Coelacanth Announces Q2 2024 Financial and Operating Results

Rhea-AI Summary

Coelacanth Energy Inc. (TSXV: CEI) has released its Q2 2024 financial and operating results. Key highlights include:

- Oil and natural gas sales increased 283% to $3.16 million in Q2 2024 compared to Q2 2023
- Adjusted funds flow improved to $262,000 in Q2 2024 from -$756,000 in Q2 2023
- Average production grew 229% to 944 boe/d in Q2 2024 vs Q2 2023
- Operating netback improved to $15.10/boe in Q2 2024 from -$0.49/boe in Q2 2023

The company is progressing its Two Rivers Montney Project, with construction of the Two Rivers East infrastructure to begin soon. The facility is expected to handle up to 16,000 boe/d and start up in April 2025. Coelacanth has secured financing and believes the project is on schedule and budget.

Positive

• Oil and natural gas sales increased 283% year-over-year to $3.16 million in Q2 2024
• Adjusted funds flow improved to $262,000 in Q2 2024 from -$756,000 in Q2 2023
• Average production grew 229% year-over-year to 944 boe/d in Q2 2024
• Operating netback improved to $15.10/boe in Q2 2024 from -$0.49/boe in Q2 2023
• Two Rivers East facility expected to handle up to 16,000 boe/d when completed in April 2025
• Secured financing and on schedule for Two Rivers Montney Project

Negative

• Net loss increased to $2.33 million in Q2 2024 from $2.17 million in Q2 2023
• Cash flow from operating activities decreased to -$480,000 in Q2 2024 from $765,000 in Q2 2023
• Natural gas sales price decreased 49% year-over-year to $1.55/mcf in Q2 2024

Calgary, Alberta--(Newsfile Corp. - August 29, 2024) - COELACANTH ENERGY INC. (TSXV: CEI) ("Coelacanth" or the "Company") is pleased to announce its financial and operating results for the three and six months ended June 30, 2024. All dollar figures are Canadian dollars unless otherwise noted.

FINANCIAL RESULTS		Three Months Ended									Six Months Ended
		June 30									June 30
($000s, except per share amounts)		2024			2023			% Change			2024			2023			% Change
Oil and natural gas sales		3,164			826			283			6,830			1,780			284
Cash flow from (used in) operating activities		(480	)		765			(163	)		2,776			(1,277	)		(317	)
Per share - basic and diluted (1)		(-)			-			(-)			0.01			(-)			100
Adjusted funds flow (used) (1)		262			(756	)		(135	)		1,340			(1,310	)		(202	)
Per share - basic and diluted		-			(-)			(-)			-			(-)			(-)
Net loss		2,329			2,165			8			3,530			3,954			(11	)
Per share - basic and diluted		-			0.01			(100	)		0.01			0.01			-
Capital expenditures (1)		2,522			3,642			(31	)		3,785			8,781			(57	)
Adjusted working capital (1)											64,386			56,500			14
Common shares outstanding (000s)
Weighted average - basic and diluted		529,400			425,447			24			529,298			425,282			24
End of period - basic											530,126			426,389			24
End of period - fully diluted											617,804			469,143			32

 

(1) See "Non-GAAP and Other Financial Measures" section.

