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Quebec Hydropower Export Retaliation examines using electricity exports to counter U.S. tariffs amid Canada-U.S. trade tensions, weighing clean energy supply, grid reliability, energy security, legal risks, and long-term market impacts.

Key Points

Using Quebec electricity exports as leverage against U.S. tariffs, and its economic, legal, and diplomatic consequences.

✅ Revenue loss for Quebec and higher costs for U.S. consumers

✅ Risk of legal disputes under trade and energy agreements

✅ Long-term erosion of market share and grid cooperation

As trade tensions between Canada and the United States continue to escalate, with electricity exports at risk according to recent reporting, discussions have intensified around potential Canadian responses to the imposition of U.S. tariffs. One of the proposals gaining attention is the idea of reducing or even halting the export of energy from Quebec to the U.S. This measure has been suggested by some as a potential countermeasure to retaliate against the tariffs. However, experts and industry leaders are urging caution, emphasizing that the consequences of such a decision could have significant economic and diplomatic repercussions for both Canada and the United States.

Quebec plays a critical role in energy trade, particularly in supplying hydroelectric power to the United States, especially to the northeastern states, including New York where tariffs may spike energy prices according to analysts, strengthening the case for stable cross-border flows. This energy trade is deeply embedded in the economic fabric of both regions. For Quebec, the export of hydroelectric power represents a crucial source of revenue, while for the U.S., it provides access to a steady and reliable supply of clean, renewable energy. This mutually beneficial relationship has been a cornerstone of trade between the two countries, promoting economic stability and environmental sustainability.

In the wake of recent U.S. tariffs on Canadian goods, some policymakers have considered using energy exports as leverage, echoing threats to cut U.S. electricity exports in earlier disputes, to retaliate against what is viewed as an unfair trade practice. The idea is to reduce or stop the flow of electricity to the U.S. as a way to strike back at the tariffs and potentially force a change in U.S. policy. On the surface, this approach may appear to offer a viable means of exerting pressure. However, experts warn that such a move would be fraught with significant risks, both economically and diplomatically.

First and foremost, Quebec's economy is heavily reliant on revenue from hydroelectric exports to the U.S. Any reduction in these energy sales could have serious consequences for the province's economic stability, potentially resulting in job losses and a decrease in investment. The hydroelectric power sector is a major contributor to Quebec's GDP, and recent events, including a tariff threat delaying a green energy bill in Quebec, illustrate how trade tensions can ripple through the policy landscape, while disrupting this source of income could harm the provincial economy.

Additionally, experts caution that reducing energy exports could have long-term ramifications on the energy relationship between Quebec and the northeastern U.S. These two regions have developed a strong and interconnected energy network over the years, and abruptly cutting off the flow of electricity could damage this vital partnership. Legal challenges could arise under existing trade agreements, and even as tariff threats boost support for Canadian energy projects among some stakeholders, the situation would grow more complex. Such a move could also undermine trust between the two parties, making future negotiations on energy and other trade issues more difficult.

Another potential consequence of halting energy exports is that U.S. states may seek alternative sources of energy, diminishing Quebec's market share in the long run. As the U.S. has a growing demand for clean energy, especially as it looks to transition away from fossil fuels, and looks to Canada for green power in several regions, cutting off Quebec’s electricity could prompt U.S. states to invest in other forms of energy, including renewables or even nuclear power. This could have a lasting effect on Quebec's position in the U.S. energy market, making it harder for the province to regain its footing.

Moreover, reducing or ceasing energy exports could further exacerbate trade tensions, leading to even greater economic instability. The U.S. could retaliate by imposing additional tariffs on Canadian goods or taking other measures that would negatively impact Canada's economy. This could create a cycle of escalating trade barriers that would hurt both countries and undermine the broader North American trade relationship.

While the concept of using energy exports as a retaliatory tool may seem appealing to some, the experts' advice is clear: the potential economic and diplomatic costs of such a strategy outweigh the short-term benefits. Quebec’s role as an energy supplier to the U.S. is crucial to its own economy, and maintaining a stable, reliable energy trade relationship is essential for both parties. Rather than escalating tensions further, it may be more prudent for Canada and the U.S. to seek diplomatic solutions that preserve trade relations and minimize harm to their economies.

