit his cooperation with Russia, the usually wooden Xi seemed to thumb his nose against Washington with a rare hug for Putin.

New Delhi, like many Western chancelleries, had been betting on the thesis that Moscow and Beijing could not collaborate beyond a point. In a corollary to this thesis, Delhi has been hoping that Putin will not ignore India’s concerns in drawing too close to China that has emerged as India’s principal external challenge. The time has come for Delhi to reexamine its Russia thesis and its corollary as the Sino-Russian partnership goes from strength to strength.

India’s former Army Chief, General M M Naravane, put India’s concerns succinctly, “The closer alignment between Moscow and Beijing could potentially embolden the latter in its assertive actions in the region – including territorial disputes with India along the Himalayan border. Russia’s tacit support or neutrality in such conflicts could complicate India’s strategic calculus and necessitate a reassessment of its foreign policy priorities. Given a no-limits partnership and the premise that China is undoubtedly supporting the Russian war effort, India can no longer assume Russia’s support in reining-in China in the event of a clash.”

Beyond the question of border security, Delhi has reasons to worry that Putin’s support for China’s positions in the Indo-Pacific would undermine India’s effort to build a balanced regional order in Asia. In the aftermath of the Cold War in the 1990s, India had joined hands with Russia and China in promoting a ‘multipolar world’. However, as India’s conflict with China deepened in recent years, Delhi has underlined the importance of a preventing Chinese dominance over Asia. Moscow’s growing regional security cooperation with Beijing would make India’s quest for a multipolar Asia that much more challenging.

The Sino-Russian partnership might also reduce the Indian compulsions to avoid too tight a strategic embrace with the US. During the Cold War, India turned to Russia to balance China and blunt the Sino-US entente in Asia. Delhi may no longer hope to get that kind of strategic depth from the Russian partnership. Although Moscow understands India’s difficulties with China and would want to sustain the traditional bonds with Delhi, Russia is likely to be constrained by the logic of its confrontation with the West.

Moscow believes that the “collective West” poses an extraordinary threat to Russian interests and the alignment with China is critical in addressing it. For India, the principal contradiction is with China; the US and its allies are seen as part of the solution in Delhi. This structural contradiction between the Russian and Indian security imperatives will not be easy to finesse, as the conflict between the West and Sino-Russian entente escalates.

• About the author: Professor C Raja Mohan is a Visiting Research Professor at the Institute of South Asian Studies (ISAS), an autonomous research institute at the National University of Singapore
• Source: This article was published by Institute of South Asian Studies (ISAS)

Canada is a major energy producer, consumer, and exporter with a diverse and dynamic energy sector. Historically, hydroelectric power dominated Canada’s energy mix, but oil and natural gas production have grown. The majority of Canada’s oil and natural gas output is in Alberta; in contrast, hydroelectric and renewable energy make up a larger share of energy output in Quebec and British Columbia. 

Primary energy production in Canada grew at an average annual rate of 2.6% between 2012 and 2022; Canada’s share increased from 3.2% to 3.6% of total global energy production.¹ Crude oil production followed by natural gas production mainly drove this growth. By 2022, oil production accounted for 51.7% of Canada’s total energy production, followed by natural gas at 32.4% (Table 1). As of 2022, Canada was the world’s sixth-largest energy producer.

Canada’s energy consumption has remained stable despite inflation-adjusted GDP per capita growth, mainly because of improvements in energy efficiency. Between 2012 and 2022, natural gas use increased at an annual growth rate of 2.6%, making it the primary source of energy with the largest growth contribution.

