EX-99.3

The following discussion and analysis is management’s opinion of TransGlobe Energy Corporation's ("TransGlobe" or the "Company") historical financial and operating results and should be read in conjunction with the message to shareholders and the audited consolidated financial statements of the Company for the years ended December 31, 2021 and 2020, together with the notes related thereto (the "Consolidated Financial Statements"). The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) in the currency of the United States, except otherwise noted. Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com. The Company’s Annual Report on Form 40-F may be found on EDGAR at www.sec.gov.

Throughout this MD&A and in other materials disclosed by the Company, TransGlobe adheres to generally accepted accounting principles ("GAAP"), however the Company also employs certain non-GAAP and other financial measures to analyze financial performance, financial position, and cash flow including, "netback", "capital expenditures" and "funds flow from operating activities". Additionally, other financial measures are used to analyze performance including, but not limited to, "funds from operations" and "net debt". These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other companies. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net earnings (loss), cash flow generated by operating activities, and cash flow used in investing activities, as indicators of TransGlobe’s performance.

Readers are cautioned that the MD&A should be read in conjunction with the Company’s disclosure in the sections entitled "Non-GAAP and Other Financial Measures", "Forward-looking Statements" and “Oil and Gas Advisories” included at the end of this MD&A.

The 2022 outlook provides information as to management’s expectation for results of operations for 2022. Readers are cautioned that the 2022 outlook may not be appropriate for other purposes. The Company’s expected results are sensitive to fluctuations in the business environment in the jurisdictions that the Company operates in, and may vary accordingly. This outlook contains forward-looking statements that should be read in conjunction with the Company’s disclosure under “Forward-Looking Statements”, outlined at the end of this Management’s Discussion and Analysis (“MD&A").

The 2022 production outlook for the Company is provided as a range to reflect timing and performance contingencies.

As announced on January 20, 2022, the Company has fully executed its agreement (the “Merged Concession agreement”) with the Egyptian General Petroleum Corporation (“EGPC”) to merge its three existing Eastern Desert concessions with a 15-year primary term and improved Company economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession agreement with the Company, the Company paid the first modernization payment ($15.0 million) and signature bonus ($1.0 million) as part of the conditions precedent to the official signing ceremony on January 19, 2022. On February 1, 2022, TransGlobe paid the second modernization payment ($10.0 million). In accordance with the Merged Concession agreement, TransGlobe will make a further four annual equalization payments of $10.0 million each beginning February 1, 2023 until February 1, 2026. The Company also has minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on the February 1, 2020 effective date.

The Merged Concession agreement consolidates the Company’s three existing producing concessions in the Eastern Desert which, in December 2021, had a combined average production of 9,394 Bopd (8,590 Bopd heavy crude; 803 Bopd light and medium crude). As the Merged Concession agreement is effective as of February 1, 2020, there will be an effective date adjustment owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the effective date. The quantum of the effective date adjustment is expected to be finalized with EGPC in the coming months.

Total corporate production is expected to range between 12.4 and 13.4 Mboe/d (mid-point of 12.9 Mboe/d) for 2022 with a 93% weighting to oil and liquids. Egypt oil production is expected to range between 10.0 and 10.8 Mbbls/d (mid-point of 10.4 Mbbls/d) in 2022. Canadian production is expected to range between 2.4 and 2.6 Mboe/d (mid-point of 2.5 Mboe/d) in 2022.

Funds flow from operations in any given period is dependent upon the timing and market price of crude oil sales in Egypt. Because these factors are difficult to accurately predict, the Company has not provided funds flow from operations guidance for 2022. Funds flow from operations and inventory levels in Egypt may fluctuate significantly from quarter to quarter due to the timing of crude oil sales.

The Company’s 2022 capital program of $57.7 million (before capitalized G&A) includes $33.1 million for Egypt and $24.6 million for Canada. The 2022 plan was prepared to focus on value accretive projects within its portfolio, maximize free cash flow to direct at future growth opportunities and to increase the Company’s production base and return to shareholder distributions. The 2022 drilling program includes 17 Egypt wells and 7 Canadian Cardium wells in South Harmattan.

The 2022 $33.1 million Egypt capital program is predominantly weighted towards 13 development wells within the Eastern Desert, including two Arta Nukhul horizontal multi-stage completion wells. Additionally, two exploration wells are planned for the second half of the year along with a further two water injection wells, bringing the total planned number of wells in Egypt to 17. The Egypt capital program includes $12.6 million of other spending, of which half relates to materials, including long-lead capital items which are expected to provide continuity into 2023. With the finalization of the Merged Concession agreement, the primary focus of the 2022 Egypt plan is to accelerate the exploitation of the Company’s Eastern Desert acreage while optimizing the potential of modern, horizontal multi-stage completion wells in accessing the Company’s contingent resource base.

The 13 well development program, already underway, consists of nine vertical development wells in K-field, the two previously mentioned horizontal wells in Arta field, and two further vertical wells in Arta field.

Egypt production is expected to average between 10.0 and 10.8 Mbbl/d for the year.

The $24.6 million Canada program consists of drilling seven (seven net) horizontal wells all targeting the Cardium light oil resource at South Harmattan along with additional maintenance/development capital. The Cardium drilling program in 2022 consists of six 1-mile and one 2-mile wells. Two of these wells are expected to be drilled in Q1-2022. The remaining five wells are expected to be drilled in late June through August, and all wells are expected to be completed and brought on-stream in late summer to early fall 2022.

Canada production is expected to average between 2.4 and 2.6 Mboe/d for the year.

	TransGlobe 2022 Capital ($MM)				Gross Well Count
	Development		Exploration		Drilling
Concession	Wells	Other¹	Wells	Total²	Development	Exploration	Injection	Total
Eastern Desert	18.9	12.4	1.6	32.9	13	2	2	17
South Ghazalat	-	0.2	-	0.2	-	-	-	-
Egypt	18.9	12.6	1.6	33.1	13	2	2	17
Canada	21.1	3.5	0.0	24.6	7	-	-	7
2022 Total	40.0	16.1	1.6	57.7	20	2	2	24

($000s, except per share amounts, price and volumes)	2021	% Change	2020	% Change	2019
Operations
Average production volumes
Crude oil (bbls/d)	11,336	(4)	11,858	(18)	14,527
NGLs (bbls/d)	740	(6)	785	35	582
Natural gas (Mcf/d)	4,667	-	4,686	(16)	5,594
Total (boe/d)	12,854	(4)	13,425	(16)	16,041
Average sales volume
Crude oil (bbls/d)	11,960	(14)	13,871	3	13,441
NGLs (bbls/d)	740	(6)	785	35	582
Natural gas (Mcf/d)	4,667	-	4,686	(16)	5,594
Total (boe/d)	13,478	(13)	15,437	3	14,954
Average realized sales prices¹
Crude oil ($/bbl)	63.12	76	35.80	(35)	55.31
NGLs ($/bbl)	32.16	120	14.59	(36)	22.93
Natural gas ($/Mcf)	2.93	79	1.64	24	1.32
Total oil equivalent ($/boe)	58.79	76	33.41	(35)	51.10
Inventory (Mbbls)	-	(100)	227.9	(76)	964.5
Petroleum and natural gas sales²	303,956	61	188,771	(32)	278,929
Petroleum and natural gas sales, net of royalties²	169,006	47	114,675	(18)	140,096
Cash flow generated by operating activities	44,962	42	31,709	(29)	44,836
Funds flow from operations³	44,831	47	30,443	(35)	46,871
Funds flow from operations per share⁴:
Basic	0.62		0.42		0.65
Diluted	0.61		0.42		0.65
Net earnings (loss)	40,338	(152)	(77,397)	1,837	(3,995)
Net earnings (loss) per share:
Basic	0.56		(1.07)		(0.06)
Diluted	0.55		(1.07)		(0.06)
Capital expenditures⁵	26,822	258	7,498	(80)	36,932
Dividends declared	-	-	—	-	5,078
Dividends declared per share	-	-	—	-	0.070
Total assets	239,095	19	201,147	(35)	308,325
Cash and cash equivalents	37,929	10	34,510	4	33,251
Working capital⁶	21,032	37	15,349	(52)	32,194
Total long-term debt, including current portion	3,040	(86)	21,464	(42)	37,041

⁶ Supplementary financial measure that is comprised of current assets less current liabilities, as determined in accordance with IFRS.

