Tethys Petroleum — Management Reports 2024

Apr 26, 2024

Tethys Petroleum Limited

Management’s Discussion and Analysis for the year ended December 31, 2023

Contents

Nature of business	1
Financial highlights	2
Operational highlights	4
Operational review	6
Financial review	13
Risks, uncertainties and other information	22
Forward looking statements	23
Glossary	25

The following MD&A is dated April 26, 2024 and should be read in conjunction with the Tethys Petroleum Limited (hereinafter “the Company”) and its subsidiaries (hereinafter together with subsidiaries “the Group”) audited consolidated financial statements and related notes for the year ended December 31, 2023. The accompanying consolidated financial statements of the Group have been prepared by management and approved by the Group’s Audit Committee and Board of Directors. The consolidated financial statements have been prepared in accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board (“IFRS Accounting Standards”). Amounts are stated in thousands of US dollars unless otherwise noted. Additional information relating to the Group can be found on the SEDAR website www.sedar.com and the Group’s website at www.tethys-group.com .

Readers should also read the “Forward-Looking Statements” legal advisory wording contained at the end of this MD&A.

Nature of Business

Tethys Petroleum Limited is an oil and gas company operating within the Republic of Kazakhstan. Tethys’ principal activity is the exploration and development of crude oil and natural gas fields. The address of the Company’s registered office is Grand Pavilion Hibiscus Way, 802 West Bay Road, Grand Cayman KY1-1205, Cayman Islands. The domicile of Tethys is the Cayman Islands where it is incorporated.

The Company has its primary listing on TSX Venture Exchange (“TSXV”). The Company is also listed on the Kazakhstan Stock Exchange (“KASE”).

1

Financial highlights

(All references to $ are United States dollars unless otherwise noted and tabular amounts are in thousands, unless otherwise stated)

		Twelve months ended December 31	Twelve months ended December 31	Twelve months ended December 31
	2023	2022	**Change **	2021	**Change **
Oil and gas sales revenues	36,479	65,492	(44%)	15,906	312%
Profit/(loss) for the year	9,736	12,300	(21%)	(3,989)	-
Earnings/(loss) ($) per share -basic	0.08	0.11	(27%)	(0.04)	-
Adjusted EBITDA1	25,080	52,459	(52%)	9,674	442%
Capital expenditure	12,068	22,977	(47%)	15,491	48%
		As at 31 December
	2023	2022	**Change **	2021	**Change **
Total assets	85,331	87,266	(2%)	73,944	18%
Cash & cash equivalents	7,216	14,538	(50%)	9,277	57%
Short & long-term borrowings	-	2,510	(100%)	6,578	(62%)
Total non-current liabilities	38,264	32,488	18%	16,603	96%
Net (cash)/debt1	(7,202)	(6,834)	5%	11,583	-
Number of ordinary shares outstanding	115,075,013	116,107,233	(1%)	107,548,114	8%

Note 1 - Adjusted EBITDA and net debt are non-GAAP Measures, refer to page 20 for details.

Twelve months 2023 versus twelve months in 2022

• Oil and gas sales revenues decreased by 44% to $36.5 million from $65.5 million. Oil sales revenue was $34.3 million compared with $60.4 million in the prior year with the reduction due to lower production volume and lower average price received. Gas sales revenue was $2.2 million compared with $5.1 million in the prior year. Gas revenue in 2023 represents an adjustment to the estimated amount receivable for gas delivered in 2022 as gas production in 2023 was minimal, further details are given on page 11;

• The profit for the year was $9.7 million compared with $12.3 million in 2022. Profit before tax reduced by 55% to $18.5 million from $41.3 million mainly due to the lower oil and gas revenues and a lower depletion charge. This reduction was offset by a reduction in the tax charge to $8.7 million from $29.0 million resulting in a 21% reduction in profit for the year after tax;

• Adjusted EBITDA, a non-GAAP measure, was $25.1 million, a significant reduction from the $52.5 million in 2022, mainly as a result of the lower oil and gas revenues;

• Capital expenditure of $12.1 million was lower than the $23.0 million in 2023 and mainly comprises payments to the drilling contractor, purchase of equipment and construction of facilities in preparation for the resumption of oil production;

• Total assets reduced by 2% to $85.3 million from $87.3 million at the end of the prior year. Property, plant & equipment increased by $8.2 million which was offset by a reduction in cash & cash equivalents of $7.3 million and a reduction in trade & other receivables of $3.0 million;

• Cash & cash equivalents were $7.2 million compared with $14.5 million at the end of the prior year. Cash inflow from operating activities was $9.8million (2022: $34.1 million), net cash used in investing activities was $11.0 million (2022: $22.5 million) and net cash used in financing activities was $5.9 million (2022: $5.2 million) including repayment of borrowings of $3.1 million (2022:$2.8 million) and dividend payment of $2.6 million (2022: $1.7 million);

2

Financial highlights - continued

• Short & long-term borrowings at December 31, 2023 were nil (2022: $2.5 million) after the Gemini debenture was repaid in April 2023. The Group is now debt free;

• Total non-current liabilities increased by 17% to $38.1 million from $32.5 million at the end of the prior year due to an increase in the deferred tax liability of $3.8 million and the recognition of a liability for historical costs due to the government of $2.0 million, refer to page 7 for further details;

• Net cash/debt (which includes deferred revenue), a non-GAAP measure, increased from $6.8 million to $7.2 million net cash. This includes a reduction in deferred oil revenue from $5.2 million to nil as well as the reductions in borrowings and cash & cash equivalents mentioned above;

• The number of ordinary shares outstanding reduced by 1% to 115.1 million as a result of shares repurchased and cancelled.

Twelve months 2022 versus twelve months in 2021

• Oil and gas sales revenues increased by 312% to $65.5 million from $15.9 million. Oil sales were $60.4 million compared with $6.0 million in the prior year and gas sales were $5.1 million compared with $9.9 million in the prior year. Gas revenue from January 1, 2022 was recorded on an estimated basis as the price had not yet been agreed;

• The profit for the year was $12.3 million compared with a loss of $4.0 million in 2021. The profit for the year was a result of the higher oil revenues partly offset by lower gas revenues, and higher production and administrative expenses. The result also included a $1.8 million impairment charge relating to unsuccessful wells (2021: $1.0 million) and a tax charge of $29.0 million (2021: $7.7 million) comprising current tax of $9.2 million and deferred tax of $19.8 million;

• Adjusted EBITDA, a non-GAAP measure, was $52.5 million, a significant improvement from the $9.7 million in 2021, reflecting the better contribution from oil production partly offset by a lower contribution from gas;

• Capital expenditure increased to $23.0 million from $15.5 million due to higher payments for drilling costs;

• Total assets increased by 18% to $87.3 million due mainly to the $5.3 million increase in cash and $5.1 million increase in trade and other receivables due to non-payment for gas since January 1, 2022;

• Cash & cash equivalents increased by $5.3 million to $14.5 million. Cash inflow from operating activities was $34.1 million (2021: $14.9 million), net cash inflow from investing activities was $22.5 million (2021: $8.7 million) and net cash used in financing activities was $5.2 million (2021: positive $1.4 million) including repayment of borrowings of $2.8 million and the Company’s first dividend payment of $1.7 million;

• Short & long-term borrowings decreased to $2.5 million from $6.6 million due to repayment of the Gemini unsecured loan during the year;

• Total non-current liabilities increased to $32.5 million from $16.6 million mainly due to the increase in provision for deferred taxes of $19.6 million partly offset by the reduction in noncurrent borrowings of $3.9 million;

• Net debt (which includes deferred revenue) reduced from $11.6 million to $6.8 million net cash reflecting the cash generated from operations;

• The number of ordinary shares outstanding increased by 8% to 116.1 million as a result of shares issued on conversion of half of the Gemini debenture.

