The information contained within this Announcement is deemed by TransGlobe Energy Corporation to constitute inside information as stipulated under the Market Abuse Regulation (EU) No. 596/2014 as it forms part of UK law by virtue of the European Union (Withdrawal) Act 2018 (“MAR”).

Calgary, Alberta–(Newsfile Corp. – March 17, 2022) – TransGlobe Energy Corporation (AIM: TGL) (TSX: TGL) (NASDAQ: TGA) (“TransGlobe” or the “Company”) is pleased to announce its financial and operating results for the three months and year ended December 31, 2021. All dollar values are expressed in United States dollars unless otherwise stated. TransGlobe’s 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, 2021 and 2020, are available on TransGlobe’s website at www.trans-globe.com.

FINANCIAL HIGHLIGHTS:

• 2021 sales averaged 13,478 boe/d in 2021 with an average realized price of $58.79/boe; average realized price on Egyptian sales of $62.94/bbl and Canadian sales of $38.40/boe;
• Funds flow from operations of $44.8 million ($0.62 per share) in 2021;
• 2021 net earnings of $40.3 million ($0.56 per share), inclusive of a $31.5 million non-cash impairment reversal and a $0.1 million unrealized loss on derivative commodity contracts;
• The Company ended the year with positive working capital of $21.0 million, including cash of $37.9 million;

OPERATIONAL HIGHLIGHTS:

• 2021 production averaged 12,854 boe/d (Egypt 11,336 bbls/d, Canada 1,518 boe/d), a decrease of 4% from 2020 primarily attributable to natural declines in Egypt, partially offset by the re-commencement of Eastern Desert drilling and well optimization activities;
• Inventoried entitlement crude oil in Egypt decreased to nil as at December 31, 2021 from 227.9 Mbbls as at December 31, 2020;
• Ended the year with 46.1 MMboe of 2P reserves, up 19% from 2020 year end of 38.9 MMboe;
• Drilled and completed eight development oil wells and performed six recompletions in the Eastern Desert in Egypt;
• Drilled one exploration well and performed one recompletion in the Western Desert in Egypt;
• Drilled three horizontal Cardium oil wells and completed one standing well at Harmattan in Canada;

CORPORATE HIGHLIGHTS:

• As previously announced, the amendment, extension and merger of the Company’s Eastern Desert concession agreements into a single agreement (the “Merged Concession agreement”) was ratified by Egypt’s Parliament and signed into law by the President in December 2021;

2022 (TO DATE) HIGHLIGHTS:

• As previously announced, TransGlobe signed the Merged Concession agreement at an official signing ceremony with the Ministry of Petroleum held on January 19, 2022;
• The Company remitted the initial modernization payment of $15.0 million and signature bonus of $1.0 million as part of the conditions precedent to the official signing of the Merged Concession agreement;
• In accordance with the Merged Concession agreement, TransGlobe made another modernization payment to EGPC in the amount of $10.0 million on February 1, 2022;
• January 2022 average production of 12,291 boe/d, February 2022 average production of 12,392 boe/d;
• A cargo of Gharib blend crude shipped at the end of January 2022, marketed by Mercuria Energy Trading;
• Declared a dividend of $0.10 per common share, which will be paid in cash on May 12, 2022 to shareholders of record on April 29, 2022.

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, 2021 and 2020. 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, 2021, 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		2021			2020			% Change			2021			2020			% Change
Petroleum and natural gas sales1		93,428			50,989			83			303,956			188,771			61
Petroleum and natural gas sales, net of royalties1		58,043			33,309			74			169,006			114,675			47
Realized derivative (loss) gain on commodity contracts		(3,096	)		(6	)		51,500			(10,475	)		6,801			(254	)
Unrealized derivative gain (loss) on commodity contracts		2,803			(941	)		(398	)		(88	)		(180	)		(51	)
Production and operating expense		15,518			19,326			(20	)		61,430			64,462			(5	)
Overlift		(828	)		–			(100	)		14,723			–			100
Selling costs		55			1,008			(95	)		3,921			2,111			86
General and administrative expense		7,416			3,593			106			20,353			11,990			70
Depletion, depreciation and amortization expense		7,068			7,647			(8	)		25,434			31,049			(18	)
Income tax expense		6,050			3,408			78			22,411			13,530			66
Cash flow (used in) generated by operating activities		(1,956	)		14,180			(114	)		44,962			31,709			42
Funds flow from operations2		15,269			7,202			112			44,831			30,443			47
Basic per share3		0.21			0.10						0.62			0.42
Diluted per share3		0.21			0.10						0.61			0.42
Net earnings (loss)		6,560			(2,855	)		(330	)		40,338			(77,397	)		(152	)
Basic per share		0.09			(0.04	)					0.56			(1.07	)
Diluted per share		0.09			(0.04	)					0.55			(1.07	)
Capital expenditures4		8,694			255			3,309			26,822			7,498			258
Working capital7		21,032			15,349			37			21,032			15,349			37
Long-term debt, including current portion		3,040			21,464			(86	)		3,040			21,464			(86	)
Common shares outstanding
Basic (weighted average)		72,550			72,542			–			72,544			72,542			–
Diluted (weighted average)		73,750			72,542			2			73,182			72,542			1
Total assets		239,095			201,147			19			239,095			201,147			19
Operating
Average production volumes (boe/d)		12,763			12,384			3			12,854			13,425			(4	)
Average sales volumes (boe/d)		12,763			15,712			(19	)		13,478			15,437			(13	)
Inventory (Mbbls)		–			227.9			(100	)		–			227.9			(100	)
Average realized sales price ($/boe)5		67.03			35.27			90			58.79			33.41			76
Production and operating expenses ($/boe)6		13.22			13.37			(1	)		12.49			11.41			9

