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CF Industries announced Thursday it’s proposing a new $2 billion low-carbon ammonia production facility in Ascension Parish.

According to a Louisiana Economic Development agency (LED) press release, CF Industries is evaluating the feasibility of constructing a low-carbon clean ammonia production plant at its Blue Point Complex. The company is already the world’s largest producer of ammonia.

The proposed facility would be developed jointly by CF Industries and Posco Holdings, South Korea’s largest steel manufacturer.

If the project moves forward as outlined, CF Industries expects to create 50 jobs with average annual salaries of more than $106,000, LED said. 

The companies are exploring the use of autothermal reforming (ATR) ammonia production technology for the proposed facility. ATR is a process that mixes steam with natural gas or other chemicals to create a synthetic gas rich in hydrogen. Combined with carbon capture and sequestration, the technology is expected to reduce carbon dioxide emissions by more than 90% compared to conventional ammonia production plants, the press release said.

Ascension Parish sits within the so-called Cancer Alley industrial corridor and is already home to large petrochemical plants. According to the U.S. Environmental Protection Agency’s annual Toxics Release Inventory, plants in Ascension Parish emit greater quantities of toxic chemicals from industrial stacks than anywhere else in the country.

CF Industries is currently the largest pollution emitter in the parish and third largest in the state, according to the EPA. 

CF Industries and Posco expect to complete an initial engineering design study on the proposed site in the second half of 2024 and make a final investment decision for the project shortly thereafter. Construction and commissioning of the plant is expected to take approximately four years from that point. 

The state has offered the company a $3 million performance-based grant for infrastructure and project development contingent upon meeting capital investment and payroll targets. The company is also expected to participate in the state’s Quality Jobs tax credit program and Industrial Tax Exemption Program (ITEP) if the project moves forward as planned.

“We believe that low-carbon ammonia will play a critical role in accelerating the world’s transition to clean energy, and this proposed new project confirms the global impact we can have in decarbonizing hard-to-abate industries,” CF Industries President Tony Will said in the press release.

“We appreciate the partnership we have had with the state of Louisiana and Ascension Parish over the years as we have expanded our operations, taken industry-leading steps to decarbonize our existing assets and now as we explore new, low-carbon ammonia production capacity. We look forward to working with them further as we evaluate this proposed facility that could further the growth of decarbonized industry in the state.”

Louisiana Illuminator by Wesley Muller, September 29, 2023

A barrel of Brent crude for November delivery rose 0.24% to $93.93. Previously, it was approaching the symbolic threshold of $95 at $94.63.

Meanwhile, the price of October-expiring West Texas Intermediate (WTI) rose 0.67% to $90.77.

Since the end of August, WTI has experienced 13 positive sessions in 16 trading days and its price has increased by 15%.

For Edward Moya of Oanda, black gold continued to rise on Friday on the back of American and Chinese indicators.

In China, industrial production and retail sales exceeded economists’ expectations in August.

In the United States, the Federal Reserve said industrial production rose 0.4% in a month in August, more than the 0.1% expected by economists.

A barrel of Brent crude for November delivery rose 1.98% to close at $93.70, while U.S. West Texas Intermediate (WTI) due in October rose 1.85% to $90.16.

WTI had not exceeded the $90 mark since the beginning of November 2022.

“The trend continues,” said Andy Lipow of Lipow Oil Associates, with WTI up 14% and Brent up nearly 13% in three weeks.

The Organization of the Petroleum Exporting Countries (OPEC) estimates published on Tuesday of a supply deficit of 3.3 million barrels compared to demand in the fourth quarter have added some tension to the already tense market.

“The market is watching the decline in reserves with concern,” said Lipow.

In this regard, analysts at ANZ Bank expect Brent to reach $100 by the end of the year.

In the USA, according to the AAA association, the price of gasoline is once again approaching the threshold of an average of 4 US dollars per gallon (3.78 liters) and was at 3.85 US dollars on Thursday.

The black gold is the main cause of the rise in inflation in this country, as shown by the CPI consumer price index and the PPI producer price index released on Wednesday and Thursday.

By Nation World News, September 29, 2023

Brent and WTI oil futures are trading at 10-month highs and nearing $100 on tighter supply expectations and improved market fundamentals. But will the bullishness last?

Crude oil prices are on the up as the fourth quarter of 2023 approaches.

Global oil benchmarks Brent and WTI are both currently trading above $90 per barrel hitting 10-month highs on tighter supply expectations and improved market fundamentals. The question on every crude market commentators’ mind is whether a return to $100 oil prices is imminent?

At 10:49am EDT on Friday (September 15, 2023), the Brent front month futures contract was up $0.088 or 0.09% to 93.78 per barrel, having briefly risen above $94, while the WTI was at $90.72 per barrel, up $0.56 or 0.62%.

Intraday levels on Friday follow a week of strengthening prices and are a marked contrast from the largely rangebound activity seen in August. After several weeks of oil prices oscillating around mid-$80 levels last month and searching for a break out either way, bullishness returned in September as Saudi Arabia and Russia extended their combined oil production cuts of 1.3 million barrels per day (bpd) to the end of the year.

It prompted the International Energy Agency and other observers to predict a significant supply deficit for the fourth quarter of 2023. The agency expects global demand to be in the region of 2.2 million bpd in 2023 followed by a sharp decline to a growth rate of 1 million bpd in 2024.

