Tethys Petroleum — Management Reports 2022

Apr 26, 2022

Tethys Petroleum Limited

Management’s Discussion and Analysis for the year ended December 31, 2021

Contents

Nature of business	1
Financial highlights	2
Operational highlights	4
Operational review	6
Financial review	11
Risks, uncertainties and other information	20
Forward looking statements	21
Glossary	23

The following MD&A is dated April 25, 2022 and should be read in conjunction with the Group’s audited consolidated financial statements and related notes for the year ended December 31, 2021. 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 International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. Amounts are stated in 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 (hereinafter “Tethys” or the “Company”, together with its subsidiaries “the Group") 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 One Nexus Way, Camana Bay, Grand Cayman, KY1-9005, 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
	2021	2020	**Change **	2019	**Change **
Oil and gas sales revenues	15,906	13,040	22%	12,717	3%
Loss for the year	(3,989)	(38,521)	(90%)	(8,803)	338%
Loss ($) per share -basic	(0.04)	(0.40)	(90%)	(0.13)	208%
Adjusted EBITDA1	9,647	7,012	38%	6,471	9%
Capital expenditure	15,491	9,515	71%	6,801	40%
		As at 31 December
	2021	2020	**Change **	2019	**Change **
Total assets	73,944	53,817	37%	108,834	(51%)
Cash & cash equivalents	9,277	1,747	431%	694	152%
Short & long term borrowings	6,578	5,549	19%	40,196	(86%)
Total non-current liabilities	16,603	11,867	40%	9,776	21%
Net (cash)/debt1	(2,699)	3,802	(171%)	39,502	(90%)
Number of ordinary shares outstanding	107,548,114	104,955,999	2%	68,324,430	54%

Note 1 - Adjusted EBITDA and net debt are non-GAAP Measures, refer to page 18 for details.

Twelve months 2021 versus twelve months in 2020

• Oil and gas sales and other revenues increased by 22% to $15.9 million from $13.0 million due to significantly higher oil revenue, partially offset by lower gas revenue. Oil revenue increased from $2.0 million to $6.0 million. In 2020, there was an additional $2.6 million of oil sales received during the testing phase of the KBD-02 well which was offset against the exploration asset. Gas revenues decreased from $11.0 million to $9.9 million due to lower production volumes and lower average prices in 2021;

• The loss for the year was $4.0 million against a loss of $38.5 million in 2020. Profit before tax for the year was $3.8 million with a tax charge of $7.7 million. The 2020 result included an impairment charge of $57.6 million and gains of $15.0 million, mainly from early settlement of borrowings on favourable terms, and a tax credit of $3.3 million;

• Adjusted EBITDA, a non-GAAP measure, was $9.6 million, an improvement from the $7.0 million in 2020 reflecting the increase in revenues. Production and administrative expenses which were higher in 2021 by $0.5 million were offset by foreign exchange gains which were $0.4 million higher;

• Total assets increased by $20.1 million to $73.9 million due to an increase in cash of $7.5 million and property, plant and equipment which increased by $11.5 million due to capital expenditure on oil & gas properties exceeding depletion, depreciation and amortisation;

• Cash & cash equivalents increased by $7.5 million to $9.3 million. Cash from operating activities was $14.9 million (2020: $17.5 million), net cash from investing activities was $8.7 million (2020:$5.5 million) and $1.4 million (2020: $nil) was raised during the year from issuing new ordinary shares;

• Short & long term borrowings increased to $6.6 million from $5.5 million from accrued loan interest. There were no new loans or loan repayments due during the year;

2

Financial highlights - continued

• Net cash, a non-GAAP measure, of $2.7 million increased from net debt of $3.8 million net debt due mainly to the increase in cash & cash equivalents of $7.5 million;

Twelve months 2020 versus twelve months in 2019

• Oil and gas sales and other revenues increased by 3% to $13.0 million from $12.7 million due to significantly higher oil revenue partially offset by lower gas revenue. Oil revenue increased from $0.6 million to $2.0 million. There was an additional $2.6 million of oil sales received during the testing phase of the KBD-02 well which have been offset against the exploration asset. Gas revenues decreased from $12.1 million to $11.0 million notwithstanding production volumes being 11% higher due to lower average prices;

• Loss for the year was $38.5 million against a loss of $8.8 million in 2019. This includes an impairment charge of $57.6 million and gains of $15.0 million, mainly from early settlement of borrowings on favourable terms versus a one-off loss of $4.1 million in 2019, mainly relating to the DSFK settlement. Revenue was $0.3 million higher in 2020, DD&A was $0.8 million lower and finance costs were $3.8 million lower due to significantly lower debt from early 2020 when borrowings were repaid and converted to shares. There was also a net tax credit of $3.3 million related to the impairment against a tax charge of $0.3 million in 2019;

• Adjusted EBITDA, a non-GAAP measure, was $7.0 million, an improvement from the $6.6 million in 2019 reflecting the increase in revenues and a lower foreign exchange loss. Production and administrative expenses were at a similar level to 2019;

• Total assets decreased by $55.0 million mainly due to the impairment. In addition, capital expenditure was higher than depletion of oil & gas properties, cash balance was higher and trade and other receivable balance was lower;

• Short & long term borrowings decreased to $5.5 million from $40.2 million after the majority of borrowings were repaid or converted into shares of the Company in early 2020;

• Net debt, a non-GAAP measure, reduced to $3.8 million from $39.5 million which includes the decrease in short & long term borrowings and the increase in cash;

• The number of ordinary shares increased by 54% to 105.0 million due to the shares for debt transactions.

