Argyle announces successful exit of its investment in The Mufflerman
Mufflerman, based in London Ontario, operates a network of automotive repair locations under multiple banners across the province. Founded over 60 years ago, the Company has built a reputation for high-quality service and trusted local relationships.
Argyle initially acquired the platform in early 2021. Over the hold period, Mufflerman evolved into one of Ontario's leading multi-store operators in the automotive aftermarket. The transformation was driven by a focused buy-and-build strategy, disciplined operational upgrades, and a capital structure purpose-built for growth.
The Company benefitted from its senior leadership team, led by Costa Haitas and Argyle partner, Glenn Gatcliffe, who spearheaded efforts to professionalize operations, improve margin performance, and integrate new locations. As part of its M&A strategy, Argyle completed five tuck-in acquisitions, financed on balance sheet, enabling the business to triple its EBITDA during the investment period.
"We're incredibly proud of what was accomplished with Mufflerman," said Mark MacPherson, Co-Founder and Managing Partner at Argyle. "This transaction is a clear example of Argyle's ability to identify and scale regional leaders through thoughtful M&A, hands-on operational support, and disciplined capital management. The Company is well-positioned for continued growth under its new ownership."
About Argyle
Founded in 2016, Argyle is a Toronto-based private equity firm focused on partnering with family-owned businesses in Canada's lower middle market. Argyle invests in traditional businesses in industrial products, manufacturing, distribution, and business services.
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FRONTERA ANNOUNCES SECOND QUARTER 2025 RESULTS
Increased Total Production 1% Quarter over Quarter Generated Quarterly Operating EBITDA of $76.1 Million Generated Adjusted Infrastructure EBITDA of $27.1 million and $14.3 million Segment Income Declared Quarterly Dividend of C$0.0625 Per Share, or $3.5 Million in Aggregate, Payable on or around October 16, 2025 CALGARY, AB, Aug. 13, 2025 /CNW/ - Frontera Energy Corporation (TSX: FEC) (" Frontera" or the " Company") today reported financial and operational results for the second quarter ended June 30, 2025. All financial amounts in this news release and in the Company's financial disclosures are in United States dollars, unless otherwise stated. Gabriel de Alba, Chairman of the Board of Directors, commented: "Despite a volatile global macro-economic and oil market backdrop, Frontera continued to execute on its strategic goals and priorities across its businesses in the second quarter delivering strong operating results and completing significant value-generating initiatives for its shareholders and bondholders. The Company generated $76.1 million in Operating EBITDA, produced $27.1 million of Adjusted Infrastructure EBITDA, and maintained a strong balance sheet, finishing the quarter with a total cash balance of $197.5 million while reducing its upstream net debt by 30%. Following the expiry of the 90‑day consultation and negotiation period arising from the Notice of Intent -and in view of the uncertainty introduced by the Government of Guyana—we have recognized an impairment of over $430 million related to our investment in the Corentyne block, in accordance with prudent accounting standards. The Joint Venture remains firmly of the view that its interests in, and the license for, the Corentyne block remain in place and in good standing and that the Petroleum Agreement has not been terminated. We remain committed to working with the Government of Guyana to resolve these issues amicably, while preparing to assert and protect our legal and contractual rights through all available legal remedies, as necessary. The Company prioritized returning capital to all investors via its successful $80 million tender offer and consent solicitation of its senior unsecured notes due in 2028 and, subsequent to the quarter, the completion of a C$91 million substantial issuer bid, the largest in the Company's history. The Company also declared a quarterly dividend of C$0.0625 per share, or approximately $3.5 million in aggregate, and initiated a non-course issuer bid program. Over the last twelve-months, Frontera has returned over $144 million to shareholders via dividends and share repurchases while also reducing the outstanding aggregate principal amount of its senior unsecured notes by over 20%. These efforts underscore the success of the Company's return of capital focus to its stakeholders. The Company will continue to consider similar investor-focused initiatives in 2025 and beyond, including additional dividends, distributions, and share or bond buybacks, based on the overall results of the businesses, oil prices and cash flow generation. Additionally, the Company will consider all options to enhance the value of its common shares, and in so doing may consider other strategic initiatives or transactions." Orlando Cabrales, Chief Executive Officer (CEO), Frontera, commented: "Frontera's second quarter financial and operating results demonstrate the decisive steps we are taking to deliver stakeholder value, maintain financial and operational flexibility, and reduce leverage over the long-term. We increased our total production quarter over quarter driven by increased processing capacity at SAARA, investments in new flow lines in our heavy oil fields, a successful well intervention program within our light and medium blocks and new commercialized volumes of natural gas production from the VIM-1 block. During the quarter, we continued to prioritize operational improvements, reducing capital spending and cost and process efficiencies across our business, delivering a 10.3% decrease in production costs quarter-over-quarter driven by fewer well interventions and the implementation of new production technologies. We also reduced our transportation costs by 5.7% quarter-over-quarter driven by higher domestic wellhead sales. Our standalone and growing Colombia infrastructure business, which includes the Company's interest in ODL, generated an Adjusted Infrastructure EBITDA of $27.1 million. At Puerto Bahia, the Reficar connection was completed by the end of the quarter and now the efforts shift to the first transported volumes which are expected during the third quarter of 2025. Strategic investments in the port, including the LPG JV with Empresas Gasco, are progressing on schedule. The port is also pursuing additional investment opportunities that leverage its facilities and infrastructure for sustainable long-term growth. Consistent with our strategy, following the end of the quarter, the Company announced it had reached an agreement to divest its interest in the Company's non-core Perico and Espejo fields in Ecuador. This transaction is consistent with our strategy of maximizing value over volumes and supports a stronger focus on our higher-impact Colombian upstream operations. As a result, we are adjusting our 2025 production guidance to account for the impact of Ecuador sale to 39,500 to 41,000 boed. In light of the current oil price environment, we are also adjusting our capital expenditures guidance downwards, by approximately $20 million, reducing development facilities capex to $45 - 65 million and exploration capex to $25 - 35 million, reflecting our disciplined approach to capital spending and ability to identify ongoing operational efficiencies. Additionally, we are providing Operating EBITDA Guidance at a $70/bbl