TD Bank Group could be hit with more severe penalties than previously expected, says a banking analyst after a report that the investigation it faces in the U.S. is tied to laundering illicit fentanyl profits.
National Bank analyst Gabriel Dechaine said in a note that the worst-case scenario of the multiple U.S. investigations TD faces needs reassessing after the Wall Street Journal reported the link on Thursday.
The newspaper said the U.S. Justice Department investigation is focused on how Chinese drug traffickers allegedly used TD to launder at least US$653 million, and bribed TD employees to do so.
TD did not comment directly on the report, but said its anti-money laundering defences had been deficient.
“Criminals constantly seek to use banks to launder money. Regrettably, our U.S. (anti-money laundering) program did not effectively thwart these activities. This is unacceptable, and we must and we will do better,” said spokeswoman Elizabeth Goldenshtein in a statement.
She said the bank continues to co-operate with law enforcement and regulators, and that a comprehensive effort is underway to strengthen its anti-money laundering program.
Dechaine said the severity of the allegations means TD could not only face fines well above the $500 million to $1 billion that many investors have anticipated, but also more severe regulator-imposed limitations on its business activities.
“We believe investors need to put greater weight on worst-case scenarios for the stock,” he said in a note.
The cumulative fines could easily hit $2 billion, while regulators could put in place restrictions, including limits on its balance sheet growth, that could affect bank operations for years, said Dechaine.
In a worst-case scenario, the issue could erode TD’s future earnings potential by more than $1 billion, he said, and he has dropped his price target for the bank’s TSX-listed shares by almost nine per cent to $84.
The link to drug trafficking comes the same week TD announced it had taken an initial provision of US$450 million in connection to the ongoing U.S. regulatory inquiry into its anti-money laundering compliance program.
The bank said on Tuesday its discussions with three U.S. regulators and the Department of Justice are ongoing, and it anticipates additional financial penalties.
Separately, Canada’s financial-crime watchdog Fintrac levied a $9.2-million penalty against the bank on Thursday for non-compliance with money laundering and terrorist financing measures.
TD Bank’s stock price was down more than four per cent in midday trading Friday to $75.85 on the Toronto Stock Exchange.
Canopy said in a Friday news release that it intends to use the net proceeds for working capital and general corporate purposes.
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The Smiths Falls, Ontario-based business also said it plans to exchange approximately CA$27.5 million of existing debt, which matures in September 2025, for a new senior unsecured convertible debenture that matures in five years.
Under the deal, the unidentified investor will acquire the convertible debenture in an aggregate principal amount equal to CA$96,358,375.
Canopy will issue to the investor an additional 3,350,430 common share purchase warrants.
Each warrant entitles the holder to acquire a common share at an exercise price of CA$16.18 for a period of five years.
The convertible debenture bears interest at a rate of 7.5% per year.
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The debenture will be convertible into common shares at the option of the investor at a price of CA$14.38 per share. That’s the Canadian dollar equivalent of the average Nasdaq closing price of the shares for the five trading days preceding the agreement.
Canopy shares trade as CGC on the Nasdaq and WEED on the Toronto Stock Exchange.
TORONTO — TD Bank Group could be hit with more severe penalties than previously expected, says a banking analyst after a report that the investigation it faces in the U.S. is tied to laundering illicit fentanyl profits.
National Bank analyst Gabriel Dechaine said in a note that the worst-case scenario of the multiple U.S. investigations TD faces needs reassessing after the Wall Street Journal reported the link on Thursday.
Article content
The newspaper said the U.S. Justice Department investigation is focused on how Chinese drug traffickers allegedly used TD to launder at least US$653 million, and bribed TD employees to do so.
TD did not comment directly on the report, but said its anti-money laundering defences had been deficient.
“Criminals constantly seek to use banks to launder money. Regrettably, our U.S. (anti-money laundering) program did not effectively thwart these activities. This is unacceptable, and we must and we will do better,” said spokeswoman Elizabeth Goldenshtein in a statement.
She said the bank continues to co-operate with law enforcement and regulators, and that a comprehensive effort is underway to strengthen its anti-money laundering program.
Dechaine said the severity of the allegations means TD could not only face fines well above the $500 million to $1 billion that many investors have anticipated, but also more severe regulator-imposed limitations on its business activities.
“We believe investors need to put greater weight on worst-case scenarios for the stock,” he said in a note.
Article content
The cumulative fines could easily hit $2 billion, while regulators could put in place restrictions, including limits on its balance sheet growth, that could affect bank operations for years, said Dechaine.
In a worst-case scenario, the issue could erode TD’s future earnings potential by more than $1 billion, he said, and he has dropped his price target for the bank’s TSX-listed shares by almost nine per cent to $84.
The link to drug trafficking comes the same week TD announced it had taken an initial provision of US$450 million in connection to the ongoing U.S. regulatory inquiry into its anti-money laundering compliance program.
The bank said on Tuesday its discussions with three U.S. regulators and the Department of Justice are ongoing, and it anticipates additional financial penalties.
Separately, Canada’s financial-crime watchdog Fintrac levied a $9.2-million penalty against the bank on Thursday for non-compliance with money laundering and terrorist financing measures.