3

Operational Highlights

		Quarter ended December 31	Quarter ended December 31	Quarter ended December 31	Year	ended December	31
	Units	2023	2022	Change	2023	2022	Change
Kazakhstan
Oil	bopd	1,419	4,358	(67%)	3,180	4,154	(23%)
Gas	boe/d	2	1,066	(100%)	5	1,350	(100%)
Total	boe/d	1,421	5,424	(74%)	3,185	5,504	(42%)
Oil
Oil production	bbls	130,523	400,941	(67%)	1,160,764	1,516,301	(23%)
Oil sold	bbls	169,012	402,695	(58%)	1,163,421	1,512,259	(23%)
Revenue	$’000	4,245	16,845	(75%)	34,259	60,402	(43%)
Cost of production	$’000	2,119	4,150	(49%)	12,018	14,460	(17%)
Contribution before tax	$’000	2,126	12,695	(83%)	22,241	45,942	(52%)
Revenue	$/bbl	25.12	41.83	(40%)	29.45	39.94	(26%)
Cost of production	$/bbl	16.23	10.35	57%	10.35	9.54	9%
Contribution before tax	$/bbl	8.89	31.48	(72%)	19.10	30.40	(37%)
Gas
Gas production	Mcm	36	16,661	(100%)	285	83,713	(100%)
Gas sold	Mcm	-	16,253	(100%)	232	81,802	(100%)
Revenue	$’000	2,179	1,802	21%	2,209	5,079	(57%)
Cost of production	$’000	2,357	1,696	39%	4,449	5,376	(17%)
Contribution before tax	$’000	(178)	106	-	(2,240)	(297)	655%
Revenue	$/Mcm	-	110.86	-	-	62.09	-
Cost of production	$/Mcm	-	101.79	-	-	64.22	-
Contribution before tax	$/Mcm	-	9.07	-	-	(2.13)	-

Oil

• Oil production for the quarter averaged 1,419 bopd compared with 4,358 bopd in Q4 2022 and for the year averaged 3,180 bopd compared with 4,154 bopd in 2022. The Group produced oil from the Kul-bas field from three pilot production wells and three appraisal wells in 2023 (2022: 3 pilot wells and 3 appraisal wells). Further details are provided on page 10;

• Total oil production for Q4 2023 was 130,523 barrels compared with 400,941 barrels in Q4 2022 and for the year was 1,160,764 barrels compared with 1,516,301 barrels in 2022;

• Oil revenue for the quarter was $4.2 million (2022: $16.8 million) or $25.12/bbl (2022: $41.83/bbl) and for the year was $34.3 million (2022: $60.4 million) or $29.45/bbl (2022: $39.94/bbl);

• Oil production costs for the quarter were $2.1 million (2022: $4.2 million) or $16.23/bbl (2022: $10.35/bbl) resulting in a contribution before tax of $8.89/bbl (2022: $31.48/bbl) and for the year production costs were $12.0 million (2022: $14.5 million) or $10.35/bbl (2022: $9.54/bbl) resulting in a contribution before tax of $19.10/bbl (2022: $30.40/bbl). Further details of production costs are given on page 16.

4

Operational Highlights - continued

Gas

• Gas production in 2023 was minimal, averaging 2 boe/d compared with 1,066 boe/d in Q4 2022 and for the year averaged 5 boe/d compared with 1,350 boe/d in 2022. The reduction in production resulted from the closure of the gas fields due to the gas price dispute with the Group’s customer QazaqGaz, a state-owned enterprise;

• Gas revenue for the year of $2.2 million is the result of an adjustment to the estimated price receivable for the gas delivered in 2022. Payment was received for gas delivered in January-April 2022 at a higher price than was recognised in 2022 and payment for the remaining eight months, which remains outstanding, is also expected to at a higher price than recognised in 2022, albeit lower than for the payment received for the first four months of 2022;

• Gas production costs for the quarter were $2.4 million (2022: $1.7 million or $101.79/Mcm). For the year gas production costs were $4.4 million (2022: $5.4 million or $64.22/Mcm). Further details of production costs are given on pages 16.

Outlook

The information provided under this heading is considered as forward-looking information; as such please refer to Forward-Looking Statements on page 23 of this MD&A.

The Group's objective is to become one of the leading oil and gas exploration and production company in Central Asia. The goal is to exercise capital discipline and generate cash flow from new and existing discoveries within our acreage under license. The Group seeks to provide good employment opportunities, support for the local communities and seeks to be a leading company in the economically and ecologically sensitive Aral Sea area.

The Group's long-term ambition is to achieve a significant role in the production and delivery of hydrocarbons from the Central Asian region. The specific focus of management in the short term is to:

• Continue our development of the Group’s oil & gas fields and licenses to increase production levels and revenues. The particular focus is the Kul-bas oil field where we are working towards a full commercial production license;

• Continue to improve the marketing of oil and gas to achieve best prices;

• Continue to improve the logistics where the Group can increase its ability to ship oil volumes at reduced costs; and

• Continue to fund the Group’s development plans from operations while exploring potential financing and partnership alternatives.

5

Operational Review

Significant events and transactions for the year

• McDaniel & Associates estimates of oil & gas reserves and economic evaluation

The Group’s “Proved” 1P reserves at December 31, 2023 were 49.5 million BOE (2022: 45.8 million BOE) and “Proved + Probable” 2P reserves were 85.7 million BOE (2022: 82.2 million BOE). The net present value after tax of the Group’s 2P reserves as at December 31, 2023 was $628.7 million (2022: $610.5 million), based on a 10% discount rate. Refer to the section below headed Reserves for further details and basis of preparation.

• Oil & gas operations

For details of oil & gas operations during the year, refer to sections below headed Results of Operations and Operational Review.

 Dividend declared

On January 18, 2023, the Company announced the approval of a quarterly dividend of 3 CAD cents per ordinary share with a record date of January 26, 2023 and payment date of February 9, 2023. The total amount of dividends paid was $2,599,000.

 Normal course issuer bid

On February 9, 2023 the Company announced that it intended to make another normal course issuer bid, subject to exchange approval. The Company was authorized to acquire up to 5,805,361 ordinary shares (roughly 5% of the shares outstanding of the Company) during the period on or about February 10, 2023 to February 10, 2024. The Company uses ATB Capital Markets as its member broker to conduct the purchases. Purchases are made through the facilities of the TSX Venture Exchange. Purchase and payment for the securities are made by the Company in accordance with exchange requirements. The price which the Company pays is the market price at the time of acquisition. The Group believes the shares are undervalued and any repurchases will provide a positive return on investment and enhance shareholder value. The securities being bought are to be cancelled and returned to the treasury.

During the year the Company repurchased 240,245 of its shares (2022: 1,009,740 shares) and cancelled 1,032,220 shares (2022: nil).