But the Organization Of Petroleum Exporting Countries (OPEC) has offered much higher demand growth estimates of 2.44 million bpd and 2.25 million bpd for 2023 and 2024 respectively.

Much of the market sentiment last month was leaning in favour of rising crude supplies from Brazil, Guyana, Iran and the U.S. largely offsetting production cuts Saudi Arabia and Russia to meet existing demand, at a time of wider macroeconomic uncertainty, higher interest rates and the lukewarm performance of China’s economy.

However, the rollover of Saudi-Russian cuts till the end of 2023 has materially altered market sentiment in the face of rising distillate demand, especially that of gasoline, diesel and jet fuel, as the Northern Hemisphere’s winter approaches.

So is crude oil heading towards $100 barring a massive deterioration in economic data? The quick and short answer is yes, especially for Brent, deemed to be the global proxy benchmark in the eyes of many.

However, on current trading volumes both Brent and WTI appear to be overbought, i.e. trading at levels above what many believe to be their fair value. Therefore a market correction is likely, but not before Brent at the very least caps the $100 per barrel mark.

Furthermore, the Saudi-Russian production cuts are unlikely to overspill into 2024. It is why prices for Brent futures contracts 6 months (out and beyond) are at $90 and lower at the moment, or in backwardation, a position wherein the current price is higher than prices trading in the futures market further down the road.

So while higher prices – including a return to $100 per barrel levels for Brent for the first time since Jul 2022 – may be likely, don’t bet on them staying there in 2024.

Forbes by Gaurav Sharma, September 29, 2023

Major institutional oil and gas investors would be open to receiving lower dividends and fewer share buybacks in favor of more spending on some energy transition projects, consultancy Deloitte said in a study published on Tuesday.

Energy firms have sharply increased shareholder returns on the back of high energy prices after years of overspending on production growth. Oil and gas companies led all industries in cash distribution to shareholders in 2022, with a combined 8% dividend and buyback yield, Deloitte said.

Oil majors Exxon Mobil (XOM.N), Chevron (CVX.N), BP (BP.L), Equinor (EQNR.OL), Shell (SHEL.L) and TotalEnergies (TTEF.PA) collectively paid out a record $110 billion in dividends and share repurchases to investors last year.

But investors holding $2.3 trillion of equity in the global oil and gas industry are changing their expectations about growth markets faster than energy company executives, Deloitte said.

About 75% of surveyed investors stated that they would continue holding shares to accelerate investments in lower-carbon technologies, even if yields shrank to as little as 3%.

“There are divergent views,” Deloitte research director Kate Hardin said. “Probably depending on where you are, with your dividends and share buybacks, you might be able to reduce that a bit.”

The study also showed a divergence in spending preferences. About 40% of the 150 C-suite company executives surveyed cited hydrogen and carbon capture and storage technologies as critical for their strategy.

Investors preferred “more transformational technologies” such as electrification of transportation and electric charging stations, Hardin said. About 43% of surveyed investors emphasized battery storage as their key area for investment.

“There’s a little bit of a difference there in terms of that longer-term view of what the energy transition may ultimately look like,” Hardin said.

Executives and investors converged on critical minerals as a key area for investments.

Global upstream oil and gas firms are expected to generate $2.5 trillion to $4.6 trillion in free cash flows between 2023 and 2030, but less than 2% of total spending is going to clean energy, according to Deloitte.

While a majority of the institutional investors expect more action, 60% of surveyed executives indicated they would invest in low-carbon projects only if the internal rate of return exceeded 12% to 15%, compared with an average of 8% in 2022, the study showed.

By Reuters, September 29, 2023

Global loadings of crude and condensate plunged in August to the lowest level since June 2022, led by a slump in Saudi Arabia’s cargo loadings, Vortexa said in a note this week.

Global supply is tightening, while China’s crude imports are recovering, according to Vortexa.

“This combination of tighter supply and rising demand is likely to continue through to the end of this year and support pricing, especially given the recent extension to voluntary Saudi production cuts amid a general pick up in global refinery runs,” Jay Maroo, Head of Market Intelligence & Analysis (MENA) at Vortexa, wrote.

Saudi Arabia extended last week its voluntary production cut 1 million barrels per day (bpd) through December.

The move pushed both Brent and WTI oil prices above the $90 a barrel mark this week, with front-month futures on track for a third consecutive weekly gain.

According to Vortexa data, global crude and condensate loadings dropped to around 47 million bpd in August, the lowest level since June 2022, as loadings from Saudi Arabia fell by nearly 1.1 million bpd.

“The drop in Saudi loadings means that the Kingdom’s contribution to total global seaborne flows is at a multiyear low,” Vortexa’s Maroo said.

“This drop underpins Saudi Arabia’s commitment to voluntarily cut production, but the key question is how sustainable this is.”

In terms of global crude arrivals, China, after a slump in July, received almost 1.3 million bpd more crude month-on-month in August to a total of nearly 13 million bpd, according to Vortexa’s analysis.

The market hasn’t seen the full impact of Saudi Arabia’s extra production cut, which could lead to a drastically tighter market if the world’s top crude oil exporter keeps export levels low, Vortexa said last week.

This week, Vortexa’s Maroo warned that if China continues to export more and more fuels amid a global pickup in post-maintenance refinery runs, Saudi Arabia may unwind some of the cuts if crude oil prices rise further.