According to the Canadian Centre for Energy Information (CCEI), the energy sector contributes significantly to government revenues. Between 2017 and 2021, the energy sector accounted for 4.6% of total industry tax revenue. The oil and natural gas extraction industry accounts for about 83% of government petroleum-related revenues. In 2022, the combination of rising oil and natural gas prices and higher production volumes contributed to the overall increase in revenue for the oil and natural gas extraction industry.^2,3 According to CCEI, Canada’s energy sector accounted for approximately 11.8% of the nominal gross domestic product (GDP) and approximately 3.5% of total employment in 2022.⁴

Canada’s distribution bottlenecks hinder crude oil flow outside the domestic refining market, including to refiners on the U.S. Gulf Coast. The Trans Mountain Expansion (TMX) Project on the Trans Mountain Pipeline aims to increase Canada’s crude oil exports to the worldwide market through Pacific coast ports. The expansion will more or less triple the pipeline’s present capacity of 300,000 barrels per day (b/d) for transporting crude oil from Alberta’s oil sands to Canada’s Pacific coast, where it will be exported to markets in Asia or the United States. The TMX pipeline began operations in May 2024.^5,6,7

Canada has many policy measures to support the transition to lower carbon fuels, including carbon pricing, clean fuel regulations, coal phaseout, nuclear power plant expansion, methane regulations, energy-efficiency programs, and the decarbonization of the transportation sector.⁸ Canada’s energy-related carbon dioxide (CO₂) emissions from oil and coal consumption have declined, while natural gas has increased between 2012 and 2022.⁹ However, as of 2022, oil remains the largest source of energy-related CO₂ emissions with 51% of the total. In December 2023, Canada’s government proposed a cap-and-trade system to reduce greenhouse gas emissions in the oil and natural gas sector to achieve net-zero emissions by 2050. If signed into law, the cap-and-trade system would be implemented in 2030, limiting emissions to between 131 metric tons (mt) of CO₂ equivalent per year and 137 mt of CO₂ equivalent per year, down from 171 mt of CO₂ equivalent per year in 2019.¹⁰

Petroleum and Other Liquids

Canada had proved oil reserves of 163 billion barrels as of January 2024, ranking fourth in the world behind Venezuela, Saudi Arabia, and Iran.¹¹ Oil sands account for 97% of the country’s total oil reserves.¹² These large deposits are spread across three regions in Alberta and Saskatchewan: Athabasca, Peace River, and Cold Lake.

In 2023, Canada was the world’s fourth-largest petroleum and other liquids producer and was a liquid fuels net exporter. Nearly all of Canada’s energy exports are destined for the United States. Many U.S. refineries are configured to process heavy oils like those produced in Canada’s oil sands.

In 2023, 5.8 million b/d of petroleum and other liquid fuels were produced in Canada, growing at an average annual rate of 3.8% between 2013 and 2023. Crude oil (including condensate) contributed 2.9% to the growth, and the remaining 0.9% growth was from natural gas liquids (NGLs). Liquid fuels production in Canada has increased because of increasing production from Alberta’s oil sands and upgraded synthetic crude oil.¹³ Approximately 83% of crude oil production in Canada in 2022 originated in Alberta. In 2022, oil sands production accounted for 65% of total crude oil production, and conventional, offshore, and tight oil accounted for the remaining 35%.¹⁴

Offshore production in Canada is concentrated in the eastern provinces and accounts for less than 5% of total production. Severe weather and difficult deep-water conditions have hampered the progress of three projects in Newfoundland, Labrador, and Nova Scotia. These challenges exacerbate both technical difficulties and exploration and production costs.

Western Canadian Sedimentary Basin (WCSB) producers have traditionally focused on natural gas production, but because of a lack of midstream infrastructure and export capacity, the focus has shifted to producing liquid fuels for use as domestic diluents in nearby oil sands projects. Alberta’s extra-heavy crude oil must be mixed with lighter liquids, such as plant condensate or pentanes before it can flow through pipelines and reach downstream facilities.

Canada’s petroleum and other liquids consumption was 2.5 million b/d in 2023, of which 32% was motor gasoline, 24% was distillate fuel oil, and 7% was liquefied petroleum gases. The main petroleum and other liquids consuming sectors were transportation (60%), non-energy use(24%), and industry (7%).