While the idea of using Quebec’s energy exports as leverage in response to U.S. tariffs may appear attractive on the surface, and despite polls showing support for tariffs on energy and minerals among Canadians, it carries significant risks. Experts emphasize the importance of maintaining a stable energy export strategy to protect Quebec’s economy and preserve positive diplomatic relations with the U.S. Both countries have much to lose from further escalating trade tensions, and a more measured approach is likely to yield better outcomes in the long run.

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Clorox Enel 70 MW VPPA accelerates renewable energy, sourcing Texas solar from the Roadrunner project to support 100% renewable electricity, Scope 2 reductions, and grid decarbonization through a virtual power purchase agreement starting in 2021.

Key Points

A 12-year virtual power purchase agreement for 70 MW of Texas solar to advance Clorox's 100% renewable electricity goal.

✅ 12-year contract supporting 100% renewable electricity by 2021

✅ Supplies 70 MW from Enel's Roadrunner solar project in Texas

✅ Cuts Scope 2 emissions via grid-delivered virtual PPA

The Clorox Company and a wholly owned subsidiary of Enel Green Power North America announced today the signing of a 12-year, 70 megawatt (MW) virtual power purchase agreement (VPPA) for the purchase of renewable energy, aligned with carbon-free electricity investments across the power sector beginning in 2021. Representing about half of Clorox's 100% renewable electricity goal in its operations in the U.S. and Canada, this agreement is expected to help Clorox accelerate achieving its goal in 2021, four years ahead of the company's original plan.

"Climate change and rising greenhouse gas emissions pose a real threat to the health of our planet and ultimately the long-term well-being of people globally. That's why we've taken action for more than 10 years to measure and reduce the carbon footprint of our operations," said Benno Dorer, chair and CEO, The Clorox Company. "Our agreement with Enel helps to expand U.S. renewable energy infrastructure, reflecting our view that companies like Clorox play an important role in addressing global climate change, as landmark policies like the U.S. climate deal further accelerate the transition. We believe this agreement will significantly contribute toward Clorox achieving our goal of 100% renewable electricity in our operations in the U.S. and Canada in 2021, four years earlier than originally planned. Our commitment to climate stewardship is an important pillar of our new IGNITE strategy and part of our overall efforts to drive Good Growth – growth that's profitable, sustainable and responsible."

The 70MW VPPA between Clorox and Enel Green Power North America for the purchase of renewable energy delivered to the electricity grid is for the second phase of Enel's Roadrunner solar project to be built in Texas, and complement global clean energy collaborations such as Canada-Germany hydrogen cooperation announced recently. Roadrunner is a 497-direct current megawatt (MWdc) solar project that is being built in two phases. The first phase, currently under construction, comprises around 252 MWdc and is expected to be completed by the end of 2019, while the remaining 245 MWdc of capacity is expected to be completed by the end of 2020. Once fully operational, the solar plant could generate up to 1.2 terawatt-hours (TWh) of electricity annually, while avoiding an estimated 800,000 metric tons of carbon dioxide emissions per year.

Based on the U.S. Environmental Protection Agency Greenhouse Gas Equivalencies Calculator[i], this VPPA is estimated to avoid approximately 140,000 metric tons of CO2 emissions each year. This is equivalent to the annual impact that 165,000 acres of U.S. forest can have in removing CO2 from the atmosphere, and illustrates why cleaning up Canada's electricity is central to emissions reductions in the power sector, or the carbon impact of the electricity needed to power more than 24,000 U.S. homes annually.

"We are proud to support Clorox on their path towards 100% renewable electricity in its operations in the U.S. and Canada by helping them achieve about half their goal through this agreement," said Georgios Papadimitriou, head of Enel Green Power North America. "This agreement with Clorox reinforces the continued significance of renewable energy as a fundamental part of any company's sustainability strategy."

Schneider Electric Energy & Sustainability Services advised Clorox on this power purchase agreement and, amid heightened investor attention exemplified by the Duke Energy climate report, supported the company in its project selection, analysis, negotiations and deal execution.