	2021				2020
($000s, except per share amounts, price and volumes)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Operations
Average production volumes
Crude oil (bbls/d)	11,241	11,877	11,414	10,802	10,886	10,473	12,696	13,404
NGLs (bbls/d)	716	677	857	710	755	798	826	761
Natural gas (Mcf/d)	4,832	4,734	4,834	4,259	4,454	4,633	4,665	4,996
Total (boe/d)	12,763	13,342	13,077	12,221	12,384	12,044	14,300	14,997
Average sales volumes¹
Crude oil (bbls/d)	11,241	13,402	14,879	8,271	14,215	9,110	10,865	21,341
NGLs (bbls/d)	716	677	857	710	755	798	826	761
Natural gas (Mcf/d)	4,832	4,734	4,834	4,259	4,454	4,633	4,665	4,996
Total (boe/d)	12,763	14,868	16,542	9,691	15,712	10,680	12,470	22,934
Average realized sales prices²
Crude oil ($/bbl)	71.84	64.76	60.39	53.26	37.40	37.14	23.40	40.47
NGLs ($/bbl)	40.76	35.40	27.03	26.42	18.96	15.65	11.43	12.49
Natural gas ($/Mcf)	3.88	2.71	2.58	2.46	1.85	1.80	1.31	1.61
Total oil equivalent ($/boe)	67.03	60.85	56.48	48.47	35.27	33.63	21.63	38.42
Inventory (Mbbls)	-	-	140.3	455.7	227.9	534.0	408.7	242.1
Petroleum and natural gas sales³	93,428	83,234	85,018	42,277	50,989	33,046	24,549	80,187
Petroleum and natural gas sales, net of royalties³	58,043	42,316	50,595	18,052	33,309	16,740	11,392	53,234
Cash flow (used in) generated by operating activities	(1,956)	27,026	23,832	(3,940)	14,180	(3,349)	24,551	(3,672)
Funds flow from operations⁴	15,269	12,381	17,100	81	7,202	323	(2,764)	25,683
Basic per share⁵	0.21	0.17	0.24	-	0.10	-	(0.03)	0.35
Diluted per share⁵	0.21	0.17	0.24	-	0.10	-	(0.03)	0.35
Net earnings (loss)	6,560	37,080	7,722	(11,024)	(2,855)	(5,957)	(13,367)	(55,218)
Basic per share	0.09	0.51	0.11	(0.15)	(0.04)	(0.08)	(0.19)	(0.76)
Diluted per share	0.09	0.51	0.11	(0.15)	(0.04)	(0.08)	(0.19)	(0.76)
Capital expenditures⁶	8,694	11,624	3,597	2,907	254	437	1,229	5,577
Total assets	239,095	267,263	208,479	197,150	201,147	205,583	221,347	241,219
Cash and cash equivalents	37,929	53,952	43,639	28,669	34,510	27,065	34,837	23,830
Working capital⁷	21,032	17,667	17,136	7,055	15,349	12,708	35,112	53,294
Total long-term debt, including current portion	3,040	6,882	16,951	21,699	21,464	25,946	27,071	36,591

⁷ Supplementary financial measure that is comprised of current assets less current liabilities, as determined in accordance with IFRS.

The Company’s financial results are influenced by fluctuations in commodity prices, including price differentials. The following table shows select market benchmark prices and foreign exchange rates:

In 2021, the average price of Dated Brent oil was 69% higher than in 2020. Egypt production is priced based on Dated Brent, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company. The PSCs provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSCs, the Contractor's share of excess ranges between 0% and 30%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost oil ranges from 25% to 30% in Egypt. The balance of the production after maximum cost recovery is shared with the government (profit oil). Depending on the contract, the Egyptian government receives 70% to 85% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less cost oil and may receive more production-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. For reporting purposes, the Company records the government’s share of production as royalties and taxes (all taxes are paid out of the government’s share of production) which will increase during times of rising oil prices and decrease in times of declining oil prices. If oil prices are sufficiently low and the Gharib Blend/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSCs and any eligible extension periods.

EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC cooperation and approval to schedule liftings. Once liftings occur, the Company incurs a 30-day collection cycle on liftings as a result of direct marketing to third-party international buyers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings.

TransGlobe pays royalties to the Alberta provincial government and landowners in accordance with the established royalty regime. In Alberta, Crown royalty rates are based on reference commodity prices, production levels and well depths, and are offset by certain incentive programs in place to promote drilling activity by reducing overall royalty expense.

In 2021, the average price of Edmonton Sweet index oil (expressed in US$) was 87% higher than in 2020. In 2021, the average price of AECO natural gas increased by 73% compared to 2020.

Netback per barrel in Egypt increased by 101% in 2021 compared to 2020. The increase was primarily due to 75% higher average realized sales price, partially offset by 110% higher royalties and taxes per bbl, 10% higher production and operating expenses per bbl and 118% higher selling costs per bbl.

In Egypt, petroleum and natural gas sales increased by $84.3 million to $257.3 million from 2020. This was primarily due to an increase in realized prices, partially offset by a decrease in sales volumes from the prior year. The realized sales price for the year ended December 31, 2021 was $62.94/bbl (2020 - $35.94/bbl), which was $7.74/bbl lower (2020 - $5.82/bbl lower) than the average Dated Brent oil price of $70.68/bbl for 2021 (2020 - $41.76/bbl). The difference between the average selling price and Dated Brent is due to a gravity/quality adjustment and is also impacted by the specific timing of direct sales.

In Egypt, royalties and taxes in 2021 increased by $67.0 million from 2020, representing 59% of petroleum and natural gas sales in 2021 (2020 - 49%). Royalties and taxes are settled on a production basis, therefore, the correlation of royalties and taxes to oil sales fluctuates depending on the timing of entitlement oil sales. If sales volumes had been equal to production volumes during the year, royalties and taxes as a percentage of revenue would have been 63% (2020 - 58%). In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the terms of the PSCs. In periods when the Company sells more than its entitlement production, royalties and taxes as a percentage of revenue will be lower than the terms set out in the PSCs. The increase in total royalties and taxes, and the relative increase from 49% in 2020 to 59% in 2021, was due to excess cost oil in the West Bakr concession, partially offset by sales outpacing production in 2021. Excess cost oil occurs when the current costs and historic cost amortization, permissible within the PSCs, are less than the proportion of cost oil value. In the case of West Bakr, 100% of excess cost oil belongs to EGPC, which effectively increases the royalties and taxes burden.