3

Operational highlights

		Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
		December 31			December 31
	Units	2021	2020	**Change **	2021	2020	**Change **
Kazakhstan
Oil	bopd	3,329	1,743	91%	887	1,053	(16%)
Gas	boe/d	1,855	2,129	(13%)	1,902	2,071	(8%)
Total	boe/d	5,184	3,872	35%	2,789	3,124	(11%)
Oil
Production	Bbls	306,248	160,373	91%	323,647	384,228	(16%)
Oil revenue1	$’000	5,740	1,992	188%	6,007	1,992	202%
Production costs1	$’000	857	225	281%	1,399	430	225%
Gross margin	$’000	4,883	1,767	176%	4,608	1,562	195%
Gas
Production	Mcm	28,993	33,292	(13%)	117,944	128,436	(8%)
Gas revenue	$’000	3,314	2,419	37%	9,899	11,045	(10%)
Production costs	$’000	460	516	(11%)	1,854	2,349	(21%)
Gross margin	$’000	2,673	1,903	40%	7,864	8,696	(10%)

Note 1 – in 2020, oil sales of $2.6 million and oil production costs of $0.2 million relating to test production from the KBD-02 well were capitalised to exploration & evaluation expenditure and not shown in the Company’s income statement. This changed from 30 September 2020 when commercial reserves were determined.

Oil

• Oil production in Q4 2021 averaged 3,329 bopd compared with 1,743 bopd in Q4 2020 and for the year averaged 887 bopd compared with 1,053 bopd in 2020. In 2020, test production from the KBD-02 exploration well commenced in April and continued until the end of December when it was closed for the required reporting and approval process. In 2021, production commenced from the new KBD-03 well in September, with the new KBD-06 well and KBD-02 well added to production in October, followed by the new KBD-07 well in December. Accordingly, the Group was producing from four oil wells in the Klymene field by the end of 2021;

• Total oil production for Q4 2021 was 306,248 barrels compared with 160,373 barrels in Q4 2020 and for the year was 323,647 barrels compared with 384,228 barrels in 2020;

• Oil revenue was significantly higher in the quarter at $5.7 million compared with $2.0 million in 2020 reflecting significantly higher production and prices received. For the year, oil revenue was $6.0 million compared with $2.0 million in 2020. While the total number of barrels produced was lower, the average price received was significantly higher. In addition, in 2020 an additional $2.6 million in oil sales relating to test production from the KBD-02 well was capitalised to exploration & evaluation expenditure and not shown in the Group’s income statement. This changed from 30 September 2020 when commercial reserves were determined;

• Oil production costs were higher in the quarter and for the year compared with the comparable prior year periods reflecting the scaling up of activities and the production from four wells versus only one well in the prior year;

• The gross margin from oil operations in Q4 2021 was $4.9 million compared with $1.8 million in Q4 2020 and for the year was $4.6 million compared with a $1.6 million gross margin in 2020.

4

Operational highlights - continued

Gas

• Gas production in Q4 2021 averaged 1,855 boe/d compared with 2,129 boe/d in Q4 2020 and for the year averaged 1,902 boe/d compared with 2,071 boe/d in 2020. Production was from 21 wells, 13 in the Kyzyloi area and 8 in the Akkulka area. The reduction in production represents natural decline from existing wells;

• Total gas production for Q4 2021 was 28,993 Mcm compared with 33,292 Mcm in Q4 2020 and for the year was 117,944 Mcm compared with 128,436 Mcm in 2020;

• Gas revenue for the quarter was $3.3 million compared with $2.4 million in the prior year with the higher average price received more than offsetting the lower production. For the year, gas revenue was $9.9 million compared with $11.0 million in 2020 reflecting the lower production as well as a lower average price in the current year;

• Gas production costs were lower for the quarter and the year mainly due to non-recurring materials costs in the prior year;

• The gross margin from gas operations in Q4 2021 was $2.7 million compared with $1.9 million in Q4 2020 and for the year was $7.9 million compared with a $8.7 million gross margin in 2020.

5

Operational Review

Outlook

The information provided under this heading is considered as forward looking information; as such please refer to Forward Looking Statements on page 21 of this MD&A.

The Group's objective is to become a leading oil and gas exploration and production company in Central Asia, by exercising capital discipline, by generating cash flow from existing discoveries and by maturing large exploration prospects within our highly-attractive frontier acreage. The Group produces both crude oil and natural gas in Kazakhstan.

The Group's long-term ambition is to achieve a significant role in the production and delivery of hydrocarbons from the Central Asian region to local and global markets, especially to the Chinese market. In common with many oil and gas companies, in implementing its strategies, the Group considers farm-out/farm-in and joint venture opportunities and new projects which provide synergy with the Group’s activities. Meanwhile, the specific focus of management in the short term is to:

• Continue our development of the Group’s oil & gas fields to increase production levels and revenues, in particular the Klymene oil field where we are working towards a full commercial production license;

• Obtain required approvals for recently drilled wells and upcoming license renewals; and

• Fund the Group’s development plans from existing resources by working in collaboration with our service providers and oil & gas customers.