TD Bank’s stock price was down more than four per cent in midday trading Friday to $75.85 on the Toronto Stock Exchange.
This report by The Canadian Press was first published May 3, 2024.
Primaris REIT (PMZ.UN-T) is coming off a strong first quarter and has significantly increased its war chest for further shopping centre acquisitions, its CEO said during the trust’s May 2 quarterly investors and analysts call.
The REIT’s net income rose by $10.3 million from a year earlier to reach $45.88 million in its first quarter ended March 31, one in which positives outweighed negatives.
Primaris is Canada’s only enclosed shopping centre-focused real estate investment trust and the country’s largest owner of enclosed malls by property count.
“The acquisitions completed in 2023, our larger national footprint and high asset quality continues to increase our relevance with both existing tenants and new and exciting new-to-market retailers,” chief executive officer Alex Avery said during a May 2 conference call to review the trust’s financial and operational performance.
“We have robust liquidity and are finding lots of attractive opportunities. We have capacity for more than $1.5 billion of acquisitions and require no financing conditions in our deals.
“This profile as a well-capitalized and credible counter-party in the market is a real differentiator in what is a currently challenging transaction market for many participants.”
First quarter highlights
In comparison to the first quarter of 2023, Primaris saw:
its investment portfolio rise to 39 properties from 35;
gross leasable area increase to 12.5 million square feet from 10.9 million;
in-place occupancy improve to 92 per cent from 90.6 per cent;
committed occupancy rise to 94.1 per cent from 91.3 per cent;
weighted average net rent per occupied square foot increase to $25.10 from $24.30;
same-property cash net operating income growth of two per cent;
and same-store sales productivity per square foot jump to $628 from $607. The sales number increases to $677 with the inclusion of the REIT’s two major 2023 acquisitions, Conestoga Mall in Waterloo, Ont., and Halifax Shopping Centre.
Primaris was spun off from H&R REIT through a non-taxable distribution of units on Dec. 31, 2021. Concurrently, Healthcare of Ontario Pension Plan (HOOPP) contributed six large-format shopping centres in exchange for approximately 26 per cent of Primaris’ units.
Primaris’ total assets were valued at $3.93 billion and unencumbered assets at $3.3 billion in the first quarter. Total assets were valued at $3.28 billion and unencumbered assets at $2.71 billion a year earlier.
Total available liquidity rose to $684.33 million from $468.3 million during the same period 12 months earlier. The total-debt-to-total-assets ratio was 38.9 per cent compared to 33.5 per cent during the first three months of 2023.
Steady leasing activity
Conestoga Mall in Waterloo, Ont. (Courtesy Ivanhoe Cambridge)
Primaris completed 149 leasing deals totalling about 500,000 square feet in the first quarter and the tenant renewal rate was 82.3 per cent. There were 26 lease deals with new tenants covering 150,700 square feet.
President and chief operating officer Pat Sullivan said Primaris is in advanced negotiations with a number of large-format tenants and he anticipates those deals closing over the next two quarters.
Primaris has 883,000 square feet of 2024 expiring leases remaining to deal with and Sullivan claims to have no concerns about completing those negotiations.
“Our leasing and operations teams work diligently to identify new brands that would complement and enhance our tenant mix, while proactively working to reduce exposure to those tenants that are losing relevance with the consumer,” Sullivan said.
Rent growth
There was a 7.4 per cent weighted average spread on renewing rents across 277,000 square feet. Primaris typically pushes for two per cent annual increases in its leases, but it varies depending on the tenant, according to Sullivan.
The macro environment for malls — including a declining supply of retail gross leasable area, population growth, rising tenant sales and increasing tenant demand for space — creates a significant opportunity to drive rent growth and higher occupancy to quality tenants with the ability to pay increasing rents over time, Sullivan explained.
“The financial health of tenants continues to be quite favourable and the dialogue with tenants looking for new expansion opportunities remains robust.”
The $54-million redevelopment of the former Sears store at Halifax Shopping Centre was completed last year. A 56,200-square-foot Simons, a 38,500-square-foot Winners, a 13,000-square-foot Dollarama and a 15,000-square-foot PetSmart opened in the space during the first quarter of this year.
Garden City Square and other dispositions
Primaris entered into an agreement to sell Garden City Square — an open-air, non-grocery-anchored retail property in Winnipeg — for $31 million during the quarter. The deal is expected to close on May 23.
“This is our first non-core, income-producing property disposition entered into since the spin-off and aligns with our strategy to focus on a growing high-quality portfolio of market-leading enclosed shopping centres in Canada,” Avery said. “This disposition improves our overall portfolio quality and growth profile and further demonstrates Primaris’ ability to transact. We are currently engaged in discussions with prospective purchasers for further dispositions.
“Our capital recycling program is a key pillar supporting our profile as a buyer of market-leading malls and positions us well to capitalize on future opportunities.”
The majority of assets for sale are smaller, unenclosed retail properties, but an industrial building and land parcels are also available. The assets, including Garden City Square, are valued at $124 million.
Primaris continues to buy back units
Primaris’ net asset value per unit was $21.86 at the end of the first quarter while its unit price closed at $13.49 on the Toronto Stock Exchange on May 2. Its 52-week low price is $12.11 while the 52-week high price is $14.24. The REIT has a market cap of $1.3 billion.