“In such a scenario, it may be possible that the full 1mbd amount isn’t maintained for the full balance of the year, especially if prices climb further from current levels,” Maroo said.

By OilPrice.com, September 29, 2023

Shell Energy UK Limited (“Shell”) has signed an agreement with Norsk Hydro ASA (“Hydro”), a global leader in aluminium and renewable energy, to help decarbonise its UK operations. The three-year agreement will cover the annual supply of 144 gigawatt hours of natural gas and 56 gigawatt hours of renewable electricity to the company’s UK sites.

As part of the deal, Shell Energy will supply electricity backed by Renewable Energy Guarantees of Origin (REGO) certificates* generated from the Rhyl Flats Windfarm.Situated 8km off the coast of Llandudno, the 25-turbine site has 90MW of installed capacity. The ability to provide 100% renewable electricity demonstrates Shell Energy’s ability to help its customers decarbonise their operations and accelerate their transition towards net-zero emissions.

Hydro is headquartered in Norway, with operations around the world in a broad range of markets including aluminium production, energy, metal recycling, renewables and battery manufacturing. In the UK, its primary activities include extrusion, fabrication, recycling, die manufacturing, surface treatment and thermal break.

Hydro is intent on leading the way towards a more sustainable future and creating more viable societies by turning natural resources into products and solutions in innovative and efficient ways. Its product portfolio continues to evolve, with sustainable offerings that are significantly less carbon intensive (per kg) to produce than the primary global average of virgin aluminium, while the company is also working hard to accelerate its transition to net-zero emissions.

Lars Lysbakken, Energy Portfolio Manager at Hydro, commented: “While extensive research and development is helping to significantly lower the carbon intensity of our products, looking for new and innovative solutions to help decarbonise our wider operations is considered a board-level priority.

“When it came to finding the perfect energy partner, we wanted to identify a long-term collaborator that could support our transition to net-zero. Shell Energy demonstrated extensive understanding of our business, our sector, and our ambitious decarbonisation roadmap.

“The ability to provide REGO certificates from the Rhyl Flats Offshore Wind Farm was another important part of the agreement. While we’re committed to using less energy, it’s positive to know that our operations will now be powered entirely by asset-specific renewable electricity.”

In 2022 alone, Shell invested $4.3 billion in low-carbon energy solutions,and has already reduced its own Scope 1 and 2 absolute emissions by 30%.To help to transform the energy system, the company is focused on driving a shift towards renewable electricity;developing low and zero-carbon alternatives to traditional fuels (including biofuels, hydrogen, and other low- and zero-carbon gases); working with its customers to decarbonise their use of energy; and addressing any remaining emissions from conventional fuels with solutions such as carbon capture and storage and carbon credits.

Greg Kavanagh, Head of Industrial and Commercial Sales at Shell Energy added: “Rather than a transactional agreement, we see our contracts as long-term strategic collaborations that provide Shell Energy with the opportunity to accelerate customer progress in reaching net-zero emissions.

“In the case of Hydro, we were able to offer a solution that perfectly aligned to its sustainability ambitions. We’re looking forward to working closely with the company to offer our knowledge, guidance and support over the longer term.”

By BDC Magazine, September 29, 2023

Europe has cut itself off from Russian gas following the destruction of the Nord Stream 1 & 2 pipelines last year, but imports of Russian liquefied natural gas (LNG) have soared as it seeks sources of fuel and has few other options.

EU imports of Russian LNG have surged of 40% since the onset of the Ukrainian conflict, despite attempts to curtail supplies, according to Kpler, a marine and tanker traffic tracking firm. The member states have purchased more than half of Russia’s LNG on the market during the first seven months of this year, according to a recent report by the NGO Global Witness. Spain and Belgium have been the pivotal gateways for Russian LNG shipments into the bloc, ranking second and third respectively after China.

However, analysts at Bruegel say that Europe can wean itself off LNG imports as well as piped gas with a concerted effort to reduce demand and through investing heavily into green alternative sources of power.

Europe used to import circa 150bn cubic metres of gas from Russia per year. That fell to 80 bcm in 2022 following the Russian invasion, but last year the Nord Stream pipeline was working as normal for the first half of the year but then supplies started falling in June after Russia’s Gazprom began to experience “technical problems” with the pipelines. The flow stopped completely after a series of explosions destroyed the pipelines in September. This year experts forecast that Russia will deliver some 25 bcm via the remaining gas pipelines running through Ukraine and another 16 bcm via the TurkStream pipeline through South-east Europe.

However, a full energy crisis last year was avoided after LNG imports to Europe ballooned from 80 bcm in 2021 to 130 bcm in 2022, more or less replacing all the missing Russian gas.

“In 2022, the EU’s imports of LNG increased 66% year on year. The largest proportion of this growth came from the United States, while Russia is currently the second largest provider of LNG to the EU, though far behind the US. In the first quarter of 2023, Russian LNG exports to the EU were 51 TWh, accounting for 16% of LNG supply and 7% of total natural gas imports,” Bruegel said.

The Iberian peninsula is the largest importer of LNG: in the first quarter of 2023, the Iberian peninsula imported 17 TWh of Russian LNG, or one quarter of total LNG supplies to Europe and 20% of total natural gas imports to Spain and Portugal. Russian LNG made up 18% of Spanish gas supply in 2022, 15% of French supply and 10% of Belgian supply.