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, 2021 were 41.9 million BOE (2020: 36.7 million BOE) and “Proved + Probable” 2P reserves were 79.3 million BOE (2020: 78.6 million BOE). The net present value after tax of the Group’s 2P Kazakh reserves as at December 31, 2021 was $533.4 million (2020: $364.3 million), based on a 10% discount rate. Refer to section below headed Reserves for further details and basis of preparation.

• Drilling operations

For details of drilling operations during the year, refer to sections below headed Results of Operations and Operational Review – Kazakhstan, Oil operations update and Gas operations update.

• Oil sales agreement

In December, 2021 the Group agreed a contract for the sale of 50,000 tons of crude oil at a minimum price of $265 per ton ($33.71 per bbl), including 12% VAT. In accordance with the terms of the contract, payment of $13,250,000 was received in advance from the buyer.

6

Operational Review - continued

• Private placement

In order to fund short term cash obligations, the Company completed a private equity placement in April 2021 for 2,592,115 ordinary shares at 0.67 CAD per share (C$1,736,717), approximately $1.4 million. These proceeds were used to fund previously incurred drilling expenses, 2D and 3D seismic expenses as well as general and administrative expenses. The placement was to Pope Investments II, LLC, an investment fund managed by Pope Asset Management, LLC. William Wells, the Chairman of Tethys Petroleum is the President of Pope Asset Management, LLC and has a minority ownership interest in Pope Investments II, LLC.

Significant events and transactions subsequent to the year-end

• State of emergency due to protests in Kazakhstan

On January 2, 2022, rallies were held in the Mangistau region against a sharp increase in the price of liquefied gas, which later turned into mass protests across the country with economic and political demands. On January 4 and 5, 2022 protesters clashed with law enforcement officers in the city of Almaty, which resulted in damage to public and private property, looting and other crimes.

To ensure order and normalize the situation in the country, the President of the Republic of Kazakhstan introduced a State of Emergency for the period from January 5 to January 19, 2022, throughout the territory of Kazakhstan, and also received assistance from countries that are members of the Collective Security Treaty Organization. The measures taken by the President included the imposition of a curfew, strengthening measures to protect especially important state and strategic facilities, as well as facilities that ensure the vital activity of the population and the functioning of transport, the imposition of restrictions on movement, holding meetings and rallies, and other measures aimed at ensuring the safety of the population.

The Group increased salaries and wages to its employees to address affordability of fuel and has taken other appropriate measures to reduce the impact of the state of emergency in Kazakhstan on operating and financial results.

• Normal Course Issuer Bid

In February 2022, the Company announced that it had received TSXV approval to make a Normal Course Issuer Bid. The Company may acquire up 5,377,000 ordinary shares (roughly 5% of the shares outstanding of the Company) during the period on or about February 7, 2022 to February 7, 2023. The Company plans to use ATB Capital Markets as its member broker to conduct the purchases. Purchases will be effected through the facilities of the Exchange. Purchase and payment for the securities will be made by the Company in accordance with Exchange requirements. The price which the Company will pay will be the market price at the time of acquisition. The Board of Directors believes the shares are undervalued and any repurchases will provide a positive return on investment and enhance shareholder value.

• The situation in Ukraine

On February 24, 2022, the Russian Federation announced the recognition of the self-announced Luhansk People’s Republic and Donetsk People’s Republic independence, and the Russian military

7

Operational Review - continued

mobilized its troops to the territory of Ukraine. As a response to Russian actions, the United States, Canada, the European Union, and other states imposed severe sanctions against Russia including the banning of a number of Russian financial institutions from SWIFT, restricted transportation to and from territory of the Russian Federation, and many others, which led to the sharp devaluation of the Russian ruble and the Kazakhstani tenge. Kazakhstan and Russia have many close economic connections, for example, the vast majority of Kazakhstan oil is exported through pipelines and ports in Russia. The Group’s financial position is currently not materially affected by the events in Ukraine as the Group’s oil revenues are from domestic sales and made in US dollars, which reduces the Group’s foreign exchange risk. The management of the Group is continuing to assess the potential impact of these events on the Group.

• Oil sales agreement

On March 3, 2022 the Group agreed a second contract for the sale of 50,000 tons of crude oil, in this case at a minimum price of $385 per ton ($48.98 per bbl), including 12% VAT. In accordance with the terms of the contract, payment of $19,250,000 was received in advance from the buyer.

Reserves

Following the completion of the annual evaluation of the Kazakhstan reserves 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 41.9 million BOE (2020: 36.7 million BOE) and “Proved + Probable” 2P reserves were 79.3 million BOE (2020: 78.6 million BOE).

The net present value after tax of the Group’s 2P Kazakh reserves as at December 31, 2021 was $533.4 million (2020: $364.3 million) based on a 10% discount rate.