 

¹ Petroleum and natural gas sales for the three and twelve months ended December 31, 2021 are inclusive of overlift revenues of ($0.8 million) and $14.7 million, respectively.
² Non-GAAP financial measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. The most directly comparable GAAP measure for funds flow from operations is cash flow generated by operating activities. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
³ Non-GAAP ratio that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. Includes a non-GAAP financial measure component of funds flow from operations. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
⁴ Non-GAAP financial measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
⁵ Supplementary financial measure that is comprised of petroleum and natural gas sales, as determined in accordance with IFRS, divided by the Company’s average daily production volumes.
⁶ Supplementary financial measure that is comprised of production and operating expenses, as determined in accordance with IFRS, divided by the Company’s average daily production volumes.
⁷ Supplementary financial measure that is comprised of current assets less current liabilities, as determined in accordance with IFRS.

SELECTED ANNUAL INFORMATION

($000s, except per share amounts, price and volumes)		2021			% Change			2020			% Change			2019
Operations
Average production volumes
Crude oil (bbls/d)		11,336			(4	)		11,858			(18	)		14,527
NGLs (bbls/d)		740			(6	)		785			35			582
Natural gas (Mcf/d)		4,667			–			4,686			(16	)		5,594
Total (boe/d)		12,854			(4	)		13,425			(16	)		16,041
Average sales volume
Crude oil (bbls/d)		11,960			(14	)		13,871			3			13,441
NGLs (bbls/d)		740			(6	)		785			35			582
Natural gas (Mcf/d)		4,667			–			4,686			(16	)		5,594
Total (boe/d)		13,478			(13	)		15,437			3			14,954
Average realized sales prices1
Crude oil ($/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

 

¹ Supplementary financial measure that is comprised of petroleum and natural gas sales, as determined in accordance with IFRS, less overlift revenue, divided by the Company’s average daily production volumes. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
² Petroleum and natural gas sales for the year ended December 31, 2021 are inclusive of overlift revenues of $14.7 million.
³ Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. The most directly comparable GAAP measure for funds flow from operations is cash flow from operating activities. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
⁴ Non-GAAP ratio that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. Includes a non-GAAP financial measure component of funds flow from operations. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
⁵ Non-GAAP financial measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
⁶ Supplementary financial measure that is comprised of current assets less current liabilities, as determined in accordance with IFRS.

In 2021 compared with 2020, TransGlobe:

• Reported a 4% decrease in production volumes compared to 2020. This was primarily attributable to natural declines in Egypt, partially offset by the re-commencement of Eastern Desert drilling and well optimization activities;
• Ended 2021 with nil crude oil inventory, a decrease of 227.9 Mbbls over inventoried crude oil levels at December 31, 2020. This was primarily due to annual sales volumes exceeding production volumes and the Q3-2021 cargo lifting that resulted in an overlift;
• Reported positive funds flow from operations of $44.8 million (2020 – $30.4 million). The increase in funds flow from operations from 2020 is primarily due to higher commodity prices, partially offset by lower production and excess cost oil in West Bakr;
• Petroleum and natural gas sales increased by 61%, primarily due to a 76% increase in average realized sales prices, partially offset by a 13% decrease in sales volumes in 2021;
• Reported net earnings of $40.3 million (2020 – net loss of $77.4 million) inclusive of a $0.1 million unrealized derivative loss on commodity contracts and a combined $31.5 million non-cash impairment reversal on the Company’s petroleum and natural gas (“PNG”) assets;
• Ended the year with positive working capital of $21.0 million, including $37.9 million in cash as at December 31, 2021;
• Spent $26.8 million on capital expenditures, funded entirely from cash flow from operations and cash on hand; and
• Repaid $18.9 million of long-term debt with cash on hand.