		Three Months Ended									Six Months Ended
OPERATING RESULTS (1)		June 30									June 30
		2024			2023			% Change			2024			2023			% Change
Daily production (2)
Oil and condensate (bbls/d)		284			53			436			292			49			496
Other NGLs (bbls/d)		39			14			179			38			14			171
Oil and NGLs (bbls/d)		323			67			382			330			63			424
Natural gas (mcf/d)		3,724			1,321			182			3,829			1,350			184
Oil equivalent (boe/d)		944			287			229			968			288			236
Oil and natural gas sales
Oil and condensate ($/bbl)		97.76			88.89			10			91.34			91.61			(-)
Other NGLs ($/bbl)		33.26			28.03			19			33.99			35.43			(4	)
Oil and NGLs ($/bbl)		89.86			76.11			18			84.73			79.21			7
Natural gas ($/mcf)		1.55			3.03			(49	)		2.50			3.58			(30	)
Oil equivalent ($/boe)		36.85			31.63			17			38.76			34.11			14
Royalties
Oil and NGLs ($/bbl)		21.97			20.84			5			21.36			23.41			(9	)
Natural gas ($/mcf)		0.09			0.64			(86	)		0.30			0.83			(64	)
Oil equivalent ($/boe)		7.86			7.77			1			8.48			9.02			(6	)
Operating expenses
Oil and NGLs ($/bbl)		10.34			17.49			(41	)		10.11			17.23			(41	)
Natural gas ($/mcf)		1.72			2.92			(41	)		1.69			2.87			(41	)
Oil equivalent ($/boe)		10.34			17.53			(41	)		10.11			17.23			(41	)
Net transportation expenses (3)
Oil and NGLs ($/bbl)		2.10			1.85			14			2.28			1.65			38
Natural gas ($/mcf)		0.72			1.39			(48	)		0.70			1.34			(48	)
Oil equivalent ($/boe)		3.55			6.82			(48	)		3.54			6.66			(47	)
Operating netback (loss) (3)
Oil and NGLs ($/bbl)		55.45			35.93			54			50.98			36.92			38
Natural gas ($/mcf)		(0.98	)		(1.92	)		(49	)		(0.19	)		(1.46	)		(87	)
Oil equivalent ($/boe)		15.10			(0.49	)		(3,182	)		16.63			1.20			1,286
Depletion and depreciation ($/boe)		(14.85	)		(18.34	)		(19	)		(14.63	)		(17.14	)		(15	)
General and administrative expenses ($/boe)		(15.17	)		(46.77	)		(68	)		(14.50	)		(46.56	)		(69	)
Stock based compensation ($/boe)		(14.50	)		(33.31	)		(56	)		(12.25	)		(31.21	)		(61	)
Finance expense ($/boe)		(1.53	)		(4.29	)		(64	)		(1.29	)		(3.73	)		(65	)
Finance income ($/boe)		9.89			25.59			(61	)		10.25			26.40			(61	)
Unutilized transportation ($/boe)		(6.07	)		(5.35	)		13			(4.24	)		(4.76	)		(11	)
Net loss ($/boe)		(27.13	)		(82.96	)		(67	)		(20.03	)		(75.80	)		(74	)

 

(1) See "Oil and Gas Terms" section.
(2) See "Product Types" section.
(3) See "Non-GAAP and Other Financial Measures" section.

Selected financial and operational information outlined in this news release should be read in conjunction with Coelacanth's unaudited condensed interim financial statements and related Management's Discussion and Analysis ("MD&A") for the three and six months ended June 30, 2024, which are available for review under the Company's profile on SEDAR+ at www.sedarplus.com.

OPERATIONS UPDATE

In Q2 2024, Coelacanth continued to make strides on its large Two Rivers Montney Project. All licenses have been received for construction of the Two Rivers East infrastructure that includes a battery facility and related pipeline infrastructure. Construction will commence shortly on the pipelines that connect our 5-19 pad to the battery as well as the pipelines that connect ultimately to the McMahon gas plant that will process Coelacanth's raw gas. Components for the facility have been ordered and are in construction off-site with the field construction starting later in the fall for an April 2025 start-up date. Coelacanth has secured all required financing for the project and believes it will be on schedule and on budget.

The Two Rivers East facility will ultimately handle up to approximately 16,000 boe/d consisting of 60 mmcf/d of gas plus related oil and natural gas liquids. As previously released, the 5-19 pad currently has 4 completed wells that tested at a combined rate of 4,410 boe/d (55% light oil) that will come on production once the facility is completed. ⁽¹⁾

Once on production, Coelacanth plans to drill additional wells on the 5-19 and other pads to fill the facility. Coelacanth has secured 60 mmcf/d of long-term processing and over 60 mmcf/d of gas transportation to accommodate this growth.

Coelacanth's current production comes from Two Rivers West and was 944 boe/d for the quarter. Facility restrictions on both water and gas handling will limit production at Two Rivers West until additional pipelines and facilities can be permitted and constructed. Timing of adding any material production will be longer term given the capital focus on Two Rivers East infrastructure for 2024 but Two Rivers West results show great potential for future development.

We look forward to reporting updates on the Two Rivers Project in the upcoming quarters.

(1) See "Test Results and Initial Production Rates" section for more details.

OIL AND GAS TERMS

The Company uses the following frequently recurring oil and gas industry terms in the news release:

Liquids
Bbls	Barrels
Bbls/d	Barrels per day
NGLs	Natural gas liquids (includes condensate, pentane, butane, propane, and ethane)
Condensate	Pentane and heavier hydrocarbons

 

Natural Gas
Mcf	Thousands of cubic feet
Mcf/d	Thousands of cubic feet per day
MMcf/d	Millions of cubic feet per day
MMbtu	Million of British thermal units
MMbtu/d	Million of British thermal units per day

 

Oil Equivalent
Boe	Barrels of oil equivalent
Boe/d	Barrels of oil equivalent per day

 

Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used for the calculation of boe amounts in the news release. This boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

NON-GAAP AND OTHER FINANCIAL MEASURES

This news release refers to certain measures that are not determined in accordance with IFRS (or "GAAP"). These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with IFRS as indicators of the Company's performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company's ongoing operating performance, and the measures provide increased transparency to better analyze the Company's performance against prior periods on a comparable basis.