Brent Price with a target of between $320 - $360 million and revising our Adjusted Infrastructure EBITDA Guidance to between $110 - 125 million." Second Quarter 2025 Operational and Financial Summary: (1) References to heavy crude oil, light and medium crude oil combined, conventional natural gas and natural gas liquids in the above table and elsewhere in this news release refer to the heavy crude oil, light crude oil and medium crude oil combined, conventional natural gas and natural gas liquids, respectively, product types as defined in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. (2) Represents W.I. production before royalties. Refer to the "Further Disclosures" section on page 40 of the Company's management's discussion and analysis for the three months ended on March 31, 2025 (the " MD&A"). (3) Boe has been expressed using the 5.7 to 1 Mcf/bbl conversion standard required by the Colombian Ministry of Mines & Energy. Refer to the "Further Disclosures - Boe Conversion" section on page 40 of the MD&A. (4) Non-IFRS ratio is equivalent to a "non-GAAP ratio", as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure (" NI 52-112" ). Refer to the "Non-IFRS and Other Financial Measures'' section on page 24 of the MD&A. (5) 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahia inter-segment costs related to diluent and oil purchases as well as transportation costs. (6) Supplementary financial measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 24 of the MD&A. (7) Includes the net of the put premiums paid for expired positions and the positive cash settlement received from oil price contracts during the period. Please refer to the "Gain (loss) on oil price risk management contracts" section on page 15 of the MD&A for further details. (8) Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 24 of the MD&A. (9) Net (loss) income attributable to equity holders of the Company. (10) Capital management measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 24 of the MD&A. (11)" Unrestricted Subsidiaries" include CGX Energy Inc., listed on the TSX Venture Exchange under the trading symbol "OYL"; FEC ODL Holdings Corp., including its subsidiary Frontera Pipeline Investment AG (" FPI", formerly named Pipeline Investment Ltd); Frontera BIC Holding Ltd.; Frontera Energy Guyana Holding Ltd.; Frontera Energy Guyana Corp.; and Frontera Bahía Holding Ltd. (" Frontera Bahia"), including Sociedad Portuaria Puerto Bahia S.A (" Puerto Bahia"). Refer to the "Liquidity and Capital Resources" section on page 31 of the MD&A. Second Quarter 2025 Operational and Financial Results: The Company recorded a net loss of $455.2 million or $5.89/share in the second quarter of 2025, compared with a net income of $27.5 million or $0.35/share in the prior quarter and net loss of $2.8 million or $0.03/share in the second quarter of 2024. Net loss from operations for the second quarter included a loss from operations of $474.8 million (net of non-cash impairment expenses of $477.0 million), finance expenses of $18.3 million and foreign exchange expenses of $2.6 million, partially offset by $14.1 million from share of income from associates, an income tax recovery of $13.0 million (including $14.3 million of deferred income tax recovery), $11.7 million of gain on the repurchase of its outstanding 7.875% Senior Unsecured Notes due in 2028 (the " 2028 Senior Unsecured Notes") net of the consent solicitation, and $4.0 million related to a gain on risk management contracts. This compares with a net loss, attributable to equity holders of the Company, of $2.8 million, mainly resulting from an income tax expense of $32.7 million (including $31.4 million of deferred income tax expenses), finance expenses of $17.4 million, foreign exchange losses of $7.5 million and $3.6 million related to a loss on risk management contracts, partially offset by an income from operations of $45.2 million and $13.4 million from the share of income from associates. Production averaged 41,055 boe/d in the second quarter of 2025, up 1% compared to 40,477 boe/d in the prior quarter and up 3% against 39,912 boe/d in the second quarter of 2024. Compared to the first quarter 2025, heavy crude oil production, increased by 1%, mainly due to increased processing capacity at SAARA and investments in new flow lines in the Cajua field; light and medium crude oil production, increased by 3% driven by a successful well intervention program; and conventional natural gas production increase by 37%, as a result of new commercialized volumes of natural gas from the VIM-1 Block. Natural gas liquids production decreased 4%, compared to the prior quarter, primarily as a result of natural decline. Operating EBITDA was $76.1 million in the second quarter of 2025 compared to $83.5 million in the prior quarter and $110.3 million in the second quarter of 2024. The decrease in operating EBITDA compared to the prior quarter was mainly due to lower Brent prices during the quarter, partially offset by lower production and transportation costs during the quarter. Cash provided by operating activities in the second quarter of 2025 was $41.8 million, compared to $70.1 million in the prior quarter and $149.8 million in the second quarter of 2024. The Company reported a total cash position of $197.5 million at June 30, 2025, compared to $199.8 million at March 31, 2025 and $215.1 million at June 30, 2024. During the quarter, the Company closed and funded the recapitalization of its interest in Oleoducto de los Llanos Orientales S.A. (" ODL") through a $220 million non-recourse, secured loan and received $115 million in net proceeds. In addition, the Company repurchased $80 million in aggregate principal amount of its outstanding 2028 Senior Unsecured Notes. Subsequent to the quarter, the Company paid $66.5 million to shareholders through its substantial issuer bid (as described further below). As at June 30, 2025, the Company had a total crude oil inventory balance of 1,142,536 barrels compared to 911,886 barrels at March 31, 2025. The Company had a total inventory balance in Colombia of 629,147 barrels, including 493,510 crude oil barrels and 135,637 bbls of diluent and others. This compared to 392,821 barrels as at March 31, 2025, and 758,794 barrels as at June 30, 2024. The Increase in inventory levels was associated with higher quarter over quarter production levels. Capital expenditures were approximately $59.4 million in the second quarter of 2025, compared with $46.7 million in the prior quarter and $80.2 million in the second quarter of 2024. During the second quarter, the Company drilled 26 development wells mainly at the Quifa and CPE-6 blocks. The Company's net sales realized price was $58.86/boe in the second quarter of 2025, compared to $62.26/boe in the prior quarter and $72.36/boe in the second quarter of 2024. The decrease was primarily driven by a lower Brent benchmark oil price, which was partially offset by stronger oil price differentials, the realized gain from oil price risk management contracts and lower royalties paid in cash. The Company's operating netback was $33.52/boe in the second quarter of 2025, compared with $34.52/boe in the prior quarter and $45.76/boe in the second quarter of 2024. Despite a $8.27/bbl decrease in the Brent benchmark oil price, the Company partially offset the lower netback through: (i) stronger oil price differentials, (ii) a reduction in production costs (excluding energy costs), net of realized FX hedge impact, mainly as a result of a reduction of well intervention activities and the adoption of new field