In Egypt, production and operating expenses fluctuate periodically due to changes in inventory volumes as a portion of costs are capitalized and expensed when sold. Production and operating expenses decreased by 7% ($3.9 million) in 2021 compared with 2020. The decrease was primarily due to a decrease in crude oil sales in 2021 compared to 2020, resulting in less operating costs previously capitalized to inventory being expensed in 2021 compared to 2020 ($2.2 million). The decrease was also due to lower production handling fees. These decreases were partially offset by an increase in manpower cost and workovers. The increase in production and operating expenses per bbl from $12.11/bbl in 2020 to $13.30/bbl in 2021 was primarily due to a comparative 5% decrease in production in Egypt.

Selling costs increased by $1.8 million to $3.9 million in 2021. Selling costs per bbl increased by 118% to $0.96/bbl in 2021. These increases were due to the specific shipping terms of the two cargo liftings that occurred in Egypt in 2021 when compared to the two cargo liftings that occurred in 2020.

Netbacks per boe in Canada increased by 177% in 2021 compared with 2020. The increase was primarily due to a 104% higher average realized sales price, partially offset by a 115% increase in royalties per boe and a 15% increase in production and operating expenses per boe.

In Canada, petroleum and natural gas sales increased by $16.2 million to $31.9 million from 2020. This was primarily due to an increase in realized prices, partially offset by a decrease in sales volumes from the prior year.

In Canada, royalties increased by $2.7 million from 2020, representing 16% of petroleum and natural gas sales during 2021 compared to 15% during the prior year. This increase was primarily due to an increase in crown royalties and in freehold and overriding royalties as a result of improved commodity pricing, and a decrease in Gas Cost Allowance (“GCA”) rebates received in 2021 compared to 2020. This was partially offset by lower royalties due to royalty holidays on the three oil wells drilled during 2021. TransGlobe pays royalties to the Alberta provincial government and landowners in accordance with an established royalty regime. In Alberta, Crown royalty rates are based on reference commodity prices, production levels and well depths, and are offset by certain incentive programs in place to promote drilling activity by reducing overall royalty expense.

Production and operating expenses increased by 15% ($0.9 million) in 2021 compared with 2020. The increase was primarily due to an increase in chemical costs and power and utilities due to an increase in commodity prices and the strengthening of the Canadian dollar in 2021. This was partially offset by a decrease in transportation costs and gas processing fees.

Overlift refers to a situation where the Company lifts barrels in excess of its entitlement crude oil inventory at the time of sale. An overlift liability represents an obligation for the Company to deliver the equivalent future entitlement production. Settlement of the overlift liability occurs when this entitlement production is delivered or when there is an agreement in place to offset amounts owed from the counterparty. At the time of an overlift, the Company recognizes the revenue from the cargo lifting, with an equivalent cost recorded to an expense resulting in no net earnings impact related to the overlifted barrels during the period.

Gross G&A decreased by 1% in 2021 compared with 2020. This decrease was primarily due to lower salary expense in 2021 resulting from one-time restructuring charges, partially offset by higher professional fees and increased corporate travel.

Share-based compensation increased significantly in 2021 compared to 2020. This increase was primarily due to an increase in the Company's average share price in 2021 and the associated revaluation of the Company’s potential obligations.

Capitalized G&A decreased by 11% from the prior year due to less staff time allocated to capital projects as a result of reduced headcounts, partially offset by increased capital activity in 2021. The increase in capitalized G&A and overhead recoveries per boe is primarily due the decrease in sales volumes in 2021, partially offset by the decrease in capitalized G&A and overhead recoveries noted from the prior year.

Finance costs decreased by 55% to $1.1 million in 2021, primarily due to a lower balance of long-term debt outstanding in the year when compared to 2020.

During 2021, TransGlobe repaid the remaining $15.0 million outstanding on the Mercuria prepayment. This agreement expired on December 31, 2021.

As at December 31, 2020 the Company had in place a revolving Canadian reserves-based lending facility with ATB Financial totaling C$15.0 million ($11.0 million). On June 4, 2021, the ATB facility was renewed and increased to C$22.5 million ($17.7 million), of which C$3.9 million ($3.0 million) was drawn at December 31, 2021 (December 31, 2020 - C$8.3 million/$6.6 million). Under the renewed agreement, the Company is required to enter into hedging arrangements based on its debt utilization. If utilization is below 50%, TransGlobe is required to hedge 25% of its annual forecasted average daily Canadian production of oil and natural gas volumes (net of royalties); utilization of between 50%-69% requires a hedge of 50%; utilization of 70% and above requires a hedge of 60%. There were no other changes to the key terms of the agreement from December 31, 2020. During the year ended December 31, 2021, the Company repaid C$5.0 million ($3.9 million) and drew C$0.5 million ($0.4 million) on the revolving facility.

The prepayment agreement and reserves-based lending facility are subject to certain covenants, the details of which are outlined in Note 17 to the Company's Consolidated Financial Statements. The Company was in compliance with its covenants as at December 31, 2021. Refer to the related description of TransGlobe's debt included in the December 31, 2021 Consolidated Financial Statements.

² Supplementary financial measure that is comprised of depletion, depreciation and amortization, determined in accordance with IFRS, divided by the Company’s average daily production volumes. Refer to “Non-GAAP and Other Financial Measures" contained within this MD&A.

In Egypt, gross DD&A fluctuates periodically due to changes in inventory volumes as the DD&A per barrel associated with capitalized inventory barrels is also capitalized and subsequently expensed when sold. In 2021, DD&A decreased by 25% ($5.8 million) for the year ended December 31, 2021, compared to 2020. This decrease was primarily due to a lower depletable base and a decrease in production.

In Canada, gross DD&A increased by 8% ($0.6 million) during the year ended December 31, 2021, compared to 2020. The increase was primarily attributable to an increase in depletable base as a result of higher expected future development costs, partially offset by a decrease in production.

Intangible exploration and evaluation (“E&E”) assets are tested for impairment if facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount and when they are reclassified to petroleum and natural gas assets. There were no indicators of impairment or impairment reversal on the Company’s E&E assets as at December 31, 2021.

During the first quarter of 2020, TransGlobe recorded an impairment loss of $33.5 million on its E&E assets. This was comprised of a $29.5 million impairment loss on the South Ghazalat concession and a $4.0 million impairment loss on the North West Gharib concession. The impairment loss recognized on these two concessions represented the entire E&E asset balances in the concessions. The E&E impairment losses were taken after consideration of the scale of exploration results compared to investments to date and consideration of the uncertainly of the timing of additional exploration activities in these areas given the economic environment in Q1-2020.

In 2020, the disruption to the oil and gas industry experienced during Q1-2020 and the resulting downward pressure on commodity prices led to an assessment of impairment indicators present on the Company’s PNG assets that required it to perform an assessment of the recoverability of these assets as at March 31, 2020. The Company recorded a non-cash impairment loss of $40.0 million on its PNG assets during the first quarter of 2020. This was comprised of a $24.7 million impairment loss on the West Gharib concession, a $6.6 million impairment loss on the West Bakr concession, a $4.6 million impairment loss on the North West Gharib concession and a $4.1 million impairment loss on the Canadian assets. These impairment losses were recorded to reduce the carrying value of these PNG assets to their projected recoverable amounts, which was $23.8 million in West Gharib, $55.0 million in West Bakr, $nil in North West Gharib and $60.0 million in Canada. No further impairment losses were recognized in 2020.