Pipelines account for 88% of the crude oil transportation modes. The Canadian Energy Regulator (CER) regulates Canada’s pipelines. Canada’s oil operating capacity is 4.3 million b/d as of 2021. Canada’s pipelines transport crude oil from the western provinces to refineries in the United States and Quebec and Ontario and to export terminals. Four primary crude oil export pipelines are in Western Canada: Enbridge Canada Main Pipeline, Keystone Pipeline, Trans Mountain Pipeline, and Express Pipeline. Together, these pipelines can ship 96% of all withdrawals from the WCSB. Enbridge Canadian Mainline, which is owned by Enbridge Pipelines Inc., accounts for approximately 58% of all Canada’s oil exports.^15,16,17

As of 2023, Canada had 14 refineries and a nameplate crude oil processing capacity of 1.7 million b/d (Table 2). These refineries process crude oil into various products, such as gasoline, diesel, and home heating oil, that are essential for transportation and heating. The refineries are in six provinces, and the largest concentrations are in Alberta and Ontario, which account for 49% of the total capacity. Most of the crude oil is refined into motor gasoline and diesel fuel.^18,19

Canada’s refineries supply petroleum to domestic and export markets, and the United States is the main destination for Canada’s refined products. In Canada, more crude oil is produced than refined domestically, but it imported an average 57% of its total crude oil trade between 2019 and 2023 because eastern refineries are not connected to domestic crude oil production supplies.²⁰ The nine refineries in Western Canada have a combined capacity of 653,000 b/d, or 38% of Canada’s total nameplate refining capacity.

Oil sands are a mixture of sand, water, and bitumen. Bitumen is a crude oil extracted from the ground that is too thick to transport via pipelines. Bitumen can be either upgraded into a lighter synthetic crude oil or diluted with light hydrocarbon condensate, which is referred to as diluted bitumen or dilbit.²¹

Upgraders are partial refiners that convert the residue of the bitumen and remove all the sulfur, making the synthetic crude oil easier to process. This process makes it ideal for less sophisticated refineries, like those in Canada. About half of the synthetic crude oil produced in Alberta is sold domestically, and the rest is exported to the United States.²²

Dilbit contains around 60% bitumen, which produces a lot of residue during distillation. Dilbit refineries require a lot of residue conversion capacity, which Canada’s refineries do not have. As a result, nearly 95% of Alberta’s dilbit is exported to the United States, leaving very little dilbit to be used in Canada.²³

Refinery	Operator	Nameplate crude oil distillation capacity  (thousand barrels per day)	Location
Data source: Oil & Gas Journal, 2023 Worldwide Refining Survey
Saint John Refinery	Irving Oil Ltd.	320,000	Saint John, New Brunswick
The Jean Gaulin Refinery	Valero Energy Corp.	218,500	Levis, Quebec
Strathcona Refinery	Imperial Oil Ltd.	186,200	Strathcona, Alberta
Edmonton Refinery	Suncor Energy Inc.	146,000	Edmonton, Alberta
Montreal Refinery	Suncor Energy Inc.	137,000	Montreal, Quebec
Co-op Refinery Complex	Federated Co-operatives Limited	130,000	Regina, Saskatchewan
Sarnia Refinery	Imperial Oil Ltd.	113,050	Sarnia, Ontario
Nanticoke Refinery	Imperial Oil Ltd.	107,350	Nanticoke, Ontario
Scotford Refinery	Shell Canada Ltd.	95,000	Scotford, Alberta
Sarnia Refinery	Suncor Energy Inc.	85,000	Sarnia, Ontario
Corunna Refinery	Shell Canada Ltd.	80,750	Sarnia, Ontario
Burnaby Refinery	Parkland Fuel Corp.	55,000	Burnaby, British Columbia
The Cenovus Lloydminster Refinery	Husky Energy Inc.	29,000	Lloydminster, Alberta
Prince George Refinery	Tidewater Midstream & Infrastructure Ltd.	12,000	Prince George, British Columbia
Total		1,714,850

