AIM & TSX: “TGL” & NASDAQ: “TGA”

This Announcement contains inside information as defined in Article 7 of the Market Abuse Regulation No. 596/2014 (“MAR”). Upon the publication of this Announcement, this inside information is now considered to be in the public domain.

CALGARY, Alberta, March 12, 2021 (GLOBE NEWSWIRE) — TransGlobe Energy Corporation (“TransGlobe” or the “Company”) is pleased to announce its financial and operating results for the three months and year ended December 31, 2020. All dollar values are expressed in United States dollars unless otherwise stated. TransGlobe’s Condensed Consolidated Interim Financial Statements together with the notes related thereto, as well as TransGlobe’s Management’s Discussion and Analysis for the years ended December 31, 2020 and 2019, are available on TransGlobe’s website at

www.trans-globe.com

.

2020 HIGHLIGHTS:

• 2020 production averaged 13,425 boe/d (Egypt 11,147 bbls/d, Canada 2,278 boe/d), a decrease of 16% from 2019 primarily due to deferred well interventions in Egypt during low oil prices, the curtailed 2020 capital program and natural declines;
• Sales averaged 15,437 boe/d in 2020 with an average realized price of $33.41/boe; 2020 average realized price on Egyptian sales of $35.94/bbl and Canadian sales of $18.82/boe;
• Inventoried entitlement crude oil in Egypt decreased to 227.9 Mbbls as at December 31, 2020 from 964.5 Mbbls as at December 31, 2019;
• Ended the year with 38.9 MMboe of 2P reserves, down 14% from 2019 year end of 45.3 MMboe;
• Funds flow from operations of $30.4 million ($0.42 per share) in 2020;
• 2020 net loss of $77.4 million ($1.07 per share), is inclusive of a $73.5 million non-cash impairment loss and a $0.2 million unrealized loss on derivative commodity contracts;
• The Company ended the year with positive working capital of $15.3 million, including cash and cash equivalents of $34.5 million;
• Drilled and completed one development oil well and performed four recompletions in Egypt during 2020;
• Drilled one horizontal Cardium oil well in Canada during 2020;
• Business continuity plans remain effective across our locations in response to COVID-19 with minimal health and safety impacts or disruption to production; and
• The Company announced a merged concession agreement with a 15-year primary term and improved Company economics on December 3, 2020. The agreement is currently awaiting ratification by the Egyptian Parliament but will have a Feb, 2020 effective date upon ratification.
  

2021 (TO DATE) HIGHLIGHTS:

• January 2021 average production of 12,480 boe/d, February 2021 average production of 12,007 boe/d;
• Completed monthly sales to EGPC of 167.0 Mbbl for proceeds of $8.6 million;
• Stimulated and equipped the 2-mile horizontal South Harmattan well drilled, but uncompleted, in Q1-2020;
• Began work to expand the production handling capacity at South Ghazalat; and
• Work has begun on the SGZ-6X recompletion to the deeper, more prospective lower Bahariya reservoir.
  

FINANCIAL AND OPERATING RESULTS

Additional financial information is provided in the Company’s audited Consolidated Financial Statements together with the notes related thereto, as well as TransGlobe’s Management’s Discussion and Analysis for the years ended December 31, 2020 and 2019. These documents, along with other documents affecting the rights of securityholders and other information relating to the Company, may be found on SEDAR at www.sedar.com and in the Company’s Annual Report on Form 40-F for the fiscal year ended December 31, 2020, filed on EDGAR at

www.sec.gov

.

(US$000s, except per share, price, volume amounts and % change)