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties

Production Volumes

		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

 

Sales Volumes (excludes volumes held as inventory)

		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

 

1 There are no sales volumes associated with overlift revenue.

Netback

Consolidated netback

		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

 

¹ Non-GAAP financial measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
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.
³ The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2021 and December 31, 2020.
⁴ Non-GAAP ratio that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. Includes a non-GAAP financial measure component of netback. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.

Egypt

		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

 

¹ Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
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.
³ The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2021 and December 31, 2020.
⁴ Supplementary financial measures that are comprised of petroleum and natural gas sales, royalties, current taxes, production and operating expenses and selling costs, determined in accordance with IFRS, divided by the Company’s average daily production volumes. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.

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 production sharing concessions (“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.

Canada

		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

 

¹ Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.
² Supplementary financial measures that are comprised of petroleum and natural gas sales, royalties, current taxes, production and operating expenses and selling costs, determined in accordance with IFRS, divided by the Company’s average daily production volumes. Refer to “Non-GAAP and Other Financial Measures” contained within the annual MD&A.

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.

Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss)

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

		Years Ended December 31
		2021			2020
REVENUE
Petroleum and natural gas sales, net of royalties		169,006			114,675
Finance revenue		9			106
Other revenue		32			641
		169,047			115,422
EXPENSES
Production and operating		61,430			64,462
Overlift		14,723			–
Selling costs		3,921			2,111
General and administrative		20,353			11,990
Foreign exchange loss		47			24
Finance costs		1,141			2,520
Depletion, depreciation and amortization		25,434			31,049
Asset retirement obligation accretion		207			259
Loss (gain) on financial instruments		10,563			(6,621	)
Impairment (reversal) loss		(31,521	)		73,495
		106,298			179,289
Earnings (loss) before income taxes		62,749			(63,867	)
Income tax expense – current		22,411			13,530
NET EARNINGS (LOSS)		40,338			(77,397	)
OTHER COMPREHENSIVE INCOME (LOSS)
Currency translation adjustments		(62	)		766
COMPREHENSIVE INCOME (LOSS)		40,276			(76,631	)
Net earnings (loss) per share
Basic		0.56			(1.07	)
Diluted		0.55			(1.07	)

 

Consolidated Balance Sheets

(Expressed in thousands of U.S. Dollars)

		As at			As at
		December 31, 2021			December 31, 2020
ASSETS
Current
Cash		37,927			34,510
Accounts receivable		12,217			9,996
Prepaids and other		4,024			3,530
Product inventory		–			5,828
		54,168			53,864
Non-Current
Intangible exploration and evaluation assets		2,673			584
Property and equipment
Petroleum and natural gas assets		173,804			140,059
Other		2,202			2,917
Deferred taxes		6,246			3,723
		239,093			201,147
LIABILITIES
Current
Accounts payable and accrued liabilities		26,110			20,176
Current portion of share-based compensation liabilities		6,174			1,491
Derivative commodity contracts		88			398
Current portion of lease obligations		764			1,553
Current portion of long-term debt		–			14,897
		33,136			38,515
Non-Current
Long-term debt		3,040			6,567
Asset retirement obligations		14,102			13,042
Share-based compensation liabilities		3,959			544
Lease obligations		36			461
Deferred taxes		6,246			3,723
		60,519			62,852
SHAREHOLDERS’ EQUITY
Share capital		153,021			152,805
Accumulated other comprehensive income		1,838			1,900
Contributed surplus		24,896			25,109
Deficit		(1,181	)		(41,519	)
		178,574			138,295
		239,093			201,147

 

Consolidated Statements of Changes in Shareholders’ Equity

(Expressed in thousands of U.S. Dollars)

		Years Ended December 31
		2021			2020
Share Capital
Balance, beginning of year		152,805			152,805
Stock options exercised		(340	)		–
Transfer from contributed surplus on exercise of options		556			–
Balance, beginning and end of year		153,021			152,805
Accumulated Other Comprehensive Income
Balance, beginning of year		1,900			1,134
Currency translation adjustment		(62	)		766
Balance, end of year		1,838			1,900
Contributed Surplus
Balance, beginning of year		25,109			24,673
Share-based compensation expense		343			436
Transfer to share capital on exercise of options		(556	)		–
Balance, end of year		24,896			25,109
(Deficit) Retained Earnings
Balance, beginning of year		(41,519	)		35,878
Net earnings (loss)		40,338			(77,397	)
Balance, end of year		(1,181	)		(41,519	)