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

	2021	2020
	Gross fluid Net Net production	Gross fluid Net Net production
	barrels m3 barrels days **bopd **	barrels m3 barrels days **bopd **
Q1	1,308 8,227 8,227 90 91	- - - 90 -
Q2	- - - 91 -	4,827 30,361 30,079 91 331
Q3	1,462 9,197 9,172 92 100	30,848 194,025 193,776 92 2,106
Q4	48,690 306,248 306,248 92 3,329	25,497 160,373 160,373 92 1,743
Total	51,460 323,672 323,647 365 887	61,172 384,759 384,228 365 1,053

8

Operational Review - continued

Oil operations update

In 2020, test production from the KBD-02 exploration well commenced in April and continued until the end of December when it was closed for the required reporting and approval process. In 2021, production commenced from the new KBD-03 well in September, with the new KBD-06 well and KBD02 well added to production in October, followed by the new KBD-07 well in December. Accordingly, the Group was producing from four oil wells in the Klymene field by the end of 2021.

The KBD-02, KBD-06 and KBD-07 wells are in the approved pilot production project which runs to the end of 2022. Production from these wells for the period October 15, 2021 to December 31, 2021 was 33,472 tons (263,120 bbls) and the pilot production project allows a production quota of 123,000 tons (966,903 bbls) for 2022. The Group is working in the near-term to extend the pilot production project. In the medium-term the Group is working towards obtaining a full commercial production license in 2024.

Historically, the Group has produced oil under a pilot license project which requires all production to be sold domestically. A commercial production licence will require investment in additional infrastructure, such as a gas utilisation facility, but it is anticipated will allow a percentage of oil to be sold at higher export prices than can be achieved for domestic market sales.

KBD-03 is an appraisal well located outside the area covered by the pilot production project. Production from KBD-03 was 6,653 tons (52,300 bbls) for the period August 31, 2021 to December 31, 2021. Drilling of a second appraisal well, KBD-08, was completed on January 1, 2022 and is currently being tested. The Group can produce from appraisal wells outside the pilot production project for a maximum of 90 days from each zone. The Group anticipates producing from KBD-03 until June 2022 and from KBD-08 until August 2022 after which the wells will be shut in for the required reporting and approval process. Once approval has been given for these two wells they are expected to be added again to production in the second half of 2023. Further details on these wells are shown in the following table.

					Oil		Oil
Well name	Drilling start & end date	Development object	Perforation date (testing days)	Perforation intervals	production volumes upon objects	Commission date	production volume as of 31.12.2021
					testing bbls		bbls
		Jurassic	05/04/2020 (90 days)	2,403-2,441 38 meters	31,875
КBD-02	19/07/2019 06/10/2019	Lower Cretaceous	11/07/2020 (84 days)	2,136-2,152 15.5 meters	201,903	15/10/2021	97,709
		Upper Cretaceous	10/10/2020 (87 days)	2,035-2,022 2,014-2,009 18.3 meters	158,367
КBD-03	01/05/2021 27/07/2021	Jurassic Lower Cretaceous	31/08/2021 (90 days) 15/12/2021	2,403-2,441 38 meters 2,136-2,151 15.5 meters	40,640 11,660	Tba	52,300
		Upper Cretaceous	Tba	Tba	Tba
КBD-06	19/05/2021 25/07/2021	Lower Cretaceous	14/10/2021	2,137-2,146 9.4 meters	-	15/10/2021	163,264
КBD-07	08/10/2021 20/12/2021	Jurassic	27/12/2021	2,399-2,420 2,424-2,438 34.7 meters	-	28/12/2021	2,147

9

Operational Review - continued

The Group plans to drill up to three further exploration wells in the Kul-bas Exploration Contract area in 2022, KBD-04, KBD-05 and KBD-09.

In addition to the above-mentioned wells, which are all in the Kul-bas Exploration Contract area, the Group drilled the AKD-13 exploration well in the separate Akkulka Exploration Contract area. The well reached its target depth of approximately 2,500 meters, however no promising reservoirs for oil and gas saturation were identified and the well has been plugged and abandoned. There are no plans at this time to drill further deep wells in the Akkulka Exploration Contract area.

Joint Venture – Aral Oil Terminal (“AOT”)

The Group has a 50% interest in the AOT which was previously used to tranship oil after it was trucked by the buyer to the AOT. This arrangement ceased in late 2016 when a new rail line and terminal was constructed closer to the Tethys oil field. The Group continues to consider its options with regard to disposing of its interest in the terminal.

Gas production – Kyzyloi and Akkulka Contracts

		2021				2020	2020
	Mcm	Mcf	**Mcm/d **	**Boe/d **	Mcm	Mcf		**Mcm/d **	**Boe/d **
Kyzyloi
Q1	21,154	746,942	235	1,383	24,643	870,144		274	1,611
Q2	20,935	739,226	230	1,354	24,028	848,431		264	1,544
Q3	20,182	712,615	219	1,291	24,297	857,937		264	1,554
Q4	20,933	739,138	228	1,339	23,093	815,419		251	1,477
Total	83,204	2,937,921	228	1,342	96,061	3,391,931		263	1,549
Akkulka
Q1	9,371	330,898	104	613	7,333	258,930		81	480
Q2	8,902	314,332	98	576	7,129	251,733		78	461
Q3	8,407	296,868	91	538	7,714	272,373		84	493
Q4	8,060	284,613	88	516	10,199	360,139		119	652
	34,740	1,226,711	95	560	32,375	1,143,175		89	522
Total
Grand total	117,944	4,164,632	323	1,902	128,436	4,535,106		352	2,071

Gas operations update

During 2021, the Group produced dry gas from a total of 21 wells at a depth of approximately 480600m below surface, comprising 13 producing wells in the Kyzyloi field and 8 in the Akkulka field. Gas production for the quarter decreased to 316 Mcm per day compared with 370 Mcm per day in Q4 2020. For the year production decreased to 323 Mcm per day from 352 Mcm per day. No new wells were added during the year and the reduction in production from the prior year represents natural decline of the current wells.