• Prosecutor’s claim against Kul-bas LLP

On February 9, 2023, the Group announced that the Prosecutor’s Office of the Aktobe region in the Republic of Kazakhstan initiated a claim against Kul-bas LLP, a Tethys subsidiary registered in the Republic to cancel the subsoil rights for the Kul-bas license.

On February 27, 2023, the Group announced that the Astana Specialized Economic Court ruled that there were not sufficient grounds for satisfying the claim made by the Prosecutor’s Office. The time period for filing an appeal has passed and no appeal has been filed. Management is of the understanding that this issue has now been closed and believes the removal of this risk will allow Tethys to better focus on growing the Group and its operations.

6

Operational Review - continued

• Gemini debenture repayment

In April 2023, the Company repaid in full the Gemini debenture which amounted to $3.1 million including accrued interest. The Group no longer has any loan borrowings and is debt free.

• Annual General Meeting

On September 21, 2023, the Company announced the results of its Annual General meeting. All resolutions put to shareholders at the AGM were passed at the meeting.

Significant events and transactions subsequent to the year-end

• Deferred payment obligation adjustment

The Group announced on February 14, 2024 that it had previously recognized in its interim financial statements a deferred payment obligation for historical costs incurred by the government on geological investigation of the Kul-Bas exploration area. The total amount of approximately $28.3 million was to be paid quarterly over a period of up to 10 years from April 2023. The equivalent amount recognized in the Group’s interim financial statements was $18.1 million on a net present value basis.

After a further examination of the nature of acquired geological information, involving communication with the State Geology Committee, the Group determined that certain costs amounting to $25.1 million do not qualify as historical costs and, therefore, are not due for reimbursement to the government and that the amount owing was in fact approximately $3.2 million payable quarterly over a period of 10 years.

Subsequently, the Group communicated its findings to the Aktobe Tax Department and requested confirmation for the exclusion of these costs from its obligations. On February 12, 2024 the Aktobe Tax Department responded and affirmed the Group’s position. As a result, the Group made an adjustment to the amounts previously recognized in its balance resulting in a reduction of the previously reported liabilities of approximately $16.1 million on a present value basis, from the abovementioned $18.1 million to $2.0 million.

• Oil & gas operations

For details of oil & gas operations subsequent to the year end, refer to sections below headed Results of Operations and Operational Review.

Reserves

Following the completion of the annual evaluation of the Group’s reserves in Kazakhstan by the independent qualified reserves evaluator, McDaniel & Associates, of Calgary, Canada, in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators ("NI 51-101"), the Group’s Total Gross (i.e. before the application of Kazakh Mineral Extraction Tax) Oil and Gas Reserves consisting of “Proved” 1P reserves were 49.5 million BOE (2022: 45.8 million BOE) and “Proved + Probable” 2P reserves were 85.7 million BOE (2022: 82.2 million BOE). The net present value after tax of the Group’s 2P reserves as at December 31, 2023 was $628.7 million (2022: $610.5 million) based on a 10% discount rate.

7

Operational Review - continued

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. Both oil and gas reserves are based on availability of sufficient funding to allow development of the known accumulations.

Results of Operations and Operational Review - Kazakhstan

Oil production

	2023 2022
	Gross fluid Net Net production Gross fluid bl Net production
	barrels Net arres m3 barrels days bopd m3 barrels days **bopd **
Q1	42,049 264,483 264,483 90 2,939 66,648 419,205 419,205 90 4,658
Q2	50,450 317,319 315,357 91 3,465 55,729 350,523 350,523 91 3,852
Q3	71,622 450,489 450,401 92 4,896 54,951 345,632 345,632 92 3,757
Q4	21,223 133,487 130,523 92 1,419 63,744 400,941 400,941 92 4,358
Total	185,344 1,165,778 1,160,764 365 3,180 241,072 1,516,301 1,516,301 365 4,154

Oil production from pilot production project and appraisal wells

The Group produced from six wells in 2023 as shown in the table on pages 10.

The KBD-02, KBD-06 and KBD-07 wells are in the approved pilot production project (PPP) which initially ran until the end of 2022 but was extended until October 16, 2023. Production from these wells from January 1, 2023 until the October 16, 2023 was 836,475 barrels compared with the Group’s quota under the PPP for 2023 of 1,056,257 barrels (132,729 tons). From the commencement of production until October 16, 2023 production from the PPP wells was 2,510,183 barrels.

In addition to the PPP wells, the Group has drilled a number of successful appraisal wells outside of the PPP area and is allowed to produce from these wells for a maximum of 90 days from each zone before the wells are closed for the required reporting and approval process.

The KBD-03 and KBD-08 appraisal wells completed their testing in 2022 and produced a total of 253,184 barrels and 226,090 barrels respectively. Test production from the KBD-04, KBD-10 and KBD11 appraisal wells produced a total of 324,293 barrels from January 1, 2023 until October 16, 2023.

All wells were closed from the end of the exploration contract on October 16, 2023. The PPP wells are required to remain closed until the Group obtains a commercial production license although the Group has received the necessary permissions to restart testing of the appraisal wells from April 2024.

Progress towards a commercial production license

On July 27, 2023 the Group announced that it was moving forward on the necessary steps to achieve a license for commercial production with a goal of signing a production contract for a 25-year period by January 2024. The Group completed the reserve estimation for Kul-Bas and a mining allotment of 67.72 km2 was approved at the end of June 2023. The contract for a preparatory period of three years with the assigned mining allotment for the Kul-Bas exploration and production contract was signed by the MoE on July 28, 2023 and the Group has prepared a Field Development Project (FDP). In order to meet the ecological requirements, the Group needs to install gas turbines to convert the gas produced from the wells. These have been purchased and are in the process of being installed.

On January 25, 2024 the Company successfully presented the FDP to the Central Committee on Exploration and Development (CCED) and was expecting to receive the official protocol within two

8

Operational Review - continued

weeks. This approval is critical toward achieving the license for commercial production. The next steps are to get approval for the gas utilization program, secure ecology and gas flaring permits and successfully install the necessary equipment for the gas utilization and oil handling.

On March 20, 2024 the Group announced, regarding the commercial license, that while the Working Group for the Gas Processing Program of the MoE provided a positive review on March 1, the Ministry had still not yet issued the official minutes of the Working Group, causing a delay beyond the March 15 deadline. Consequently, Tethys has initiated the process of reapplying for the ecology permit necessary for commercial production. Tethys is now hoping to receive the commercial license by the end of May.

On April 5, 2024 the Group announced that it had received the permit from the Ministry of Ecology which will allow for test oil production from the KBD-10 and KBD-11 wells and regarding the commercial license, the Ministry of Energy has not yet issued the official minutes of the Working Group, and the Company is trying to determine the reason for the delay.

Main facilities

Construction contractors are working on the oil handling facilities and gas turbine site. Work has been carried out to prepare the booster compressor station equipment for startup and this equipment is ready for production. The oil handling and gas utilization facilities are not yet complete, but the Group expects to have them in place and operational when the commercial license is received.

The Company is considering plans for a railway terminal at Sagyr and expects design plans to be completed in May 2024. Sagyr is approximately 10 km from the Kulbas field.