Non-GAAP Financial Measures

Adjusted funds flow (used)
Management uses adjusted funds flow (used) to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and abandonment obligations and to repay debt, if any. Adjusted funds flow (used) is a non-GAAP financial measure and has been defined by the Company as cash flow from (used in) operating activities excluding the change in non-cash working capital related to operating activities, movements in restricted cash deposits and expenditures on decommissioning obligations. Management believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such may not be useful for evaluating the Company's cash flows. Adjusted funds flow (used) is reconciled from cash flow from (used in) operating activities as follows:

		Three Months Ended June 30						Six Months Ended June 30
($000s)		2024			2023			2024			2023
Cash flow from (used in) operating activities		(480	)		765			2,776			(1,277	)
Add (deduct):
Decommissioning expenditures		328			210			476			752
Restricted cash deposits		422			(1,237	)		846			(784	)
Change in non-cash working capital		(8	)		(494	)		(2,758	)		(1	)
Adjusted funds flow (used) (non-GAAP)		262			(756	)		1,340			(1,310	)

 

Net transportation expenses
Management considers net transportation expenses an important measure as it demonstrates the cost of utilized transportation related to the Company's production. Net transportation expenses is calculated as transportation expenses less unutilized transportation and is calculated as follows:

		Three Months Ended June 30						Six Months Ended June 30
($000s)		2024			2023			2024			2023
Transportation expenses		826			318			1,371			596
Unutilized transportation		(522	)		(139	)		(747	)		(248	)
Net transportation expenses (non-GAAP)		304			179			624			348

 

Operating netback
Management considers operating netback an important measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated as oil and natural gas sales less royalties, operating expenses, and net transportation expenses and is calculated as follows:

		Three Months Ended June 30						Six Months Ended June 30
($000s)		2024			2023			2024			2023
Oil and natural gas sales		3,164			826			6,830			1,780
Royalties		(674	)		(203	)		(1,495	)		(471	)
Operating expenses		(888	)		(458	)		(1,782	)		(899	)
Net transportation expenses		(304	)		(179	)		(624	)		(348	)
Operating netback (loss) (non-GAAP)		1,298			(14	)		2,929			62

 

Capital expenditures
Coelacanth utilizes capital expenditures as a measure of capital investment on property, plant, and equipment, exploration and evaluation assets and property acquisitions compared to its annual budgeted capital expenditures. Capital expenditures are calculated as follows:

	Three Months Ended June 30		Six Months Ended June 30
($000s)	2024	2023	2024	2023
Capital expenditures - property, plant, and equipment	184	3,022	577	6,559
Capital expenditures - exploration and evaluation assets	2,338	620	3,208	2,222
Capital expenditures (non-GAAP)	2,522	3,642	3,785	8,781

 

Capital Management Measures

Adjusted working capital
Management uses adjusted working capital as a measure to assess the Company's financial position. Adjusted working capital is calculated as current assets and restricted cash deposits less current liabilities, excluding the current portion of decommissioning obligations.

($000s)		June 30, 2024			December 31, 2023
Current assets		60,515			87,616
Less:
Current liabilities		(5,098	)		(28,754	)
Working capital		55,417			58,862
Add:
Restricted cash deposits		7,206			6,784
Current portion of decommissioning obligations		1,763			1,943
Adjusted working capital (Capital management measure)		64,386			67,589

 

Non-GAAP Financial Ratios

Adjusted Funds Flow (Used) per Share
Adjusted funds flow (used) per share is a non-GAAP financial ratio, calculated using adjusted funds flow (used) and the same weighted average basic and diluted shares used in calculating net loss per share.

Net transportation expenses per boe
The Company utilizes net transportation expenses per boe to assess the per unit cost of utilized transportation related to the Company's production. Net transportation expenses per boe is calculated as net transportation expenses divided by total production for the applicable period.

Operating netback per boe
The Company utilizes operating netback per boe to assess the operating performance of its petroleum and natural gas assets on a per unit of production basis. Operating netback per boe is calculated as operating netback divided by total production for the applicable period.