Two new shallow gas wells were drilled at the end of 2021, AKK-28 and AKK-29 and both successfully tested commercial quantities of gas. The required reporting and approval process for these new wells is expected to take 8-9 months after which these wells are expected to be added to production around September 2023.

The Group plans to conduct 900km of 2D seismic at a cost of up to $1.7 million in 2022 and drill up to eight shallow gas wells to increase gas production, four in the Kyzyloi contract area and four in the Kul-bas contract area.

10

Financial Review

Summary of Quarterly Results

	Q4, 2021	Q3, 2021	Q2, 2021	Q1, 2021	Q4, 2020	Q3, 2020	Q2, 2020	Q1, 2020	Q1, 2020
Oil and gas sales revenues	9,054	2,516	1,952	2,384	4,414	2,148	2,977	3,501
(Loss)/profit for the period	(3,023)	(108)	(765)	(93)	(34,756)	(240)	3,907	(7,432)
(Loss)/earnings per share ($):	(0.04)	(0.00)	(0.01)	(0.00)	(0.35)	(0.00)	0.04	(0.09)
Adjusted EBITDA	6,945	1,064	511	1,127	2,459	1,220	1,885	1,448
Capital expenditure1	7,884	4,004	2,767	836	7,976	1,385	289	165
Total assets	73,944	58,553	54,691	52,751	53,817	92,304	92,459	96,421
Cash & cash equivalents	9,277	658	508	433	1,747	4,575	650	4,519
Short & long term borrowings	6,578	6,298	6,034	5,785	5,549	9,572	13,159	24,342
Total non-current liabilities	16,603	13,050	12,657	15,574	11,867	16,632	16,320	15,659
Net (cash)/debt2	(2,699)	5,640	5,526	5,352	3,802	4,997	12,509	19,823
Number of common shares	107,548,114	107,548,114	107,548,114	104,955,999	104,955,999	104,955,999	104,955,999	86,955,999
outstanding

Note 1 – Amounts stated are prior to offset of sales from test production.

Note 2 - Adjusted EBITDA and net debt are non-GAAP Measures, refer to page 18 for details.

• Quarterly gas revenue has fluctuated in the range $1.8 to $3.5 million range since Q1 2020, mainly due to changes in price as production has remained relatively stable, albeit with a natural decline. Oil sales from the KBD-02 exploration well test production commenced in April 2020 but these were offset against capitalised exploration expenditure and so are not shown in the table above. Once commercial reserves were established at September 30, 2020 oil sales from this well were recognised as revenue which accounts for the revenue increase in Q4 2020. The well was shut in at the end of December 2020 for the required reporting and approval process. Oil sales commenced again towards the end of Q3 2021 from the KBD-03 well followed by the KBD-06, KBD-02 and KBD-07 wells in Q4 2021, which accounts for the significant increase in revenue in Q4 2021.

• (Loss)/profit for the quarter has fluctuated due to the abovementioned revenue changes as well as a number of one-off factors. Profit before tax in the current quarter was $4.1 million although after a $7.1 million tax charge the loss after tax was $3.0 million. The Q1 2020 quarter included a $15.3 million impairment charge of the Akkulka oil asset, a further $42.4 million impairment was recognised in Q4 2020 and $1.0 million in Q4 2021. Gains from loan modifications were recognised in Q1 2020 of $8.3 million, Q2 2020 of $4.0 million and $2.8 million in Q4 2020.

• Adjusted EBITDA, a non-GAAP measure, has been positive every quarter in the $0.5 to $2.5 million range until the Q4 2021 quarter when adjusted EBITDA increased significantly to $6.9 million due mainly to the increase in oil revenues;

• Total assets reduced Q4 2020 mainly due to the above-mentioned Akkulka oil impairment and increased in Q4 2021 due to the increase in cash & cash equivalents and capital expenditure on oil & gas properties;

• Short & long term borrowings reduced in Q2 and Q3 2020 as the remaining past due loans were settled. New shareholder loans of $4.8 million were received in Q2 2020 and $2.5 million in Q4 2020;

• Net (cash)/debt, a non-GAAP measure, was affected by the changes in borrowings mentioned above and in Q4 2021 by the increase in cash from higher oil revenues;

11

Financial Review - continued

• Shares were issued in Q1 2020 as part of the conversion of borrowings into equity and a private placement was made in Q1 2021 as described above under in the section Significant events and transactions for the year.