production technologies, (iii) lower energy costs, net of realized FX hedge impact, driven by lower market prices, and (iv) lower transportation costs, due to reduced transported volumes, primarily resulting from improved domestic wellhead sales. Production costs (excluding energy cost), net of realized FX hedge impact, averaged $9.01/boe in the second quarter of 2025, compared with $10.04/boe in the prior quarter and $10.79/boe in the second quarter of 2024. The decrease in production cost primarily due to lower well services activities and the implementation of new field production technologies. Energy costs, net of realized FX hedging impacts, averaged $4.71/boe in the second quarter of 2025, compared to $5.38/boe in the prior quarter and up from $4.74/boe in the second quarter of 2024. The decrease quarter over quarter was mainly due to lower market prices. Transportation costs, net of realized FX hedging impacts averaged $11.62/boe in the second quarter of 2025, compared with $12.32/boe in the prior quarter and $11.07/boe in the second quarter of 2024. The decrease during the quarter was mainly due to reduced transported volumes, primarily resulting from improved domestic wellhead sales. ODL volumes transported were 235,804 bbl/d during the second quarter of 2025, volumes transported were in line with Q1 2025, which saw 236,387 bbl/d in volumes transported. Total Puerto Bahia liquids volumes were 53,280 bbl/d during the second quarter 2025 compared to 51,579 bbl/d the first quarter of 2025. Adjusted Infrastructure EBITDA in the second quarter of 2025 was $27.1 million, compared to $28.6 million in the first quarter of 2025. The decrease was mainly due to higher operating costs in SAARA, offset by positive results in the ODL segment driven by the pipeline tariff increase and lower costs during the quarter. Frontera's Sustainability Strategy The Company is advancing towards its 2028 sustainability goals as well as on the 2025 plan, with progress in almost every goal during the second quarter. On the sustainability front, and in alignment with our supply chain strategy, we launched the Business Network for Responsible Business Conduct to promote best practices in human rights due diligence. In the second quarter of 2025, local suppliers accounted for 11.37% of total purchases, reflecting the Company's ongoing commitment to support local economic development. Additionally, Frontera maintained strong performance in health and safety indicators, reporting achieved a Total Recordable Incident Rate (" TRIR") of 0.71. The Company also attained a water reuse rate of 37.6% within its operational activities. Enhancing Shareholder Returns The Company continues to consider investor-focused initiatives in the second half of 2025 and beyond, including additional dividends, distributions, share or bond buybacks, based on the overall results of the businesses, oil prices and cash flow generation. Additionally, the Company also continues to consider all options to enhance the value of its common shares, and in so doing may consider forms of strategic initiatives or transactions, which may include a further return of capital to shareholders, a merger or a business combination, or the transfer, sale or other disposition of all or a significant portion of the business, assets or securities of the Company, the recapitalization or separation or of interest in one or more subsidiaries or in assets of the Company, whether in one or a series of transactions. However, there can be no assurance that any such initiative or transaction will occur or if it occurs, the timing thereof. NCIB: Subsequent to the quarter, on July 15,2025, the Company announced the initiation of a Normal Course Issuer Bid, commencing July 18, 2025 and ending July 17, 2026, through which the Company may purchase up to 3,502,962 shares for cancellation, representing approximately 5% of the issued and outstanding shares as at July 15, 2025. As at August 12, 2024, the Company has repurchased approximately 78,400 common shares for cancellation for approximately $0.4 million. SIB: On July 15, 2025, the Company announced that, it had taken up and paid for 7,583,333 common shares (approximately 9.77% of the total number of Frontera's issued and outstanding common shares as at July 10, 2025) at a price of CAD$12.00 per common share, representing an aggregate purchase price of approximately CAD $91.0 million pursuant to a substantial issuer bid. The July 2025 substantial issuer bid had a 92.6% participation and the tendered shares were purchased on a pro rata basis, shareholders who tendered to the substantial issuer bid had approximately 10.54% of their tendered shares purchased by the Company. With an over 90% consistent participation rate in the SIBs, the Company's capital distribution strategy has proven effective and well received by the shareholders. After the cancellation of the common shares taken up and paid for by the Company, approximately 70.06 million common shares remained issued and outstanding. Bond Capped Cash Tender Offer & Consent Solicitation: On June 10, 2025, the Company announced the results of the cash tender and consent solicitation of its outstanding 2028 Senior Unsecured Notes. The Company received the requisite consents to implement the proposed amendments to the indenture governing the notes with a 50.38% approval, and validly delivered tenders in excess of the maximum tender amount set forth in the offer, Bondholders who participated in the tender offer had their notes repurchased pursuant to a proration factor of 55.63%. The transaction reduced the amount of the Company's outstanding notes by $80 million three years before maturity, for a total cash consideration of $57.6 million and recognizing a gain after fees and expenses associated with transaction of $11.7 million. The tender offer and consent solicitation provided the Company with increased financial flexibility, while also reducing its outstanding debt obligations. The amendments to the indenture aim to modernize Frontera's indenture in line with that of its peers and also provides targeted operational flexibility to deliver long-term business and reserve growth, including as a result of inorganic transactions. The carrying value for the 2028 Senior Unsecured Notes, as of June 30, 2025, is $310.3 million. Dividend: Pursuant to Frontera's dividend policy, Frontera's Board of Directors has declared a dividend of C$0.0625 per common share to be paid on or around October 16, 2025, to shareholders of record at the close of business on October 2, 2025. This dividend payment to shareholders is designated as an "eligible dividend" for purposes of the Income Tax Act (Canada). This dividend is eligible for the Company's Dividend Reinvestment Plan which provides Canadian resident shareholders of Frontera the option to automatically reinvest the cash dividends on their common shares into additional common shares, without paying brokerage commissions or services charges. Frontera's Three Core Businesses Frontera's three core businesses include: (1) its Colombia and Ecuador Upstream Onshore business, (2) its standalone and growing Colombian Infrastructure business, and (3) its potentially transformational Guyana Exploration business offshore Guyana. 