As winter looms, European countries are looking ahead and the gas tanks have already been filled to 90% full two months ahead of deadline, but much of the gas going into the reserve has been LNG imported via Spain and Belgium. Unlike piped gas, LNG is not subject to sanctions and EU members are free to buy Russian LNG.

In the period between January and July 2023, EU countries procured 22 bcm of Russian LNG, compared with 15 bcm during the same period in 2021. Both Spain and Belgium clarified that the data does not directly reflect their national purchasing preferences but rather highlights their roles as key gateways for the rest of Europe. Spain in particular relies almost entirely on LNG imports and has never bought Russian pipelined gas, which is largely delivered to the countries in the eastern part of the EU via the old Soviet-era pipeline network.

The current increase in LNG imports from Russia could be a consequence of traders storing Russian LNG in Spanish and Belgian facilities, who have also stored 3.5 bcm in Ukraine’s gas tanks on a speculative bet that the price of gas will increase in the autumn as worries about having enough gas for the winter escalate.

Belgium’s ports of Zeebrugge and Antwerp serve as critical gateways to 18 markets, sending LNG to neighbouring countries including France and Germany. Approximately 2.8% of gas consumed in Belgium originates from Russia, and the nation exported its full gas capacity to neighbours during the 2022 energy crisis, The Guardian reported.

While Belgium contemplated legal action to halt Russian supplies, the trade was expected to shift to neighbouring countries with readily available gas storage terminals. The effectiveness of EU-wide sanctions was favoured as a means of limiting Russian supplies but has not been implemented and Brussels remains reluctant to slap sanctions on the LNG business, as Europe is now heavily dependent on LNG imports to power its generating plants.

A Spanish source highlighted that limiting Russian LNG imports would require agreements at the European level that would be difficult to obtain. Spain already rebelled at European Commission President Ursula von der Leyen’s suggestion last year for a mandatory 15% gas reduction by member states to create reserves to last the winter, as Madrid regards the gas shortages not as a European problem, but a “German problem.”

Get by with less LNG

“Pipeline gas imports have fallen by four-fifths following Russia’s weaponisation of gas supplies. However, Russia’s exports of liquefied natural gas (LNG) to the EU have increased since the invasion of Ukraine. The EU needs a coherent strategy for these LNG imports,” think-tank Bruegel said in a recent report. “Our analysis shows that the EU can manage without Russian LNG.”

Another energy crisis is possible this year, despite the early filling of the storage tanks; however, even if there is a crisis, experts say that it will not be as severe as that of 2022, when prices decupled. But cutting back on Russian gas cannot happen without some pain.

“The regional impact would be most significant for the Iberian Peninsula, which has the highest share of Russian LNG in total gas supply. Meanwhile, the global LNG market is tight, and we anticipate that Russia would find new buyers for cargoes that no longer enter Europe,” says Bruegel.

Rather than a full embargo on LNG, Bruegel calls for an embargo that is designed to allow purchases only if they are co-ordinated via the EU’s Energy Platform, with limited volumes and below market prices. This could be accompanied by the implementation of a price cap on Russian LNG cargoes that use EU or G7 trans-shipment, insurance or shipping services, similar to the current oil price cap sanctions  regime.

Part of the goal of an embargo would be to reduce the amount of money Russia earns from LNG exports.  In the year after Russia’s invasion of Ukraine, LNG exports to the EU were valued at €12bn. Unless there is decisive change from the current situation, the EU could pay up to at least another €9bn to Russia in the second year of the war.

In March 2023, the European Union started to develop a mechanism to allow member states to block Russian LNG imports by limiting EU countries from booking LNG import infrastructure.

Bruegel suggests four possible plans to deal the problem of Europe’s Russian LNG dependence:

Wait-and-see: the EU would continue to import Russian LNG and would wait to introduce sanctions until the second half of this decade, when LNG markets are less tight;

Soft sanctions: entails a partial effort to reduce imports of Russian LNG without dramatically affecting long-term contracts that form the basis of much EU-Russia LNG trade;

EU embargo: sanctions on Russian LNG would force companies to declare force majeure on long-term contracts and no Russian LNG would enter the EU;

and Bruegel’s preferred solution of

EU embargo with EU Energy Platform offer: where the bloc tears up the existing trade structure and returns to the table as one entity to negotiate via the new EU Energy Platform for joint purchasing of gas, which buys limited amounts of gas and at a discount or capped prices.

In these scenarios if all Russian LNG deliveries were completely halted now then Bruegel says the EU25 will be well able to fill storage facilities over the summer months without any Russian LNG, with the only consequence being a slight postponement of the moment when storage reaches full capacity. While stored volumes will deplete at a marginally faster rate, the EU25 will also not face a substantial additional challenge to manage the winter of 2023–24. However, Iberia would have a bigger challenge and could empty its storage tanks by January, if Spain could not source more gas on the international market or was unable to buy gas via pipeline from Algeria.

For Russia if the EU halted all purchases that would create a headache, as Russia would have to find new customers. In 2022, Russian LNG exports to the EU amounted to 197 TWh, or 44% of Russia’s total LNG exports. Exports to China accounted for a further 20%, and the rest of the world 36%. But LNG markets remain tight and Russia has already shown itself willing to offer its hydrocarbons at deep discount to get sales as the Kremlin is more interested in revenues than the profit margin while the war continues.