Supplementary Financial Measures

The supplementary financial measures used in this news release (primarily average sales price per product type and certain per boe and per share figures) are either a per unit disclosure of a corresponding GAAP measure, or a component of a corresponding GAAP measure, presented in the financial statements. Supplementary financial measures that are disclosed on a per unit basis are calculated by dividing the aggregate GAAP measure (or component thereof) by the applicable unit for the period. Supplementary financial measures that are disclosed on a component basis of a corresponding GAAP measure are a granular representation of a financial statement line item and are determined in accordance with GAAP.

PRODUCT TYPES

The Company uses the following references to sales volumes in the news release:

Natural gas refers to shale gas
Oil and condensate refers to condensate and tight oil combined
Other NGLs refers to butane, propane and ethane combined
Oil and NGLs refers to tight oil and NGLs combined
Oil equivalent refers to the total oil equivalent of shale gas, tight oil, and NGLs combined, using the conversion rate of six thousand cubic feet of shale gas to one barrel of oil equivalent.

The following is a complete breakdown of sales volumes for applicable periods by specific product types of shale gas, tight oil, and NGLs:

	Three Months Ended June 30		Six Months Ended June 30
Sales Volumes by Product Type	2024	2023	2024	2023
Condensate (bbls/d)	56	6	38	7
Other NGLs (bbls/d)	39	14	38	14
NGLs (bbls/d)	95	20	76	21
Tight oil (bbls/d)	228	47	254	42
Condensate (bbls/d)	56	6	38	7
Oil and condensate (bbls/d)	284	53	292	49
Other NGLs (bbls/d)	39	14	38	14
Oil and NGLs (bbls/d)	323	67	330	63
Shale gas (mcf/d)	3,724	1,321	3,829	1,350
Natural gas (mcf/d)	3,724	1,321	3,829	1,350
Oil equivalent (boe/d)	944	287	968	288

 

TEST RESULTS AND INITIAL PRODUCTION RATES

The A5-19 Basal Montney well was production tested for 5.9 days and produced at an average rate of 117 bbl/d oil and 630 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The C5-19 Lower Montney well was production tested for 5.8 days and produced at an average rate of 736 bbl/d oil and 2,660 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The D5-19 Lower Montney well was production tested for 12.6 days and produced at an average rate of 170 bbl/d oil and 580 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The E5-19 Lower Montney well was production tested for 11.4 days and produced at an average rate of 312 bbl/d oil and 890 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable and production was starting to decline.

For the short-term production test of the C10-08 Upper Montney well in February 2024, the well was production tested for 2 days and produced at an average rate of 359 bbl/d oil and 5,236 mcf/d gas (net of load fluid and energizing fluid) over that period. This was an inline test to prove deliverability after four months of production. At the end of the test, flowing wellhead pressure and production rates were stable.

A pressure transient analysis or well-test interpretation has not been carried out on these five wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.

Any references to peak rates, test rates, IP30, IP90, IP180 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will continue production and decline thereafter and are not indicative of long-term performance or ultimate recovery. IP30 is defined as an average production rate over 30 consecutive days, IP90 is defined as an average production rate over 90 consecutive days and IP180 is defined as an average production rate over 180 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company.

FORWARD-LOOKING INFORMATION

This document contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.

More particularly and without limitation, this news release contains forward-looking statements and information relating to the Company's oil and condensate, other NGLs, and natural gas production, capital programs, and adjusted working capital. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities, and the availability and cost of labour and services.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs, and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty, and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Coelacanth is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in northeastern British Columbia, Canada.

Further Information

For additional information, please contact:

Coelacanth Energy Inc.
Suite 2110, 530 - 8^th Avenue SW
Calgary, Alberta T2P 3S8
Phone: (403) 705-4525
www.coelacanth.ca

Mr. Robert J. Zakresky
President and Chief Executive Officer

Mr. Nolan Chicoine
Vice President, Finance and Chief Financial Officer

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/221433

FAQ

What was Coelacanth Energy's (CEIEF) revenue in Q2 2024?

Coelacanth Energy's oil and natural gas sales (revenue) in Q2 2024 were $3.164 million, a 283% increase from $826,000 in Q2 2023.

How much did Coelacanth Energy (CEIEF) produce in Q2 2024?

Coelacanth Energy's average production in Q2 2024 was 944 boe/d, a 229% increase from 287 boe/d in Q2 2023.

When is Coelacanth Energy's (CEIEF) Two Rivers East facility expected to start up?

Coelacanth Energy's Two Rivers East facility is expected to start up in April 2025, with a capacity to handle up to approximately 16,000 boe/d.

What was Coelacanth Energy's (CEIEF) operating netback in Q2 2024?

Coelacanth Energy's operating netback in Q2 2024 was $15.10/boe, improved from -$0.49/boe in Q2 2023.