	Three Months Ended December 31						Years Ended December 31
Financial	2020		2019		% Change		2020		2019		% Change
Petroleum and natural gas sales	50,989		64,201		(21	)	188,771		278,929		(32	)
Petroleum and natural gas sales, net of royalties	33,309		28,473		17		114,675		140,096		(18	)
Realized derivative loss gain on commodity contracts	(6	)	(218	)	97		6,801		(1,259	)	640
Unrealized derivative loss on commodity contracts	(941	)	(1,201	)	(22	)	(180	)	(1,586	)	89
Production and operating expense	19,326		15,119		28		64,462		50,626		27
Selling costs	1,008		638		58		2,111		1,287		64
General and administrative expense	3,593		3,868		(7	)	11,990		16,611		(28	)
Depletion, depreciation and amortization expense	7,647		8,764		(13	)	31,049		34,948		(11	)
Income tax expense	3,408		6,003		(43	)	13,530		26,098		(48	)
Cash flow generated by operating activities	14,180		23,740		(40	)	31,709		44,836		(29	)
Funds flow from operations 1	7,202		3,171		127		30,443		46,871		(35	)
Basic per share	0.10		0.04				0.42		0.65
Diluted per share	0.10		0.04				0.42		0.65
Net loss	(2,855	)	(8,202	)	(65	)	(77,397	)	(3,995	)	1,837
Basic per share	(0.04	)	(0.11	)			(1.07	)	(0.06	)
Diluted per share	(0.04	)	(0.11	)			(1.07	)	(0.06	)
Capital expenditures	255		10,996		(98	)	7,498		36,932		(80	)
Dividends declared	–		–		–		–		5,078		(100	)
Dividends declared per share	–		–				–		0.07
Working capital	15,349		32,194		(52	)	15,349		32,194		(52	)
Long-term debt, including current portion	21,464		37,041		(42	)	21,464		37,041		(42	)
Common shares outstanding
Basic (weighted average)	72,542		72,542		–		72,542		72,514		–
Diluted (weighted average)	72,542		72,542		–		72,542		72,514		–
Total assets	201,147		308,325		(35	)	201,147		308,325		(35	)
Operating
Average production volumes (boe/d)	12,384		15,362		(19	)	13,425		16,041		(16	)
Average sales volumes (boe/d)	15,712		14,688		7		15,437		14,954		3
Inventory (Mbbls)	227.9		964.5		(76	)	227.9		964.5		(76	)
Average realized sales price ($/boe)	35.27		47.51		(26	)	33.41		51.10		(35	)
Production and operating expenses ($/boe)	13.37		11.19		19		11.41		9.28		23

1	Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies.

SELECTED ANNUAL INFORMATION

($000s, except per share amounts, price and volumes)	2020		% Change		2019		% Change		2018
Operations
Average production volumes
Crude oil (bbls/d)	11,858		(18	)	14,527		14		12,708
NGLs (bbls/d)	785		35		582		(25	)	780
Natural gas (Mcf/d)	4,686		(16	)	5,594		(2	)	5,707
Total (boe/d)	13,425		(16	)	16,041		11		14,439
Average sales volumes
Crude oil (bbls/d)	13,871		3		13,441		1		13,282
NGLs (bbls/d)	785		35		582		(25	)	780
Natural gas (Mcf/d)	4,686		(16	)	5,594		(2	)	5,707
Total (boe/d)	15,437		3		14,954		–		15,013
Average realized sales prices
Crude oil ($/bbl)	35.80		(35	)	55.31		(7	)	59.57
NGLs ($/bbl)	14.59		(36	)	22.93		(16	)	27.17
Natural gas ($/mcf)	1.64		24		1.32		5		1.26
Total oil equivalent ($/boe)	33.41		(35	)	51.10		(6	)	54.59
Inventory (Mbbls)	227.9		(76	)	964.5		70		568.1
Petroleum and natural gas sales	188,771		(32	)	278,929		(7	)	299,144
Petroleum and natural gas sales, net of royalties	114,675		(18	)	140,096		(21	)	176,227
Cash flow generated by operating activities	31,709		(29	)	44,836		(35	)	69,192
Funds flow from operations 1	30,443		(35	)	46,871		(26	)	63,282
Funds flow from operations per share:
Basic	0.42				0.65				0.87
Diluted	0.42				0.65				0.86
Net (loss) earnings	(77,397	)	1,837		(3,995	)	(125	)	15,677
Net (loss) earnings per share:
Basic	(1.07	)			(0.06	)			0.22
Diluted	(1.07	)			(0.06	)			0.22
Capital expenditures	7,498		(80	)	36,932		(9	)	40,706
Dividends declared	–		–		5,078		101		2,527
Dividends declared per share	–		–		0.070		100		0.035
Total assets	201,147		(35	)	308,325		(3	)	318,296
Cash and cash equivalents	34,510		4		33,251		(36	)	51,705
Working capital	15,349		(52	)	32,194		(37	)	50,987
Total long-term debt, including current portion	21,464		(42	)	37,041		(29	)	52,355
Net debt-to-funds flow from operations ratio 2	0.20				0.10				0.02
Reserves
Total proved (MMboe) 3	22.8		(10	)	25.4		(6	)	26.9
Total proved plus probable (MMboe) 3	38.9		(14	)	45.3		3		44.1

1	Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies.
2	Net debt-to-funds flow from operations ratio is a measure that represents total long-term debt (including the current portion) net of working capital, over funds flow from operations for the trailing 12 months and may not be comparable to measures used by other companies.
3	As determined by the Company’s 2020, 2019 & 2018 independent reserves evaluator, GLJ Ltd. (“GLJ”), in their reports dated February 9, 2021, February 4, 2020 and January 22, 2019 with effective dates of December 31, 2020, December 31, 2019 and December 31, 2018. The reports of GLJ have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time and National Instrument 51-101.