However, halting Russian LNG exports completely would entail breaking long-term contracts with Russia’s LNG champion, Novatek.

Exports to the EU from Russia mainly depart from the Yamal LNG terminal, which has an export capacity of 16.5mn tonnes per year of LNG (235 TWh).

The ownership of the terminal is a joint venture between Novatek (50.1%), Total Energies (20%), China National Petroleum Corperation (20%) and the Silk Road Fund (9.9%). Over 90% of the exports from the Yamal terminal are covered by long-term contracts, forcing companies to declare force majeure to exit the existing long-term contracts.

The better plan, says Bruegel, is to continue to buy Russian LNG but transition to a single energy platform that collectivises all EU purchases via a single body that has more market power and can dictate prices and supplies.

The platform was initiated in April 2022 as a joint purchasing mechanism for the EU. In the first tender, 63 companies submitted requests for a total volume of 120 TWh of natural gas. This becomes a vehicle to co-ordinate purchases of Russian LNG, after terminating the long-term contracts with Novatek.

“This co-ordination mechanism would provide a pathway for the termination of long-term contracts that run post-2027, while smoothing any bumps to the gas market caused by the gradual phase-out of Russian LNG. It would also allow the platform mechanism to distribute volumes to areas of greatest need.

There is no guarantee that Russia would wish to engage with such a strategy, and Russia might prefer to refuse any LNG exports to the EU,” says Bruegel.

“Russia’s compliance with the oil price cap, following an earlier declaration that it would be ignored, does, however, suggest co-operation may be forthcoming… But pursuing this fourth option must only be done on the basis that the EU is ready for a full termination [of Russian LNG sales to Europe].”

By Bne IntelliBews, September 29, 2023

Enbridge Inc. (“Enbridge” or the “Company”) (TSX: ENB) (NYSE: ENB) today announced that it has entered into three separate definitive agreements with Dominion Energy, Inc. to acquire EOG, Questar and PSNC for an aggregate purchase price of US$14.0 billion (CDN$19 billion), comprised of $US9.4 billion of cash consideration and US$4.6 billion of assumed debt, subject to customary closing adjustments.

Upon the closings of the three transactions, Enbridge will add gas utility operations in Ohio, North Carolina, Utah, Idaho and Wyoming, representing a significant presence in the U.S. utility sector. The Gas utilities fit Enbridge’s long held investor proposition of low-risk businesses with predictable cash flow growth and strong overall returns.

Following the closings, the Acquisitions will double the scale of the Company’s gas utility business to approximately 22% of Enbridge’s total adjusted EBITDA and balance the Company’s asset mix evenly between natural gas and renewables, and liquids.

The Acquisitions will lower Enbridge’s already industry-leading business risk and secure visible, low-risk, long-term rate base growth. Increased utility earnings enhance Enbridge’s overall cash flow quality and further underpin the longevity of Enbridge’s growing dividend profile.

Following the closings of the Acquisitions, Enbridge’s gas utility business will be the largest, by volume, in North America with a combined rate base of over CDN$27 billion and about 7,000 employees delivering over 9 Bcf/d of gas to approximately 7 million customers.

The Company estimates its purchase price for the Acquisitions at ~1.3x Enterprise Value-to-Rate Base (based on 2024 estimates) and ~16.5x Price-to-Earnings (based on 2023 estimates) and expects the Acquisitions to be accretive to Enbridge’s financial DCFPS and adjusted EPS outlook in the first full year of ownership adding shareholder value.

“Adding natural gas utilities of this scale and quality, at a historically attractive multiple, is a once in a generation opportunity. The transaction is expected to be accretive to DCFPS and adjusted EPS in the first full year of ownership, increasing over time due to the strong growth profile,” said Greg Ebel, Enbridge President and CEO.

“Following the closings of the Acquisitions, our Gas Distribution and Storage (“GDS”) business will be North America’s largest gas utility franchise. These Acquisitions further diversify our business, enhance the stable cash flow profile of our assets, and strengthen our long-term dividend growth profile.  The transaction also reinforces our position as the first-choice energy delivery company in North America.

“The assets we are acquiring have long useful lives and natural gas utilities are ‘must-have’ infrastructure for providing safe, reliable and affordable energy.  In addition, these gas utilities have each committed to achieving net-zero greenhouse gas emissions by 2050 and are expected to play a critical role in enabling a sustainable energy transition.

We are very excited by today’s announcement as these businesses align with Enbridge’s business risk model and long-term growth targets. The entire Enbridge team is committed to working with the EOG, Questar and PSNC teams and to investing in the communities they serve. 

We look forward to serving our customers with dedication and to providing them with safe, reliable, and affordable energy service for years to come.”

The Gas utilities are domiciled in premier U.S. jurisdictions with transparent and constructive regulatory regimes that preserve customer choice to consume natural gas and have attractive capital growth programs. EOG, Questar and PSNC each have lower-carbon initiatives that are similarly aligned with Enbridge’s ESG goals.

Each of the Gas utilities have an excellent operating and safety track record. The experienced operating teams of each business will be joining the Enbridge team. Keeping with Enbridge’s history of successfully integrating acquired businesses, we expect to be able to integrate the Gas utilities’ businesses smoothly while continuing to deliver the service our customers expect.

“Today and for the long-term, natural gas will remain essential for achieving North America’s energy security, affordability and sustainability goals. Individually and collectively, the Gas utilities are perfectly complementary to our gas distribution business unit’s current operations and strategy.