Name	Operator	Capacity (thousand barrels per day)
Data source: Canada Energy Regulator—REGDOCS
Enbridge Canadian Mainline	Enbridge Inc	2,890
Keystone Pipeline	TC Energy	591
Express Pipeline	Express Pipeline LLC	310
Trans Mountain Pipeline	Trans Mountain Corporation (TMC)	300
Milk River Pipeline	Inter Pipeline Ltd. (IPL)	98
Aurora Pipeline	Aurora. Pipeline Company Ltd	45
Wascana Pipeline	Plains Midstream Canada ULC (PMC)	40
Total		4,274

Natural Gas and LNG

Canada’s proved natural gas reserves are estimated to be 87 trillion cubic feet (Tcf) as of January 2024.²⁴ Most of these reserves are found in the Western Canadian Sedimentary Basin (WCSB). Natural gas reserves are also present in other regions of Canada, such as offshore fields off the eastern coast of Newfoundland and Nova Scotia, the Arctic region, and the Pacific coast. In March 2016, the Canadian Energy Regulator published a study on the Liard Basin located in northwest Canada that spans the borders of British Columbia, Yukon, and the Northwest Territories. The study found that it contains 219 Tcf of marketable unconventional natural gas, making it the world’s ninth-largest shale gas resource.

Canada is the world’s fifth-largest natural gas producer, following the United States, Russia, Iran, China, and Qatar, and produced 6.6 Tcf of dry natural gas in 2022.²⁵ Most natural gas production in Canada takes place in the WCSB, mainly concentrated in British Columbia and Alberta, which accounted for 98.7% of the total output in 2022.

Natural gas production in Canada increased from 5.8 Tcf in 2012 to 6.6 Tcf in 2022, despite a decline in the number of wells drilled. The productivity of individual wells increased because of technological advancements in horizontal drilling and hydraulic fracturing.²⁶

Natural gas consumption in Canada has increased by an average of 2% per year between 2012 and 2022. Natural gas consumption was 4.6 Tcf in 2022; 32% was used by industry, 27% by residential customers, and 26% by commercial and public services. Natural gas consumption is highest in Alberta (44%), followed by Ontario (30%), and British Columbia (BC) (9%).²⁷

Canada currently has eight LNG export projects in different stages of development. Together, these projects have a potential production capacity of 2.5 Tcf of LNG. Although most export projects are in British Columbia, one export project has been proposed that includes Newfoundland and Labrador. Canada also has four LNG liquefaction plants and two LNG import plants that serve the domestic market, although most of them operate at low volumes. LNG Canada in Kitimat (BC) is set to become Canada’s first large-scale LNG export facility, and it has a target to start exporting by 2025. Most of the other projects will begin operations between 2027 and 2030.²⁸

The NOVA Inventory Transfer (NIT) is a pricing point for natural gas produced in the WCSB. It’s a trading hub in Alberta linked to several export markets and storage facilities. Other reference points include Dawn, Ontario, and Station 2 on the Enbridge BC Pipeline. The Canada Energy Regulator (CER) has approved many natural gas pipeline projects in the last five years, including Nova Gas Transmission Ltd. System’s projects to add capacity in key areas. Westcoast Energy has also proposed upgrades to its Enbridge BC Pipeline because of growing BC production. In late October 2023, TC Energy announced that it had completed construction of the Coastal GasLink earlier that month.^29,30

New natural gas-fired power plants in Canada are replacing coal-fired plants. The Canadian government has pledged to phase out coal use for power generation by 2030. In its place, 18 natural gas-fired facilities are in the planning and approval stages, and four are currently under construction. These facilities include the Suncor Oilsands Cogeneration Base Plant with a power generation capacity of 800 megawatts (MW), ATCO Strathcona Cogeneration Plant in Alberta (116 MW), and the Great Plains Power Station in Saskatchewan (360 MW).