In 2020 compared with 2019, TransGlobe:

• Reported a 16% decrease in production volumes compared to 2019. In Egypt, the decrease was primarily attributable to the curtailed 2020 capital program, deferred well interventions and natural declines.
• Ended 2020 with the inventoried crude oil of 227.9 Mbbls, a decrease of 736.6 Mbbls over inventoried crude oil levels at December 31, 2020, primarily due to annual sales volumes exceeding production volumes.
• Reported positive funds flow from operations of $30.4 million (2019 – $46.9 million). The decrease in funds flow from operations from 2019 is primarily due lower production and lower commodity prices;
• Petroleum and natural gas sales decreased by 32%, primarily due to a 35% decrease in average realized sales prices;
• Reported a net loss of $77.4 million (2019 – net loss of $4.0 million) inclusive of a $0.2 million unrealized derivative loss on commodity contracts and a combined $73.5 million non-cash impairment loss on the Company’s petroleum and natural gas (“PNG”) and exploration and evaluation (“E&E”) assets;
• Ended the year with positive working capital of $15.3 million, including $34.5 million in cash and cash equivalents as at December 31, 2020;
• Spent $7.5 million on capital expenditures, funded entirely from cash flow from operations and cash on hand;
• Repaid $16.5 million of long-term debt with cash on hand.

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties

Production Volumes

	2020	2019
Egypt crude oil (bbls/d)	11,147	13,713
Canada crude oil (bbls/d)	711	814
Canada NGLs (bbls/d)	785	582
Canada natural gas (Mcf/d)	4,686	5,594
Total Company (boe/d)	13,425	16,041

Sales Volumes (excludes volumes held as inventory)

	2020	2019
Egypt crude oil (bbls/d)	13,160	12,627
Canada crude oil (bbls/d)	711	814
Canada NGLs (bbls/d)	785	582
Canada natural gas (Mcf/d)	4,686	5,594
Total Company (boe/d)	15,437	14,954

Netback

Consolidated netback

	2020		2019
($000s, except per boe amounts)	$	$/boe	$	$/boe
Petroleum and natural gas sales	188,771	33.41	278,929	51.10
Royalties 2	74,096	13.11	138,833	25.44
Current taxes 2	13,530	2.39	26,098	4.78
Production and operating expenses	64,462	11.41	50,626	9.28
Selling costs	2,111	0.37	1,287	0.24
Netback 1	34,572	6.13	62,085	11.36

1	The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2020 and December 31, 2019 (these figures do not include TransGlobe’s Egypt entitlement crude oil held as inventory at December 31, 2020).
2	Royalties and taxes are settled at the time of production. Fluctuations in royalty and tax costs per bbl are due to timing differences between the production and sale of the Company’s entitlement crude oil.

Egypt

	2020		2019
($000s, except per boe amounts)	$	$/boe	$	$/boe
Oil sales	173,086	35.94	256,193	55.59
Royalties 2	71,741	14.89	136,616	29.64
Current taxes 2	13,530	2.81	26,098	5.66
Production and operating expenses	58,305	12.11	43,252	9.38
Selling costs	2,111	0.44	1,287	0.28
Netback 1	27,399	5.69	48,940	10.63

1	The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2020 and December 31, 2019 (these figures do not include TransGlobe’s Egypt entitlement crude oil held as inventory at December 31, 2020).
2	Royalties and taxes are settled at the time of production. Fluctuations in royalty and tax costs per bbl are due to timing differences between the production and sale of the Company’s entitlement crude oil.

Netback per barrel in Egypt decreased by 46% in 2020 compared to 2019. The decrease was due to a 35% lower realized oil price, 57% higher selling costs and 29% higher production and operating expenses.

Royalties and taxes as a percentage of revenue were 49% in 2020 (2019 – 64%). 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 58% (2019 – 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 set out in 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 relative decrease, from 64% in 2019 to 49% in 2020, was due to sales outpacing production in 2020, partially offset by Q1-2020 excess cost oil in the West Bakr concession. Excess cost oil occurs when the current costs and historic cost amortization, permissible within the PSC, 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 royalty burden.

In Egypt, the average selling price for the year ended December 31, 2020 was $35.94/bbl (2019 – $55.59/bbl), which was $5.82/bbl lower (2019 – $8.77/bbl lower) than the average Dated Brent oil price of $41.76/bbl for 2020 (2019 – $64.36/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, 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 increased by 35% ($15.1 million) in 2020 compared with 2019. The increase was primarily related to a decrease in crude oil inventory through sales to both EGPC and Mercuria, where operating costs previously capitalized to inventory were expensed in the period of sale ($14.0 million). The increase was also caused by higher manpower costs as well as operating expenses related to the South Ghazalat concession which began operating in 2020, partially offset by a decrease in workovers and production handling fees. The increase in production and operating expenses per barrel from $9.38/bbl in 2019 to $12.11/bbl in 2020 was due to a 19% decrease in production primarily attributed to the curtailed 2020 capital program, deferred well interventions and natural declines.