In Q3-2021, TransGlobe determined that there were indicators of impairment reversal present on its petroleum and natural gas (“PNG”) assets in

the West Gharib, West Bakr, North West Gharib and Canada cash-generating units (“CGU”) due to an increase and stabilization in forecasted commodity prices. Based on the results of the impairment reversal calculations completed, recoverable amounts were determined to be greater than the carrying values of the CGUs tested, resulting in $31.5 million of impairment reversal being recorded. This was comprised of a $20.5 million impairment reversal on the West Gharib concession, a $4.6 million impairment reversal on the West Bakr concession, a $3.0 million reversal on the North West Gharib concession and a $3.4 million reversal on the Canadian assets. The impairment reversal for all CGUs was limited to total accumulated impairments adjusted for depletion.

There were no indicators of impairment or impairment reversal on TransGlobe’s developed and producing (“D&P”) assets as at December 31, 2021.

In Egypt, the Company incurred $14.6 million in capital expenditures during 2021 primarily associated with drilling seven development wells in West Bakr, one development well in NW Gharib, performing six recompletions in West Bakr, and completing development/maintenance projects in the Eastern Desert. In the Western Desert, the Company drilled an oil exploration well at South Ghazalat, recompleted the SGZ-6X well to the lower Bahariya reservoir, and expanded the South Ghazalat early production facility in 2021.

In Canada, the Company incurred $12.2 million in capital expenditures during 2021 associated with drilling and completing three horizontal Cardium oil wells in the Harmattan area. TransGlobe also stimulated, equipped and tied in the Cardium oil well that was drilled, but not completed in 2020.

As at December 31, 2021 and March 17, 2022, the Company had 72,774,830 common shares issued and outstanding and 3,083,249 stock options issued and outstanding, of which 1,809,727 were exercisable in accordance with their terms into an equal number of common shares of the Company.

Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs that maintain and increase production and reserves, to acquire strategic oil and gas assets, to repay current liabilities and debt and ultimately to provide a return to shareholders. TransGlobe’s capital programs are funded by existing working capital and cash provided from operating activities. The Company's cash flow from operations varies significantly from quarter to quarter, depending on the timing of oil sales from cargoes lifted in Egypt, and these fluctuations in cash flow impact the Company's liquidity.

Funding for the Company’s capital expenditures is provided by cash flows from operations and cash on hand. The Company expects to fund its 2022 exploration and development program through the use of working capital and cash flow from operations. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources and capital expenditures.

Working capital is the amount by which current assets exceed current liabilities. As at December 31, 2021, the Company had a working capital surplus of $21.0 million (December 31, 2020 - $15.3 million). The increase in working capital is primarily due to an increase in cash resulting from collections on accounts receivable during the year, an increase in accounts receivable due to increased sales, and a decrease in the current portion of long-term debt with full repayment of the Mercuria prepayment agreement occurring in 2021. These increases were partially offset by a decrease in crude oil inventory and an increase in accounts payable driven by the 2021 capital program.

As at December 31, 2021, all of the Company's cash is on deposit with high credit-quality financial institutions.

Over the past 10 years, the Company experienced delays in the collection of accounts receivable from EGPC. The length of delay peaked in 2013, returned to historical delays of up to six months in 2017, and has since fluctuated within an acceptable range. As at December 31, 2021, amounts owing from EGPC were $6.1 million. The Company considers there to be minimal credit risk associated with amounts receivable from EGPC.

In Egypt, the Company sold 1,120.0 Mbbls of entitlement crude oil to EGPC in 2021 for net proceeds of $63.5 million. During the year, the Company collected a total of $63.1 million of accounts receivable from EGPC, an additional $6.6 million has been collected subsequent to the year end. The Company incurs a 30-day collection cycle on sales to third-party international buyers. Depending on the Company's assessment of the credit of crude oil purchasers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo lifting. As at December 31, 2021, the Company held no crude oil inventory.

As at December 31, 2021, the Company has a revolving Canadian reserves-based lending facility with ATB totaling C$22.5 million ($17.7 million), of which C$3.9 million ($3.0 million) was drawn and outstanding. During 2021, the Company repaid C$5.0 million ($3.9 million) and had drawings of C$0.5 million ($0.4 million) on this facility. During 2021, the $15.0 million outstanding under the prepayment agreement with Mercuria was repaid in full.

The Company actively monitors its liquidity to ensure that cash flows, credit facilities and working capital are adequate to support these financial liabilities, as well as the Company’s capital programs.

To date, the Company has experienced no difficulties with transferring funds abroad (see "Risks and Uncertainties").

Product inventory consists of the Company's Egypt entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the unsold entitlement crude oil as determined on a concession by concession basis. All oil produced is delivered to EGPC facilities. EGPC owns the storage and export facilities from where the Company's product inventory is sold. The Company requires EGPC’s cooperation to schedule liftings and works with EGPC on a continuous basis to schedule cargoes. Crude oil inventory levels fluctuate from quarter to quarter depending on EGPC approvals, as well as the timing and size of cargoes in Egypt. As at December 31, 2021, the Company held nil crude inventory. Since the Company began directly marketing its oil on January 1, 2015, crude oil inventory levels have fluctuated from year to year. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows.

The following table summarizes the operating expenses and depletion capitalization in unsold entitlement crude oil inventory.

As part of its principal business, the Company entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity. The principal commitments of the Company as at December 31, 2021 are as follows:

		Payment Due by Period¹
($000s)	Recognized in Financial Statements	Contractual Cash Flows	Less than 1 year	1-3 years	4-5 years	More than 5 years
Accounts payable and accrued liabilities	Yes-Liability	26,112	26,112	-	-	-
Long-term debt	Yes-Liability	3,040	-	3,040	-	-
Lease obligations²	Yes-Liability	800	764	36	-	-
Drilling commitment	No	1,000	1,000	-	-	-
Share-based compensation liabilities	Yes-Liability	10,133	6,174	3,959	-	-
Derivative commodity contracts	Yes-Liability	88	88	-	-	-
Equipment and facility leases³	No	481	481	-	-	-
Total		41,654	34,619	7,035	-	-

Pursuant to the approved South Ghazalat development lease, the Company is committed to drill one exploration well during the initial four year period of the 20 year development lease. The Company has issued a production guarantee in the amount of $1.0 million which will be released when the commitment well has been drilled.

In the normal course of its operations, the Company may be subject to litigation and claims. Although it is not possible to estimate the extent of potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the results of operations, financial position or liquidity of the Company.

On March 31, 2015, TG Holdings Yemen, Inc. ("TG Holdings"), a wholly-owned subsidiary of TransGlobe, relinquished its 13.8% interest in a concession in western Yemen known as "Block 32". In 2018, the Ministry of Oil and Minerals of the Republic of Yemen (“MOM”) raised claims against the contractor parties, including TG Holdings. The claims variously related to accounting practices, environmental and asset integrity/retirement claims, claims related to payment of customs duties and penalties, claims related to amounts allegedly owing to third parties for employment and facilities usage claims, and claims related to the handover of the concession.

A decision was rendered by the arbitral tribunal with an effective date of March 31, 2021. The final award determined that the contractor parties, including TG Holdings, are entitled to their share of Production Sharing Oil that was lifted by MOM in the amount of $5.0 million. The award also determined that the contractor parties, including TG Holdings, are jointly and severally liable for certain costs in the amount of $6.5 million.

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2021.