Oil prices and marketing

On November 21, 2023, the Group announced that in early 2023, the MoE issued an order restricting the export of certain refined oil products beyond the Eurasian Economic Union's territory. This regulation, in combination with effects from the war in Ukraine, has negatively impacted the price of domestic oil in Kazakhstan. The Group's oil price at the field dropped from approximately 50% of Brent at the beginning of the year to approximately 30% of Brent in October. The average price of the Group's oil sales dropped to $242 per metric ton as compared to $312 per metric ton for the same period in 2022. This decline resulted in an estimated loss in revenue exceeding $10 million.

Given these issues and the requirement to shut in production until receipt of the commercial license, Tethys is particularly focused on costs optimization. This has led to delays in its exploration program in regards to seismic acquisition and in drilling new wells and in also reducing some staffing. The Group has laid off 22 temporary employees with another 32 employees drawing a half salary without having to work. Tethys plans to maintain full time employment for the other employees but will need to continue to monitor all costs closely during this period. The Tethys board and management are appreciative of the Tethys work force and are doing what it can to find continued work within Tethys for all employees. We are hopeful the oil field operations can resume soon.

Given the reduction in oil prices in the Republic of Kazakhstan, Tethys is reducing its exploration and operating plans to incorporate lower oil price estimates. While Tethys acquired three new licenses in the auction at the end of last year, it has not acquired new licenses in either of the two government auctions in 2024. The priority has been to address the costs necessary for the gas utilization required for the commercial license. The Tethys board wishes to assure shareholders that Tethys will continue to work to maintain a good return on shareholders’ equity on any new investment.

9

Operational Review - continued

Pilot production project and appraisal oil well production details

Well name Drilling start & end dates	Zone Perforation date (testing days) Perforation intervals meters Production during testing bbls Commission date 2023 production (Total to date) bbls
КBD-02 19/07/2019 06/10/2019	Jurassic 05/04/2020 (90 days) 38.9 32,268 08/09/2022 141,875 (834,606) Barremian 11/07/2020 (84 days) 15.5 204,394 - Aptian 10/10/2020 (87 days) 18.3 160,321 15/10/2021
КBD-03 01/05/2021 27/07/2021	Jurassic 31/08/2021 (90 days) 38 41,142 Awaiting FDP to convert into commercial Nil (253,184) Barremian 15/12/2021 (90 days) 15.5 157,397 Aptian 24/03/2022 (69 days) 2.0 54,645
KBD-04 22/04/2022 08/07/2022	Jurassic 28/07/2022 (87 days) 40.5 47,988 Awaiting FDP to convert into commercial 55,852 (135,152) Hauterivian 11/11/2022 (83 days) 2.0 54,929 Upper Barremian 07/03/2023 (25 days) 2.0 32,236
КBD-06 19/05/2021 25/07/2021	Barremian 14/10/2021 9.4 - 15/10/2021 490,695 (1,278,169)
КBD-07 08/10/2021 20/12/2021	Jurassic 27/12/2021 (204 days) 34.7 - 28/12/2021 203,902 (397,408) Aptian 28/07/2022 14.5 - 29/07/2022
KBD-08 19/10/2021 01/01/2022	Jurassic 26/02/2022 (5 days) 34.5 67 Awaiting FDP to convert into commercial Nil (226,090) Upper Barremian 28/05/2022 (47 days) 5.5 56,257 Barremian 07/07/2022 (88 days) 10 169,767
KBD-10 17/03/2023 14/07/2023	Jurassic - - - Awaiting FDP to convert into commercial 142,318 (142,318) Barremian 08/08/2023 (69 days) 9.1 142,318 Upper Barremian - - -
KBD-11 23/01/2023 24/04/2023	Jurassic 28/04/2023 (0 days) 36.9 - Awaiting FDP to convert into commercial 126,122 (126,122) Lower Barremian 21/08/2023 (56 days) 3.2 36,125 Barremian 19/05/2023 (43 days) 7.0 89,997 Upper Barremian Outstanding 9.3 -

• Field Development Plan (FDP)

10

Operational Review - continued

Other activities including exploration

The Group has started negotiations with oil buyers on possible prepayments in 2024 and has been in communication with JSC KTO regarding transport of oil through KTO’s pipeline network and has initiated a feasibility study. The Group is preparing a seismic campaign on the Aral-4 block that includes 700 km of 2D seismic in 2024, with an additional 300 km to be acquired later based on the results. On the Diyar block, 334 km of seismic is planned for this underexplored area, the total cost of which is estimated at $2.5 million.

Gas production – Kyzyloi and Akkulka Contracts

		2023				2022	2022
	Mcm	Mcf	**Mcm/d **	**Boe/d **	Mcm	Mcf		**Mcm/d **	**Boe/d **
Kyzyloi
Q1	177	6,246	2	12	19,106	674,642		212	1,249
Q2	-	-	-	-	17,354	612,786		191	1,122
Q3	-	-	-	-	12,909	455,801		140	826
Q4	-	-	-	-	12,946	457,137		141	828
Total	177	6,246	-	3	62,315	2,200,366		171	1,005
Akkulka
Q1	65	2,305	1	4	7,347	259,422		82	480
Q2	-	-	-	-	6,045	213,438		66	391
Q3	7	242	-	-	4,291	151,502		47	274
Q4	36	1,264	-	2	3,715	131,191		40	238
Total	108	3,811	-	2	21,398	755,553		59	345
Grand total	285	10,057	1	5	83,713	2,955,919		230	1,350

Gas operations update

On April 28, 2022 the Group received a letter from its gas customer QazaqGaz, a Republic of Kazakhstan state-owned enterprise, proposing a new gas sales pricing mechanism to apply with effect from January 1, 2022 with a minimum and maximum gas price that, in the Group’s view, was unlikely to be economic for Tethys. The Group has been engaging with QazaqGaz and MoE to reach a mutually acceptable outcome on past and future gas pricing while, at the same time, considering other options for the sale of its gas production. It has also been considering the possible impact on its future development plans.

On January 18, 2023, the Group announced, following the Department of Ecology’s refusal to issue permission for emissions related to Kyzyloi and Akkulka gas operations, that it had temporarily shut down the gas field operations. On March 29, 2023, the Group announced that the gas field production remained closed while it continued to pursue a resolution with QazaqGaz, regarding both payment and price for gas already delivered and the terms of a new gas sales contract for future production.

On November 21, 2023 Tethys announced that it has had to forego estimated gas revenues of approximately $10 million in 2023 due to the continued dispute with QazaqGaz and that Tethys was being asked to amend its existing contract to receive a price of 60% of the price of a barrel of Brent crude oil for each thousand cubic meter of gas (approx. $51/Mcm at a Brent price of $85/bbl).

Due to the impasse with QazaqGaz, the Group did not receive any payment for the gas delivered in 2022 until December 2023 when it announced it had entered into an agreement with QazaqGaz resulting in payment for the gas delivered in the first four months of 2022 equivalent to $4.3 million. Tethys management is continuing to work on resolving the remaining issues, including for the gas

11

Operational Review - continued

delivered between May and December 2022 and the terms of a gas sales contract for future production. The Group is hoping to achieve a successful negotiation, but may be forced to take the matter to arbitration if an acceptable agreement cannot be reached.