Canada

	2020		2019
($000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	8,679	33.36	15,159	51.02
Natural gas sales	2,815	9.85	2,705	7.95
NGL sales	4,191	14.59	4,872	22.93
Total sales	15,685	18.82	22,736	26.75
Royalties	2,355	2.83	2,217	2.61
Production and operating expenses	6,157	7.39	7,374	8.68
Netback	7,173	8.60	13,145	15.46

Netbacks per boe in Canada decreased by 44% in 2020 compared with 2019. The decrease is mainly due to a 30% lower realized sales price and an 8% increase in royalties, partially offset by a 15% decrease in production and operating expenses.

In 2020, the Company’s Canadian operations incurred $0.1 million higher royalty costs than in 2019. The increase in royalties was primarily due to an increase in mineral taxes. Mineral taxes are an annual tax on PNG productive mineral rights on freehold properties payable to the Crown. A further increase in royalties was caused by a decrease in Gas Cost Allowance (“GCA”) rebates received in 2020 compared to 2019. Royalties amounted to 15% of petroleum and natural gas sales revenue during 2020 compared to 10% during the prior year. 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 decreased by 15% compared with 2019. The decrease was primarily due to a decrease in transportation costs.

Consolidated Statements of Loss and Comprehensive Loss

(Expressed in thousands of U.S. Dollars, except per share amounts)

		Years Ended December 31
		2020		2019
REVENUE
	Petroleum and natural gas sales, net of royalties	114,675		140,096
	Finance revenue	106		471
	Other revenue	641		–
		115,422		140,567
EXPENSES
	Production and operating	64,462		50,626
	Selling costs	2,111		1,287
	General and administrative	11,990		16,611
	Foreign exchange loss (gain)	24		(147	)
	Finance costs	2,520		4,256
	Depletion, depreciation and amortization	31,049		34,948
	Asset retirement obligation accretion	259		215
	(Gain) loss on financial instruments	(6,621	)	2,845
	Impairment loss	73,495		7,937
	Gain on disposition of assets	–		(114	)
		179,289		118,464
(Loss) earnings before income taxes		(63,867	)	22,103
Income tax expense – current		13,530		26,098
NET LOSS		(77,397	)	(3,995	)
OTHER COMPREHENSIVE INCOME
	Currency translation adjustments	766		2,073
COMPREHENSIVE LOSS		(76,631	)	(1,922	)
Net loss per share
	Basic	(1.07	)	(0.06	)
	Diluted	(1.07	)	(0.06	)

Consolidated Balance Sheets

(Expressed in thousands of U.S. Dollars)

			As at		As at
			December 31, 2020		December 31, 2019
	ASSETS
	Current
		Cash and cash equivalents	34,510		33,251
		Accounts receivable	9,996		10,681
		Prepaids and other	3,530		4,338
		Product inventory	5,828		17,516
			53,864		65,786
	Non-Current
		Intangible exploration and evaluation assets	584		33,706
		Property and equipment
		Petroleum and natural gas assets	140,059		196,150
		Other	2,917		4,296
		Deferred taxes	3,723		8,387
			201,147		308,325
	LIABILITIES
	Current
		Accounts payable and accrued liabilities	21,667		32,156
		Derivative commodity contracts	398		217
		Current portion of lease obligations	1,553		1,219
		Current portion of long-term debt	14,897		–
			38,515		33,592
	Non-Current
		Long-term debt	6,567		37,041
		Asset retirement obligations	13,042		13,612
		Other long-term liabilities	544		614
		Lease obligations	461		589
		Deferred taxes	3,723		8,387
			62,852		93,835
	SHAREHOLDERS’ EQUITY
		Share capital	152,805		152,805
		Accumulated other comprehensive income	1,900		1,134
		Contributed surplus	25,109		24,673
		(Deficit) Retained earnings	(41,519	)	35,878
			138,295		214,490
			201,147		308,325

Consolidated Statements of Changes in Shareholders’ Equity

(Expressed in thousands of U.S. Dollars)

			Years Ended December 31
			2020		2019
	Share Capital
		Balance, beginning of year	152,805		152,084
		Stock options exercised	–		547
		Transfer from contributed surplus on exercise of options	–		174
		Balance, end of year	152,805		152,805
	Accumulated Other Comprehensive Income
		Balance, beginning of year	1,134		(939	)
		Currency translation adjustment	766		2,073
		Balance, end of year	1,900		1,134
	Contributed Surplus
		Balance, beginning of year	24,673		24,195
		Share-based compensation expense	436		652
		Transfer to share capital on exercise of options	–		(174	)
		Balance, end of year	25,109		24,673
	(Deficit) Retained Earnings
		Balance, beginning of year	35,878		44,951
		Net loss	(77,397	)	(3,995	)
		Dividends	–		(5,078	)
		Balance, end of year	(41,519	)	35,878