Clorox Commits to Scope 1, 2 and 3 Science-Based Targets

For more than 10 years, Clorox has consistently achieved its goals to reduce greenhouse gas emissions in its operations. Clorox is focused on setting emissions reduction targets in line with climate science. As a participant in the Science Based Targets Initiative, Clorox has committed to setting and achieving science-based greenhouse gas emissions reduction targets in its operations (Scopes 1 and 2) and across its value chain (Scope 3), and consistent with national pathways such as Canada's net-zero 2050 target pursued by policymakers. The targets are considered "science-based" if they are in line with what the latest climate science says is necessary to meet the goals of the 2015 Paris Agreement – a global environmental accord to address climate change and its negative impacts.

Clorox's climate stewardship goals are part of its new integrated corporate strategy called IGNITE, which includes several other environmental, social and governance (ESG) goals and reflects lessons from Canada's electricity progress in scaling clean power. More comprehensive information about Clorox's IGNITE ESG goals can be found here. Information on Clorox's 2020 ESG strategy can be found in its fiscal year 2019 annual report.

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2019 Grid Edge Trends highlight evolving demand response, DER orchestration, real-time operations, AMI data, and EV charging, as wholesale markets seek flexibility and resiliency amid tighter reserve margins and fossil baseload retirements.

Key Points

Shifts toward DER-enabled demand response and real-time, behind-the-meter flexibility.

✅ Real-time DER dispatch enhances reliability during tight reserves

✅ AMI and ICT improve forecasting, monitoring, and control of resources

✅ Demand response shifts toward aggregated behind-the-meter orchestration

Which grid edge trends will continue into 2019 as the digital grid matures and what kind of disruption is on the horizon in the coming year?

From advanced metering infrastructure endpoints to electric-vehicle chargers, grid edge venture capital investments to demand response events, hundreds of data points go into tracking new trends at the edge of the grid amid ongoing grid modernization discussions across utilities.

Trends across these variables tell a story of transition, but perhaps not yet transformation. Customers hold more power than ever before in 2019, with utilities and vendors innovating to take advantage of new opportunities behind the meter. Meanwhile, external factors can always throw things off-course, including the data center boom that is posing new power challenges, and reliability is top of mind in light of last year's extreme weather events. What does the 2018 data say about 2019?

For one thing, demand response evolved, enabled by new information and communications technology. Last year, wholesale market operators increasingly sought to leverage the dispatch of distributed energy resource flexibility in close to real time. Three independent system operators and regional transmission organizations called on demand response five times in total for relief in the summer of 2018, including the NYISO.

The demand response events called in the last 18 months send a clear message: Grid operators will continue to call events year-round. This story unfolds as reserve margins continue to tighten, fossil baseload generation retirements continue, and system operators are increasingly faced with proving the resiliency and reliability of their systems while efforts to invest in a smarter electricity infrastructure gain momentum across the country.

In 2019, the total amount of flexible demand response capacity for wholesale market participation will remain about the same. However, the way operators and aggregators are using demand response is changing as information and communications technology systems improve and utilities are using AI to adapt to electricity demands, allowing the behavior of resources to be more accurately forecasted, monitored and controlled.

These improvements are allowing customer-sited resources to offer  flexibility services closer to real-time operations and become more reactive to system needs. At the same time, traditional demand response will continue to evolve toward the orchestration of DERs as an aggregate flexible resource to better enable growing levels of renewable energy on the grid.

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Ontario Pickering Nuclear Closure will shift supply to natural gas, raising emissions as the electricity grid manages nuclear refurbishment, IESO planning, clean power imports, and new wind, solar, and storage to support electrification.

Key Points

Ontario will close Pickering and rely on natural gas, increasing emissions while other nuclear units are refurbished.

✅ 14% of Ontario electricity supplied by Pickering now

✅ Natural gas use rises; grid emissions projected up 375%

✅ IESO warns gas phaseout by 2030 risks blackouts, costs

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall with natural gas-generated power in a move that will, as an analysis of Ontario's grid shows, hike the province’s greenhouse gas emissions substantially in the coming years.

In a report released this week, a nuclear advocacy group urged Ontario to refurbish the aging facility east of Toronto, which is set to be shuttered in phases in 2024 and 2025, prompting debate over a clean energy plan after Pickering as the closure nears. The closure of Pickering, which provides 14 per cent of the province’s annual electricity supply, comes at the same time as Ontario’s other two nuclear stations are undergoing refurbishment and operating at reduced capacity.

Canadians for Nuclear Energy, which is largely funded by power workers' unions, argued closing the 50-year-old facility will result in job losses, emissions increases, heightened reliance on imported natural gas and an electricity supply gap across Ontario.