2025 Guidance Update Frontera is adjusting its 2025 production guidance to reflect its Colombian operations only, now targeting 39,500 to 41,000 boed, following the divestment of its non-core assets in Ecuador. The Company is also revising its capital expenditures guidance downwards by approximately $20 million, reducing its development facilities capex to $45 - 65 million and exploration capex to $25 - 35 million. These changes reflect on the Company's disciplined approach to capital spending and ability to identify ongoing operational efficiencies. Additionally, the Company is providing Operating EBITDA Guidance at a $70/bbl Brent Price targeting between $320 - $360 million and revising our Adjusted Infrastructure EBITDA Guidance targeting between $110 - 125 million. (1) The Company's 2025 original and updated average production guidance range does not include in-kind royalties, operational consumption, quality volumetric compensation or potential production from successful exploration activities planned in 2025. (2) Per-bbl/boe metric on a share before royalties' basis. (3) Calculated using net production after royalties. (4) Supplementary financial measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 24 of the MD&A for further details. (5) Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 24 of the MD&A for further details (6) 2025 Original Guidance Operating EBITDA calculated at Brent between $75/bbl and COP/USD exchange rate of 4,250:1. (7) 2025 Updated Guidance Operating EBITDA calculated at Brent between $70/bbl and COP/USD exchange rate of 4,150:1.. (8) Other includes HSEQ activities and new field production technologies. Colombia & Ecuador Upstream Onshore Colombia During the second quarter of 2025, Frontera produced 39,778 boe/d from its Colombian operations (consisting of 27,535 bbl/d of heavy crude oil, 9,850 bbl/d of light and medium crude oil, 3,118 mcf/d of conventional natural gas and 1,846 boe/d of natural gas liquids). In the second quarter of 2025, the Company drilled 26 development wells mainly at the Quifa and CPE-6 blocks and completed well interventions at 22 others. Currently, the Company has 1 drilling rig and 2 well intervention rigs active at its Quifa and CPE-6 blocks in Colombia. Quifa Block: Quifa SW and Cajua At Quifa, second quarter 2025 production averaged 17,576 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company invested in facility expansion and the installation of new flow lines in the Cajua field, in the Quifa block to support new well production and the SAARA connection. In the second quarter 2025, the Company handled an average of approximately 1.78 million barrels of water per day in Quifa including SAARA. CPE-6 At CPE-6, second quarter 2025 production averaged approximately 7,771 bbl/d of heavy crude oil, decreasing from 8,056 bbl/d during the first quarter of 2025. During the second quarter 2025, the Company invested in the expansion of crude oil storage capacity and the implementation of new field production technologies. The Company handled an average of approximately 327 thousand barrels of water per day in CPE-6 in the second quarter of 2025. The Company's current water handling capacity in CPE-6 is approximately 370 thousand barrels of water per day. Other Colombia Developments At Guatiquia, production during the second quarter 2025 averaged 5,385 bbl/d of light and medium crude compared with 5,119 bbl/d in the first quarter 2025. During the quarter the Company performed a sidetrack in its Coralillo 3 well. In the Cubiro block production averaged 1,057 bbl/d of light and medium crude oil in the second quarter of 2025 compared with 1,213 bbl/d in the first quarter 2025. At VIM-1 (Frontera 50% W.I., non-operator), production averaged 1,960 boe/d of light and medium crude oil in the second quarter of 2025 compared to 1,840 boe/d of light and medium crude oil in the first quarter 2025. At the Sabanero block, production averaged 2,189 boe/d of heavy oil crude production in the second quarter of 2025 compared to 2,346 boe/d in the first quarter 2025. Colombia Exploration Assets At VIM-1, following engagement efforts with authorities and communities, the joint venture operating the VIM-1 block (Frontera 50% W.I., non-operator) has shifted its focus from Hidra-1 to the Guapo-1 exploratory well. By the second quarter 2025, all necessary designs and permits were secured for roadwork and site preparation for Guapo-1, with drilling and completion expected to occur in the second half of 2025. At Llanos 119, the Company is awaiting the decision of the Agencia Nacional de Hidrocarburos (ANH) on transferring exploration commitments to VIM-46 for a 3D seismic survey. Meanwhile, pre-seismic and pre-drilling social and environmental studies are underway at Llanos-99 and VIM-46. Ecuador In Ecuador, second quarter 2025 production averaged approximately 1,277 bbl/d of light and medium crude oil compared to 1,467 bbl/d in the prior quarter. At the Espejo block (Frontera holds a 50% W.I. and is a non-operator), long-term tests continued at the Espejo Sur-B3 well with production of 330 bbl/d gross and a water cut of 78%. Subsequent to the quarter, the Company agreed to divest its 50% interest in the Perico and Espejo blocks in Ecuador. The total cash consideration to Frontera for the blocks is $7.8 million, subject to working capital and other customary adjustments as of the effective date of January 1, 2025. The agreement includes an additional contingent consideration of $750,000, payable to Frontera upon the Perico block achieving cumulative gross production of two million barrels as from January 1, 2025. Closing of the transaction is subject to satisfaction of customary closing conditions, including the receipt of regulatory approvals for closing and operations takeover from the Ministry of Energy of Ecuador, and is expected to occur by the second quarter of 2026. 2. Infrastructure Colombia Frontera's Infrastructure Colombia Segment includes the Company's 35% equity interest in the ODL pipeline through Frontera's wholly owned subsidiary, FPI and the Company's 99.97% interest in Puerto Bahia. Beginning in 2024, the Infrastructure Colombia Segment also includes the Company's reverse osmosis water treatment facility (SAARA) and its palm oil plantation (ProAgrollanos). Frontera processed 119,409 barrels of water per day at is SAARA reverse osmosis water-treatment facility during the quarter and remains focused on reaching its goal of processing 250,000 barrels of water per day. On the Puerto Bahia side, the Reficar connection's construction was completed by the end of the quarter and, the Company's efforts shift to the first transported volumes, which are expected during the third quarter of 2025. The Company is progressing with its growth plans, including the LPG joint venture with Empresas Gasco. Infrastructure Colombia Segment Results Adjusted Infrastructure EBITDA in the second quarter of 2025 was $27.1 million, compared with $28.6 million during the first quarter 2025. The decrease was mainly due to higher operating costs in SAARA, offset by positive results in the ODL segment driven by the pipeline tariff increase and lower costs during the quarter. (1) Non-IFRS financial measure Segment capital expenditures for the three months ended June 30, 2025, totaled $4.8 million primarily driven by Puerto Bahia investments of $3.9 million, including: (i) $3.4 million in investment towards the Reficar connection, (ii) tank maintenance, and (iii) general cargo terminal facilities with additional investment in the SAARA project. (1) Non-IFRS financial measures (equivalent to a "non-GAAP financial measures", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures'' section on page 24 of the MD&A. The following table shows the volumes pumped per injection point in ODL: The following table shows throughput for the liquids port facility at Puerto Bahia: The following table shows the barrels of water per day treated and irrigated in SAARA and field performance indicators for Proagrollanos: (1) Tons per hectare per year for the three months ended June 30, are calculated using the total production for the last twelve months ended June 30. 