Primaris has continually been repurchasing units since March 2022 because they’ve been trading at a significant discount to net asset value.
“We are very comfortable in continuing to buy back units,” Avery said.
May 3 (Reuters) – Canada’s main stock index jumped on
Friday, led by gains in technology shares after slowing U.S.
jobs growth in April raised hopes of early interest rate cuts by
the U.S. Federal Reserve.
At 9:31 a.m. ET (1331 GMT), the Toronto Stock Exchange’s
S&P/TSX composite index was up 147.89 points, or
0.68%, at 21,971.11.
(Reporting by Shubham Batra in Bengaluru)
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TORONTO — dynaCERT Inc. (TSX: DYA) (OTCMKTS: DYFSF) (FRA: DMJ) (“dynaCERT” or the “Company”) is pleased to announce the appointment of Dr. James Damien Tansey as a director of the Company.
Originally trained in environmental sciences, Dr. Tansey brings 20 years of experience at the interface of university research and the private sector. He also brings to dynaCERT expertise in carbon markets, clean technology, social acceptability of novel technologies, impact investing and social innovation. Dr. Tansey has also been an advisor and investor in early stage companies including Gemina Labs, Exro Technologies, Syniad Innovations Inc. and Charitable Impact. He was founder of NatureBank Asset Management and previously CIO of Global Sustainable Capital Management (UK).
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Dr. Tansey is the CEO and a Director of Carbon Done Right Developments, Vancouver BC ( TSX:V KLX), a public company focused on the development of carbon credits from nature based solutions which to date has developed a portfolio of over 43Mt of carbon credits.
Dr. Tansey is also currently Associate Professor of the Sauder School of Business, University of British Columbia where he established the Centre for Social Innovation and Impact Investing. He has served as an advisor to the BC Government on Clean Energy strategy and Social Enterprise and was a Committee member for the Federal Social Innovation and Social Finance Advisory Task Force that launched the $755 Million social finance fund.
As CEO and Founder of NatureBank Asset Management he established one of the largest carbon market development companies in Canada and helped establish two of the largest forest carbon projects in the world: Great Bear Rainforest and Mai Ndombe in the DRC. The Company delivered the world’s first carbon neutral Olympics in 2010 in Vancouver, Canada. Until 2006, he was Deputy Director and Lecturer at James Martin Institute, Saïd Business School at Oxford. Dr. Tansey was also Senior Research Associate of the University of British Columbia and led projects on scenario modelling, impact of genomics and social determinants of health.
Dr. Tansey holds a Ph.D. in Sociology of Risk from the School of Environmental Sciences, University of East Anglia; a B.Sc. in Environmental Sciences from the University of East Anglia and an International Baccalaureate from Atlantic College.
Dr. Tansey was granted the Queen Elizabeth Diamond Jubilee Medal for environmental contributions to the Province (2013) and was included in the Top 40 under 40 and a Finalist with the Ernst and Young Entrepreneur of the Year.
Dr. James Tansey, director of dynaCERT, stated, “dynaCERT’s development of proprietary technology aimed at reducing carbon emissions will benefit our world for generations to come. dynaCERT’s professional management has a profound understanding of the latest developments and trends in the hydrogen marketplace and is poised to continue advancing as a global leader in this space. I am eager to work alongside dynaCERT’s world-class team and being part of a company that is advancing hydrogen innovations.”
Jim Payne, President and CEO of dynaCERT stated, “The dynaCERT Board of Directors is very pleased to welcome Dr. James Tansey as a director of the Company. Dr. Tansey has the proven track record to support dynaCERT in its upcoming Carbon Credit programme which will benefit all our clients by providing an annual stream of income to users of our HydraGEN™ technology in addition to reducing fuel costs. Our entire Company, our stakeholders, clients, dealers and shareholders are joining me in greeting Dr. Tansey as a dynamic strong supporter of the furtherance of our hydrogen technology on a global scale across many industries world-wide.”
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About dynaCERT Inc.
dynaCERT Inc. manufactures and distributes Carbon Emission Reduction Technology along with its proprietary HydraLytica™ Telematics, a means of monitoring fuel consumption and calculating GHG emissions savings designed for the tracking of possible future Carbon Credits for use with internal combustion engines. As part of the growing global hydrogen economy, our patented technology creates hydrogen and oxygen on-demand through a unique electrolysis system and supplies these gases through the air intake to enhance combustion, which has shown to lower carbon emissions and improve fuel efficiency. Our technology is designed for use with many types and sizes of diesel engines used in on-road vehicles, reefer trailers, off-road construction, power generation, mining and forestry equipment. Website: www.dynaCERT.com.
READER ADVISORY
Except for statements of historical fact, this news release contains certain “forward-looking information” within the meaning of applicable securities law. Forward-looking information is frequently characterized by words such as “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate” and other similar words, or statements that certain events or conditions “may” or “will” occur. Although we believe that the expectations reflected in the forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. We cannot guarantee future results, performance of achievements. Consequently, there is no representation that the actual results achieved will be the same, in whole or in part, as those set out in the forward-looking information.