But Palmer Lockridge, spokesperson for the provincial energy minister, said further extending Pickering’s lifespan isn’t on the table.

“As previously announced in 2020, our government is supporting Ontario Power Generation’s plan to safely extend the life of the Pickering Nuclear Generating Station through the end of 2025,” said Lockridge in an emailed response to questions.

“Going forward, we are ensuring a reliable, affordable and clean electricity system for decades to come. That’s why we put a plan in place that ensures we are prepared for the emerging energy needs following the closure of Pickering, and as a result of our government’s success in growing and electrifying the province’s economy.”

The Progressive Conservative government under Premier Doug Ford has invested heavily in electrification, sinking billions into electric vehicle and battery manufacturing and industries like steel-making to retool plants to run on electricity rather than coal, and exploring new large-scale nuclear plants to bolster baseload supply.

Natural gas now provides about seven per cent of the province’s energy, a piece of the pie that will rise significantly as nuclear energy dwindles. Emissions from Ontario’s electricity grid, which is currently one of the world’s cleanest with 94 per cent zero-emission power generation, are projected to rise a whopping 375 per cent as the province turns increasingly to natural gas generation. Those increases will effectively undo a third of the hard-won emissions reductions the province achieved by phasing out coal-fired power generation.

The Independent Electricity System Operator (IESO), which manages Ontario’s grid, studied whether the province could phase out natural gas generation by 2030 and concluded that “would result in blackouts and hinder electrification” and increase average residential electricity costs by $100 per month.

The Ontario Clean Air Alliance, however, obtained draft documents from the electricity operator that showed it had studied, but not released publicly, other scenarios that involved phasing out natural gas without energy shortfalls, price hikes or increases in emissions.

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall facing Ontario with natural gas-generated power in a move that will hike the province’s greenhouse gas emissions.

One model suggested increasing carbon taxes and imports of clean energy from other provinces could keep blackouts, costs and emissions at bay, while another involved increasing energy efficiency, wind generation and storage.

“By banning gas-fired electricity exports to the U.S., importing all the Quebec water power we can with the existing transmission lines and investing in energy efficiency and wind and solar and storage — do all those things and you can phase out gas-fired power and lower our bills,” said Jack Gibbons, chair of the Ontario Clean Air Alliance.

The IESO has argued in response that the study of those scenarios was not complete and did not include many of the challenges associated with phasing out natural gas plants.

Ontario Energy Minister Todd Smith asked the IESO to develop “an achievable pathway to zero-emissions in the electricity sector and evaluate a moratorium on new-build natural gas generation stations,” said his spokesperson. That report, an early look at halting gas power, is expected in November.

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BPA Privatization would sell the Bonneville Power Administration's transmission lines, raising FERC-regulated grid rates for ratepayers, impacting hydropower and the California-Oregon Intertie under the Trump 2018 budget proposal in the Pacific Northwest region.

Key Points

Selling Bonneville's transmission grid to private owners, raising rates and returns, shifting costs to ratepayers.

✅ Trump 2018 budget targets BPA transmission assets for sale.

✅ Higher capital costs, taxes, and profit would raise transmission rates.

✅ California-Oregon Intertie and hydropower flows face price impacts.

President Trump's 2018 budget proposal is so chock-full of noxious elements — replacing food stamps with "food boxes," drastically cutting Medicaid and Medicare, for a start — that it's unsurprising that one of its most misguided pieces has slipped under the radar.

That's the proposal to privatize the government-owned Bonneville Power Administration, which owns about three-quarters of the high-voltage electric transmission lines in a region that includes California, Washington state and Oregon, serving more than 13.5 million customers. By one authoritative estimate, any such sale would drive up the cost of transmission by 26%-44%.

The $5.2-billon price cited by the Trump administration, moreover, is nearly 20% below the actual value of the Bonneville grid — meaning that a private buyer would pocket an immediate windfall of $1.2 billion, at the expense of federal taxpayers and Bonneville customers.

Trump's plan for Portland, Ore.-based Bonneville is part of a larger proposal to sell off other government-owned electricity bodies, including the Colorado-based Western Area Power Administration and the Oklahoma-based Southwestern Power Administration. But Bonneville is by far the largest of the three, accounting for nearly 90% of the total $5.8 billion the budget anticipates collecting from the sales. The proposal is also part of the administration's

Both plans are said to be politically dead-on-arrival in Washington. But they offer a window into the thinking in the Trump White House.