3. Guyana Exploration On March 26, 2025, the Company and its subsidiaries Frontera Petroleum International Holding B.V. and Frontera Energy Guyana Holding Ltd. (the " Investors") sent a Notice of Intent to the Government of Guyana (the " GoG"). In this Notice of Intent, the Investors alleged breaches of the United Kingdom – Guyana Bilateral Investment Treaty and the Guyana Investment Act by the GoG. The communication initiated a 90-day period for consultations and negotiations between the parties to resolve the dispute amicably. After the 90-day period, no mutually, acceptable solution has been produced. As informed in previous quarters, Frontera Energy Guyana Corp. (" Frontera Guyana") and CGX Resources Inc. (" CGX Resources" and together with Frontera Guyana, the " Joint Venture") and its stakeholders are prepared to assert their legal rights. On July 23, 2025, the GoG, through its legal counsel, responded to the Investors, rejecting their claims regarding the Corentyne block license. The GoG reaffirmed its view that the Joint Venture's interest expired on June 28, 2024, but noted that it may consider a final meeting with the Investors, on a without prejudice basis, in October 2025, and the Joint Venture would be informed as to whether such a meeting will occur in September 2025 The Joint Venture remains firmly of the view that its interests in, and the license for, the Corentyne block remain in place and in good standing and that the Petroleum Agreement has not been terminated. Although the 90-day consultation and negotiation period derived from the Notice of Intent has now expired, the Joint Venture and its stakeholders continue to invite the GoG to amicably resolve the issues affecting the Joint Venture's investments in the Corentyne block. Should the parties not reach a mutually agreeable solution, the Joint Venture and its stakeholders are prepared to assert their legal rights. The Company evaluated the Corentyne E&E asset's recoverability given the GoG's conduct and communications, and its unwillingness to recognize the Joint Venture's rights during the consultation periods, which have since expired. Although all contractual requirements of the Company have been met and an external legal assessment determined that the Company's interests in the licenses and agreements for the Corentyne block remain valid, the GoG's positions mentioned above have restricted the Company's ability to develop activities under those licenses and agreements. This situation has led to uncertainty regarding the asset's future development and constituted an impairment indicator. Consequently, the Company recognized an impairment of $432.2 million in its income statement, and the Corentyne E&E asset's carrying value as of June 30, 2025 is $Nil (December 31, 2024 $431.9 million). The Joint Venture jointly hold 100% working interest in the Corentyne block, located offshore Guyana. Frontera Guyana and CGX Resources have agreed that their respective participating interests are 72.52% and 27.48%, which includes a 4.52% interest which CGX Resources agreed to assign to Frontera Guyana in 2023. The assignment of this 4.52% participating interest remains subject to the approval of the Government of Guyana, but is believed to be enforceable between Frontera Guyana and CGX Resources. Hedging Update As part of its risk management strategy, Frontera uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company's strategy aims to protect 40-60% of its estimated net after royalties' production using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside, thereby allowing the Company to take a more dynamic approach to the management of its hedging portfolio. The following table summarizes Frontera's hedging position as of August 13, 2025. The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD. As of August 13, 2025 the Company had the following foreign currency derivatives contracts: Second Quarter 2025 Financial Results Conference Call Details A conference call for investors and analysts will be held on Thursday, August 14th, 2025, at 11:00 a.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, Rene Burgos, Chief Financial Officer, and other members of the senior management team. Analysts and investors are invited to participate using the following dial-in numbers: A replay of the conference call will be available until 11:59 p.m. Eastern Time on August 21st, 2025. About Frontera: Frontera Energy Corporation is a Canadian public company involved in the exploration, development, production, transportation, storage and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. The Company has a diversified portfolio of assets with interests in 22 exploration and production blocks in Colombia, Ecuador and Guyana, and pipeline and port facilities in Colombia. Frontera is committed to conducting business safely and in a socially, environmentally and ethically responsible manner. Twitter: Facebook: LinkedIn: Cautionary Note Concerning Forward-Looking Statements This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, the Company's goal of enhancing shareholder value by returning capital to shareholders, the Company's intent to consider future shareholder initiatives including a potential future separation and other strategic transactions involving the Infrastructure business, the expected date for pre-drilling and drilling activity to commence in the Lower Magdalena Valley and Llanos Basins in Colombia, the operational timing of the connection project between Puerto Bahia and Reficar, holding the conference call for investors and the timing thereof, the Company's exploration and development plans and objectives, production levels, profitability, costs, future income generation capacity, cash levels (including the timing and ability to release restricted cash), regulatory approval, and the Company's hedging program and its ability to mitigate the impact of changes in oil prices) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: volatility in market prices for oil and natural gas; the newly imposed U.S. trade tariffs affecting over fifty countries and escalating tensions with China; the impact of the Russia-Ukraine conflict and the conflict in the Middle East; actions of the Organization of Petroleum Exporting Countries; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company's ability to raise capital and to continually add reserves through acquisition and development; the Company's ability to complete strategic initiatives or transactions to enhance the value of its common shares and the timing thereof; the Company's ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants contained in the agreements that govern indebtedness; political developments in the countries where the Company operates; the uncertainties involved in interpreting drilling results and other geological data; geological, technical, drilling and processing problems; timing on receipt of government approvals; fluctuations in foreign exchange or interest rates and stock market volatility, the ability of the Joint Venture to reach an agreement with the GoG in respect of the Joint Venture's interest in the PA and PPL for the Corentyne block, and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 10, 2025 filed on SEDAR+ at Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein. This news release contains future oriented financial information and financial outlook information (collectively, "FOFI") (including, without limitation, statements regarding expected average production), and are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraph. The FOFI has been prepared by management to provide an outlook of the Company's activities and results, and such information may not be appropriate for other purposes. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's reasonable estimates and judgments, however, actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it is made, and the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or results or otherwise, unless required by applicable laws. Non-IFRS Financial Measures This press release contains various "non-IFRS financial measures" (equivalent to "non-GAAP financial measures", as such term is defined in NI 52-112), "non-IFRS ratios" (equivalent to "non-GAAP ratios", as such term is defined in NI 52-112), "supplementary financial measures" (as such term is defined in NI 52-112) and "capital management measures" (as such term is defined in NI 52-112), which are described in further detail below. Such measures do not have standardized IFRS definitions. The Company's determination of these non-IFRS financial measures may differ from other reporting issuers and they are therefore unlikely to be comparable to similar measures presented by other companies. Furthermore, these financial measures should not be considered in isolation or as a substitute for measures of performance or cash flows as prepared in accordance with IFRS. These financial measures do not replace or supersede any standardized measure under IFRS. Other companies in our industry may calculate these measures differently than we do, limiting their usefulness as comparative measures. The Company discloses these financial measures, together with measures prepared in accordance with IFRS, because management believes they provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. These financial measures highlight trends in the Company's core business that may not otherwise be apparent when relying solely on IFRS financial measures. Further, management also uses non-IFRS measures to exclude the impact of certain expenses and income that management does not believe reflect the Company's underlying operating performance. The Company's management also uses non-IFRS measures in order to facilitate operating performance comparisons from period to period and to prepare annual operating budgets and as a measure of the Company's ability to finance its ongoing operations and obligations. Set forth below is a description of the non-IFRS financial measures, non-IFRS ratios, supplementary financial measures and capital management measures used in the MD&A. Operating EBITDA EBITDA is a commonly used non-IFRS financial measure that adjusts net income as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and DD&A. Operating EBITDA is a non-IFRS financial measure that represents the operating results of the Company's primary business, excluding the following items: restructuring, severance and other costs, post-termination obligation, payments of minimum work commitments and, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, and share-based compensation) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA, as they are not indicative of the underlying core operating performance of the Company. A reconciliation of Operating EBITDA to net loss is as follows: Three months ended June 30 Six months ended June 30 ($M) 2025 2024 2025 2024 Net loss (455,212) (2,846) (427,688) (11,349) Finance Income (2,073) (1,816) (3,556) (3,408) Finance expenses 18,310 17,429 33,715 34,699 Income tax (recovery) expense (12,957) 32,659 (22,608) 59,244 Depletion, depreciation and amortization 60,600 63,188 127,994 129,000 Expense (recovery) of asset retirement obligation 151 45 526 (997) Expenses of impairment 476,960 392 478,094 1,419 Trunkline incident costs — — 2,000 — Post-termination obligation (406) (364) (109) 186 Shared-based compensation 1,624 754 2,486 1,040 Restructuring, severance and other cost 9,526 1,052 10,527 2,855 Share of income from associates (14,124) (13,407) (29,233) (27,301) Foreign exchange loss 2,553 7,518 314 8,615 Other (income) loss (1,303) 2,774 (1,191) 3,133 Unrealized (gain) loss on risk management contracts (3,556) 3,646 (8,342) 11,585 Non-controlling interests (168) (288) (295) (443) Gain on repurchased of notes (11,735) (415) (11,925) (709) Debt extinguishment cost 5,964 — 5,964 — Colombian Temporary taxes 1,919 — 2,858 — Operating EBITDA 76,073 110,321 159,531 207,569 Capital Expenditures Capital expenditures is a non-IFRS financial measure that reflects the cash and non-cash items used by the Company to invest in capital assets. This financial measure considers oil and gas properties, plant and equipment, infrastructure, exploration and evaluation assets expenditures which are items reconciled to the Company's Statements of Cash Flows for the period. Infrastructure Colombia Calculations Each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative, is a non-IFRS financial measure, and each is used to evaluate the performance of the Infrastructure Colombia Segment operations. Adjusted Infrastructure Revenue includes revenues of the Infrastructure Colombia Segment including ODL's revenue direct participation interest. Adjusted Infrastructure Operating Costs includes costs of the Infrastructure Colombia Segment including ODL's cost direct participation interest. Adjusted Infrastructure General and Administrative includes general and administrative costs of the Infrastructure Colombia Segment including ODL's general and administrative direct participation interest. A reconciliation of each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative is provided below. (1) Revenues and expenses related to ODL are accounted for using the equity method, as described in Note 12 of the Interim Condensed Consolidated Financial Statements. Adjusted Infrastructure EBITDA The Adjusted Infrastructure EBITDA is a non-IFRS financial measure used to assist in measuring the operating results of the Infrastructure Colombia Segment business. (1) Non-IFRS financial measure Net Sales Net sales is a non-IFRS financial measure that adjusts revenue to include realized gains and losses from oil risk management contracts while removing the cost of any volumes purchased from third parties. This is a useful indicator for management, as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these oil risk management activities. The deduction of cost of purchases is helpful to understand the Company's sales performance based on the net realized proceeds from its own production, the cost of which is partially recovered when the blended product is sold. Net sales also exclude sales from port services, as it is not considered part of the oil and gas segment. Refer to the reconciliation in the "Sales" section on page 10 of the MD&A. Operating Netback and Oil and Gas Sales, Net of Purchases Operating netback is a non-IFRS financial measure and operating netback per boe is a non-IFRS ratio. Operating netback per boe is used to assess the net margin of the Company's production after subtracting all costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performance expressed as profit per barrel and is an indicator of how efficient the Company is at extracting and selling its product. For netback purposes, the Company removes the effects of any trading activities and results from its Infrastructure Colombia