The Merged Concession Agreement was fully executed on January 19, 2022. Pursuant to the Merged Concession Agreement, the Company is committed to remit modernization payments of $65.0 million over six years from the February 1, 2020 effective date of the agreement; $15.0 million due prior to signing and five further instalments of $10.0 million payable annually from February 1, 2022 – February 1, 2026.

As at December 31, 2021, TransGlobe had an asset retirement obligation ("ARO") of $14.1 million (December 31, 2020 - $13.0 million) for the future abandonment and reclamation costs of the Canadian assets. The estimated ARO liability includes assumptions of actual costs to abandon and/or reclaim wells and facilities, the time frame in which such costs will be incurred, as well as inflation factors in order to calculate the undiscounted total future liability. TransGlobe calculated the present value of the obligations using discount rates between 0.95% and 1.68% (December 31, 2020- 2.00%) to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the cash flow estimate was 2% per annum (December 31, 2020 - 2%).

In Egypt, under model concession agreements and the Fuel Material Law, liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process. While the current risk to the Company of becoming liable for decommissioning liabilities in Egypt is low, future changes to legislation could result in decommissioning liabilities in Egypt. Any increase in Egyptian decommissioning liabilities could adversely affect the Company's financial condition.

In relation to petroleum wells, under good oilfield practices, the contractor is responsible for decommissioning non-producing wells under a decommissioning plan approved by EGPC during the life of the concession agreement. If EGPC agrees that a producing well is not economic, then the contractor may be responsible for decommissioning the well under an EGPC approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes. As EGPC has discretion on decommissioning wells, there is a risk that the Company could incur well decommissioning costs. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism.

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings (loss) at each reporting period. TransGlobe has not obtained collateral or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

In conjunction with the prepayment agreement, discussed further in the “Liquidity and Capital Resources” section of this MD&A, TransGlobe also entered into a marketing contract with Mercuria to market nine million barrels of TransGlobe's Egypt entitlement crude oil production. The pricing of the crude oil sales is based on market prices at the time of sale. The Company was committed to hedge 60% of its forecasted 1P entitlement production. This agreement matured on December 31, 2021.

In conjunction with the revolving Canadian reserves-based lending facility with ATB, the Company is required to enter into hedging arrangements based on its debt utilization. If utilization is below 50%, TransGlobe is required to hedge 25% of its annual forecasted average daily Canadian production of oil and natural gas volumes (net of royalties); utilization of between 50%-69% requires a hedge of 50%; and utilization of 70% and above requires a hedge of 60%.

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at December 31, 2021, the fair values of which have been presented on the Consolidated Balance Sheet:

TransGlobe’s results are affected by a variety of business risks and uncertainties in the international petroleum industry. Many of these risks are not within the control of management, however, the Company has adopted several strategies to reduce and minimize the effects of these risks:

Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on TransGlobe.

The Company actively manages its cash position and maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future cash flow from operations, working capital and availability under existing credit facilities will be adequate to support these financial liabilities and its capital programs.

The political changes that created financial instability in Egypt in 2011 could present challenges to the Company if the issues re-emerge in future years. Future instability could reduce the Company’s ability to access debt, capital and banking markets. To mitigate potential financial risk factors, the Company maintains a strong liquidity position. Management regularly evaluates operational and financial risk strategies and continues to monitor the 2022 capital budget and the Company’s long-term plans. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company anticipates that direct sales will continue to reduce financial risk in future periods.

Market risk is the risk or uncertainty arising from possible market price movements and the associated impact on the future performance of the business. The market price movements that the Company is exposed to include commodity prices, foreign currency exchange rates and interest rates, all of which could have a positive or negative impact on TransGlobe.

The Company’s operational results and financial condition are partially dependent on the commodity prices received for its production of oil, natural gas and NGLs.

Any movement in commodity prices would have an effect on the Company’s financial condition which could result in the delay or cancellation of drilling, development or construction programs, all of which could have a material adverse impact on the Company. The Company uses financial derivative contracts from time to time, as deemed necessary, to manage fluctuations in commodity prices in the normal course of operations. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.

As the Company’s business is conducted primarily in U.S. dollars and its financial instruments are primarily denominated in U.S. dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, long-term debt, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes that 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would decrease net earnings for the year ended December 31, 2021 by approximately $0.8 million and conversely, a 10% decrease in the value of the Canadian dollar against the U.S. dollar would increase net earnings by $0.8 million for the same period.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2021 was $1.3 million (2020 - $3.0 million) in equivalent U.S. dollars. The Company estimates that a 10% increase in the value of the Egyptian pound against the U.S. dollar would decrease net earnings for the year ended December 31, 2021 by approximately $0.1 million and conversely a 10% decrease in the value of the Egyptian pound against the U.S. dollar would increase net earnings by $0.1 million for the same period. The Company does not currently utilize derivative instruments to manage foreign currency exchange risk.

The Company maintains nominal balances of British Pounds sterling to pay in-country costs incurred in operating its London office. Foreign exchange risk on these funds is not considered material.

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable interest debt. No derivative contracts were entered into during 2021 to mitigate interest rate risk. When assessing interest rate risk applicable to the Company’s variable interest debt the Company believes 1% volatility is a reasonable measure. The effect of interest rates increasing by 1% would decrease the Company’s net earnings, for the year ended December 31, 2021, by $0.1 million and conversely, the effect of interest rates decreasing by 1% would increase the Company’s net earnings, for the year ended December 31, 2021, by $0.1 million.

Credit risk is the risk of loss if counterparties do not fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to cash equivalents and accounts receivable, the majority of which are in respect of oil and gas operations. The Company is currently, and may in the future, be exposed to third-party credit risk through its contractual arrangements with its current or future joint interest partners, marketers of its petroleum production and other parties, including the government of Egypt. Significant changes in the oil and gas industry, including fluctuations in commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect the Company’s ability to realize the full value of its accounts receivable. The Company has historically had significant receivables outstanding from the Government of Egypt. In the past, the timing of payments on these receivables from the Government of Egypt were longer than the industry standard. Despite these factors, the Company expects to collect these receivables in full, though there can be no assurance that this will occur. In the event the Government of Egypt fails to meet its obligations, or other third-party creditors fail to meet their obligations to the Company, such

failures could individually or in the aggregate have a material adverse effect on the Company, its cash flow from operating activities and its ability to conduct its ongoing capital expenditure program. The Company has not experienced any material credit loss in the collection of accounts receivable to date.

TransGlobe entered into a joint marketing arrangement with EGPC in December 2014. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. Buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. The Company anticipates that direct sales will continue to reduce credit risk in future periods.

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash to fund capital programs necessary to maintain and increase production and proved reserves, to acquire strategic oil and gas assets and to repay debt.

The Company actively maintains its credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future cash flows from operations, working capital and availability under existing credit facilities will be adequate to support these financial liabilities and its capital programs. All of the payments received from the lifting and sale of the Company's entitlement crude oil are deposited directly to its accounts held in London, England.

Crude oil inventory levels fluctuate from quarter to quarter depending on the timing and size of tanker liftings in Egypt. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from quarter to quarter. During 2020 crude inventory levels decreased as sales exceeded production. Throughout 2021 crude inventory levels decreased as sales exceeded production. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows.

To date, the Company has experienced no difficulties with transferring funds abroad.