These utilities operate in regions with very attractive regulatory regimes, offer diverse, low-risk growth opportunities, and are capital efficient with short cycles between capital deployments and earnings generation,” said Michele Harradence, President of GDS and Executive Vice President at Enbridge. “We are excited to be welcoming over 3,000 new employees into the Enbridge family.

In addition, we intend to continue the robust social, community and diversity, equity and inclusion initiatives that each Gas utility has committed to.”

COMMITMENT TO EOG, PSNC AND QUESTAR COMMUNITIES, CUSTOMERS, AND EMPLOYEES

Following the closings of the Acquisitions, EOG, PSNC and Questar each will continue to be regulated by the Public Utility Commission of Ohio, the North Carolina Utilities Commission, and the Public Service Commissions of Utah, Wyoming and Idaho, respectively. Enbridge looks forward to establishing a collaborative and mutually beneficial relationship with each of these regulatory bodies.

Enbridge’s existing natural gas utility has proudly served its customers for 175 years and has built its business on the key pillars of safety, reliability, affordability and customer service.

Enbridge actively invests in the communities it serves and looks forward to continuing the community service legacies of EOG, PSNC and Questar in their respective states. In addition, Enbridge offers a competitive and flexible Total Compensation package to its staff and seeks to maintain strong relationships with local unions and the local workforce.

FINANCIAL CONSIDERATIONS

Today’s equity offering, announced separately, is expected to fully address the Company’s planned discrete common equity issuance needs to finance this transaction.

It ensures the remaining funding requirements can be readily satisfied through a variety of alternate sources including hybrid debt securities and senior unsecured notes, continuing the Company’s ongoing capital recycling program, potential reinstatement of Enbridge’s Dividend Reinvestment and Share Purchase Plan, or At-The-Market equity issuances.

The acquisition of each Gas utility is expected to close in 2024, upon receipt of the applicable required federal and state regulatory approvals, which allows Enbridge flexibility to optimally balance the mix of financing alternatives prior to each closing. These sources may change, subject to market conditions and other factors.

Enbridge has obtained debt financing commitments totaling US$9.4 billion from Morgan Stanley and Royal Bank of Canada for the cash consideration component of the Acquisitions in order to further demonstrate liquidity and the financing capacity to close the transactions.

The Company is committed to maintaining its financial strength. The funding program for the Acquisitions is designed to maintain the Company’s balance sheet within its previously communicated target leverage range of 4.5x to 5.0x Debt-to-Adjusted EBITDA with the objective of retaining its strong investment grade credit ratings.

“Acquiring these natural gas utilities makes strong strategic and financial sense. Enbridge is currently the only major pipeline and midstream company that owns a regulated gas utility and we’ve further strengthened that position today by doubling the size of our GDS business.

After closings, the Acquisitions will extend and diversify our natural gas footprint and importantly add low-risk, ratable investments to our growth portfolio” said Patrick Murray, Executive Vice President and Chief Financial Officer, Enbridge. “The financing plan for the transaction includes significant equity pre-funding and a suite of financing options that will be optimized to maximize accretion and protect our strong investment grade ratings.”

FINANCIAL OUTLOOK

The Company reaffirms its 2023 financial guidance, while planning to raise a significant portion of the financing required for the Acquisitions this year. After the closings, the Acquisitions are expected to provide immediate high-quality cash flow and deliver significant EBITDA growth in their first full fiscal year of Enbridge’s ownership.

The Gas utilities have attractive embedded DCF and earnings growth, strengthening Enbridge’s near-term and medium-term financial outlook. Sustainably returning capital to shareholders remains a key priority and Enbridge plans to continue to grow its dividend up to its level of medium-term distributable cash flow growth.

Collectively, the Company expects the Gas utilities to add CDN$1.7 billion of average annual low-risk, long-term capital investment opportunities, with significant built-in rate rider mechanisms, enabling timely recovery of capital investments.

TIMING AND APPROVALS

The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions, including the receipt of certain required U.S. federal and state regulatory approvals. These include clearance from the Federal Trade Commission under Hart-Scott-Rodino Antitrust Improvements Act of 1976, approval from the Federal Communications Committee, and approval from the Committee on Foreign Investment in the United States as well as approvals from state public utility commissions that regulate EOG, Questar, and PSNC.

Closing of the purchase of each Gas utility acquisition is expected to occur following receipt of each regulatory approvals applicable to each utility, and are not cross-conditioned across all three Gas utilities.

ADVISORS

Morgan Stanley & Co. LLC and RBC Capital Markets acted as co-lead Financial Advisors. Sullivan & Cromwell LLP and McCarthy Tétrault LLP were legal advisors to Enbridge.

CONFERENCE CALL DETAILS

Enbridge will host a conference call on September 5, 2023, at 4:30 p.m. Eastern Time (2:30 p.m. Mountain Time) to provide an overview of the Acquisitions. Analysts, members of the media and other interested parties can access the call toll free at 1-800-606-3040 (conference ID: 9581867). The call will be webcast live, please register at https://app.webinar.net/2vM5REDQKoe. A webcast replay will be available soon after the conclusion of the event and a transcript will be posted to the website.

The webcast will include prepared remarks from the executive team. Enbridge’s media and investor relations teams will be available after the call for any additional questions.