Forward-looking information is based on the opinions and estimates of management at the date the statements are made and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those anticipated in the forward-looking information. Some of the risks and other factors that could cause the results to differ materially from those expressed in the forward-looking information include, but are not limited to: uncertainty as to whether our strategies and business plans will yield the expected benefits; availability and cost of capital; the ability to identify and develop and achieve commercial success for new products and technologies; the level of expenditures necessary to maintain and improve the quality of products and services; changes in technology and changes in laws and regulations; the uncertainty of the emerging hydrogen economy; including the hydrogen economy moving at a pace not anticipated; our ability to secure and maintain strategic relationships and distribution agreements; and the other risk factors disclosed under our profile on SEDAR at www.sedar.com. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
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The forward-looking information contained in this news release is expressly qualified by this cautionary statement. We undertake no duty to update any of the forward-looking information to conform such information to actual results or to changes in our expectations except as otherwise required by applicable securities legislation. Readers are cautioned not to place undue reliance on forward-looking information.
Neither the Toronto Stock Exchange nor its Regulation Services Provider (as that term is defined in the policies of the Toronto Stock Exchange) accepts responsibility for the adequacy or accuracy of the release.
Canada’s largest oil and gas producer Canadian Natural Resources is looking at opportunities to significantly increase bitumen output at its main oil sands mine, the company said on Thursday.
President ScottStauth said the company is considering a 195 000 barrel-a-day (b/d) expansion at its Horizon mining and upgrading plant in northern Alberta through new extraction and treatment processes. Previously the company said it could add 75 000 b/d of bitumen, but Stauth said Canadian Natural had been able to enhance engineering and scale up the processes.
Horizon currently has capacity to produce about 255 000 b/d of synthetic crude oil made from bitumen.
Stauth said the expansion would depend upon new pipeline export capacity as well as government financial support for a carbon capture and storage project proposed by the Pathways Alliance group, which Canadian Natural is part of.
“That fiscal policy is absolutely key for us to be able to move any additional expansion volumes forward,” Stauth said on an earnings call. “Also important in terms of that would be securing and working on enhancing egress capacity.”
In its earnings release, Canadian Natural said it will benefit from the start-up of the Trans Mountain oil pipeline expansion, in which it can move 94 000 bb/d.
The company also increased its shipping commitment on the Flanagan South pipeline to the US Gulf Coast in the first quarter, to 77 500 b/d from 22 500 b/d.
Canadian Natural missed analysts’ estimates for first-quarter profit, hurt by lower-than-expected production and a drop in natural gas and synthetic crude oil prices.
The firm posted an adjusted profit of C$1.37 a share, below analysts’ average estimates of C$1.48 a share, according to LSEG data. Net earnings were C$987-million compared with C$1.8-billion for the first quarter of 2023.
The Calgary-based company produced 1.33-million barrels of oil equivalent per day (boepd) in the first quarter, slightly higher than the same period last year but lower than analysts’ expectations of 1.35 million boepd.
Oil sands mining production fell 3% from year-ago levels to 445209 bb/ld, due to planned and unplanned maintenance.
The company’s realized natural gas price fell 40% to C$2.55 per thousand cubic feet on average for the quarter from a year earlier, amid a slump in North American gas markets due to record production and low heating demand during a mild winter.
In oil sands mining, synthetic crude oil prices decreased nearly 8% to an average C$88.84/bl.
Canadian Natural said it will shift some drilling activity away from dry gas wells and towards heavy oil, and plans to ramp up activity in the second half of the year when it anticipates stronger pricing.
Canadian Natural shares were last down 0.3% at C$102.80 on the Toronto Stock Exchange.
The content in this section is supplied by Business Wire for the purposes of distributing press releases on behalf of its clients. Postmedia has not reviewed the content.
THOUSAND OAKS, Calif. — All amounts are in U.S. Dollars unless otherwise indicated:
2023 HIGHLIGHTS
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Adjusted EBITDA(1) was $39.1 million in 2023 compared to $25.1 million in 2022, an increase of 56%. This increase was due to the increase in production of 70% and lower realized losses from commodity contracts partially offset by a decrease in average prices of 22%
Net revenues for 2023 were $50.6 million, an increase of 35% compared to 2022. This increase was primarily due to a 70% increase in production partially offset by a 22% decrease in average prices in 2023 compared to 2022
Net income in 2023 was $19.3 million ($0.54 per basic share) compared to $16.6 million ($0.47 per basic share) in 2022. Net income increased by $2.6 million or 16% over 2022 due to higher production, lower realized losses and higher unrealized gains on commodity contracts partially offset by lower prices, and higher depreciation and income tax expense compared to 2022
Average production for 2023 was 2,796 BOEPD, an increase of 70% compared to 2022 production of 1,640 BOEPD. The increase is due to production from the wells that were drilled and completed in 2023
The Company’s NPV10 of Total Proved Reserves was $482.6 million for 2023, which was a 6% decrease from 2022 according to the Company’s December 31, 2023, independent reserves evaluation, due primarily to lower estimated future pricing and the 2023 production
Netback from operations(2) decreased to $42.97 per BOE compared to $54.56 per BOE in 2022, a decrease of 21%. Netback including commodity contracts(2) for 2023 was $41.61 per BOE compared to $47.79 per BOE in 2022, a decrease of 13% from the prior year. These decreases compared to the prior year were due to lower average prices of 22%
Production and operating expense per barrel averaged $6.61 per BOE in 2023 compared to $8.19 per BOE in 2022, a decrease of 19%. The decrease was due to increased production which reduced the per barrel fixed costs as well as lower production taxes
The net debt of the Company at December 31, 2023 was $29.4 million. As of December 31, 2023, the Company has $10 million of available borrowing capacity on the credit facility
The ratio of debt to Adjusted EBITDA was 0.68 at December 31, 2023
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(1)
Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
(2)
Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
Kolibri’s President and Chief Executive Officer, Wolf Regener commented:
“We are excited about the continued production and cash flow growth of the Company in 2023 after our transformative year in 2022. The Company increased Adjusted EBITDA(1) by 56% by successfully drilling and completing eight wells during the year which increased production by 70%. Management is expecting to build on the Company’s continued growth in 2024. We drilled two additional wells in December 2023 and January 2024 that will be fracture stimulated later in the year. In April, we finished drilling the Nickel Hill 35-1H and Nickel Hill 35-2H wells (both 62.9% working interest) under budget and faster than we had forecasted. We expect to begin fracture stimulation operations on these wells in early May.