Consolidated Statements of Cash Flows

(Expressed in thousands of U.S. Dollars)

				Years Ended December 31
				2020		2019
	OPERATING
		Net loss		(77,397	)	(3,995	)
		Adjustments for:
			Depletion, depreciation and amortization	31,049		34,948
			Asset retirement obligation accretion	259		215
			Impairment loss	73,495		7,937
			Share-based compensation	857		2,237
			Finance costs	2,520		4,256
			Unrealized loss on financial instruments	180		1,586
			Unrealized (gain) on foreign currency translation	(62	)	(153	)
			Gain on asset disposition	–		(114
		Asset retirement obligations settled		(458	)	(46	)
		Changes in non-cash working capital		1,266		(2,035	)
	Net cash generated by operating activities			31,709		44,836
	INVESTING
		Additions to intangible exploration and evaluation assets		(337	)	(5,377	)
		Additions to petroleum and natural gas assets		(6,726	)	(30,626	)
		Additions to other assets		(435	)	(929	)
		Proceeds from asset dispositions		–		114
		Changes in non-cash working capital		(3,544	)	(291	)
	Net cash used in investing activities			(11,042	)	(37,109	)
	FINANCING
		Issue of common shares for cash		–		547
		Interest paid		(1,918	)	(3,664	)
		Increase in long-term debt		406		476
		Payments on lease obligations		(1,703	)	(1,945	)
		Repayments of long-term debt		(16,504	)	(16,523	)
		Dividends paid		–		(5,078	)
		Changes in non-cash working capital		161		(200	)
	Net cash used in financing activities			(19,558	)	(26,387	)
	Currency translation differences relating to cash and cash equivalents			150		206
	NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			1,259		(18,454	)
	CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			33,251		51,705
	CASH AND CASH EQUIVALENTS, END OF YEAR			34,510		33,251

LIQUIDITY AND CAPITAL RESOURCES

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. TransGlobe’s management will continue to steward capital and focus on cost reductions in order to maintain balance sheet strength through the current volatile oil price environment.

Funding for the Company’s capital expenditures is provided by cash flows from operations and cash on hand. The Company expects to fund its 2021 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, 2020, the Company had a working capital surplus of $15.3 million (December 31, 2019 – $32.2 million). The decrease in working capital is primarily due to the $15.0 million outstanding balance of the Mercuria prepayment agreement being reclassified as current during the year, a decrease in cash resulting from repayments on long-term debt, payments on accounts payable during the year, a decrease in crude oil inventory due to increased sales to EGPC in 2020, partially offset by a decrease in accounts payable.

As at December 31, 2020, the Company’s cash equivalents balance consisted of short-term deposits with an original term to maturity at purchase of one month or less. All of the Company’s cash and cash equivalents are 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, 2020, amounts owing from EGPC were $6.0 million. The Company considers there to be minimal credit risk associated with amounts receivable from EGPC.

In Egypt, the Company completed a second crude oil sale in Q4-2020 for total proceeds of $16.2 million, which were collected in December 2020. 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, 2020, the Company held 227.9 Mbbls of entitlement oil as inventory.

As at December 31, 2020, the Company had $86.0 million of revolving credit facilities with $21.5 million drawn and $64.5 million available. The Company has a prepayment agreement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $15.0 million was drawn and outstanding as at December 31, 2020. During 2020, the Company repaid $15.0 million of this prepayment agreement. The Company also has a revolving Canadian reserves-based lending facility with ATB that was renewed and reduced as at June 30, 2020 from C$25.0 million ($19.2 million) to C$15.0 million ($11.0 million). The reduction in the ATB facility is a result of lower forecasted commodity prices and the associated impact on asset value. During 2020, the Company repaid C$2.0 million ($1.5 million) and had drawings of $C0.5 million ($0.4 million) on this facility, leaving C$8.3 million ($6.6 million) drawn and outstanding.

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.

MANAGEMENT STRATEGY AND OUTLOOK

The 2021 outlook provides information as to management’s expectation for results of operations for 2021. Readers are cautioned that the 2021 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 “Advisory on Forward-Looking Information and Statements” within this announcement.

2021 Outlook

The 2021 production outlook for the Company is provided as a range to reflect timing and performance contingencies.

Global reaction to the spread of COVID-19 and the related economic fallout has created significant volatility, uncertainty, and turmoil in the oil and gas industry. Oil demand significantly deteriorated as a result of the pandemic and corresponding preventative measures taken globally to mitigate the spread of the virus. While market conditions have recently improved, The Company may record lower per boe results in 2021 due to these events which may continue to negatively affect TransGlobe’s business.

TransGlobe maintains a strong balance sheet with modest debt and is the operator across all of its producing assets, which gives the Company significant capital flexibility and a high degree of discretion in its forward investment program. The Company intends to use all available tools to minimize balance sheet risk and position itself for future success.