Segment from the per barrel metrics and adds the effects attributable to transportation and operating costs of any realized gain or loss on foreign exchange risk management contracts. Refer to the reconciliation in the "Operating Netback" section on page 9. The following is a description of each component of the Company's operating netback and how it is calculated. Oil and gas sales, net of purchases, is a non-IFRS financial measure that is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining costs. Oil and gas sales, net of purchases per boe, is a non-IFRS ratio that is calculated using oil and gas sales, net of purchases, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below: (1) Excludes sales from infrastructure services, as they are not part of the oil and gas segment. Refer to the "Infrastructure Colombia" section on page 19 for further details. Non-IFRS Ratios Realized oil price, net of purchases, and realized gas price per boe Realized oil price, net of purchases, and realized gas price per boe are both non-IFRS ratios. Realized oil price, net of purchases, per boe is calculated using oil sales net of purchases, divided by total sales volumes, net of purchases. Realized gas price is calculated using sales from gas production divided by the conventional natural gas sales volumes. (1) Non-IFRS financial measure. Net sales realized price Net sales realized price is a non-IFRS ratio that is calculated using net sales (including oil and gas sales net of purchases, realized gains and losses from oil risk management contracts and less royalties). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. A reconciliation of this calculation is provided below: Three months ended June 30 Six months ended June 30 ($M) 2025 2024 2025 2024 Oil and gas sales, net of purchases ($M) (1)(2) 170,943 217,130 368,918 417,904 Gain (loss) on oil price risk management contracts, net ($M) (3) 431 (3,796) (3,710) (7,285) (-) Royalties ($M) (2,304) (5,774) (5,364) (10,280) Net Sales ($M) 169,070 207,560 359,844 400,339 Sales volumes, net of purchases (boe) 2,872,688 2,868,593 5,936,619 5,615,246 Oil and gas sales, net of purchases ($/boe) 59.51 75.69 62.14 74.42 Premiums received (paid) on oil price risk management contracts (4) 0.15 (1.32) (0.62) (1.30) Royalties ($/boe) (0.80) (2.01) (0.90) (1.83) Net sales realized price ($/boe) 58.86 72.36 60.62 71.29 (1) Non-IFRS financial measure. (2) 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahia inter-segment costs related to diluent and oil purchases as well as transportation costs. (3) Includes the net amount of put premiums paid for expired positions and the positive cash settlement received from oil price contracts during the period. Refer to the "Gain (Loss) on Risk Management Contracts" section on page 15 for further details. (4) Supplementary financial measure. Purchase crude net margin Purchase crude net margin is a non-IFRS financial measure that is calculated using the purchased crude oil and products sales, less the cost of those volumes purchased from third parties including its transportation and refining costs. Purchase crude net margin per boe is a non-IFRS ratio that is calculated using the Purchase crude net margin, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below: (1) Cost of third-party volumes purchased for use and resale in the Company's oil operations, including its transportation and refining costs. (2) 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahía inter-segment costs related to diluent and oil purchases as well as transportation costs. Production costs (excluding energy cost), net of realized FX hedge impact, and production cost (excluding energy cost), net of realized FX hedge impact per boe Production costs (excluding energy cost), net of realized FX hedge impact is a non-IFRS financial measure that mainly includes lifting costs, activities developed in the blocks, processes to put the crude oil and gas in sales condition and the realized gain or loss on foreign exchange risk management contracts attributable to production costs. Production cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using production cost (excluding energy cost), net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below: (1) See "Gain (Loss) on Risk Management Contracts" on page 15. (2) Non-IFRS financial measure. Energy costs, net of realized FX hedge impact, and production cost, net of realized FX hedge impact per boe Energy costs, net of realized FX hedge impact is a non-IFRS financial measure that describes the electricity consumption and the costs of localized energy generation and the realized gain or loss on foreign exchange risk management contracts attributable to energy costs. Energy cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using energy cost, net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below: (1) See "Gain (Loss) on Risk Management Contracts" on page 15. (2) Non-IFRS financial measure. Transportation costs, net of realized FX hedge impact, and transportation costs, net of realized FX hedge impact per boe Transportation costs, net of realized FX hedge impact is a non-IFRS financial measure, that includes all commercial and logistics costs associated with the sale of produced crude oil and gas such as trucking and pipeline, and the realized gain or loss on foreign exchange risk management contracts attributable to transportation costs. Transportation cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using transportation cost, net of realized FX hedge impact divided by net production after royalties. A reconciliation of this calculation is provided below: Three months ended June 30 Six months ended June 30 2025 2024 2025 2024 Transportation costs ($M) 38,701 34,917 78,250 70,112 (-) Realized gain on FX hedge attributable to transportation costs ($M) (1) — (634) — (1,043) Puerto Bahía inter-segment costs (2) 692 470 1,328 901 Transportation costs, net of realized FX hedge impact ($M) (2)(3) 39,393 34,753 79,578 69,970 Net Production (boe) 3,389,204 3,139,955 6,652,293 6,210,568 Transportation costs, net of realized FX hedge impact ($/boe) 11.62 11.07 11.96 11.27 (1) See "Gain (Loss) on Risk Management Contracts" on page 15. (2) 2024 prior period figures are different compared with those previously reported as a result as a result of the inclusion of Puerto Bahia inter-segment costs related to cost of diluent and oil purchased, and transportation cost. (3) Non-IFRS financial measure. Supplementary Financial Measures Realized (loss) gain on oil risk management contracts per boe Realized (loss) gain on oil risk management contracts includes the gain or loss during the period, as a result of the Company´s exposure in derivative contracts of crude oil. Realized (loss) gain on oil risk management contracts per boe is a supplementary financial measure that is calculated using Realized (loss) gain on risk management contracts divided by total sales volumes, net of purchases. Royalties per boe Royalties includes royalties and amounts paid to previous owners of certain blocks in Colombia and cash payments for PAP. Royalties per boe is a supplementary financial measure that is calculated using the royalties divided by total sales volumes, net of purchases. NCIB weighted-average price per share Weighted-average price per share under the 2023 NCIB is a supplementary financial measure that corresponds to the weighted-average price of common shares purchased under the 2023 NCIB during the period. It is calculated using the total amount of common shares repurchased in U.S. dollars divided by the number of common shares repurchased. Capital Management Measures Restricted cash short- and long-term Restricted cash (short- and long-term) is a capital management measure, that sums the short-term portion and long-term portion of the cash that the Company has in term deposits that have been escrowed to cover future commitments and future abandonment obligations, or insurance collateral for certain contingencies and other matters that are not available for immediate disbursement. Total cash Total cash is a capital management measure to describe the total cash and cash equivalents restricted and unrestricted available, is comprised by the cash and cash equivalents and the restricted cash short and long-term. Total debt and lease liabilities Total debt and lease liabilities are capital management measures to describe the total financial liabilities of the Company and is comprised of the debt of the 2028 Unsecured Notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets. Definitions: SOURCE Frontera Energy Corporation