“During the first quarter of 2024, the Company reworked three wells which were impacted by offset fracture stimulations. Wells that were impacted by offset fracture stimulations reduced production for the quarter by about 275 BOEPD. Production in the first quarter averaged about 3,305 BOEPD. At the end of the first quarter of 2024, production from the impacted wells hadn’t fully recovered yet, and another two reworks were undertaken in April. Even with the impacted wells, oil production is tracking above our year end reserve engineer’s forecast.
“Adjusted EBITDA(1) was $39.1 million in 2023 compared to $25.1 million in 2022, an increase of 56%. This increase was due to a 70% increase in production and lower realized losses from commodity contracts partially offset by a 22% decrease in average prices.
“The average production for 2023 was 2,796 BOEPD, an increase of 70% compared to 2022 production of 1,640 BOEPD. The increase is due to production from the wells that were drilled and completed in 2023.
“Net revenues for 2023 were $50.6 million, an increase of 35% compared to 2022. This increase was primarily due to a 70% increase in production partially offset by a 22% decrease in average prices in 2023 compared to 2022.
“Net income in 2023 was $19.3 million compared to $16.6 million in 2022, an increase of 16% due to higher production, lower realized losses and higher unrealized gains on commodity contracts partially offset by lower prices and higher depreciation and income tax expense compared to 2022.
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“Netback from operationsdecreased to $42.97 per BOE compared to $54.56 per BOE in 2022, a decrease of 21%. Netback including commodity contractsfor 2023 was $41.61 per BOE compared to $47.79 per BOE in 2022, a decrease of 13% from the prior year. These decreases compared to the prior year were due to lower average prices of 22%.
“Production and operating expense per barrel averaged $6.61 per BOE in 2023 compared to $8.19 per BOE in 2022, a decrease of 19%. The decrease was due to increased production which reduced the per barrel fixed costs and lower production taxes.”
Fourth Quarter
Year Ended
2023
2022
%
2023
2022
%
Net Income:
$ Thousands
$4,797
$2,793
72%
$19,280
$16,643
16%
$ per basic common share
$0.14
$0.08
75%
$0.54
$0.47
15%
Adjusted EBITDA(1)
$10,502
$6,838
53%
$39,080
$25,112
56%
Capital Expenditures
$15,996
$17,184
(7%)
$53,173
$37,097
43%
Average Production (Boepd)
2,842
1,868
52%
2,796
1,640
70%
Gross Revenue
17,192
12,455
38%
64,390
48,376
33%
Average Price per Barrel
$65.76
$72.47
(9%)
$63.10
$80.82
(22%)
Netback from operations per Barrel(2)
$44.40
$48.39
(8%)
$42.97
$54.56
(21%)
Netback including commodity contracts per Barrel(2)
$43.43
$46.05
(6%)
$41.61
$47.79
(13%)
December 2023
December 2022
Cash and Cash Equivalents
$598
$1,037
Working Capital
$(11,916)
$(6,569)
Borrowing Capacity
10,042
6,842
(1)
Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
(2)
Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
YEAR ENDED 2023 TO YEAR ENDED 2022
For 2023, oil and gas gross revenues increased $16.0 million or 33% to $64.4 million. Oil revenues before royalties increased by 40% to $59.7 million due to an 73% increase in production partially offset by a 19% decrease in prices. Natural gas revenues before royalties decreased by $1.0 million or 37% due to a 59% decrease in average gas prices partially offset by a 54% increase in natural gas production. NGL revenue before royalties increased by $0.1 million or 3% due to a 71% increase in production partially offset by a 40% decrease in average prices.
Average production for 2023 was 2, 796 BOEPD, an increase of 70% compared to 2022 average production of 1,640 BOEPD due to the wells drilled during 2023.
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Production and operating expenses increased by $1.0 million due to an increase in production for 2023. Production and operating expense per barrel averaged $6.61 per BOE in 2023 compared to $8.19 per BOE in 2022, a decrease of 19%. The decrease was due to increased production which reduced the fixed per barrel costs and lower production taxes.