With $15.0 million owed to Mercuria Energy Trading SA (“Mercuria”) and $6.6 million owed to ATB Financial (“ATB”), TransGlobe is in compliance with its debt covenants. During 2020, the Company repaid $15.0 million on the prepayment facility with Mercuria and $1.5 million to ATB. The Company exited 2020 with $34.5 million cash on hand. TransGlobe is actively engaged with Mercuria on an amendment and extension to the facility currently maturing in September, 2021.

As announced in early December, 2020, the Company reached an agreement with the Egyptian General Petroleum Company (“EGPC”) to merge its three existing Eastern Desert concessions with a 15-year primary term and improved Company economics. Ratification of the concession is anticipated in Q2-2021, and the February 1, 2020 effective date for the improved concession terms supports increased investment in advance of ratification. Subject to ratification, the Company will pay EGPC a signature bonus and an equalization payment in installments. An initial equalization payment of $15.0 million and signature bonus of $1.0 million are due on ratification, with five further annual equalization payments of $10.0 million each being made over five years (beginning February 1, 2022 until February 1, 2026). The Company will also have 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.

With the approval of the agreement to merge the Eastern Desert concessions and recent commodity price improvements, the Company has moved forward to re-start investment in Egypt and also in Canada to support growth plans in both countries. The Company’s recently announced 2021 capital program of $27.2 million (before capitalized G&A) includes $16.6 million for Egypt and $10.6 million for Canada. The 2021 plan was prepared to focus on value accretive projects within its portfolio, maximize free cash flow to direct at future value growth opportunities and to increase the Company’s production base.

Total corporate production is expected to range between 12.0 and 13.0 Mboe/d (mid-point of 12.5 Mboe/d) for 2021 with a 93% weighting to oil and liquids. Egypt oil production is expected to range between 9.7 and 10.5 Mbbls/d (mid-point of 10.1 Mbbls/d) in 2021. Canadian production is expected to range between 2.3 and 2.5 Mboe/d (mid-point of 2.4 Mboe/d) in 2021. The 2021 mid-point production guidance broken out by product type is summarized below:

Mid-point production guidance	Egypt	Canada	Total
Light and medium crude oil (bbls/d)	791	800	1,591
Heavy crude oil (bbls/d)	9,309	–	9,309
Conventional natural gas (Mcf/d)	–	4,800	4,800
Associated natural gas liquids (bbls/d)	–	800	800
Total (boe/d)	10,100	2,400	12,500

The Company has and will continue to monitor its economic thresholds for shutting-in production in Canada. In Egypt, the Company continues to carry out economic reviews to determine whether offline production should be brought back on or if well interventions should be carried out. If oil prices return to the lows in Q2 of 2020, the Company may choose to shut-in uneconomic production and 2021 production guidance could be negatively impacted.

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 2021. 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 below chart provides a comparison of well netbacks in the Company’s Egyptian and Canadian assets under multiple price sensitivities. The Egyptian netbacks reflect the existing PSC terms in the Eastern Desert and do not reflect the potential netbacks once ratification occurs to merge the Eastern Desert PSCs. A typical Cardium well produces both oil and natural gas/NGLs. The price of each commodity varies significantly, therefore the below chart presents the netback of each revenue stream separately.

Netback sensitivity
Benchmark crude oil price ($/bbl) 1	30.00		40.00		50.00	60.00	70.00
Benchmark natural gas price ($/Mcf) 2	1.97		2.05		2.13	2.20	2.28
Netback ($/boe)
Egypt – crude oil 3	(4.80	)	(0.70	)	3.40	7.20	9.50
Canada – crude oil 4	13.80		22.40		30.20	37.60	45.10
Canada – natural gas and NGLs 4	2.40		4.50		6.40	8.20	10.00

1	Benchmark Egypt crude oil price is Dated Brent; benchmark Canada crude oil price is WTI.
2	Benchmark natural gas price is AECO.
3	Egypt assumptions: using anticipated 2021 Egypt production profile, Gharib Blend price differential estimate of $5.00/bbl applied consistently at all price points, concession differentials of 4%, 5% and 5% applied to WG/WB/NWG, respectively, operating costs estimated at ~$15.20/bbl, pre-concession merger ratification terms, and maximum cost recovery resulting from accumulated cost pools.
4	Canada assumptions: using anticipated 2020 Canada production profile, Edmonton Light price differential estimate of C$5.00/bbl, Edmonton Light to Harmattan discount of C$2.50/bbl, operating costs estimated at ~C$7.00/boe, NGL mixture price at 45% of Edmonton Light, and takes into consideration Canadian tax pools.

2021 Capital Budget

The Company’s 2021 capital program of $27.2 million (before capitalized G&A) includes $16.6 million for Egypt and $10.6 million for Canada. The 2021 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. The 2021 drilling program includes 12 Egypt wells and 3 Canadian Cardium wells in South Harmattan.