In view of the payment received, Tethys decided to restart gas production in January 2024 and in the first quarter of 2024 production averaged 245 Mcm/d from 20 wells in the Akkulka and Kyzyloi gas fields. Assuming a satisfactory outcome on gas pricing, Tethys plans to connect a further five wells and work over two wells during Q3 2024.

On April 5, 2024 the Group announced that it has been continuing to work on a resolution with QazaqGaz over the dispute on the payment of gas produced by the Group. We have been unable to come to an agreement and gas production has been shut in. Due to the shutdown of gas production, a significant number of employees may be forced to take a temporary furlough and are at risk of permanent dismissal. Sixteen employees have been put on furlough. In an effort to reduce the number of staff laid off, seventeen employees have been transferred from TethysAralGas to KulBas in order to assist with the oil production on KBD-10 and KBD-11.

12

Financial Review

Summary of Quarterly Results

	Q4, 2023	Q3, 2023	Q2, 2023	Q1, 2023	Q4, 2022	Q3, 2022	Q2, 2022	Q1, 2022	Q1, 2022
Oil & gas sales and other	6,431	11,069	9,079	9,900	18,647	16,364	16,578	13,903
revenues
(Loss)/profit for the period	(1,142)	4,243	4,132	2,503	(9,223)	7,605	6,532	7,386
Basic (loss)/earnings ($) per share	(0.02)	0.04	0.04	0.02	(0.09)	0.07	0.06	0.07
Adjusted EBITDA1	5,244	7,647	6,089	6,070	12,497	13,932	13,322	11,525
Capital expenditure	5,289	3,139	1,319	2,321	4,099	5,710	975	12,193
Total assets	85,331	103,606	95,849	81,161	87,266	84,131	73,133	77,361
Cash & cash equivalents	7,216	9,973	3,597	7,264	14,538	15,009	6,137	11,651
Short & long-term borrowings	-	-	-	2,675	2,510	4,711	7,185	6,872
Total non-current liabilities	38,264	45,572	49,484	32,335	32,488	14,602	14,008	15,335
Net (cash)/debt1	(7,202)	(6,463)	(3,578)	(4,536)	(6,834)	(2,342)	4,709	14,863
Number of common shares	115,075,013	115,075,013	115,075,013	115,075,013	116,107,233	107,548,114	107,548,114	107,548,114
outstanding

Note 1 - Adjusted EBITDA and net debt are non-GAAP Measures, refer to page 20 for details.

• The decrease in oil and gas revenues from Q4 2022 is due to lower production and average price realized for oil production and closure of the gas fields during 2023 due to the price dispute;

• (Loss)/profit for the quarter was lower in Q4 2023 due to oil production ceasing on October 16, 2023 at the end of the current production contract. Q4 2023 was impacted by a $5.2 million tax charge compared to a $18.6 million tax charge (mainly deferred tax) in Q4 2022;

• Adjusted EBITDA, a non-GAAP measure, was lower in Q1-Q4 2023 due to due to lower production and average price realized for oil production and closure of the gas fields during 2023 due to the price dispute;

• Capital expenditure has continued to be made consistently throughout the 2022-2023 period as the Group drilled and tested oil wells in the Kul-Bas area, purchased equipment and constructed facilities required for the anticipated start of commercial production in 2024;

• Total assets increased in Q2 2023 as a result of recognizing $18.1 million of historical cost liabilities (and corresponding assets) due to the government, however the amounts recognized were reduced by $16.1 million in Q4 2023 as explained in more detail on page 7;

• The decrease in cash & cash equivalents in 2023 is a result of the lower cash generated from oil and gas sales than in 2022. In addition, dividends of $1.7 million and $2.6 million were paid in Q4 2022 and Q1 2023 respectively and a $3.1 million loan repayment was made in Q2 2023;

• Short & long-term borrowings reduced in Q3 2022 due to the repayment of the Gemini unsecured loan and in Q4 2022 due to conversion of a 50% share of the Gemini debenture. The remaining 50% share of the Gemini debenture was repaid in Q2 2023 and the Group is now debt free;

• Total non-current liabilities increased in Q4 2022 mainly due to the recognition of additional deferred tax liabilities. Total non-current liabilities were also impacted in Q2 2023 as a result of recognizing $18.1 million of historical cost liabilities (and corresponding assets) due to the government, however the amounts recognized were reduced by $16.1 million in Q4 2023 as explained in more detail on page 7;

• Net (cash)/debt, a non-GAAP measure, includes deferred revenue. The reduction in net debt from Q1 2022 is due to the significant cash generated from oil sales and the reduction in borrowings;

• Shares were issued for a private placement in Q4 2022 on conversion of a 50% share of the Gemini debenture and reduced in Q1 2023 from shares repurchased and cancelled.

13

Financial Review - continued

Profit for the period

		Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
		December 31			December 31
	2023	2022	Change	2023	2022	Change
Sales revenues	6,431	18,647	(66%)	36,479	65,492	(44%)
Production expenses	(1,156)	(2,311)	(50%)	(6,081)	(7,035)	(14%)
Depreciation, depletion and amortisation	(420)	(2,154)	-	(4,270)	(7,614)	(44%)
Impairment charges	(1,720)	(83)	1974%	(1,720)	(1,817)	(5%)
Administrative expenses	(1,331)	(1,720)	(27%)	(5,354)	(4,851)	9%
Share-based payments	(16)	(59)	(72%)	(95)	(188)	(50%)
Other gains and losses	(173)	(715)	(79%)	(298)	(565)	(51%)
Foreign exchange gains and loss	1,300	(2,119)	-	36	(1,147)	(96%)
Finance costs	794	(154)	-	(247)	(958)	(74%)
	(2,722)	(9,315)	(71%)	(18,029)	(24,175)	(26%)
Profit before taxation	3,709	9,332	(60%)	18,450	41,317	(55%)
Taxation	(4,851)	(18,555)	(72%)	(8,714)	(29,017)	(69%)
(Loss)/profit for theperiod	(1,142)	(9,223)	(84%)	9,736	12,300	(24%)

The Group recorded a loss after tax of $1.1 million for the quarter compared with a loss of $9.2 million in Q4 2022 and profit of $9.7 million for the year (2022: $12.3 million), the principal variances being:

• Lower profit contribution in the current quarter and current year from oil production due to lower production volume and lower average price realized and lower contribution from gas production due to the closure of the gas fields during 2023 as a result of the QazaqGaz price dispute;

• Lower production expenses, DD&A and tax charge in the current quarter and current year from the lower oil and gas production;

• A $1.7 million impairment charge in Q4 2023 and 2023 relating to lower expected future gas prices and $1.8 million Q1-Q2 2022 relating to unsuccessful exploration wells;

• Foreign exchange gain in current quarter and current year versus a loss in prior periods due to losses on currency conversion and translation of foreign currency monetary assets and liabilities;

• Lower finance costs in current quarter and current year due to the reversal of historical cost liabilities in Q4 2023 (and related interest costs) and lower finance costs in 2023 than 2022 due to repayment of remaining borrowings in April 2023;

• A tax charge in the quarter of $4.9 million (2022: $18.6 million) and for the year of $8.7 million (2022: $29.0 million) reflecting revisions to deferred tax assumptions and effective tax rates.