Name	Capacity utilization (percentage)	Capacity (billion cubic feet per day)
Data source: Canada Energy Regulator—Pipeline Profiles
NGTL System—Upstream of James River—Intra-Canada	88%	11.2
TC Canadian Mainline—Prairies—Intra-Canada	47%	6.2
Foothills System—Kingsgate—Export	78%	2.9
NGTL System—West Gate—Intra-Canada	89%	2.8
Foothills System—Monchy—Export	26%	2.2
Alliance Pipeline—Border—Export	82%	1.6
Enbridge BC Pipeline—Huntingdon—Export	53%	1.6
TC Canadian Mainline—Iroquois—Export	29%	1.2
TC Canadian Mainline—Niagara—Import	95%	0.7
M&NP Pipeline—St. Stephen—Import	34%	0.5
Total		30.9

Coal

Canada’s large coal reserves totaled 7.3 billion short tons in 2021.³¹ The majority of the reserves consist of anthracite and bituminous coal. The rest of the reserves are subbituminous and lignite. More than 90% of Canada’s coal reserves are in the western provinces, which provides a strategic advantage because of its proximity to West Coast ports for export.³²

Because the national electricity grid has reduced its coal use, Canada’s overall coal production has also declined, reaching 45.4 million short tons in 2021, compared with a peak of 86.7 million short tons in 1997. Metallurgical coal, used for steel manufacturing, accounted for 61% of Canada’s coal production in 2022.³³ British Columbia produces 57% of the coal in Canada, followed by Alberta (25%) and Saskatchewan (17%).³⁴

As of 2022, Canada’s coal accounts for 4% of the country’s total energy supply and 2% of total consumption, making Canada a net exporter of coal (Table 1). Canada’s exports are primarily metallurgical coal. Lignite coal, used to generate electricity, accounted for 45% of Canada’s coal consumption in 2022, mostly for electricity generation in Alberta and Saskatchewan.³⁵

In 2022, Nova Scotia, New Brunswick, Saskatchewan, and Alberta were still using thermal coal plants to generate electricity. Ontario stopped using coal-fired power plants in 2014, and Manitoba followed suit in 2019. Alberta has announced that it will phase out coal-fired power plants by 2024, and Nova Scotia and New Brunswick have confirmed plans to phase out coal by 2030.³⁶

In 2018, Canada’s government committed to phasing out coal use for electricity generation by 2030, except for power plants that can meet certain emissions standards through carbon capture and storage technology. The federal government has established strict emissions requirements that require coal-fired power plants to either close at the end of their lifecycle or to install carbon capture and storage (CCS) technology.

The lignite-fired Boundary Dam Power Station in Saskatchewan is currently the only power plant in Canada using CCS technology. The site began carbon capture and storage in 2014, making it the first of its kind in the world.³⁷

Biofuels

In Canada, biofuels are primarily produced from corn and wheat for ethanol and from canola and soybean for biodiesel. Canada produced 31,000 b/d of fuel ethanol and 6,000 b/d of biomass-based diesel in 2022, meeting 51% and 47% of the domestic demand, respectively.^38,39

Biofuel production in Canada increased by an annual average of 1.6% between 2012 and 2022, with biomass-based diesel contributing 1.2% and fuel ethanol contributing 0.4% of the increase. Ethanol is the top biofuel in Canada, accounting for 83% of biofuel production and 82% of biofuel consumption in 2022.