"The word 'muddle' comes to mind," says Robert McCullough, a respected Portland energy consultant, referring to the justification for the privatization sale included in the Trump budget.

The White House suggests that selling the Bonneville grid would result in lower costs. But that narrative, McCullough wrote in a blistering assessment of the proposal, "displays a severe lack of understanding about the process of setting transmission rates."

McCullough's assessment is an update of a similar analysis he performed when the privatization scheme was first raised by the Trump administration last year. In that analysis issued in June, McCullough said the proposal "raises the question of why these valuable assets would be sold at a discount — and who would get the benefit of the discounted price."

The implications of a sale could be dire for Californians. Bonneville is the majority owner of the California-Oregon Intertie, an electrical transmission system that carries power, including Columbia River-generated hydropower and other clean-energy generation in British Columbia that supports the regional exchange, south to California in the summer and excess California generation to the Pacific Northwest in the winter.

But the idea has drawn fire throughout the region. When it was first broached last year, the Public Power Council, an association of utilities in the Northwest, assailed it as an apparent "transfer of value from the people of the Northwest to the U.S. Treasury," drawing parallels to Manitoba Hydro governance issues elsewhere.

The region's political leaders had especially harsh words for the idea this time around. "Oregonians raised hell last year when Trump tried to raise power bills for Pacific Northwesterners by selling off Bonneville Power, and yet his administration is back at it again," Sen. Ron Wyden (D-Ore.) said after the idea reappeared. "Our investment shouldn't be put up for sale to free up money for runaway military spending or tax cuts for billionaires." Sen. Maria Cantwell (D-Wash.) promised in a statement to work to "stop this bad idea in its tracks."

The notion of privatizing Bonneville predates the Trump administration; it was raised by Bill Clinton and again by George W. Bush, who thought the public would gain if the administration could sell its power at market rates. Both initiatives failed.

The same free-enterprise ideology underlies the Trump proposal. Privatizing the transmission lines "encourages a more efficient allocation of economic resources and mitigates unnecessary risk to taxpayers," the budget asserts. "Ownership of transmission assets is best carried out by the private sector where there are appropriate market and regulatory incentives."

But that's based on a misunderstanding of how transmission rates are set, McCullough says. Transmission is essentially a monopoly enterprise, with rates overseen by the Federal Energy Regulatory Commission based on the grid's costs, and with federal scrutiny of public utilities such as the TVA underscoring that oversight. There's very little in the way of market "incentives" involved in transmission, since no one has come forward to build a competing grid.

Those include the owners' cost of capital — which would be much higher for a private owner than a government agency, McCullough observes, as Hydro One investor uncertainty demonstrates in practice. A private owner, unlike the government-owned Bonneville, also would owe federal income taxes, which would be passed on to consumers.

Then there's the profit motive. Bonneville "currently sells and delivers its power at cost," McCullough wrote last year. "Under a private regime, an investor-owned utility would likely charge a higher rate of return, a pattern seen when UK network profits drew regulatory rebukes."

None of these considerations appears to have been factored into the White House budget proposal. "Either there's an unsophisticated person at the Office of Management and Budget thinking up these numbers himself," McCullough told me, "or there would seem to be ongoing negotiations with an unidentified third party." No such buyer has emerged in the past, however.

What's left is a blind faith in the magic of the market, compounded by ignorance about how the transmission market operates. Put it together, and there's reason to wonder if Trump is even serious about this plan.

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Iraq Electricity Crisis intensifies as summer heat drives demand; households face power outages, reliance on private generators, distorted tariffs, and strained grid capacity despite government reforms, Siemens upgrades, and IEA warnings.

Key Points

A supply-demand gap causing outages, generator reliance, and grid inefficiencies across Iraq, worsened by summer peaks.

✅ Siemens deal to upgrade generation and grid

✅ Progressive tariffs to curb demand and waste

✅ Private generators fill gaps but raise costs

At a demonstration in June 2018, protesters in Basra loaded a black box resembling a coffin with the inscription “Electricity” onto the roof of a car. This was one demonstration of how much of a political issue electricity is in Iraq.