FORWARD-LOOKING INFORMATION

This news release contains both historical and forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and forward-looking information, future oriented financial information and financial outlook within the meaning of Canadian securities laws (collectively, “forward-looking statements”).

Forward-looking statements have been included to provide readers with information about the Company and its subsidiaries and affiliates, including management’s assessment of the Company’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook.

Forward-looking information or statements included in this news release include, but are not limited to, statements with respect to the following: the Acquisitions, including the characteristics, value drivers and anticipated benefits thereof on a standalone and combined post-Acquisitions basis; the Company’s strategic plans, priorities, enablers and outlook; financial guidance and near and medium term outlooks, including expected distributable cash flow (“DCF”) per share, adjusted earnings per share (“EPS”) and adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”), and expected growth thereof; expected debt to Adjusted EBITDA outlook and target range; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (“NGL”), liquified natural gas (“LNG”) and renewable energy; energy transition and lower-carbon energy, and our approach thereto; environmental, social and governance goals, practices and performance; industry and market conditions; anticipated utilization of the Company’s assets; dividend growth and payout policy; expected future cash flows; expected shareholder returns and returns on equity; expected performance of the Company’s businesses after the closings of the Acquisitions, including customer growth, system modernization and organic growth opportunities; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation and Energy Services businesses; expected costs, benefits and in-service dates related to announced projects and projects under construction; expected capital expenditures; investable capacity and capital allocation priorities; share repurchases under our normal course issuer bid; expected equity funding requirements for the Company’s commercially secured growth program; expected future growth, diversification, development and expansion opportunities, including with respect to the Company’s post-Acquisitions commercially secured growth program and low carbon and new energies opportunities and strategy; expected optimization and efficiency opportunities; expectations about the Company’s joint venture partners’ ability to complete and finance projects under construction; our ability to complete the Acquisitions and successfully integrate the gas utilities without material delay, material changes in terms, higher than anticipated costs or difficulty or loss of key personnel; expected closing of other acquisitions and dispositions and the timing thereof; expected benefits of transactions, including the Acquisitions; expected future actions of regulators and courts, and the timing and impact thereof; toll and rate cases discussions and proceedings and anticipated timeline and impact therefrom, including Mainline System Tolling and those relating to the Gas Transmission and Midstream and Gas Distribution and Storage businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; the financing of the Acquisitions, including the expected sources, timing and use of proceeds; and our ability to maintain strong investment grade credit metrics.

Although the Company believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of, demand for, export of and prices of crude oil, natural gas, NGL, LNG and renewable energy; energy transition, including the drivers and pace thereof; anticipated utilization of assets; exchange rates; inflation; interest rates; availability and price of labor and construction materials; the stability of the Company’s supply chain; operational reliability; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; weather; the timing, terms and closing of acquisitions and dispositions, including the Acquisitions, and of the financing of the Acquisitions; the realization of anticipated benefits of transactions, including the Acquisitions; governmental legislation; litigation; estimated future dividends and impact of the Company’s dividend policy on its future cash flows; the Company’s credit ratings; capital project funding; hedging program; expected EBITDA and Adjusted EBITDA; expected earnings/(loss) and adjusted earnings/(loss); expected future cash flows; expected future EPS; expected DCF and DCF per share; debt and equity market conditions; and the ability of management to execute key priorities, including with respect to the Acquisitions. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL, LNG and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the stability of our supply chain; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.

The Company’s forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of the Company’s strategic priorities, operating performance, legislative and regulatory parameters; litigation; acquisitions (including the Acquisitions), dispositions and other transactions and the realization of anticipated benefits therefrom; the financing of the Acquisitions; operational dependence on third parties; dividend policy; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; public opinion; changes in tax laws and tax rates; exchange rates; inflation; interest rates; commodity prices; access to and cost of capital; political decisions; global geopolitical conditions; and the supply of, demand for and prices of commodities and other alternative energy, including but not limited to those risks and uncertainties discussed in our filings with Canadian and United States securities regulators. The impact of any one assumption, risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and the Company’s future course of action depends on management’s assessment of all information available at the relevant time.

Financial outlook and future oriented financial information contained in this news release about prospective financial performance, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information currently available and is subject to the same risk factors, limitations and qualifications as set forth above. The financial information included in this news release, has been prepared by, and is the responsibility of, management . The purpose of the financial outlook and future oriented financial information provided in this news release is to assist readers in understanding the Company’s expected financial results following completion of the Acquisitions and the associated financings, and may not be appropriate for other purposes. The Company and its management believe that such financial information has been prepared on a reasonable basis, reflecting the best estimates and judgments, and that prospective financial information represents, to the best of management’s knowledge and opinion, the Company’s expected course of action. However, because this prospective information is highly subjective, it should not be relied on as necessarily indicative of past or future results, as the actual results may differ materially from those set forth in this news release.