14

Financial Review - continued

Sales & other revenue

	Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
		December 31			December 31
	2023	2022	Change	2023	2022	Change
By region and type
Kazakhstan - Oil	4,245	16,845	(75%)	34,259	60,402	(43%)
Kazakhstan - Gas	2,179	1,802	21%	2,209	5,079	(57%)
Other revenue	7	-	-	11	11	-
Total	6,431	18,647	(66%)	36,479	65,492	(44%)

Kazakhstan – Oil revenue

• Oil revenue for the quarter was $4.2 million (Q4 2022: $16.8 million) or $25.12/bbl (Q4 2022: $41.83) and for the year was $34.3 million (2022: $60.4 million) or $29.45/bbl (2022: $39.94/bbl).

• Production during 2023 and 2022 was from six wells in the Kul-bas field, three wells under a pilot production project and three exploration wells, although the mix of wells was different in each year. A total of eight wells have been drilled in Kul-Bas that are capable of production.

• On November 21, 2023, the Group announced that in early 2023, the MoE issued an order restricting the export of certain refined oil products beyond the Eurasian Economic Union's territory. This regulation, in combination with effects from the war in Ukraine, has negatively impacted the price of domestic oil in Kazakhstan. The Group's oil price at the field dropped from approximately 50% of Brent at the beginning of the year to approximately 30% of Brent in October. The average price of the Group's oil sales dropped to $242 per metric ton as compared to $312 per metric ton for the same period in 2022 (the Group uses a conversion factor from tons to barrels of 7.958). This decline resulted in an estimated loss in revenue exceeding $10 million.

Kazakhstan - Gas revenue

• Gas revenue in 2023 represents an adjustment to the estimated amount receivable for gas delivered in 2022 as gas production in 2023 was minimal, further details are given on page 11.

• Oil and gas sales are subject to exchange rate risk – refer to page 22 – “ Sensitivities ”.

15

Financial Review - continued

Production expenses

		Quarter ended December 31	Quarter ended December 31	Quarter ended December 31	Year	ended December 31	ended December 31
	Units	2023	2022	Change	2023	2022	Change
Kazakhstan direct production
expenses
Oil production costs	$000’s	814	1,761	(54%)	4,457	5,121	(13%)
Gas production	$000’s	342	550	(38%)	1,624	1,914	(15%)
Total	$000’s	1,156	2,311	(50%)	6,081	7,035	(14%)
Administrative expenses
Oil production	$000’s	885	649	36%	3,297	1,685	96%
Gas production	$000’s	295	649	(55%)	1,099	1,685	(35%)
Corporate	$000’s	151	422	(64%)	958	1,481	(35%)
Total	$000’s	1,331	1,720	(23%)	5,354	4,851	10%
Depreciation, depletion,
amortisation & impairment
Oil production	$000’s	420	1,740	-	4,264	7,654	(44%)
Gas production	$000’s	1,720	497	246%	1,726	1,777	(3%)
Total	$000’s	2,140	2,237	(4%)	5,990	9,431	(36%)
Oil
Total cost of production	$000’s	2,119	4,150	(49%)	12,018	14,460	(17%)
Production	bbls	130,523	400,941	(67%)	1,160,764	1,516,301	(23%)
Costper unit ofproduction	$/bbl	16.23	10.35	57%	10.35	9.54	9%
Gas
Total cost of production	$000’s	2,357	1,696	39%	4,449	5,376	(17%)
Production	boe	211	98,061	(100%)	1,676	492,687	(100%)
Cost per unit of production	$/boe	-	17.29	-	-	10.91	-
Production	Mcm	36	16,661	(100%)	285	83,713	(100%)
Costper unit ofproduction	$/Mcm	-	101.79	-	-	64.22	-
Oil and gas weighted average cost	$/boe	34.25	11.71	192%	14.11	9.87	43%

Kazakhstan – oil production

Oil production costs comprising direct production costs, administrative expenses, impairment charges and depreciation, depletion and amortisation for the quarter were $2.1 million (Q4 2022: $4.2 million) or $16.23/bbl (Q4 2022: $10.35/bbl) and for the year were $12.0 million (2022: $14.5 million) or $10.35/bbl (2022: $9.54/bbl). These costs reflect production from up to six wells in 2023 compared with up to six wells in 2022, although the mix of wells was different in each year. In total eight wells have been drilled in Kul-Bas that are capable of production.

Kazakhstan – gas production

Gas production costs comprising direct production costs, administrative expenses and depreciation, depletion and amortisation for the quarter were $2.4 million (Q4 2022: $1.7 million) which includes an impairment of $1.7 million and for the year were $4.4 million (2022: $5.4 million). Since the gas fields were closed during 2023 unit of production measurements are not meaningful, although in 2022 the cost of production in Q4 was $101.79/Mcm and $64.22/Mcm for the year.

16

Financial Review - continued

		2023	2022
Kazakhstan oil production:
Staff costs		1,837	1,697
Taxes & other mandatory payments		991	2,274
Transportation & travel		481	117
Materials & diesel		380	311
Health & safety, blowout prevention		297	318
Camp services		254	198
Contractors		134	131
Repairs & maintenance		12	15
Other		71	61
Direct oilproduction expenses		4,457	5,121
Kazakhstan gas production:
Staff costs		530	854
Health & safety, blowout prevention		327	116
Contractors & security		306	333
Materials & diesel		196	292
Repairs & maintenance		103	41
Camp services		52	-
Taxes & other mandatory payments		51	155
Transportation		27	51
Other		33	73
Directgasproduction expenses		1,624	1,914
Total directproduction expenses		6,081	7,035

Administrative expenses

		Quarter ended	Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
			December	31			December 31
		2023	2022		**Change **	2023	2022	**Change **
Staff costs and director fees		938	887		6%	4,011	2,720	47%
Professional fees		148	450		(67%)	567	1,198	(53%)
Other administrative expenses		245	383		(36%)	776	933	(17%)
Total		1,331	1,720		(23%)	5,354	4,851	10%
G&A expenses per boe ($)		10.18	3.45		195%	4.59	2.41	90%

• Administrative costs were lower in the quarter due to lower professional fees and other administrative expenses but were higher for the year mainly due to higher staff costs in Kazakhstan.

• Professional fees were lower in the quarter and for the year mainly due to lower legal fees.

• Other administrative expenses were lower for the quarter and the year. Other administrative costs includes office costs, travel, regulatory costs, insurance, investor relations, socio-economic contributions in Kazakhstan, vehicles costs and bank fees.

Taxation

Taxation on corporate profits in Kazakhstan comprises Corporate Income Tax (CIT) at 20% and Excess Profits Tax (EPT) which applies at graduated rates on profits earned above certain profit thresholds. The Group measures its deferred tax liabilities using the average CIT and EPT rate expected to apply over the periods the deferred tax balances are expected to reverse. The Group’s deferred tax liability mainly arises from the different treatment of fixed asset capital allowances for tax purposes and depletion of oil & gas assets for accounting purposes. It also includes withholding taxes that are expected to apply on payment of interest due on intra-group loans.

17

Financial Review - continued

Liquidity and Capital Resources

The Group’s processes for managing liquidity risk includes preparing and monitoring capital and operating budgets, co-ordinating and authorising project expenditures and ensuring appropriate authorisation of contractual agreements. The budget and expenditure levels are reviewed on a regular basis and updated when circumstances indicate change is appropriate. The Group seeks additional financing based on the results of these processes.