The demand for biofuels, particularly ethanol and renewable diesel, is rising because of regulations; biofuel consumption grew at an average annual rate of 7.6% between 2012 and 2022. As of 2022, Canada was the world’s seventh-largest biofuel consumer. Industry accounted for 58% of total biofuel consumption, followed by transportation (22%) and residential use (20%).⁴⁰

Renewable diesel, a biomass-based fuel that can be blended with or used as a replacement fuel for petroleum diesel, is becoming increasingly popular. In June 2023, Tidewater Midstream’s stand-alone renewable diesel facility, the first of its kind in Canada, began operating. Covenant Energy in Saskatchewan has announced plans to move forward with a renewable diesel facility on the edge of Lloydminster, and Imperial Oil has committed to constructing a renewable diesel facility near Edmonton.⁴¹

Several provinces, such as British Columbia and Ontario, have implemented biofuel requirements. These policies require a certain percentage of biofuels, typically ethanol in gasoline and biodiesel in diesel, to be blended into conventional fuels. Starting January 2023, Quebec required gasoline to contain 10% renewable content and diesel to contain 15%.⁴²

Canada’s biofuels market is driven by federal and provincial regulations, such as the Renewable Fuels Regulations, the Clean Fuel Standard, and the low-carbon fuel standards in British Columbia and Quebec. 

The Clean Fuel Regulation (CFR), implemented in 2022, requires the carbon intensity of transportation fuels to be reduced and promotes biofuels. In June 2021, the Net Zero Canada Act became law, committing the government to achieving net zero emissions by 2050.⁴³

Electricity 

Canada is the world’s seventh-largest electricity generator, at an average 638 billion kilowatthours (kWh) in 2022, and renewables accounted for 70% of electricity generation. Canada’s electric power sector contributed about 1.7% to the country’s 2022 gross domestic product (at current prices) and accounted for 0.5% of Canada’s total employment.⁴⁴ Hydropower contributed 62% of Canada’s electricity generation in 2022 and has been Canada’s primary source of electricity generation for over a century. China and Brazil are the only countries that produce more hydropower than Canada on a kilowatthour basis. Apart from hydropower, nuclear and natural gas plants are the primary sources of electricity in Canada (Table 1). 

Canada is the world’s seventh-largest electricity consumer on a per capita basis, at 14,500 kilowatthours (kWh) per person in 2022. Canada’s ranking is mainly because of the presence of energy-intensive industries, cold climate, and affordable electricity prices. In 2021, the largest electricity-consuming sector in Canada was industry (35%), followed by residential (34%), and commercial and public services (28%).⁴⁵Most electricity is used in Quebec (37%), Ontario (26%), British Columbia (12%), and Alberta (11%).⁴⁶

Canada’s electricity market is divided into provincial markets; each province has its regulatory authority overseeing generation, distribution, and pricing. Provinces with surplus electricity can sell it to neighboring provinces through a network of transmission lines. This connectivity enhances reliability and efficiency.

Canada has three electricity grids: Western Grid, Eastern Grid, and Quebec Grid. The border between Alberta and Saskatchewan is where the Eastern and Western grids meet. Canada’s electricity grids are connected to the U.S. grids by 37 major transmission lines spanning from New England to the Pacific Northwest. The Canada Energy Regulatory Commission (CER) characterizes Canada’s electricity grid as “fragmented,“ with few interconnections between different locations. Major grid connections mostly link the provinces to the United States, and electricity flows from north to south. Nunavut is the only region in Canada without an electricity grid; it relies on local diesel generation.

All of Canada’s provinces and territories except Nunavut and Prince Edward Island generate hydropower. Quebec, Manitoba, British Columbia, Ontario, and Newfoundland and Labrador use the most hydropower to meet their electricity needs, combined accounting for 97% of Canada’s total hydropower capacity. A large 1,100-MW hydropower project, Site-C in British Columbia, is underway and is expected to be completed in 2025. Provinces like Alberta have a mix of energy sources, including natural gas and coal, while others, such as Ontario, have a significant nuclear power presence.