The Company’s future success largely depends on its ability to exploit its current reserves base and to find, develop or acquire additional oil reserves that are economically recoverable. Failure to acquire, discover or develop these additional reserves will have an impact on cash flows of the Company. To mitigate these operational risks, as part of its capital approval process, the Company applies rigorous geological, geophysical and engineering analysis to each prospect. The Company utilizes its in-house expertise for all international and domestic ventures or employs and contracts professionals to handle each aspect of the Company’s business. The Company retains independent reserves evaluators to determine year-end Company reserves and estimated future net revenues.

The Company also mitigates operational risks by maintaining a comprehensive insurance program according to customary industry practice, but cannot fully insure against all risks.

To mitigate safety, environmental and social risks, TransGlobe conducts its operations in accordance with the Company's Health, Safety, Environmental, and Social Responsibility Policy to ensure compliance with government regulations and guidelines. Monitoring and reporting programs for environmental health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. Security risks are managed through security procedures designed to protect TransGlobe's personnel and assets. The Company has a Whistleblower Protection Policy which protects employees if they raise any concerns regarding TransGlobe's operations, accounting or internal control matters.

Regulatory and legal risks are identified and monitored by TransGlobe's corporate team and external legal professionals to ensure that the Company continues to comply with laws and regulations.

TransGlobe operates in countries with political, economic and social systems, which subject the Company to a number of risks that are not within the control of the Company. These risks may include, among others, currency restrictions and exchange rate fluctuations, loss of revenue and property and equipment as a result of expropriation, nationalization, war, insurrection and geopolitical and other political risks, increases in taxes and governmental royalties, changes in laws and policies governing operations of companies, economic and legal sanctions and other uncertainties arising from foreign and domestic governments.

Egypt experienced significant political changes over the past ten years and while this had an impact on the efficient operations of the government in general, business processes and the Company’s operations generally proceeded as normal. The current government has added stability in the Egyptian political landscape; however, the possibility of future political changes exists. Future political changes could have a material adverse impact on the Company's operations.

In February 2022, Russian military forces invaded Ukraine. In response, Ukrainian military personnel and civilians are actively resisting the invasion. Many countries throughout the world have provided aid to the Ukraine in the form of financial aid and in some cases military equipment and weapons to assist in their resistance to the Russian invasion. The North Atlantic Treaty Organization ("NATO") has also mobilized forces to NATO member countries that are close to the conflict as deterrence to further Russian aggression in the region. The outcome of the conflict is uncertain and is likely to have wide-ranging consequences on the peace and stability of the region and the world economy.

In addition, certain countries including Canada and the United States, have imposed strict financial and trade sanctions against Russia, which sanctions may have far reaching effects on the global economy. As part of the sanctions package, the German government paused the certification process for the 1,200 km Nord Stream 2 natural gas pipeline that was built to carry natural gas from Russia to Germany. Russia is a major exporter of oil and natural gas. Disruption of supplies of oil and natural gas from Russia could cause a significant worldwide supply shortage of oil and natural gas and have a significant impact on worldwide prices of oil and natural gas. A lack of supply and high prices of oil and natural gas could have a significant adverse impact on the world economy. The long-term impacts of the conflict and the sanctions imposed on Russia remain uncertain.

In March 2020, the World Health Organization declared COVID-19 a global pandemic which prompted many countries around the world to close international borders and implement various other restrictive measures. This resulted in a swift and significant reduction in economic activity and a sudden drop in demand for commodities. Since 2020, crude oil prices have largely recovered from their historic lows, but price support from future demand remains uncertain as countries experience varying degrees of virus outbreak and newly emerging virus variants following efforts to re-open local economies and international borders. Low commodity prices resulting from reduced demand associated with the impact of COVID-19 has had, and may continue to have, a negative impact on TransGlobe’s operational results and financial condition. Low prices for oil, liquids and natural gas will reduce the Company's funds from operations, and impact the Company's level of capital investment and may result in the reduction of production at certain producing properties.

While the duration and full impact of the COVID-19 pandemic is not yet known, effects of COVID-19 may also include disruptions to production operations, access to materials and services, increased employee absenteeism from illness, and temporary closures of the Company's facilities.

The extent to which the Company’s operational and financial results are affected by COVID-19 will depend on various factors and consequences beyond its control such as the duration and scope of the pandemic; additional actions taken by business and government in response to the pandemic, and the speed and effectiveness of responses to combat the virus. Additionally, COVID-19 and its effect on local and global economic conditions stemming from the pandemic could also aggravate the other risk factors identified in this MD&A, the extent of which is not yet known.

The preparation of financial statements in accordance with IFRS requires that management make appropriate decisions with respect to the selection of accounting policies and in formulating estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The following is included in the MD&A to aid the reader in assessing the critical accounting policies and practices of the Company. The information will also aid in assessing the likelihood of materially different results being reported depending on management's assumptions and changes in prevailing conditions which affect the application of these policies and practices. Significant accounting policies are disclosed in Note 3 of the Consolidated Financial Statements, and critical judgements and accounting estimates are disclosed in Note 4.

TransGlobe's proved and probable oil and gas reserves are evaluated and reported on by independent reserves evaluators to the Reserves, Health, Safety, Environment and Social Responsibility Committee comprised of a majority of independent directors. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserves estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts.

International operations conducted pursuant to PSCs are reflected in the Consolidated Financial Statements based on the Company's working interest in such operations. Under the PSCs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSC establishes specific terms for the Company to recover these costs and to share in the production sharing oil. Cost recovery oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each quarter. Production sharing oil is that portion of production remaining after cost recovery oil and is shared between the joint interest partners and the government of each country, varying with the level of production. Production sharing oil that is attributable to the government includes an amount in respect of all income taxes payable by the Company under the laws of the respective country. Revenue represents the Company's share and is recorded net of royalty payments to government and other mineral interest owners. For the Company's international operations; all government interests, except for income taxes, are considered royalty payments. The Company's revenue also includes the recovery of costs paid on behalf of foreign governments in international locations.

As of December 31, 2021, an evaluation was carried out, under the supervision and with the participation of the Company's management including the Chief Executive Officer and Chief Financial Officer, on the effectiveness of the Company's disclosure controls and procedures as defined in Rule 13a-15 under the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”) and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the fiscal year, the design and operation of these disclosure controls and procedures were effective to ensure that all information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.

Disclosure controls and procedures are defined as controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the issuer’s management, including its certifying officers, as appropriate to allow timely

TransGlobe's management designed and implemented internal controls over financial reporting, as defined under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, of the Canadian Securities Administrators and as defined in Rule 13a-15 under the Exchange Act. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS as issued by the IASB. Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company's internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission framework on Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2021. No changes were made to the Company's internal controls over financial reporting during the year ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Throughout this MD&A and in other materials disclosed by the Company, TransGlobe employs certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net earnings (loss), cash flow from operating activities, and cash flow used in investing activities, as indicators of the Company’s performance.

TransGlobe uses capital expenditures to measure its capital investments compared to the Company’s annual capital budgeted expenditures. The Company’s capital budget excludes the accounting impact of any accrual changes. The most directly comparable measure under IFRS is cash flow used in investing activities. The table below details the composition of capital expenditures and its reconciliation to cash flow used in investing activities.

