Category: Nieuws

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

Saudi Aramco (2222.SE) is considering selling a stake worth as much as $50 billion through a secondary share offering on the Riyadh bourse after consultations with advisers, the Wall Street Journal reported on Friday.

The sale could happen before the end of the year, the report said, adding that Aramco has been “sounding out” potential investors, such as other multinational oil companies and sovereign-wealth funds, about participating in the deal.

The Kingdom has decided to host any new Aramco offering on the Riyadh exchange to avoid legal risks associated with an international listing, the report said, citing Saudi officials and other people familiar with the plan.

Saudi Aramco declined to comment when contacted by Reuters on Friday.

Saudi Aramco is the world’s biggest oil company, with a market value of $2.25 trillion. Its shares have risen 19.6% this year.

The company completed the world’s largest initial public offering in late 2019, raising $25.6 billion and later selling more shares to raise the total to $29.4 billion.

Saudi Arabia had planned in addition to sell Aramco shares worth up to $50 billion last year, but decided market conditions were unfavourable, the Journal said.

Saudi Arabia’s Crown Prince Mohammed bin Salman, the kingdom’s de facto ruler, in January 2021 said that Saudi Aramco would sell more shares, with proceeds used bolster the country’s main sovereign wealth fund.

“There will be Aramco share offerings coming in the coming years, and this cash will be transferred to the Public Investment Fund,” said Prince Mohammed, speaking at the kingdom’s Future Investment Initiative conference.

The Public Investment Fund, which sometimes receives government injections of cash, spent 120 billion riyals ($32.00 billion) domestically last year as it sought to implement an ambitious economic agenda to wean the economy off oil by building new industries.

The fund, which manages about $700 billion in assets, made a total comprehensive loss of 58.545 billion riyals ($15.61 billion) last year, according to its annual report published last month.

Also last month, Aramco announced an additional dividend of nearly $10 billion, most of which will go to the government, in the first of several extra payouts on top of its expected $153 billion base dividend for 2022 and 2023.

It reported a 38% decline in second quarter profit to 112.81 billion riyals from the year earlier period.

Reuters by Urvi Manoj Dugar, September 29, 2023

The per barrel price for the WTI grade of crude oil reached $85 on Friday—the highest price point yet this year as falling inventory levels spook the market.

WTI crude oil briefly reached $85 per barrel before sagging to $84.90 around 10:00 a.m. ET. The last time WTI traded at a level that high was November 2022.

For the day, WTI was trading up $1.33 per barrel, or 1.59%.

Brent crude oil was also trading up on the day, by $1.05 per barrel, or 1.21%, at $87.88—also a new 2023 record.

A big factor in the rising price of crude oil are the falling inventories in the United States, which dipped another 10.6 million barrels according to the Energy Information Administration for the week ending August 25.

Another contributing factor to strong oil prices is the OPEC+ alliance, which includes heavyweights Saudi Arabia and Russia. The duo has reached a deal concerning production cuts, for which Russia has said it will provide details next week. The market is weighing the likelihood that Saudi Arabia or Russia could extend or deepen their current production cuts. More analysts than not expect that Saudi Arabia will extend its 1 million bpd production cut into October.
A third support under oil prices is the weakening dollar, which makes crude oil more affordable for non-dollar holders, thereby stimulating demand.

The price rise will make it more difficult for the Biden Administration to continue the painstakingly slow process of refilling the nation’s Strategic Petroleum Reserve, which has grown by an average of 600,000 barrels per week for the last few weeks, after draining 300 million barrels out of the SPR over the last few years.

Despite the 300 million barrels leaving the SPR and going into commercial inventories, crude oil inventories—excluding that in the SPR—are more than 100 million barrels shy of July 2020 levels.

OilPrice.com by Julianne Geiger, September 29, 2023

Abu Dhabi National Oil Company (ADNOC) will buy 30% in the Absheron gas field in the Caspian Sea in Azerbaijan by acquiring stakes from the current partners in the field, TotalEnergies and SOCAR.

The French supermajor and State Oil Company of the Republic of Azerbaijan (SOCAR) have signed an agreement to sell a 15% participating interest each in the Absheron gas field to ADNOC, TotalEnergies said on Friday.

After completion of the transaction, subject to the approval by the relevant authorities, TotalEnergies and SOCAR will each own 35% in Absheron, and ADNOC will have 30% in the gas and condensate field, where first gas was achieved last month. Financial details of the transaction are not being disclosed.

ADNOC’s investment in the Caspian region is part of the strategy of the UAE’s state oil and gas giant to expand on international gas markets.

“We believe this strategic partnership with SOCAR and TotalEnergies, unlocks the potential of the Caspian region for decades to come and complements a broader energy collaboration between the UAE and Azerbaijan that will accelerate the growth of the global renewable energy sector as both countries take bold steps to transition towards a lower-carbon future,” Musabbeh Al Kaabi, Executive Director of Low Carbon Solutions and International Growth at ADNOC, said in a statement carried by the Emirates News Agency, WAM.