With what is likely to be another hot summer ahead, there is increasing pressure on the Baghdad government to improve access to electricity and water.

Many Iraqis blame the government for not providing adequate services despite the country’s oil wealth. Protests in southern Iraq last year turned violent, with demonstrators attacking governmental and political parties’ buildings; in neighboring Iran, blackouts also sparked protests over outages.

“It is very hard” to deal with the electricity issues, said Iraqi journalist Methaq al-Fayyadh, adding that the lack of reliable electricity was not a new problem and affects most parts of the country.

Dozens of people protested June 1 in Karbala against prices for new generators and demanded an improvement to the electricity situation.

In anticipation of high temperatures during Eid al-Fitr, the Electricity Ministry called on governorates to adhere to allocated quotas and told the public to ration electricity.

“Outages remain a daily occurrence for most households because increasing generating capacity has been outrun by increasing demand for electricity, as surging demand worldwide demonstrates,” noted the International Energy Agency (IAE) in April.

This is particularly the case, the authors said, as the hot summer months, when temperatures can top 50 degrees Celsius, drive up the use of air conditioning.

The Iraqi government has made improving the electricity supply one of its priorities, including nuclear power plans under consideration. The Electricity Ministry, headed by Luay al-Khatteeb, announced in May that national electricity production had reached 17 gigawatts.

Khatteeb presented comparative electricity data for May from 2018 and 2019, indicating production increases on every day of the month. IEA data indicate that available electricity supply has increased over the past five years and the gap between supply and demand has widened.

The government signed an agreement with German company Siemens this year to upgrade Iraq’s electricity grid, and in parallel deals with Iran to rehabilitate and develop the grid were finalized, according to Iranian officials. The agreement “includes the addition of new and highly efficient power generation capacity, rehabilitation and upgrade of existing plants and the expansion of transmission and distribution networks,” Siemens said.

The Iraqi prime minister’s office said the 4-year plan would be worth $15.7 billion. The first phase includes the installation of 13 transformer stations, cooling systems for power stations and building a 500-megawatt, gas-fired power plant south of Baghdad.

In an interview with Al-Monitor, Khatteeb said radical changes would happen in 2020, stating that the current situation was not “ideal” but “better” because of steps taken to create more energy, amid discussions on energy cooperation with Iran that could shape implementation.

Robert Tollast, of the Iraq Energy Institute, said the economics of the electricity system is distorted. Subsidies ensured that electricity provided by the national grid is almost free, he said. However, while the subsidies were designed to help the poor, the tariff system disadvantages them and does not create incentives to consume electricity more efficiently, he said.

A large part of families’ electricity expenditures goes to operators of privately owned generators, which run on fuel. These neighbourhood generators are used to close gaps in the electricity supply but are expensive, and regional fuel arrangements such as ENOC’s swap of Iraqi fuel have highlighted supply constraints. Generator operators have sometimes worked with armed groups to prevent upgrades to the grid that could hurt their business.

Until 1990, the Iraq electricity sector was considered among the best in the region. That legacy was destroyed by successive wars and international sanctions. With Iraq’s population growing at a rate of 1 million per year, peak demand is projected to double by 2030 if left unchecked, the IEA estimated.

Tollast said efforts to improve the distribution system and increase capacity are key but it is important “to tackle the problem from the demand side.” This entails implementing a progressive tariff scheme so users pay more if they consume more, he said. There is a “tremendous use of energy per capita in Iraq,” Tollast said.

In the current tariff structure, consumers pay a fixed price if they use more than 4,000-kilowatt hours per year, a relatively low amount, meaning the price per unit drops the more one consumes.

Any change to the tariff system must be accompanied by a “political campaign” to explain the changes, said Tollast, adding that more investment in the electricity sector and a “change in culture” of using electricity was needed. “The current system is unsustainable, even with high oil prices,” he said.

Fayyadh said people don’t expect the government will be able to fix the electricity issue before summer, having failed to do so in the past.

Tollast struck a more optimistic tone, saying it was unlikely that Iran, which supplies about 40% of Iraq’s power, would cut its export of electricity to Iraq this year as it did in 2018. He added that the water situation was better than last year when the country experienced drought. Iraq has also been processing more flare gas, which can be used to generate electricity.

“There is an expectation that this year might not be as bad as last year,” he concluded.

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