	2021				2020
($000s)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1

Net cash used in investing activities	(9,082)	(5,982)	(3,075)	(1,082)	(1,254)	(2,320)	(2,823)	(4,645)
Changes in non-cash working capital	388	(5,642)	(522)	(1,825)	1,000	1,883	1,594	(932)
Capital expenditures	(8,694)	(11,624)	(3,597)	(2,907)	(254)	(437)	(1,229)	(5,577)

TransGlobe uses funds flow from operations to measure the Company’s ability to generate the necessary funds to maintain production at current levels, enable future growth through capital investment and repay debt. Management believes that such a measure provides an insightful assessment of TransGlobe’s operations on a continuing basis by eliminating certain non-cash charges. The most directly comparable measure under IFRS is cash flow generated by operating activities. The tables below details the composition of funds flow from operations and its reconciliation to cash flow generated by operating activities.

TransGlobe considers net debt to be a key measure to assess the Company's liquidity position at a point in time. The Company’s net debt is computed as long-term debt, including the current portion, net of working capital. Net debt does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies. The tables below detail the composition of net debt.

	2021				2020
($000s)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Long-term debt, including the current portion	3,040	6,882	16,951	21,699	6,567	25,946	27,071	36,591
Current assets	(54,170)	(86,624)	(63,847)	(51,360)	(53,864)	(55,139)	(68,667)	(85,828)
Current liabilities, excluding current portion of long-term debt	33,138	68,957	36,711	29,305	38,515	22,636	33,555	32,534
Net debt	(17,992)	(10,785)	(10,185)	(356)	(8,782)	(6,557)	(8,041)	(16,703)

Petroleum and natural gas sales, excluding overlift is a measure of operating results and is computed as petroleum and natural gas sales, net of overlift revenue. Management believes that petroleum and natural gas sales, excluding overlift is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of overlift revenue. Petroleum and natural gas sales, excluding overlift does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

The table below reconciles petroleum and natural gas sales, excluding overlift to the most directly comparable GAAP measure, petroleum and natural gas sales.

Netback is a measure of operating results and is computed as petroleum and natural gas sales, excluding overlift, net of royalties (all government interests, net of income taxes), production and operating expenses, current taxes and selling costs. The Company's netbacks include sales and associated costs of production from inventoried crude oil sold during the period. Royalties and taxes associated with inventoried crude oil are recognized in the financial statements at the time of production. As a result, netbacks fluctuate depending on the timing of entitlement crude oil sales. Management believes that netback is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

Refer to the “Netback” section of this MD&A which includes the most directly comparable GAAP measure, petroleum and natural gas sales.

TransGlobe calculates netback per boe as netback divided by average daily production. Netback is a non-GAAP financial measure component of netback per boe. Management believes that netback per boe is a key industry performance measure of operational efficiency and one that provides investors with information that is also commonly presented by other crude oil and natural gas producers. The Company’s netback per boe is disclosed

TransGlobe presents funds flow from operations per share by dividing funds flow from operations by the Company's diluted or basic weighted average common shares outstanding. Funds flow from operations is a non-GAAP financial measure. Management believes that funds flow per share provides investors an indicator of funds generated from the business that could be allocated to each shareholder's equity position.

"Average realized sales price" is comprised of total petroleum and natural gas sales, excluding overlift, divided by the Company's average daily production volumes.

"DD&A expense per boe" is comprised of DD&A expense, as determined in accordance with IFRS, divided by the Company's average daily production volumes.

“F&D costs” are calculated as the sum of development costs plus the change in FDC for the period when appropriate, divided by the change in reserves within the applicable reserves category, excluding those reserves acquired or disposed.

“FD&A costs” are calculated as the sum of development costs plus net acquisition costs plus the change in FDC for the period when appropriate, divided by the change in reserves within the applicable reserves category, inclusive of changes due to acquisitions and dispositions.

"G&A expense per boe" is comprised of G&A expense, as determined in accordance with IFRS, divided by the Company's average daily production volumes.

"Production and operating expenses per boe" is comprised of production and operating expenses, as determined in accordance with IFRS, divided by the Company's average daily production volumes.

"Royalties and taxes as a percentage of revenue" is comprised of royalties and current taxes, as determined in accordance with IFRS, divided by the Company's petroleum and natural gas sales.

"Royalties and taxes per boe" is comprised of royalties and current taxes, as determined in accordance with IFRS, divided by the Company's average daily production volumes.

"Selling costs per bbl" is comprised of selling costs, as determined in accordance with IFRS, divided by the Company's average daily production volumes.

“Working capital” is a supplementary financial measure that is comprised of current assets less current liabilities, as determined in accordance with IFRS.

This MD&A contains certain forward-looking statements and forward-looking information (collectively, "forward-looking statements"), which are based on our current internal expectations, estimates, projections, assumptions and beliefs. Forward-looking statements or information relate to the Company’s future events or performance. All statements other than statements of historical fact may be forward-looking statements. Such statements or information are often but not always identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, and similar expressions. These statements are not guarantees of future performance.

In particular, forward-looking statements in this MD&A include, but are not limited to: management’s assessment of future plans and operations; that TransGlobe will have the ability to develop its properties in the manner currently contemplated; the anticipated benefits to be derived from the Merged Agreement; the Company's expectations; the Company's expectations that it will pay dividends and the anticipated timing thereof; the Company's expected sources of funding for the development costs of its reserves; the anticipated timing of when the effective date adjustment will be finalized with EGPC; the Company's estimated 2022 capital spending in Egypt and Canada, including the capital spending to be allocated to each well; the Company's anticipated 2022 capital budget; the Company's anticipated 2022 production, including the allocation of such production between development and exploration wells and other spending; the Company's strategy and focus in 2022 including the drilling of wells and growing production; anticipated on-stream dates of the Company's wells; the focus of the Egypt 2022 capital program; the number of and location of wells to be drilled by the Company in 2022 and the anticipated timing thereof; the Company's expectations that it will be able to fund its 2022 exploration and development program through the use of working capital and cash flow from operations; the Company's future commitments and the anticipated timing thereof; the Company's anticipated abandonment and reclamation costs; the Company's ability to manage fluctuations in commodity prices, interest rates and foreign currency exchange rates; that the Company will ensure that it will have sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost; Management's expectations that its future cash flow from operations, working capital and availability under existing credit facilities will be adequate to support its financial liabilities and its capital programs; the collection of accounts receivable from the Egyptian Government; the timing of liftings of crude oil produced from the Company’s Egyptian operations; and other matters. Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. Many factors could cause TransGlobe's actual results to differ materially from those

expressed or implied in any forward-looking statements made by, or on behalf of, TransGlobe.

Forward-looking statements or information necessarily involve risks including, without limitation: risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation; loss of markets, economic and political instability; volatility of commodity prices; currency fluctuations; fluctuations in operating expenses due to changes in inventory volumes; inability to pay down the Company's debt; inability to continue to work with the EGPC to schedule cargoes; imprecision of reserves estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; incorrect assessment of the value of acquisitions; failure to realize the anticipated benefits of acquisitions; delays resulting from or inability to obtain required regulatory approvals; failure to collect the remaining accounts receivable balance from EGPC; the potential impacts of COVID-19 to the Company’s business; operating results; cash flows and/or financial condition; ability to access sufficient capital from internal and external sources; the Company's 2022 production in Egypt and Canada will be less than anticipated; the Company's exit production rates will be less than anticipated; the Company will not increase investments and growth in Egypt and Canada; the Company will successfully drill less than the number of wells that it anticipates; the Company will be unable to maximize free cash flow and increase the Company’s production base; the Company does not pay dividends in the future; the amount and allocation of 2022 capital spending disclosed herein will be different than anticipated; the Company's drilling plans and the anticipated timing thereof will be different than as disclosed herein; and the risks contained under "Risk Factors" in the Company's Annual Information Form which is available on www.sedar.com. The recovery and reserves estimates of the Company's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company.