Nuclear energy contributes in powering Canada’s electricity supply. As of 2022, nuclear power plants accounted for 13% of the country’s total electricity generation. The 19 commercial reactors in the country provide a net capacity of 14,629 MW. Ontario holds 95% of Canada’s nuclear power capacity, and the remaining 5% is in New Brunswick. In recent years, Canada has focused on updating and improving its existing reactors, as well as developing small modular reactors (SMRs), in part to address climate change, meet regional energy demand, and promote economic development.^47,48

Federal and provincial commitments to reduce carbon emissions from the electric power sector by 2030 and increase renewable energy have driven the development of non-hydro renewable energy in Canada. Between 2012 and 2022, non-hydroelectric renewable electricity generation significantly increased. On average, it grew by 9.8% per year. Wind energy contributed 8.1% to this growth, solar power contributed 1.4%, and biomass and waste contributed 0.2%. Canada has favorable market conditions for wind energy and has abundant high-quality wind resources, especially offshore and along coastlines, making it an ideal location for wind electricity.⁴⁹ Most solar power is in Ontario, but provinces such as British Columbia, Saskatchewan, and Alberta are also developing solar capacity.

Between 2000 and 2021, emissions from power generation decreased by 43% because of Ontario’s and Québec’s successful phaseout of coal-fired generation.^50,51 Renewable and natural gas power plants will replace coal-fired power generation by 2030.⁵² SaskPower, Saskatchewan’s main utility company, plans to increase the share of renewables in its portfolio from 25% to 50% by 2030, investing in wind, solar, geothermal, hydropower, and biomass.

Name	Owner	Start year	Capacity (megawatts)	Type	Location
Data source: Global Energy Monitor, Global Hydropower Tracker, May 2023
Pine Falls hydroelectric plant	Manitoba Hydro	1952	9,084	Conventional storage	Manitoba
Robert-Bourassa hydroelectric plant	Hydro Québec	1979	5,616	Conventional storage	Quebec
Churchill Falls hydroelectric plant	Nalcor Energy and Hydro-Quebec	1971	5,428	Conventional storage	Newfoundland and Labrador
La Grande 4 hydroelectric plant	Hydro Québec	1984	2,779	Conventional storage	Quebec
Mica hydroelectric plant	BC Hydro	1973	2,746	Conventional storage	British Columbia
Gordon M Shrum hydroelectric plant	BC Hydro	1968	2,730	Conventional storage	British Columbia
Revelstoke hydroelectric plant	BC Hydro	1984	2,480	Conventional storage	British Columbia
La Grande 3 hydroelectric plant	Hydro Québec	1982	2,417	Conventional storage	Quebec
La Grande 2A hydroelectric plant	Hydro Québec	1991	2,106	Conventional storage	Quebec
Beauharnois hydroelectric plant	Hydro Québec	1932	1,912	Run-of-river	Quebec
Manic 5 hydroelectric plant	Hydro Québec	1970	1,596	Conventional storage	Quebec
Sir Adam Beck 2 hydroelectric plant	Ontario Power Generation	1954	1,499	Conventional storage	Ontario
La Grande 1 hydroelectric plant	Hydro Québec	1994	1,436	Run-of-river	Quebec
Limestone hydroelectric plant	Manitoba Hydro	1990	1,350	Run-of-river	Manitoba
Manic 3 hydroelectric plant	Hydro Québec	1975	1,326	Run-of-river	Quebec
Kettle hydroelectric plant	Manitoba Hydro	1970	1,253	Run-of-river	Manitoba
Manic 2 hydroelectric plant	Hydro Québec	1965	1,229	Run-of-river	Quebec
Bersimis 1 hydroelectric plant	Hydro Québec	1956	1,178	Conventional storage	Quebec
Shipshaw hydroelectric plant	Rio Tinto Group	1943	1,145	Conventional storage	Quebec
Manic 5PA hydroelectric plant	Hydro Québec	1989	1,064	Conventional storage	Quebec
Other conventional storage	Other conventional storage	1968 (average)	21,209	64 conventional storage	17 Quebec; 15 British Columbia; 32other
Other run-of-river	Other run-of-river	1964 (average)	12,318	42 run-of-river	26 Quebec; 7 Ontario; 9 other
Other unknown	Other unknown	1943 (average)	1,052	5 unknown	2 Quebec; 3 other
Other pumped storage	Other pumped storage	1957 (average)	174	1 pumped storage	1 Ontario
Total			85,127