Depletion and depreciation expense increased $7.4 million, or 98%, in 2023 due to increased production and a higher PP&E balance.
General and administrative expenses increased $0.7 million or 21% in 2023 due to higher costs associated with the dual listing process, higher investor relations and marketing costs and increases in payroll and director costs.
Finance income increased by $1.3 million due to higher unrealized gains on financial commodity contracts recorded in 2023.
Finance expense decreased by $1.3 million due to lower realized losses on commodity contracts in 2023 compared to 2022, partially offset by higher interest expense in 2023.
FOURTH QUARTER HIGHLIGHTS:
Adjusted EBITDA(1) was $10.5 million in the fourth quarter of 2023 compared to $6.9 million in 2022, an increase of 53%. This increase was due to the increase in production partially offset by the decrease in average prices
Net revenues for the fourth quarter of 2023 were $13.4 million, an increase of 38%, compared to the fourth quarter of 2022. This increase was primarily due to an increase in production partially offset by a decrease in average prices
Net income in the fourth quarter of 2023 was $4.8 million, compared to net income of $2.8 million in the fourth quarter of 2022. The increase was due to higher average production and an unrealized gain on commodity contracts in 2023 partially offset by lower average prices and higher income tax expense in 2023
Average production for the fourth quarter of 2023 was 2,842 BOEPD, an increase of 52% compared to fourth quarter 2022 production of 1,868 BOEPD. The increase is due to production from the new wells drilled in 2023.
Netback from operations(2) decreased to $44.40 per BOE in the fourth quarter of 2023 compared to $48.39 per BOE in the fourth quarter of 2022, a decrease of 8%. Netback including commodity contracts(2) for the fourth quarter of 2023 was $43.43 per BOE compared to $46.05 in the fourth quarter of 2022, a decrease of 6% from the prior year quarter. The 2023 decreases compared to the prior year was due to the decrease in average prices
Production and operating expense per barrel averaged $7.02 per BOE in the fourth quarter of 2023 compared to $8.25 per BOE in the fourth quarter of 2022, a decrease of 15%. The decrease was due to increased production which reduced the per barrel fixed costs.
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(1)
Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
(2)
Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
FOURTH QUARTER 2023 TO FOURTH QUARTER 2022
Gross oil and gas revenues totaled $17.2 million in the fourth quarter of 2023 versus $12.5 million in the fourth quarter of 2022, an increase of 38%. Oil revenues were $16.2 million in the fourth quarter of 2023 versus $11.5 million in the fourth quarter of 2022, an increase of 41%, due to increased average production partially offset by lower prices. Natural gas revenues decreased 49% to $0.3 million in the fourth quarter of 2023 due to lower average prices partially offset by higher production. NGL revenue increased 78% to $0.7 million due to higher production, partially offset by lower average prices.
Operating expenses were $1.6 million in the fourth quarter of 2023 compared to $1.4 million in 2022 due to higher production.
General and administrative expenses increased by 6% in the fourth quarter of 2023 compared to the prior year fourth quarter due to higher costs associated with the dual listing process and higher investor relations and marketing costs.
Finance income in the fourth quarter of 2023 increased by $2.2 million from the fourth quarter of 2022 due to an unrealized gain on commodity contracts in the fourth quarter of 2023.
Finance expense in the fourth quarter of 2023 decreased by $0.9 million from the fourth quarter of 2022 due to an unrealized loss on commodity contracts in 2022 partially offset by higher interest expense.
KOLIBRI GLOBAL ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Unaudited, Expressed in Thousands of United States Dollars)
December 31,
December 31,
2023
2022
Current assets
Cash and cash equivalents
$
598
$
1,037
Trade and other receivables
5,492
5,773
Deposits and prepaid expenses
838
670
6,928
7,480
Non-current assets
Fair value of commodity contracts
78
–
Property, plant and equipment
216,161
176,554
Right of use assets
1,190
48
Total assets
$
224,357
$
184,082
Current liabilities
Trade and other payables
$
17,648
$
12,596
Current lease payable
1,068
32
Fair value of commodity contracts
128
1,421
18,844
14,049
Non-current liabilities
Loans and borrowings
29,612
17,799
Asset retirement obligations
1,966
1,425
Lease payable
162
17
Deferred taxes
3,359
–
Fair value of commodity contracts
–
594
35,099
19,835
Equity
Share capital
296,232
296,221
Contributed surplus
24,179
23,254
Deficit
(149,997
)
(169,277
)
Total equity
170,414
150,198
Total equity and liabilities
$
224,357
$
184,082
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KOLIBRI GLOBAL ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited, expressed in Thousands of United States dollars, except per share amounts)
Three months ended
December 31
Year ended
December 31
2023
2022
2023
2022
Revenue:
Oil and natural gas revenue, net
$
13,444
$
9,734
$
50,597
$
37,560
Other income
–
1
2
46
13,444
9,735
50,599
37,606
Expenses:
Production and operating
1,567
1,417
5,895
4,904
Depletion and depreciation
3,506
2,495
15,009
7,581
General and administrative
1,122
1,059
4,243
3,494
Share based compensation
259
45
790
277
6,454
5,016
25,937
16,256
Finance income
2,225
–
1,813
464
Finance expense
(1,059
)
(1,926
)
(3,836
)
(5,171
)
Income tax expense
(3,359
)
–
(3,359
)
–
Net income and comprehensive income
$
4,797
$
2,793
$
19,280
$
16,643
Net income per share
Basic
$
0.14
$
0.08
$
0.54
$
0.47
KOLIBRI GLOBAL ENERGY INC.