Loss for the period

		Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
		December 31			December 31
	2021	2020	**Change **	2021	2020	**Change **
Sales revenues	9,054	4,414	105%	15,906	13,040	22%
Production expenses	(1,317)	(741)	78%	(3,253)	(2,779)	16%
Depreciation, depletion and amortisation	(990)	(150)	560%	(3,277)	(3,634)	(10%)
Impairment charges	(1,036)	(42,350)	(98%)	(1,036)	(57,630)	(98%)
Administrative expenses	(897)	(896)	0%	(3,209)	(3,089)	4%
Share-based payments	(27)	-	-	(27)	-	-
Other gains and losses	(529)	2,769	(119%)	(399)	15,030	(103%)
Foreign exchange gains and loss	133	(318)	(142%)	230	(160)	(244%)
Finance costs	(319)	(325)	(2%)	(1,177)	(2,645)	(56%)
	(4,982)	(42,011)	(86%)	(12,148)	(54,907)	(78%)
Profit/(loss) before taxation	4,072	(37,597)	(111%)	3,758	(41,867)	(109%)
Taxation	(7,095)	2,841	(350%)	(7,747)	3,346	(332%)
Loss for theperiod	(3,023)	(34,756)	(91%)	(3,989)	(38,521)	(90%)

The Group recorded a loss after taxation of $3.0 million for Q4 2021 compared with a loss of $34.8 million in Q4 2020 and loss of $4.0 million for 2021 (2020: $38.5million loss), the principal variances being:

• Higher revenue in the quarter from oil sales of $5.7 million versus $2.0 million in Q4 2020 and $6.0 million for the year versus $2.0 million in 2020.

• Higher revenue in the quarter from gas sales of $3.3 million versus $2.4 million in Q4 2020 and $9.9 million for the year versus $11.0 million in 2020;

• Higher production costs due to the scaling up of oil production;

• Impairment charge of $1.0 million in the quarter (Q4 2020: $42.4 million) and $1.0 million for the year (2020: $57.6 million) relating to the Akkulka oil assets;

• Other gains and losses included non-recurring gains of $2.8 million for Q4 2020 and $15.0 million for the 2020 year relating to early settlement of borrowings on favourable terms. Current year amounts include non-cash valuation adjustments for expected credit losses;

• Lower finance costs due to the lower level of borrowings following settlement of the majority of borrowings in early 2020; and

• A tax charge in the quarter of $7.1 million (2020: $2.8 million tax credit) and for the year of $7.7 million (2020: $3.3 million tax credit) as explained below.

12

Financial Review - continued

Sales & other revenue

	Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
		December 31			December 31
	2021	2020	**Change **	2021	2020	**Change **
By region and type
Kazakhstan - Oil	5,740	1,992	188%	6,007	1,992	202%
Kazakhstan - Gas	3,314	2,419	37%	9,899	11,045	(10%)
Other revenue	-	3	(100%)	-	3	(100%
Total	9,054	4,414	105%	15,906	13,040	22%

Kazakhstan – Oil revenue

• The Group’s oil sales price is determined at the wellhead where the oil is sold and therefore the Group incurred no transportation or marketing costs;

• Oil was produced under a pilot production project and is sold in the domestic Kazakhstan market priced in United States dollars;

• In 2021, oil sales commenced from the new KBD-03 well in September, with the new KBD-06 well and KBD-02 well added to production in October, followed by the new KBD-07 well in December. In 2020, sales revenue from KBD-02 began to be recognised from October. There was an additional $2.6 million of oil sales received during the testing phase of KBD-02 from April-September 2020 which was offset against the exploration asset and so not shown in the table above.

Kazakhstan - Gas revenue

• Gas production is sold in local currency, Kazakhstan Tenge . The price varies from month-to-month depending on global supply and demand factors. The price received is typically higher over the winter months and rose significantly in Q4 2021 due to the rise in global gas prices;

• The Group produced dry gas from a total of 21 wells at a depth of approximately 480-600m below surface, comprising 13 producing wells in the Kyzyloi field and 8 in the Akkulka field;

• Production was lower for the quarter and the year due to natural decline from existing wells. The average price received in the quarter was significantly higher due to higher world gas prices although for the year the average price received was slightly lower than in 2020

Oil and gas sales are subject to exchange rate risk – refer to page 20 – “ Sensitivities ”.

13

Financial Review - continued

Production expenses

			Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
				December 31			December 31
		Units	2021	2020	**Change **	2021	2020	**Change **
Kazakhstan
Oil production costs		$000’s	857	225	281%	1,399	430	225%
Gasproduction costs		$000’s	460	516	(11%)	1,854	2,349	(21%)
Total		$000’s	1,317	741	78%	3,253	2,779	17%
Kul-bas costs capitalised1		$000’s	-	-	-	-	179	(100%)
Oil
Production		bbls	306,248	160,373	91%	323,647	384,228	(16%)
Cost		$/bbl	2.80	1.40	100%	4.32	1.58	173%
Gas
Production		boe	170,636	195,939	(13%)	694,149	755,899	(8%)
Cost		$/boe	2.70	2.63	3%	2.67	3.11	(14%)
Weighted average cost per boe		$/boe	2.76	2.08	33%	3.20	2.59	24%

Note 1 – in accordance with the Group’s accounting policy and industry practice oil production costs relating to test production from the KBD-02 well were capitalised to exploration & evaluation expenditure and not shown in the Group’s income statement until 30 September 2020 when commercial reserves were determined.

Kazakhstan – oil production

Oil production costs incurred in Q4 2021 were $0.9 million ($2.80/bbl) and for the year were $1.4 million ($4.232/bbl). It is difficult to make a meaningful comparison with 2020 because production from the Klymene field only began in 2020 and was scaled up significantly during Q4 2021. Production costs in Q4 2021 relate to four wells (KBD-02, KBD-03, KBD-06 and KBD-07) whereas in Q4 2020 there was only one well (KBD-02). From April-September 2020, production costs of $0.2 million were capitalised during the testing of the KBD-02.