Egypt

As announced in early December, 2020, the Company reached an agreement with the Egyptian General Petroleum Company (“EGPC”) to merge its three existing concessions with a 15-year primary term and improved Company economics. Ratification of the concession is anticipated in Q2, 2021 and the February 1, 2020 effective date for the improved concession terms supports increased investment in parallel with ratification.

The $16.6 million Egypt program is entirely allocated to development activities. The primary focus of the 2021 Egypt plan is to accelerate the exploitation of the Company’s Eastern Desert acreage with the aim of increasing oil production, while evaluating and increasing production from the more prospective lower Bahariya reservoir on the South Ghazalat development lease in the Western Desert.

The 2021 development program is principally focused on the Eastern Desert and includes: nine development wells in West Bakr (three in H and six in K pools), one Red Bed appraisal well in the NW Gharib 3X pool, two development wells targeting Arta Nukhul reservoir in West Gharib, two recompletions in West Bark, two recompletions in West Gharib, three conversions to water injectors in West Gharib, and development & maintenance projects in the Eastern Desert (West Bakr, NW Gharib and West Gharib). A recompletion of the SGZ-6X well to the more prospective lower Bahariya reservoir is also planned.

Egypt production is expected to average between 9.7 and 10.5 Mboe/d for the year and achieve an exit rate in the range of 10.4 to 10.7 Mboe/d.

Canada

The $10.6 million Canada program consists of drilling three (three net) horizontal wells and completing one (one net) standing well, all targeting the Cardium light oil resource at Harmattan, with additional maintenance/ development capital. The Cardium drilling program in 2021 consists of one 2-mile and two 1-mile development wells in South Harmattan. The one 2-mile horizontal well drilled, but not completed, in South Harmattan in 2020 will also be stimulated, equipped, and brought into production.

Canada production is expected to average between 2.3 and 2.5 Mboe/d for the year and achieve an exit rate in the range of 3.1 to 3.3 Mboe/d.

The approved 2021 capital program is summarized in the following table:

	TransGlobe 2021 Capital ($MM)				Gross Well Count
	Development		Exploration		Drilling
Concession	Wells	Other 1	Wells	Total 2	Development	Exploration	Total
West Gharib	1.1	2.0	–	3.1	2	–	2
West Bakr	9.3	0.5	–	9.8	9	–	9
NW Gharib	0.9	–	–	0.9	1	–	1
South Ghazalat	–	0.3	–	0.3	–	–	–
Egypt	11.3	5.3	–	16.6	12	–	12
Canada	9.0	1.6	–	10.6	3	–	3
2021 Total	20.3	6.9	–	27.2	15	–	15
Splits (%)	100%		0%	100%	100%	0%	100%

1	Other includes completions, workovers, recompletions and equipping

Advisory on Forward-Looking Information and Statements

Certain statements included in this news release constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. Forward-looking statements or information typically contain statements with words such as “anticipate”, “strengthened”, “confidence”, “believe”, “expect”, “plan”, “intend”, “estimate”, “may”, “will”, “would” or similar words suggesting future outcomes or statements regarding an outlook. In particular, forward-looking information and statements contained in this document include, but are not limited to, the Company’s strategy to grow its annual cash flow; anticipated drilling, completion and testing plans, including, the anticipated timing thereof, prospects being targeted by the Company, and rig mobilization plans; expected future production from certain of the Company’s drilling locations; TransGlobe’s plans to drill additional wells, including the types of wells, anticipated number of locations and the timing of drilling thereof; the timing of rig movement and mobilization and drilling activity; the Company’s plans to file development lease applications for certain of its discoveries, including the expected timing of filing of such applications and the expected timing of receipt of regulatory approvals; anticipated production and ultimate recoveries from wells; to negotiate future military access (including the expected timing thereof), including the anticipated timing of wells on production; TransGlobe’s plans to continue exploration, development and completion programs in respect of various discoveries; future requirements necessary to determine well performance and estimated recoveries; the ratification of the amendment, extension, and consolidation of the Company’s Eastern Desert Concessions; and other matters.

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.

In addition to other factors and assumptions which may be identified in this news release, assumptions have been made regarding, among other things, anticipated production volumes; the timing of drilling wells and mobilizing drilling rigs; the number of wells to be drilled; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business; future capital expenditures to be made by the Company; future sources of funding for the Company’s capital programs; geological and engineering estimates in respect of the Company’s reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities; current commodity prices and royalty regimes; availability of skilled labour; future exchange rates; the price of oil; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; future operating costs; uninterrupted access to areas of TransGlobe’s operations and infrastructure; recoverability of reserves and future production rates; that TransGlobe will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that TransGlobe’s conduct and results of operations will be consistent with its expectations; that TransGlobe will have the ability to develop its properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of TransGlobe’s reserves and resource volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; and other matters.

Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties which may cause actual results to differ materially from the forward-looking statements or information include, among other things, operating and/or drilling costs are higher than anticipated; unforeseen changes in the rate of production from TransGlobe’s oil and gas properties; changes in price of crude oil and natural gas; adverse technical factors associated with exploration, development, production or transportation of TransGlobe’s crude oil reserves; changes or disruptions in the political or fiscal regimes in TransGlobe’s areas of activity; changes in tax, energy or other laws or regulations; changes in significant capital expenditures; delays or disruptions in production due to shortages of skilled manpower equipment or materials; economic fluctuations; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; obtaining required approvals of regulatory authorities; volatility in market prices for oil; fluctuations in foreign exchange or interest rates; environmental risks; ability to access sufficient capital from internal and external sources; failure to negotiate the terms of contracts with counterparties; failure of counterparties to perform under the terms of their contracts; and other factors beyond the Company’s control. Readers are cautioned that the foregoing list of factors is not exhaustive. Please consult TransGlobe’s public filings at www.sedar.com and www.sec.goedgar.shtml for further, more detailed information concerning these matters, including additional risks related to TransGlobe’s business.

The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this news release are expressly qualified by this cautionary statement.

Oil and Gas Advisories

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.

BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 MCF: 1 Bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

References in this press release to production test rates, are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for TransGlobe. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the production test results should be considered to be preliminary.

The following abbreviations used in this press release have the meanings set forth below:

bbl	barrels
bbls/d	barrels per day
Mbbls/d	thousand barrels per day
Mbbls	thousand barrels
boe	barrel of oil equivalent
boe/d	barrels of oil equivalent per day
Mboe/d	thousand barrels of oil equivalent per day
MMbtu	One million British thermal units
Mcf	thousand cubic feet
Mcf/d	thousand cubic feet per day
NGL	Natural Gas Liquids

Production Disclosure

Production Summary (WI before royalties and taxes):
	Feb – 21	Jan – 21	Q4 – 20	Q3 – 20	Q2 – 20	Q1 – 20	Q4 – 19
Egypt (bbls/d)	9,975	10,372	10,268	9,812	11,990	12,544	12,831
Eastern Desert of Egypt (bbls/d)	9,874	10,257	10,132	9,635	11,757	12,343	12,831
Heavy Crude (bbls/d)	9,084	9,436	9,490	9,066	11,001	11,548	11,984
Light and Medium Crude (bbls/d)	790	821	642	569	756	795	847
Western Desert of Egypt (bbls/d)	101	115	136	177	233	201	–
Light and Medium Crude (bbls/d)	101	115	136	177	233	201	–
Canada (boe/d)	2,032	2,108	2,116	2,232	2,310	2,453	2,531
Light and Medium Crude (bbls/d)	576	607	618	661	706	860	908
Natural Gas (Mcf/d)	4,262	4,540	4,454	4,633	4,665	4,996	5,334
Associated Natural Gas Liquids (bbls/d)	746	744	755	798	826	761	735
Total (boe/d)	12,007	12,480	12,384	12,044	14,300	14,997	15,362

Production Guidance
	Low	High	Mid-Point
Egypt (bbls/d)	9,700	10,500	10,100
Heavy Crude (bbls/d)	8,940	9,678	9,309
Light and Medium Crude (bbls/d)	760	822	791
Canada (boe/d)	2,300	2,500	2,400
Light and Medium Crude (bbls/d)	767	833	800
Natural Gas (Mcf/d)	4,600	5,000	4,800
Associated Natural Gas Liquids (bbls/d)	767	833	800
Total (boe/d)	12,000	13,000	12,500

About TransGlobe

TransGlobe Energy Corporation is a cash flow-focused oil and gas exploration and development company whose current activities are concentrated in the Arab Republic of Egypt and Canada. TransGlobe’s common shares trade on the Toronto Stock Exchange and the AIM market of the London Stock Exchange under the symbol TGL and on the NASDAQ Exchange under the symbol TGA.

For further information, please contact:

TransGlobe Energy Corporation Randy Neely, President and CEO Eddie Ok, CFO	+1 403 264 9888 [email protected] http://www.trans-globe.com or via Tailwind Associates or FTI Consulting
Tailwind Associates (Investor Relations) Darren Engels	+1 403 618 8035 [email protected] http://www.tailwindassociates.ca
FTI Consulting (Financial PR) Ben Brewerton Genevieve Ryan	+44(0) 20 3727 1000 [email protected]
Canaccord Genuity (Nomad & Joint-Broker) Henry Fitzgerald-O’Connor James Asensio	+44(0) 20 7523 8000
Shore Capital (Joint Broker) Jerry Keen Toby Gibbs	+44(0) 20 7408 4090