Energy Trade 

Canada exports more energy than it imports (net exporter), and its largest and most important trading partner is the United States. Canada’s 2022 energy exports amounted to $240.5 billion, equivalent to 33% of the country’s total goods exports, and 90% of those energy exports were destined for the United States. The energy goods exported include crude oil, natural gas, refined petroleum products, electricity, and coal. Among these, oil and natural gas made up 90% of the total energy exports.⁵³ Canada’s energy imports were $65.3 billion in 2022, amounting to 9% of Canada’s total goods imports. 

In 2023, 92% of Canada’s crude oil exports went to the United States. Inland regions of the United States, particularly the Midwest (PADD 2) and Rocky Mountain (PADD 4) regions, are highly integrated with Canada’s oil markets, and Canada’s crude oil makes up a significant portion of U.S. refinery inputs in these regions. For this reason, Canada is the top crude oil supplier to the United States, providing 60% of U.S. crude oil imports in 2023. U.S. imports of refined products from Canada accounted for 18% of total U.S. petroleum product imports. 

Canada’s crude oil producers face complex market and logistical challenges. The transportation capacity of pipelines serving foreign markets is less than Western Canada’s crude oil supply. Canadian oil producers rely on rail for transportation as export pipelines are operating at full capacity. Since 2022, the Marathon Capline pipeline has allowed producers to increase oil sands volume from Alberta through the Gulf Coast to Asia. The Trans Mountain Expansion Project (TMX) has been in operation since May 2024 and has significantly increased the pipeline capacity to Canada’s Pacific Coast, enabling export to foreign markets. The pipeline runs parallel to the existing 715-mile pipeline route between Strathcona County (near Edmonton) and Burnaby, British Columbia, which is Canada’s only crude oil pipeline to its West Coast. The expansion project aims to enhance the capacity of the Trans Mountain pipeline system, facilitating the delivery of more crude oil to global markets.

Canada’s natural gas exports were 3.1 Tcf Bcf in 2023, and 100% of those exports went to the United States. Canada is the top natural gas supplier to the United States, providing 99.9% of U.S. imports in 2023. Most of Canada’s natural gas exports to the United States come from Western Canada and are transported to U.S. markets in the West and Midwest regions.

Canada is the world’s top electricity exporter; it exported 52 terawatthours (TWh) to the United States in 2023.⁵⁴ Hydropower is the main source of Canada’s electricity, and the United States was the primary import recipient. Provinces with abundant hydroelectric resources, such as Quebec and British Columbia, export electricity to neighboring regions and the United States, particularly the U.S. Northeast and Midwest. Canada imported 17 TWh of electricity from the United States; almost all of it came from the Pacific Northwest.⁵⁵

Canada is the eighth-largest coal exporter in the world, as of 2022, and Asia was its primary market. In 2023, Canada exported 44.7 million short tons (MMst) of coal, which includes lignite and peat. Japan (31%), China (22%), and Korea (20%) were the top destinations. On the other hand, Canada imported 6,526 MMst of coal in 2023, which mainly came from the United States (77%) and Colombia (22%). For over a decade, coal imports have been decreasing, but exports have remained mostly stable. Canada is planning to phase out traditional coal-fired electricity by 2030 domestically. However, because coal is utilized for metallurgical processes, Canada continues to export coal, which constitutes almost two-thirds of its production as of 2022.⁵⁶

Source: This article was published by EIA

Endnotes

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