FOURTH QUARTER AND YEAR ENDED 2023
(Unaudited, expressed in Thousands of United States dollars, except as noted)
4th Quarter
Year Ended Dec. 31
2023
2022
2023
2022
Oil revenue before royalties
$
16,212
$
11,478
$
59,749
$
42,795
Gas revenue before royalties
305
598
1,742
2,759
NGL revenue before royalties
675
379
2,899
2,822
17,193
12,455
64,390
48,376
Adjusted EBITDA(1)
10,502
6,854
39,080
25,112
Additions to PP&E
15,996
17,184
53,173
37,097
Statistics:
4th Quarter
Year Ended Dec. 31
2023
2022
2023
2022
Average oil production (Bopd)
2,245
1,551
2,144
1,241
Average natural gas production (mcf/d)
1,428
969
1,630
1,061
Average NGL production (Boepd)
359
155
380
222
Average production (Boepd)
2,842
1,868
2,796
1,640
Average oil price ($/bbl)
$
78.51
$
80.42
$
76.34
$
94.46
Average natural gas price ($/mcf)
$
2.32
$
6.71
$
2.93
$
7.12
Average NGL price ($/bbl)
$
20.41
$
26.66
$
20.89
$
34.88
Average price per barrel
$
65.76
$
72.47
$
63.10
$
80.82
Royalties per barrel
14.34
15.83
13.52
18.07
Operating expenses per barrel
7.02
8.25
6.61
8.19
Netback from operations(2)
$
44.40
$
48.39
$
42.97
$
54.56
Price adjustment from commodity contracts (Boe)
(0.97
)
(2.34
)
(1.36
)
(6.77
)
Netback including commodity contracts (Boe)(2)
$
43.43
$
46.05
$
41.61
$
47.79
(1)
Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
(2)
Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
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The information outlined above is extracted from and should be read in conjunction with the Company’s audited financial statements for the year ended December 31, 2023 and the related management’s discussion and analysis thereof, copies of which are available under the Company’s profile at www.sedarplus.ca.
NON-GAAP MEASURES
Netback from operations, netback including commodity contracts and adjusted EBITDA (collectively, the “Company’s Non-GAAP Measures”) are not measures or ratios recognized under Canadian generally accepted accounting principles (“GAAP”) and do not have any standardized meanings prescribed by IFRS. Management of the Company believes that such measures and ratios are relevant for evaluating returns on each of the Company’s projects as well as the performance of the enterprise as a whole. The Company’s Non-GAAP Measures may differ from similar computations as reported by other similar organizations and, accordingly, may not be comparable to similar non-GAAP measures and ratios as reported by such organizations. The Company’s Non-GAAP Measures should not be construed as alternatives to net income, cash flows related to operating activities, working capital or other financial measures and ratios determined in accordance with IFRS, as an indicator of the Company’s performance.
An explanation of how the Company’s Non-GAAP Measures provide useful information to an investor and the purposes for which the Company’s management uses the Non-GAAP Measures is set out in the management’s discussion and analysis under the heading “Non-GAAP Measures” which is available under the Company’s profile at www.sedarplus.ca and is incorporated by reference into this earnings release.
The following is the reconciliation of the non-GAAP ratio netback from operations to net income, which the Company considers to be the most directly comparable financial measure that is disclosed in the Company’s financial statements:
(US $000)
Year ended
December 31,
2023
2022
Net income
19,280
16,643
Adjustments:
Finance income
(1,813
)
(464
)
Finance expense
3,836
5,171
Stock based compensation
790
277
General and administrative expenses
4,243
3,494
Income tax expense
3,359
–
Depletion, depreciation and amortization
15,009
7,581
Other income
(2
)
(46
)
Operating netback
44,702
32,656
Netback from operations
$54.56
$54.56
The following is the reconciliation of the non-GAAP measure adjusted EBITDA to the comparable financial measures disclosed in the Company’s financial statements:
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(US $000)
Year Ended December 31,
2023
2022
Net income
19,280
16,643
Depletion and depreciation
15,009
7,581
Accretion
183
34
Interest expense
2,263
1,070
Unrealized (gain) loss on commodity contracts
(1,813
)
(461
)
Share based compensation
790
277
Interest income
–
(3
)
Income tax expense
3,359
–
Other income
(2
)
(46
)
Foreign currency loss
11
17
Adjusted EBITDA
39,080
25,112
CAUTIONARY STATEMENTS
In this news release and the Company’s other public disclosure:
(a)
The Company’s natural gas production is reported in thousands of cubic feet (“Mcfs“). The Company also uses references to barrels (“Bbls“) and barrels of oil equivalent (“Boes“) to reflect natural gas liquids and oil production and sales. Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
(b)
Discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value.