Kazakhstan – gas production

Gas production costs for the quarter were $0.5 million or $2.70/boe (Q4 2020: $0.5 million or $2.63/boe) and for the year were $1.9 million or $2.67/boe (2020: $2.3 million or $3.11/boe) in part due to the reduction in volumes as well as higher materials costs in 2020 which did not recur at the same level in 2021.

Administrative expenses

		Quarter ended	Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended	Twelve months ended
			December	31			December	31
		2021	2020		**Change **	2021	2020		**Change **
Staff		467	415		13%	1,598	1,611		(1%)
Non-executive director fees		31	89		(65%)	201	257		(22%)
Professional fees		175	154		14%	581	507		15%
Other administrative expenses		224	238		(6%)	829	714		16%
Total		897	896		0%	3,209	3,089		4%
G&A expenses per boe ($)		1.88	2.54		(26%)	3.15	2.72		16%

14

Financial Review - continued

• Staffing levels were at a similar level in 2021 to the prior year which is reflected in staff costs for the year being broadly comparable;

• Non-executive director fees were paid at the same rate in 2021 although there was a different mix in the number of directors in place during the year as well as a foreign exchange impact;

• Professional fees were higher due to a greater use of consultants as the Group increased the scale of its activities, particularly development of the Klymene oil field; and

• Other administrative expenses include office costs, travel, regulatory costs, insurance, investor relations, mandatory socio-economic contributions in Kazakhstan, vehicles costs, bank fees and other miscellaneous costs.

Foreign exchange loss - net

Foreign exchange gains and losses arise from the revaluation of monetary assets and liabilities denominated in currencies other than the functional currency of US dollars and the receipt or settlement of foreign currency denominated amounts at a different amount than the originally recorded transaction amount. These have mainly arisen in the Kazakhstan subsidiaries.

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. With the positive recent progress made in the development of the Group’s oil and gas fields the Group now expects to earn taxable profits in coming years upon which both CIT and EPT will be due. Accordingly, the Group has re-estimated its deferred tax liabilities during the period using the average CIT and EPT rate expected to apply in the periods the deferred tax balances will reverse resulting in an additional tax charge in the current period. 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.

Liquidity and Capital Resources

The Group reported a profit before tax of $3.8 million (2020: $41.9 million loss) and a loss after tax of $4.0 million (2020: $38.5 million loss) while Adjusted EBITDA, a non-GAAP measure, was $9.6 million (2020: $7.0 million). Cash flow from operating activities of $14.9 million for the year ended December 31, 2021 (2020: $17.5 million).

The Group’s accumulated deficit at that date was $406.6 million (December 31, 2020: $402.6 million) and working capital (current assets minus current liabilities) was negative $21.5 million (December 31, 2020: negative $11.8 million).

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.

15

Financial Review - continued

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.

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 the date of approval of the consolidated financial statements. 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 oil prices received during the forecast period being 25% lower than the current contractual price.

The Group would seek to mitigate this by reducing discretionary capital expenditure, including one or more of the three Kul-bas exploration wells and the eight shallow gas wells the Group is planning to drill in 2022.

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. This includes $2.7 million due for repayment of the Gemini loan in October 2022 and $6.2 million due for repayment of the convertible debenture in April 2023, although it is currently anticipated that the debenture will be converted into shares with no impact on the Group’s cash flows. After these loans have been repaid the Group will have no borrowings.

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, 2021.

16

Financial Review - continued

Cash Flow

		Quarter ended	Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
			December	31			December 31
		2021	2020		**Change **	2021	2020	**Change **
Net cash from operating activities		10,968	3,097		254%	14,914	17,493	(15%)
Capital expenditure1		(7,884)	(7,976)		(1%)	(15,491)	(6,958)	123%
Net changes in working capital		5,602	2,477		126%	7,004	1,362	414%
Other investingcash flows		9	115		(92%)	(248)	105	(336%)
Net cash used in investing activities		(2,273)	(5,384)		(58%)	(8,735)	(5,491)	57%
Proceeds from issuance of shares		-	-		-	1,401	-	-
Proceeds of borrowings		-	2,504		(100%)	-	7,304	(100%)
Repayment of borrowings		-	(2,930)		(100%)	-	(14,620)	(100%)
DSFK settlement		-	-		-	-	(3,424)	(100%)
Net cash (used in)/from financing activities		-	(426)		(100%)	1,401	(10,740)	(113%)
Effect of exchange rates		(76)	(115)		(21%)	(50)	(209)	(76%)
Net increase/(decrease) in cash		8,619	(2,828)		(405%)	7,530	1,053	615%
Cash & cash equivalents at beginningofperiod		658	4,575		(86%)	1,747	694	152%
Cash & cash equivalents at end ofperiod		9,277	1,747		431%	9,277	1,747	431%

Note 1 – 2020 capital expenditure amount was $9,515,000 net of $2,557,000 of revenue receipts capitalised during the testing phase.

Operating activities

Net cash from operating activities in the current quarter was higher due to receipts for oil sales which were $12.1 million higher than in Q4 2020. For the year receipts for oil sales were $12.0 million higher. Receipts for gas sales were at a similar level in both years. Payments relating to operating activities were significantly higher in 2021 due to availability of funds from oil sales and timing of supplier payments.