The Province
4 hours ago
- The Province
NBA approves Boston Celtics sale to private equity mogul Bill Chisholm for record $6.1B
Published Aug 13, 2025 • 1 minute read FILE - Lucky the Leprechaun, the Boston Celtics team logo, peers out from in between Celtics championship banners hanging in their new basketball team practice facility, Tuesday, June 19, 2018, in Boston. Photo by Elise Amendola / AP BOSTON — The NBA on Wednesday unanimously approved the sale of the Boston Celtics to a group led by private equity mogul Bill Chisholm, a deal that values the franchise at more than $6.1 billion — the largest ever for an American professional sports team. This advertisement has not loaded yet, but your article continues below. THIS CONTENT IS RESERVED FOR SUBSCRIBERS ONLY Subscribe now to read the latest news in your city and across Canada. Exclusive articles by top sports columnists Patrick Johnston, Ben Kuzma, J.J. Abrams and others. Plus, Canucks Report, Sports and Headline News newsletters and events. Unlimited online access to The Province and 15 news sites with one account. The Province ePaper, an electronic replica of the print edition to view on any device, share and comment on. Daily puzzles and comics, including the New York Times Crossword. Support local journalism. SUBSCRIBE TO UNLOCK MORE ARTICLES Subscribe now to read the latest news in your city and across Canada. Exclusive articles by top sports columnists Patrick Johnston, Ben Kuzma, J.J. Abrams and others. Plus, Canucks Report, Sports and Headline News newsletters and events. Unlimited online access to The Province and 15 news sites with one account. The Province ePaper, an electronic replica of the print edition to view on any device, share and comment on. Daily puzzles and comics, including the New York Times Crossword. Support local journalism. REGISTER / SIGN IN TO UNLOCK MORE ARTICLES Create an account or sign in to continue with your reading experience. Access articles from across Canada with one account. Share your thoughts and join the conversation in the comments. Enjoy additional articles per month. Get email updates from your favourite authors. THIS ARTICLE IS FREE TO READ REGISTER TO UNLOCK. Create an account or sign in to continue with your reading experience. Access articles from across Canada with one account Share your thoughts and join the conversation in the comments Enjoy additional articles per month Get email updates from your favourite authors The league said the transaction is expected to close shortly. When it does, Chisholm will take ownership of at least 51% of the team, with full control coming by 2028 at a price that could bring the total value to $7.3 billion. The previous record for a U.S. sports franchise was the $6.05 billion paid for the NFL's Washington Commanders in 2023. The record price for an NBA team was the $4 billion mortgage firm owner Mat Ishbia paid for the Phoenix Suns in 2023. Read More A Massachusetts native and graduate of Dartmouth College and Penn's Wharton School of Business, Chisholm is the managing partner of California-based Symphony Technology Group. The new ownership group also includes Boston businessmen Rob Hale, who is a current Celtics shareholder, and Bruce Beal Jr. Wyc Grousbeck led the ownership group that bought the team in 2002 for $360 million and presided over NBA championships in 2008 and '24. The franchise's 18 NBA titles is a record. Chisholm outbid at least two other groups, one led by previous Celtics minority partner Steve Pagliuca. Pagliuca has since announced plans to buy the WNBA's Connecticut Sun for $325 million and move them to Boston, but the women's league has balked at the deal. RECOMMENDED VIDEO Vancouver Whitecaps Vancouver Whitecaps Vancouver Whitecaps News Local News
Edmonton Journal
5 hours ago
- Edmonton Journal
Twins owners opt to halt sale of team, adding investors instead
MINNEAPOLIS — The Minnesota Twins are no longer for sale, executive chair Joe Pohlad announced Wednesday on behalf of his family. Article content After exploring a variety of options since publicizing the sale 10 months ago, the Pohlad family will remain the principal owner of the club and add new investors instead. Carl Pohlad, a banking magnate and the late grandfather of Joe Pohlad, bought the Twins in 1984 for $44 million. Article content Article content 'For more than four decades, our family has had the privilege of owning the Minnesota Twins. This franchise has become part of our family story, as it has for our employees, our players, this community, and Twins fans everywhere,' Joe Pohlad said in his announcement. 'Over the past several months, we explored a wide range of potential investment and ownership opportunities. Our focus throughout has been on what's best for the long-term future of the Twins. We have been fully open to all possibilities.' Article content Article content Pohlad said the family was in the process of adding two 'significant' limited partnership groups to bring in fresh ideas, bolster critical partnerships and shape the long-term vision of the franchise that relocated to Minnesota in 1961 after originating as the Washington Senators. Details about the new investors were being kept private until Major League Baseball approves the transactions, Pohlad said. Article content Article content Financial analysis earlier this year by Forbes valued the franchise at $1.5 billion, ranked 23rd in MLB. Sportico ($1.7 billion) and CNBC ($1.65 billion) pegged the Twins higher. Article content Article content The Pohlads hired Allen & Company, a New York-based investment bank, to direct the sale and keep inquiries confidential. Multiple published reports identified Justin Ishbia, a part owner of the NBA's Phoenix Suns, as the front-runner. But the Chicago White Sox announced last month that Ishbia was becoming a limited partner in a deal that provides a runway for him to become controlling owner. Article content MLB Commissioner Rob Manfred acknowledged during the All-Star break, without naming him directly, that Ishbia's decision sidetracked the process. Article content 'There will be a transaction,' Manfred said. 'You just need to be patient while they rework.' Article content The Twins are on track for their lowest attendance total in 16 seasons at Target Field, and an ownership-mandated payroll reduction last year in light of decreased regional television revenue, among other factors, has contributed to a dissatisfied customer base. The Twins traded 10 players off their roster leading up to the July 31 deadline, furthering the frustration.