Forward-looking information and statements contained in this document include the payment of dividends, including the timing and amount thereof, and the Company's intention to declare and pay dividends in the future under its current dividend policy. Future dividend payments, if any, and the level thereof is uncertain. The Company's dividend policy and any decision to pay dividends may depend on a variety of factors, including, without limitation, the funds available for the payment of dividends, free cash flow, financial requirements for the Company's operations and the execution of its strategy, ongoing production maintenance, growth through acquisitions, fluctuations in working capital and the timing and amount of capital expenditures and anticipated business development capital, payment irregularity in Egypt, debt service requirements and other factors beyond the Company's control. Further, the ability of the Company to pay dividends will be subject to applicable laws (including the satisfaction of the liquidity and solvency tests contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness.

In addition, forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on the Company's future operations. Such statements and information may prove to be incorrect and readers are cautioned that such statements and information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements or information because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; the ability of the Company's derivative financial instruments to manage its exposure thereto; currency exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; that the Company's ongoing work with the EGPC with respect to scheduling cargoes will continue be successful; the impact of potential litigation and claims on the Company; the ability of the Company to successfully market and receive payment for its oil and natural gas products; that TransGlobe's conduct and results of its operations will be consistent with its expectations; that TransGlobe will have the ability to develop its properties in the manner currently contemplated; that TransGlobe will have sufficient financial resources in the future to pay a dividend; that the Board of Directors will declare dividends in the future; and other matters.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian and U.S. securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) and on the Company's website (www.trans-globe.com).

Furthermore, the forward-looking statements or information contained herein are made as at the date hereof and the Company 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, except as may be required by applicable securities laws.

This MD&A also contains financial outlook within the meaning of applicable securities laws, including but not limited to: the Company's estimated 2022 capital spending in Egypt and Canada, including the capital spending to be allocated to each well. The financial outlook has been prepared by TransGlobe's management to provide an outlook of the Company's activities and results. The financial outlook has been prepared based on a number of assumptions including those set forth below in this MD&A, the assumptions discussed above and assumptions with respect to the costs and expenditures to be incurred by the Company, capital equipment and operating costs, foreign exchange rates, taxation rates for the Company, general and administrative expenses and the prices to be paid for the Company's production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results will likely vary from the amounts set forth in the analysis presented in this MD&A, and such variation may be material. The Company and its management believe that the financial outlook has been prepared on a reasonable basis as of January 27, 2022, reflecting the best estimates and judgments, and represent, to the best of management's knowledge and opinion, TransGlobe's expected expenditures and results of operations. However, because this information is highly subjective and subject to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, TransGlobe undertakes no obligation to update such financial outlook and forward-looking statements and information,

whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

The reader is further cautioned that the preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings (loss) as further information becomes available, and as the economic environment changes.

Mr. Ron Hornseth, B.Sc., General Manager - Canada for TransGlobe Energy Corporation, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, June 2009, of the London Stock Exchange, has reviewed the technical information contained in this report. Mr. Hornseth is a professional engineer who obtained a Bachelor of Science in Mechanical Engineering from the University of Alberta. He is a member of the Association of Professional Engineers and Geoscientists of Alberta (“APEGA”) and the Society of Petroleum Engineers (“SPE”) and has over 20 years’ experience in oil and gas.

Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

This MD&A contains a number of oil and gas metrics, including operating netback, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate TransGlobe's operating results; however, such measures are not reliable indicators of the future performance of TransGlobe and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. Management of TransGlobe uses these oil and gas metrics for its own performance measurements and to provide securityholders with measures to compare TransGlobe's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.

Average reference prices and exchange rates	2021	2020
Crude oil
Dated Brent average oil price ($/bbl)	70.68	41.76
Edmonton Sweet index ($/bbl)	63.66	34.04
Natural gas
AECO ($/MMBtu)	2.91	1.68
US/Canadian Dollar average exchange rate	1.25	1.34

	2021		2020
($000s, except per boe amounts)	$	$/boe	$	$/boe
Petroleum and natural gas sales, excluding overlift¹	289,233	58.79	188,771	33.41
Royalties²	134,950	27.43	74,096	13.11
Current taxes²	22,411	4.56	13,530	2.39
Production and operating expenses	61,430	12.49	64,462	11.41
Selling costs	3,921	0.80	2,111	0.37
Netback³	66,521¹	13.51⁴	34,572¹	6.13⁴

	2021		2020
($000s, except per boe amounts)	$	$/boe	$	$/boe
Oil sales, excluding overlift¹	257,338	62.94	173,086	35.94
Royalties²	129,891	31.77	71,741	14.89
Current taxes²	22,411	5.48	13,530	2.81
Production and operating expenses	54,379	13.30	58,305	12.11
Selling costs	3,921	0.96	2,111	0.44
Netback³	46,736¹	11.43⁴	27,399¹	5.69⁴

	2021		2020
($000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	18,225	65.87	8,679	33.36
Natural gas sales	4,984	17.55	2,815	9.85
NGL sales	8,686	32.16	4,191	14.59
Total sales	31,895	38.40	15,685	18.82
Royalties	5,059	6.09	2,355	2.83
Production and operating expenses	7,051	8.49	6,157	7.39
Netback	19,785¹	23.82²	7,173¹	8.60²

	2021		2020
($000s, except per boe amounts)	$	$/boe¹	$	$/boe¹
Gross G&A	11,760	2.39	11,893	2.10
Stock-based compensation	9,267	1.88	857	0.15
Capitalized G&A and overhead recoveries	(674)	(0.14)	(760)	(0.13)
Net G&A	20,353	4.13	11,990	2.12

	2021	2020
Egypt crude oil (bbls/d)	10,578	11,147
Canada crude oil (bbls/d)	758	711
Canada NGLs (bbls/d)	740	785
Canada natural gas (Mcf/d)	4,667	4,686
Total Company (boe/d)	12,854	13,425

	2021	2020
Egypt crude oil (bbls/d)¹	11,202	13,160
Canada crude oil (bbls/d)	758	711
Canada NGLs (bbls/d)	740	785
Canada natural gas (Mcf/d)	4,667	4,686
Total Company (boe/d)	13,478	15,437

	Years Ended December 31
($000s)	2021	2020
Interest on long-term debt	536	1,597
Interest on borrowing base facility	320	317
Amortization of deferred financing costs	103	395
Interest on lease obligations	182	211
Finance costs	1,141	2,520
Interest paid	856	1,918

	Years Ended	Year Ended
(Mbbls)	December 31, 2021	December 31, 2020
Product inventory, beginning of year	227.9	964.5
TransGlobe entitlement production	1,663.3	1,769.9
Crude oil sales	(1,891.2)	(2,506.5)
Product inventory, end of year	-	227.9

Financial AECO natural gas contracts
Period Hedged	Contract	Remaining Volume (GJ)	Daily Volume (GJ)	Bought Put C$/GJ	Sold Call C$/GJ
Jan 2022 - Mar 2022	Collar	351,000	3,900	2.50	4.20
Apr 2022 - Jun 2022	Collar	354,900	3,900	2.50	3.35
Jul 2022 - Sep 2022	Collar	358,800	3,900	2.50	3.10
Oct 2022 - Dec 2022	Collar	358,800	3,900	2.50	4.00