Investing activities

Capital expenditure in 2021 relates to seismic acquisition and interpretation as well as the drilling costs of five deep wells (KBD-03, KBD-06, KBD-07, KBD-08and AKD-13) and two shallow gas wells AKK28 and AKK-29, although a portion of the costs for these wells is not due until 2022.

Capital expenditure in 2020 relates to seismic acquisition and interpretation as well as the drilling costs paid for the KBD-02 deep well (drilled in 2019), the AKD-12 deep well and four shallow gas wells (AKK-33, AKK-100, AKK-101 and AKK-102). Oil sales revenue of $2.6 million received in 2020 was offset against the exploration asset during the KBD-02 testing period.

Financing activities

In the current year, shares were issued for proceeds of $1.4 million as described above under Significant events and transactions for the year.

Proceeds from borrowings in the prior year comprised $4.8 million from a debenture issued to Gemini in April 2020 and a $2.5 million unsecured loan received from Gemini in October 2020. Repayments of borrowings comprised $7.7 million to settle the Khan Energy loan and $6.9 million to settle the loan originally made to AGR Energy. The settlement payment to DSFK in the amount of KZT 1.4 billion ($3.4 million) was paid in Q2 2020.

17

Financial Review - continued

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 Significant Accounting Policies of the December 31, 2021 consolidated financial statements. Refer to note 4 – Critical Judgments and Accounting Estimates of the December 31, 2021 consolidated financial statements for information on the Group’s significant judgments and assumptions and critical estimates.

Off-Balance Sheet Arrangements

The Group has no off-balance sheet arrangements.

Non-GAAP Measures

Adjusted EBITDA

Adjusted EBITDA is defined as “Profit/(loss) before Interest, Tax, Depreciation, Amortisation, and noncash items” 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 amortised, or how results are taxed in various jurisdictions. The reconciliation of Adjusted EBITDA to profit/(loss) for the period is as follows:

		Quarter ended	Quarter ended	Quarter ended		Twelve months ended	Twelve months ended	Twelve months ended
			December	31			December 31
		2021	2020		**Change **	2021	2020	**Change **
Profit/(loss) before taxation		4,071	(37,597)		(111%)	3,758	(41,867)	(109%)
Depreciation, depletion and amortisation		990	150		560%	3,277	3,634	(10%)
Impairment charges		1,036	42,350		(98%)	1,036	57,630	(98%)
Other gains and losses		529	(2,769)		(119%)	399	(15,030)	(103%)
Finance costs - net		319	325		(2%)	1,177	2,645	(56%)
Adjusted EBITDA		6,945	2,459		182%	9,647	7,012	38%

Net (cash)/debt

Net (cash)/debt is calculated as total borrowings (which includes current and non-current borrowings) less cash and cash equivalents, but excludes deferred revenues. Total capital is calculated as equity (minus)plus net (cash)/debt. All figures are as stated in the December 31, 2021 consolidated financial statements.

		As at December 31	As at December 31
		2021	2020	Change
Total financial liabilities - borrowings		6,578	5,549	19%
Less: cash and cash equivalents		(9,277)	(1,747)	431%
Net (cash)/debt		(2,699)	3,802	(171%)
Total equity		22,359	24,920	15%
Total capital		19,660	28,722	(10%)

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.

18

Financial Review - continued

Stockholder Equity

As at December 31, 2021 the Company had authorised share capital of 145,000,000 (2020: 145,000,000) ordinary shares of which 107,548,114 (2020: 104,955,999) had been issued and 50,000,000 (2020: 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 107,548,114 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, 2021 was 1,728,438 (2020: 1,128,438). Loan facilities were in place which are convertible into a total of up to 17,437,354 (2020: 17,437,354) ordinary shares if held to maturity and converted on the maturity date.

Dividends

There were no dividends paid or declared in the period.

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
Borrowings	8,223	2,818	5,405	-	-
Kazakhstan work program commitments	46,438	14,702	13,067	9,187	9,482
Trade and other payables	15,969	15,969	-	-	-
Provisions	2,984	557	331	1,204	892
Total contractual obligations	73,614	34,046	18,803	10,391	10,374

19

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 2021 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 this is managed is given in note 3 to the consolidated financial statements for the year ended December 31, 2021. 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

The price of gas sales from gas produced from both the Kyzyloi and Akkulka gas fields under gas sales contracts denominated in tenge and is sensitive to a fluctuation in exchange rates. A 20% net price reduction from the 2021 average sales price, would result in a reduction of $1.9 million in gas revenues based on the 2021 gas sales volume of 115,647 Mcm.

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 2021 average sales price, would result in a reduction of $1.2 million in oil revenues based on the 2021 oil sales volume of 314,143 bbls.

Derivative Financial Instruments

The Group does not have any derivative financial instruments.

Significant equity investees

The Group does not have any significant equity investees.

20

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.

21

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.

22

AKD	Akkulka Deep well in the Akkulka Exploration Contract area
AOT	Aral Oil Terminal LLP
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
Klymene	Oilfield under development in the Kul-Bas Exploration Contract area
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
	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
sq.km	Square kilometre
TAG	Tethys Aral Gas LLP
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

23