The Group’s capital structure is comprised of shareholders’ equity and borrowings, net of cash and cash equivalents.

The Group’s objectives when managing capital is to maintain adequate financial flexibility to preserve its ability to meet financial obligations, both current and long term. The capital structure of the Group is managed and adjusted to reflect changes in economic conditions.

The Group has funded its expenditures on commitments from existing cash and cash equivalent balances, primarily received from issuances of shareholders’ equity and debt financing. None of the outstanding debt is subject to externally imposed capital requirements.

Financing decisions are made by management and the Board of Directors based on forecasts of the expected timing and level of capital and operating expenditure required to meet the Group’s commitments and development plans. Factors considered when determining whether to issue new debt or to seek equity financing include the amount of financing required, the availability of financial resources, the terms on which financing is available and consideration of the balance between shareholder value creation and prudent financial risk management.

Going concern

In assessing its going concern status, the Group has taken account of its principal risks and uncertainties, financial position, sources of cash generation, anticipated future trading performance, its borrowings, and its capital expenditure commitments and plans.

Risks and uncertainties facing the Group include the risk that oil and gas prices may be significantly lower than assumed in the Group’s forecasts, that the restart of gas production may be delayed if the issues with Qazaq gas over the price for 2022 gas deliveries and 2024 production are not resolved and that the start of commercial oil production in Kul-Bas may be delayed if the Group does not receive all the required approvals and permits for it to be awarded a commercial production licence on a timely basis. Further information on the status of these matters is provided in note 19 - Events after the reporting period.

To assess the resilience of the Group’s going concern assessment in light of the sanctions imposed on certain Russian institutions and individuals by the global community in February 2022 and subsequently, that could impact the oil price received by the Group, management performed the following downside scenario that is considered reasonably possible over the next 12 months from December 31, 2023. As such, this does not represent the Group’s ‘best estimate’ forecast, but was considered in the Group’s assessment of going concern, reflecting the current evolving circumstances and the most significant and reasonably possible risk identified at the date of approving the consolidated financial statements.

Scenario: The Group’s income and profits are materially reduced due to a 25% reduction in expected oil prices and a delay in the restart of gas production.

The Group’s forecast net cashflows under the downside scenario above is considered to be adequate to meet the Group’s financial obligations as they fall due over the next 12 months.

18

Financial Review - continued

The Board of Directors is therefore satisfied that the Group’s forecasts and projections, including the downside scenario above, show that the Group has adequate resources to continue in operational existence for at least the next 12 months from the date of this report and that it is appropriate to adopt the going concern basis in preparing the consolidated financial statements for the year ended December 31, 2023.

Cash Flow

		Quarter ended	Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
			December	31		December 31
		2023	2022		Change	2023	2022	Change
Net cash (used in)/from operating activities		(11)	5,966		-	10,110	34,083	(70%)
Interest received		245	369		(34%)	736	628	17%
Acquisition of PP&E and E&E assets		(5,289)	(3,904)		35%	(12,068)	(12,043)	0%
Net change in working capital		-	(195)		(100%)	-	(10,934)	(100%)
Other investingcash flows		499	(37)		-	(220)	(147)	50%
Net cash used in investing activities		(4,545)	(3,767)		21%	(11,552)	(22,496)	(49%)
Repayment of borrowings		-	-		-	(3,125)	(2,772)	13%
Shares repurchased		(4)	(51)		(93%)	(156)	(643)	(76%)
Dividendpaid		-	(1,741)		(100%)	(2,599)	(1,741)	49%
Net cash used in financing activities		(4)	(1,792)		(100%)	(5,880)	(5,156)	14%
Effect of exchange rates		1,803	(878)		-	-	(1,170)	(100%)
Net (decrease)/increase in cash		(2,757)	(471)		485%	(7,322)	5,261	-
Cash & cash equivalents at beginningofperiod		9,973	15,009		(34%)	14,538	9,277	57%
Cash & cash equivalents at end ofperiod		7,216	14,538		(50%)	7,216	14,538	(50%)

Operating activities

Net cash used in operating activities in the quarter was $11 thousand ($6.0 million cash generated) and for the year was positive $10.1 million (2022: $34.1 million). The reduction is due to the lower oil and gas revenues from lower oil production volume and lower average price realized and lower gas revenue due to the closure of the gas fields during 2023.

Investing activities

Capital expenditure payments made during the quarter and year were mainly to the Group’s drilling contractor and also to seismic providers and equipment suppliers.

Financing activities

The Company repaid the remainder of the Gemini debenture in Q2 2023 in the amount of $3.1 million and the unsecured Gemini loan of $2.8 million was repaid in Q3 2022. The Group paid its first dividend of $1.7 million in Q4 2022 and its second dividend of $2.6 million in Q1 2023.

Accounting policies, changes to accounting standards and critical estimates

The Group’s significant accounting policies and discussion of changes to accounting standards are disclosed in note 2 – Summary of Material Accounting Policies of the December 31, 2023 consolidated financial statements. Refer to note 4 – Critical Judgments and Accounting Estimates of the December 31, 2023 consolidated financial statements for information on the Group’s significant judgments and assumptions and critical estimates.

Off-Balance Sheet Arrangements

19

Financial Review - continued

The Group has no off-balance sheet arrangements.

Non-GAAP Measures

Adjusted EBITDA

Adjusted EBITDA is defined as “Profit or loss before Interest, Tax, Depreciation, Amortization, Impairment, Fair value gains or losses and Share Based Payments” and is calculated on the results of continuing operations. It provides an indication of the results generated by the Group’s principal business activities prior to how these activities are financed, assets are depreciated and amortized, or how results are taxed in various jurisdictions. The reconciliation of Adjusted EBITDA to profit before taxation is as follows:

		Quarter ended	Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
			December	31			December 31
		2023	2022		**Change **	2023	2022	**Change **
Profit before taxation		3,709	9,332		(60%)	18,450	41,317	(55%)
Depreciation, depletion and amortisation		420	2,154		-	4,270	7,614	(44%)
Impairment charges		1,720	83		1974%	1,720	1,817	(5%)
Share-based payments		16	59		(72%)	95	188	(50%)
Other gains and losses		173	715		(76%)	298	565	(47%)
Finance costs - net		(794)	154		-	247	958	(74%)
Adjusted EBITDA		5,244	12,497		(58%)	25,080	52,459	(52%)

Net (cash)/debt

Net (cash)/debt is calculated as total borrowings and deferred revenue less cash and cash equivalents. Total capital is calculated as equity (minus) or plus net (cash)/debt. All figures are as stated in the consolidated financial statements for the year ended December 31, 2023.

		As at December 31	As at December 31
		2023	2022	**Change **
Total financial liabilities - borrowings		-	2,510	(100%)
Deferred revenue		14	5,194	(100%)
Less: cash and cash equivalents		(7,216)	(14,538)	(50%)
Net (cash)/debt		(7,202)	(6,834)	5%
Total equity		42,192	35,116	20%
Total capital		34,990	28,282	24%

Adjusted EBITDA and net (cash)/debt shown in this MD&A do not have any standardised meaning as prescribed under IFRS and, therefore, are considered non-GAAP measures. These measures have been described and presented to provide shareholders and potential investors with additional information regarding the Group’s financial results. These measures may not be comparable to similar measures presented by other entities.