(c)
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
(d)
The Company discloses peak and 30-day initial production rates and other short-term production rates. Readers are cautioned that such production rates are preliminary in nature and are not necessarily indicative of long-term performance or of ultimate recovery.
Readers are referred to the full description of the results of the Company’s December 31, 2022 independent reserves evaluation and other oil and gas information contained in its amended and restated Form 51-101F1 Statement of Reserves Data and Other Oil and Gas Information for the year ended December 31, 2023, which the Company filed on SEDAR on March 25, 2024.
Caution Regarding Forward-Looking Information
This release contains forward-looking information including estimates of reserves, the proposed timing and expected results of exploratory and development work including fracture stimulation and production from the Company’s Tishomingo field, Oklahoma acreage, the future performance of wells including following shut-in’s and restart of well(s), the expected effects of cost reduction efforts, forecasts regarding the Company’s 2024 drilling program including expected capital expenditures, annual average production, net revenues, adjusted EBITDA, and net debt at year end, availability of funds from the Company’s reserves based loan facility, and the Company’s strategy and objectives. The use of any of the words “target”, “plans”, “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe”, “intend” and similar expressions are intended to identify forward-looking statements.
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Such forward-looking information is based on management’s expectations and assumptions, including that the Company’s geologic and reservoir models and analysis will be validated, that indications of early results are reasonably accurate predictors of the prospectiveness of the shale intervals, that previous exploration results are indicative of future results and success, that expected production from future wells can be achieved as modeled, declines will match the modeling, future well production rates will be improved over existing wells, that rates of return as modeled can be achieved, that recoveries are consistent with management’s expectations, including that new production will perform per a type curve which is similar to NSAI’s December 2023 proved type curve, that additional wells are actually drilled and completed, that design and performance improvements will reduce development time and expense and improve productivity, that discoveries will prove to be economic, that anticipated results and estimated costs will be consistent with managements’ expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the price of oil will be sustained or increase, that the Company will continue to be able to access sufficient capital through financings, credit facilities, farm-ins or other participation arrangements to maintain its projects, that the Company will continue in compliance with the covenants under its reserves-based loan facility, that the Company will not be adversely affected by changing government policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates and that global economic conditions will not deteriorate in a manner that has an adverse impact on the Company’s business and its ability to advance its business strategy.
Forward looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: any of the assumptions on which such forward looking information is based vary or prove to be invalid, including that the Company’s geologic and reservoir models or analysis are not validated, anticipated results and estimated costs will not be consistent with managements’ expectations, the risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration and development projects or capital expenditures; the uncertainty of reserve and resource estimates and projections relating to production, costs and expenses, and health, safety and environmental risks including flooding and extended interruptions due to inclement or hazardous weather), the risk of commodity price and foreign exchange rate fluctuations, risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with continued development of the Tishomingo Field, the Company or its subsidiaries is not able for any reason to obtain and provide the information necessary to secure required approvals or that required regulatory approvals are otherwise not available when required, that unexpected geological results are encountered, that completion techniques require further optimization, that production rates do not match the Company’s assumptions, that very low or no production rates are achieved, that the price of oil will decline, that the Company will cease to be in compliance with the covenants under its reserves-based loan facility and be required to repay outstanding amounts or that the borrowing base will be reduced pursuant to a borrowing base re-determination and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, that funding is not available from the Company’s reserves based loan facility at the times or in the amounts required for planned operations, that occurrences such as those that are assumed will not occur, do in fact occur, and those conditions that are assumed will continue or improve, do not continue or improve and the other risks identified in the Company’s most recent Annual Information Form under the “Risk Factors” section, the Company’s most recent management’s discussion and analysis and the Company’s other public disclosure, available under the Company’s profile on SEDAR at www.sedarplus.ca.
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With respect to estimated reserves, the evaluation of the Company’s reserves is based on a limited number of wells with limited production history and includes a number of assumptions relating to factors such as availability of capital to fund required infrastructure, commodity prices, production performance of the wells drilled, successful drilling of infill wells, the assumed effects of regulation by government agencies and future capital and operating costs. All of these estimates will vary from actual results. Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, may vary. The Company’s actual production, revenues, taxes, development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material. In addition to the foregoing, other significant factors or uncertainties that may affect either the Company’s reserves or the future net revenue associated with such reserves include material changes to existing taxation or royalty rates and/or regulations, and changes to environmental laws and regulations.
Although the Company has attempted to take into account important factors that could cause actual costs or results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The forward-looking information included in this release is expressly qualified in its entirety by this cautionary statement. Accordingly, readers should not place undue reliance on forward-looking information. The Company undertakes no obligation to update these forward-looking statements, other than as required by applicable law.
About Kolibri Global Energy Inc.
Kolibri Global Energy Inc. is a North American energy company focused on finding and exploiting energy projects in oil and gas. Through various subsidiaries, the Company owns and operates energy properties in the United States. The Company continues to utilize its technical and operational expertise to identify and acquire additional projects in oil, gas and clean and sustainable energy. The Company’s shares are traded on the Toronto Stock Exchange under the stock symbol KEI and on the NASDAQ under the stock symbol KGEI.
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