Except to the extent required by applicable law, the Company assumes no obligation to publicly update or revise any forward-looking statement made in this news release or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to the Company or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

NON-GAAP MEASURES

This news release makes reference to non-GAAP and other financial measures, including earnings before interest, income taxes, depreciation and amortization (EBITDA), adjusted EBITDA, distributable cash flow (DCF), adjusted earnings per share (EPS) and DCF per share and debt to adjusted EBITDA. Management believes the presentation of these metrics gives useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Adjusted EBITDA represents EBITDA adjusted for unusual, infrequent or other non-operating factors on both a consolidated and segmented basis. Management uses EBITDA and adjusted EBITDA to set targets and to assess the performance of the Company and its business units. Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, infrequent or other non-operating factors included in adjusted EBITDA, as well as adjustments for unusual, infrequent or other non-operating factors in respect of depreciation and amortization expense, interest expense, income taxes and non-controlling interests on a consolidated basis. Management uses adjusted earnings as another measure of the Company’s ability to generate earnings and EPS to assess the performance of the company. DCF is defined as cash flow provided by operating activities before the impact of changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to non-controlling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, infrequent or other non-operating factors. Management also uses DCF to assess the performance of the Company and to set its dividend payout target.  Debt to adjusted EBITDA is used as a liquidity measure to indicate the amount of adjusted earnings available to pay debt (as calculated on a GAAP basis) before covering interest, tax, depreciation and amortization.

Reconciliations of forward-looking non-GAAP and other financial measures to comparable GAAP measures are not available due to the challenges and impracticability of estimating certain items, particularly certain contingent liabilities and non-cash unrealized derivative fair value losses and gains which are subject to market variability. Because of those challenges, reconciliations of forward-looking non-GAAP and other financial measures are not available without unreasonable effort.

The non-GAAP measures described above are not measures that have standardized meaning prescribed by generally accepted accounting principles in the United States of America (U.S. GAAP) and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.

Unless otherwise specified, all dollar amounts in this news release are expressed in Canadian dollars, all references to “CDN,” “dollars” or “$” are to Canadian dollars and all references to “US$” are to US dollars.

By Enbridge, September 29, 2023

BP HAS completed a concept development phase study into its large-scale green hydrogen hub, H2Kwinana, in Western Australia and is now a step closer to achieving a final investment decision for the project.

In separate news, the firm has also led a US$12.5m investment in green hydrogen specialist Advanced Ionics, a climate-tech startup from Milwaukee, US. 

Established in 1955, and serving as an import terminal since 2021, Kwinana is the site of a former BP oil refinery.  

Subject to internal and government approvals, however, BP, in partnership with Macquarie Group, is planning on turning the facility into an energy hub that along with producing green hydrogen to support domestic and export demand, will also produce sustainable aviation fuel (SAF) and hydrogenated vegetable oil (HVO), also known as renewable diesel. 

The hub proposes the installation of an electrolyser of at least 75 MW, hydrogen storage, compression, and truck loading facilities, and upgrades to BP’s existing on-site hydrogen pipeline. 

As part of the study, three hydrogen production scenarios were evaluated; the first would see hydrogen production of 44 t/d; the second, 143 t/d, while a potential growth target of 429 t/d was selected as the third and final case. According to the Commonwealth Scientific and Industrial Research Organisation (CSIRO), this latter option for a large plant design is achievable. 

CSIRO also notes the cost estimates for each of these scenarios at A$334m–399m (US$213m–219m), A$1.25bn–1.49bn, and A$2.43bn–2.92bn, respectively. 

The project has already received funding support from state and federal sources, including a grant of up to A$70m for the development of the site, and A$300,000 in 2021 from the Western Australian Renewable Hydrogen Fund. 

BP, which is also a member of the Australian Hydrogen Council and the Global Hydrogen Council, said on their website: “BP’s transformation of the Kwinana site recognises the crucial role hydrogen and renewable fuels have to play in helping to decarbonize energy intensive industries like mining, minerals processing and heavy transport in Australia and across the Asia Pacific.

“In partnership with governments, customers and stakeholders, we will use our experience to create the fuels and jobs to power the energy transition.” 

In support of the planned project to produce SAF and biodiesel from bio feedstocks at Kwinana, BP has awarded Technip Energies a contract that covers the engineering, procurement, and fabrication (EPF) of a modularised hydrogen production unit. 

The unit will have a capacity of 33,000 m³/h using Technip Energies’ SMR proprietary technology and will be capable of producing hydrogen from either natural gas or biogas produced by the Kwinana biorefinery. 

Electrolyser venture

With over US$1bn already invested in technology companies, one of BP’s latest additions to its global portfolio of hydrogen projects is a sizeable investment into Advanced Ionics, a firm specialising in electrolyser technology. 

The funding round, which closed at US$12.5m and included Clean Energy Ventures, Mitsubishi Heavy Industries, and GVP Climate as additional investors, will help Advanced Ionics’ grow their Symbion water vapour electrolyser technology for heavy industry.  

Symbion helps reduce the cost and electricity requirements for green hydrogen production by symbiotically integrating with standard industrial processes to harness available heat.  

The electrolyser stack requires less than 35 kWh/kg of produced hydrogen compared to more than 50 kWh/kg for typical electrolysers. This lower electricity requirement could make green hydrogen accessible for less than $1/kg at scale. In addition, the system is made of widely available steels and other simple materials rather than expensive metals or materials common in other electrolysers, the firm explained.  

Gareth Burns, vice-president of BP ventures, said: “Advanced Ionics’ technology has the potential to drive down cost and disrupt the hydrogen market. We look forward to working with Advanced Ionics on the next stage of its growth.” 

Advanced Ionics was recognised for its technology as a finalist in BloombergNEF’s Pioneers award for 2023. The Pioneers award recognises early-stage companies seeking to introduce innovations to guide the world towards a net-zero economy. 

By The chemical Engineer, September 29, 2023