20

Financial Review - continued

Stockholder Equity

As at December 31, 2023 the Company had authorised share capital of 145,000,000 (2022: 145,000,000) ordinary shares of which 115,075,013 (2022: 116,107,233) had been issued and 50,000,000 (2022: 50,000,000) preference shares of which none had yet been issued. The preference shares have the rights as set out in the Memorandum and Articles of Association of the Company.

The number of ordinary shares issued and outstanding at the date of this MD&A was 114,857,243 and the number of preference shares issued and outstanding was nil.

The number of options issued under the Company’s Long Term Stock Incentive Plan and outstanding as at December 31, 2023 and also at the date of this MD&A was 1,802,188 (2022: 1,877,188).

No loan facilities were in place as at December 31, 2023 or at the date of this MD&A which were convertible into ordinary shares (2022: 8,718,677).

There were no warrants outstanding at December 31, 2023 (2022: nil).

Dividends

On October 26, 2022, the Group announced the approval of a dividend of 2 CAD cents per share with a record date of November 2, 2022 and payment date of November 10, 2022.

On January 18, 2023, the Company announced the approval of a quarterly dividend of 3 CAD cents per ordinary share with a record date of January 26, 2023 and payment date of February 9, 2023.

Transactions with Related Parties

Disclosure of the Group’s transactions with related parties are provided in note 17 of the consolidated financial statements.

Commitments and contingencies

Details of the Group’s commitments and contingencies including litigation, claims and assessments and work program commitments are provided in note 19 of the consolidated financial statements.

A summary of the Group’s contractual obligations, including interest, for the next five years and thereafter is shown in the table below:

			Payments due by period	Payments due by period
Contractual obligations	Total	Less than	1 – 3	4 – 5	After 5
		1year	years	years	years
Kazakhstan work program commitments	39,992	5,295	8,693	23,123	2,881
Trade and other payables	7,116	4,644	248	953	1,271
Provisions	3,591	-	894	909	1,788
Total contractual obligations	50,699	9,939	9,835	24,985	5,940

21

Risks, uncertainties and other information

Risk management is carried out by senior management as well as the Board of Directors. The Group has identified its principal risks for 2023 to include:

• (1) Liquidity and going concern;

• (2) Retention and extension of existing licences;

• (3) Production volumes and pricing – both oil and gas; and

• (4) Political, fiscal, litigation and related risks.

Financial Risk Management

The Group’s activities expose it to a variety of financial risks including: market risk, credit risk, liquidity risk, interest rate, commodity price and foreign exchange risk. Details of the Group’s exposure to these risks and how they are managed is given in note 3 to the consolidated financial statements for the year ended December 31, 2023. The Group’s overall risk management program focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group’s financial performance.

The Board of Directors has overall responsibility for the Group’s management of risk, including the identification and analysis of risks faced by the Group and the consideration of controls that monitor changes in risk and minimise risk wherever possible.

Sensitivities

Any material decline in oil prices could result in a reduction of the Group’s oil revenues in Kazakhstan. For example, a 20% net price reduction from the 2023 average sales price, would result in a reduction of $6.8 million in oil revenues based on the 2023 oil sales volume.

There was negligible gas production and sales in 2023 although based on a reasonably possible price of $90/Mcm and volume of 100,000 Mcm per annum a 20% net price reduction would result in a reduction of $1.8 million in gas revenues.

Derivative Financial Instruments

The Group does not have any derivative financial instruments.

Significant equity investees

The Group does not have any significant equity investees.

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Forward-looking statements

In the interest of providing Tethys’ shareholders and potential investors with information regarding the Group, including management’s assessment of the Group’s future plans and operations, certain statements contained in this MD&A constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project” or similar words suggesting future outcomes or statements regarding an outlook.

Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur.

By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the Group’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forwardlooking statements.

These risks, uncertainties and assumptions include, among other things: the significant uncertainty over the Group’s ability to generate sufficient cash flow from operations to meet its current and future obligations and continue as a going concern; risks of exploration and production licenses, contracts and permits being cancelled due to non-fulfilment of contractual commitments or not being renewed when they expire; the Group will not be successful obtaining governmental approvals for the export of oil at prices significantly higher than price currently realised; volatility of and assumptions regarding oil and gas prices; fluctuations in currency and interest rates; product supply and demand; market competition; ability to realise current market oil and gas prices; risks inherent in the Group’s marketing operations, including credit risks; imprecision of reserve estimates and estimates of recoverable quantities of oil and natural gas and other sources not currently classified as proved; the Group’s ability to replace and expand oil and gas reserves; unexpected cost increases or technical difficulties in constructing pipeline or other facilities; unexpected delays in its drilling operations; unexpected difficulties in transporting oil or natural gas; risks associated with technology; the timing and the costs of well and pipeline construction; the Group’s ability to secure adequate product transportation; changes in royalty, tax, environmental and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which the Group operates; the risk associated with the uncertainties, inconsistencies and contradictions in local laws and their interpretation and application in local jurisdictions in which the Group operates; the risk of international war, hostilities and terrorist threats, civil insurrection and instability affecting countries in which the Group operates; risks associated with existing and potential future lawsuits and regulatory actions made against the Group; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Tethys.

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Forward-looking statements - continued

With regard to forward looking information contained in this MD&A, the Group has made assumptions regarding, amongst other things, the continued existence and operation of existing pipelines; future prices for oil and natural gas; future currency and exchange rates; the Group’s ability to generate sufficient cash flow from operations and access to capital markets to meet its future obligations and ability to continue as a going concern; the regulatory framework representing mineral extraction taxes, royalties, taxes and environmental matters in the countries in which the conducts its business, gas production levels; and the Group’s ability to obtain qualified staff and equipment in a timely and cost effective manner to meet the Group’s demands. Statements relating to “reserves” or “resources” or “resource potential” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Although Tethys believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forwardlooking statements contained in this MD&A are made as of the date of this MD&A and, except as required by law, Tethys does not undertake any obligation to update publicly or to revise any of the included forward looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

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Bbls Barrels of oil boe/d Barrel of oil equivalent per day bopd Barrels of oil per day EBITDA Earnings before interest, taxes, depreciation and amortisation GAAP Generally accepted accounting principles Gemini Gemini IT Consultants DMCC IFRS International Financial Reporting Standards KASE Kazakhstan Stock Exchange KBD Kul-bas Deep well in the Kul-bas Exploration Contract area Kul-Bas The Kul-Bas Exploration Contract area held by Kul-Bas LLP KZT Kazakhstani Tenge m3 Cubic metre Mcf Thousand cubic feet Mcf/d Thousand cubic feet per day Mcm Thousand cubic metres Mcm/d Thousand cubic metres per day MD&A Management's Discussion & Analysis MoE Ministry of Energy National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities of the NI 51-101 Canadian Securities Administrators NPV Net present value Q1 Three month period commencing January 1 and ending 31 March Q2 Three month period commencing April 1 and ending 30 June Q3 Three month period commencing July 1 and ending 30 September Q4 Three month period commencing October 1 and ending 31 December Tethys Tethys Petroleum Limited and subsidiary companies TSX Toronto Stock Exchange TSXV TSX Venture Exchange VAT Value added tax YTD Year to date cumulative $ United States Dollar $/bbl $ per barrel $/Mcm $ per thousand cubic metre

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