Last month, TotalEnergies and its joint venture partner SOCAR began natural gas production from the Absheron gas and condensate field. The first phase of the development of the field has a production capacity of 4 million cubic meters of gas per day and 12,000 barrels per day of condensate.

The gas will be sold on the domestic market in Azerbaijan, which could free more gas from other Azerbaijani fields for exports, analysts say.

“TotalEnergies is pleased to welcome ADNOC, one of its strategic partners, into the Absheron gas field, where production of the first phase started in early July, and which offers a significant further development potential to meet the growing gas demand”, Nicolas Terraz, President, Exploration & Production at TotalEnergies, said today, commenting on the deal with the UAE firm.

By OilPrice.com, August 11, 2023

Next-Gen Biofuels: Harnessing the Power of GMOs for a Sustainable Future – EnergyPortal.eu

The quest for sustainable and renewable energy sources has been a pressing concern for governments, industries, and researchers worldwide. As we face the growing threat of climate change and depleting fossil fuel reserves, the need for cleaner and more efficient energy alternatives becomes increasingly urgent. One promising avenue in this pursuit is the development of next-generation biofuels, which harness the power of genetically modified organisms (GMOs) to produce energy-rich fuels from biomass.

Biofuels, such as ethanol and biodiesel, have been in use for several years as a means to reduce greenhouse gas emissions and dependence on fossil fuels. However, conventional biofuels are primarily derived from food crops, such as corn and sugarcane, which has raised concerns about the impact on food security and land use. Next-generation biofuels aim to address these issues by utilizing non-food biomass, such as agricultural residues, forestry waste, and dedicated energy crops, as feedstocks for fuel production.

One of the key challenges in producing next-generation biofuels is the efficient conversion of biomass into fermentable sugars, which can then be processed into fuels. This process typically involves breaking down the complex carbohydrates in plant cell walls, known as lignocellulose, into simpler sugars. However, lignocellulose is highly resistant to degradation, making this conversion process difficult and energy-intensive.

This is where GMOs come into play. By genetically engineering microorganisms, such as bacteria and yeast, scientists can enhance their ability to break down lignocellulose and ferment the resulting sugars into biofuels. These modified organisms can produce enzymes that are more efficient at degrading biomass, reducing the energy input required for the process and increasing the overall yield of biofuels.

One example of this approach is the development of genetically modified strains of the yeast Saccharomyces cerevisiae, which is commonly used in the production of ethanol. Researchers have introduced genes from other microorganisms that enable the yeast to ferment both glucose and xylose, two major sugars found in lignocellulosic biomass. This modification allows for the simultaneous fermentation of both sugars, increasing the efficiency of biofuel production and reducing the overall cost.

Another promising avenue for next-generation biofuels is the use of algae as a feedstock. Algae can grow rapidly and produce large amounts of biomass, making them an attractive source of renewable energy. Moreover, algae can be cultivated on non-arable land and in wastewater, reducing competition with food crops and providing additional environmental benefits. Genetic engineering can further enhance the potential of algae for biofuel production by increasing their lipid content, which can be converted into biodiesel, or by enabling them to directly produce biofuels, such as ethanol or butanol.

While the potential benefits of next-generation biofuels are significant, there are also concerns about the environmental and social impacts of GMOs. Critics argue that the release of genetically modified organisms into the environment could have unintended consequences, such as the spread of antibiotic resistance or the disruption of natural ecosystems. Additionally, there are concerns about the concentration of power in the hands of a few biotechnology companies, which could lead to monopolistic practices and limit access to these technologies for developing countries.

Despite these challenges, the development of next-generation biofuels offers a promising path towards a more sustainable and secure energy future. By harnessing the power of GMOs, we can unlock the full potential of biomass as a renewable energy source, reducing our reliance on fossil fuels and mitigating the impacts of climate change. As research and development in this field continue to advance, it is crucial that we also engage in an open and transparent dialogue about the risks and benefits of these technologies, ensuring that they are deployed responsibly and equitably for the benefit of all.

By energyportal.eu, August 15, 2023

In the midst of the global shift towards green energy, the Oil Trader iFex, which is an oil trading platform, trading of oil has faced significant changes and challenges. As the world becomes more conscious of environmental sustainability, the oil industry is compelled to adapt to new regulations, consumer demands, and emerging energy technologies. This article explores the dynamic landscape of trading oil in the era of green energy transition, highlighting key developments, market trends, and strategies employed by businesses in this evolving industry.

The Green Energy Transition

Understanding the Transition

The green energy transition is a continuous and crucial process that involves shifting away from conventional energy sources reliant on fossil fuels, towards cleaner and renewable alternatives. This transition is motivated by multiple factors, including the urgency to address climate change, minimize greenhouse gas emissions, and secure a sustainable energy future. As nations across the globe commit to achieving carbon neutrality, the demand for oil is anticipated to undergo significant changes.

Impact on Oil Trading

• Decreased Demand: With the increasing adoption of renewable energy sources, the demand for oil has witnessed a decline. As electric vehicles become more prevalent, the transportation sector, which heavily relies on oil, is gradually shifting towards greener alternatives. Additionally, advancements in energy-efficient technologies have reduced the overall energy consumption in various industries, further impacting oil demand.
• Volatility in Prices: The transition to green energy has introduced greater price volatility in the oil market. Fluctuations in demand and supply, coupled with geopolitical factors, have created an unpredictable trading environment. As governments implement stricter environmental regulations and incentives for renewable energy, oil prices can experience sharp fluctuations.

• Emergence of ESG Factors: Environmental, Social, and Governance (ESG) factors have gained prominence in the investment landscape. Investors are now considering a company’s environmental impact, social responsibility, and corporate governance practices when making investment decisions. Oil companies are under pressure to align with sustainable practices and demonstrate their commitment to reducing carbon emissions.

Strategies for Successful Oil Trading

To navigate the challenges and seize opportunities in the era of green energy transition, oil trading businesses must adopt comprehensive strategies that integrate sustainability, innovation, and market intelligence. The following strategies can help oil traders thrive in this changing landscape:

Diversification

In light of the persistent decline in long-term oil demand, it is prudent for traders to expand their investment portfolios by including assets related to renewable energy. By allocating resources to wind, solar, and hydroelectric projects, traders can establish a safeguard against diminishing oil revenues. Diversifying investments enables traders to capitalize on the expanding renewable energy market, while simultaneously mitigating the risks associated with a contracting oil industry.

Technological Innovation

For oil traders aiming to navigate the green energy transition, embracing technological advancements is of utmost importance. By harnessing the power of artificial intelligence, machine learning, and data analytics, traders can access valuable insights into market dynamics, optimize their supply chains, and uncover untapped opportunities. Moreover, exploring and investing in emerging technologies like carbon capture and storage allows traders to establish themselves as pioneers in the realm of sustainable energy solutions. By embracing these advancements, oil traders can proactively adapt to the changing landscape and contribute to a greener and more sustainable future.

Collaboration and Partnerships

To stay competitive, oil traders should foster collaboration and partnerships within the renewable energy sector. Engaging in joint ventures, strategic alliances, and research collaborations can facilitate knowledge sharing and help traders gain expertise in renewable energy technologies. Collaborations can also open avenues for diversified revenue streams and enable access to new markets.

Sustainable Practices and Reporting

Incorporating sustainable practices into daily operations is essential for oil traders aiming to enhance their environmental credentials. Implementing energy-efficient measures, minimizing carbon emissions, and adopting responsible waste management practices are key steps towards sustainability. Additionally, transparent reporting on environmental performance allows traders to build trust with stakeholders and meet the growing demand for ESG-focused investments.

Conclusion

As the world transitions towards a greener future, the trading of oil faces a paradigm shift. The decline in oil demand, increased price volatility, and the rise of ESG factors necessitate strategic adaptations by oil traders. Diversification, technological innovation, collaboration, and sustainable practices are critical for navigating this changing landscape successfully. By embracing these strategies, oil traders can position themselves as leaders in the era of green energy transition and thrive amidst evolving market dynamics.

By THE NATION, August 15, 2023

The Netherlands was the top destination for US liquefied natural gas supplies for the second month in a row in June, according to the Department of Energy’s newest LNG monthly report.

The report shows that US terminals shipped 45.9 Bcf of LNG to the Netherlands in June, 45.6 Bcf to France, 24.7 Bcf to Japan, 23.6 Bcf to China, and 22.7 Bcf to Argentina.

These five countries took 49.5 percent of total US LNG exports in June.

In May, US terminals shipped 64.5 Bcf of LNG to the Netherlands, while the UK was the top destination for US LNG supplies for six months in a row prior to that.

The Netherlands has expanded its capacity with the launching of Gasunie’s Eemshaven FSRU-based LNG terminal that mostly receives cargoes from the US.

The country’s first FSRU-based terminal adds to the Gate LNG import facility in Rotterdam, also operated by Gasunie and Vopak.

US LNG exports rise 9.1 percent

The US exported in total 327.8 Bcf of LNG in June, up by 9.1 percent compared to the same month last year and a drop of 10.6 percent from the prior month, the DOE report shows.

US terminals shipped 108 LNG cargoes in June, compared to 96 cargoes in June 2022 and 127 cargoes in May this year, according to the report.

Sempra’s Cameron LNG plant sent 29 shipments during June, Cheniere’s Sabine Pass plant sent 27 cargoes and its Corpus Christi terminal shipped 18 cargoes.

In addition, Freeport LNG sent 21 cargoes, Cove Point LNG sent 7 cargoes, and Elba Island LNG dispatched 6 shipments.

4924 LNG cargoes

According to DOE’s report, the weighted average price by export terminal reached 7.09/MMBtu in June.

Moreover, the report said that in the period from February 2016 through June 2023, the US exported 4924 cargoes or 15,696.5 Bcf to 44 countries.

South Korea remains the top destination for US LNG with 529 cargoes, followed by Japan with 401 cargoes, the UK with 390 cargoes, France with 377 cargoes, and Spain with 375 cargoes.

Besides these five countries, the Netherlands, China, India, Turkey, and Brazil are in the top ten as well.

By LNG Prime, August 18, 2023