 

Consolidated Statements of Cash Flows

(Expressed in thousands of U.S. Dollars)

		Years Ended December 31
		2021			2020
OPERATING
Net earnings (loss)		40,338			(77,397	)
Adjustments for:
Depletion, depreciation and amortization		25,434			31,049
Asset retirement obligation accretion		207			259
Impairment (recovery) loss		(31,521	)		73,495
Share-based compensation		9,267			857
Finance costs		1,141			2,520
Unrealized loss on financial instruments		88			180
Unrealized loss (gain) on foreign currency translation		12			(62	)
Asset retirement obligations settled		(135	)		(458	)
Changes in working capital		131			1,266
Net cash generated by operating activities		44,962			31,709
INVESTING
Additions to intangible exploration and evaluation assets		(2,089	)		(337	)
Additions to petroleum and natural gas assets		(24,636	)		(6,726	)
Additions to other assets		(97	)		(435	)
Changes in working capital		7,601			(3,544	)
Net cash used in investing activities		(19,221	)		(11,042	)
FINANCING
Issue of common shares		(340	)		–
Interest paid		(856	)		(1,918	)
Increase in long-term debt		415			406
Payments on lease obligations		(1,932	)		(1,703	)
Repayments of long-term debt		(18,937	)		(16,504	)
Changes in working capital		(365	)		161
Net cash used in financing activities		(22,015	)		(19,558	)
Currency translation differences relating to cash		(307	)		150
NET INCREASE IN CASH		3,419			1,259
CASH, BEGINNING OF YEAR		34,510			33,251
CASH, END OF YEAR		37,929			34,510

 

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.

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 prepayment agreement with Mercuria was fully repaid in the amount of $15.0 million.

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 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 “Advisory on Forward-Looking Information and Statements” within this news release.

2022 Outlook

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.

2022 Capital Budget

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.

Egypt

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.

Canada

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.

The approved 2022 capital program is summarized in the following table:

	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

 

¹ Other includes completions, workovers, recompletions and equipping.
² Table may not total due to rounding.

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 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 anticipated exit production rates; the Company’s expectations that it will increase investments and growth in Egypt and Canada; the Company’s , strategy and focus in 2022, including the drilling of wells and growing production; the Company’s plans to maximize free cash flow, to increase the Company’s production base and return to shareholder distributions; the number of and location of wells to be drilled by the Company in 2022 and the anticipated timing thereof; the focus of the Egypt 2022 capital program; the ability of the Company’s long-lead capital items to provide continuity into 2023; the expected timing of determining the effective date adjustment with EGPC under the Merged Concession agreement; the anticipated netback to be generated by the Company’s Eastern Desert acreage and in Canada; 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; the Company’s estimated 2022 capital spending and production will be as anticipated and allocated in the manner described herein 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; 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; the Company’s long-lead capital items will not provide continuity into 2023; the netback generated by the Company’s Eastern Desert acreage will be less than anticipated; the netback generated in Canada is less than anticipated; 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 Company’s future dividend payments, if any, and the level thereof is uncertain. Any decision to pay dividends will be subject to the discretion of the board of directors of the Company and may depend on a variety of factors, including, without limitation the Company’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance that dividends will be paid in the future.

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.

This news release contains information that may be considered a financial outlook under applicable securities laws about the Company’s anticipated capital expenditures for 2022 and the Company’s petroleum and natural gas sales (net of royalties), less taxes and production and operating taxes disclosed under the heading “Field Operating Netback per Bbl and Boe Calculations” in this news release. Such financial information has been prepared by management to provide an outlook of the Company’s financial results and activities and may not be appropriate for other purposes. This information has been prepared based on a number of assumptions, risk factors, limitations and qualifications including those discussed in this news release. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Company and management believe that the financial outlook has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. The financial outlook contained in this news release was made as of January 27, 2022 and the Company disclaims any intent or obligation to update publicly the news release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

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.

This news release contains a number of oil and gas metrics 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.

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.

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

 

Financial Measures Advisories

TransGlobe’s audited consolidated financial statements and notes (the “financial statements”) and Management’s Discussion and Analysis (“MD&A”) as at and for the three months and year ended December 31, 2021, are available on TransGlobe’s website at www.trans-globe.com and under the Company’s SEDAR profile at www.sedar.com. The disclosure under the section “Non-GAAP and Other Financial Measures” in TransGlobe’s MD&A as at and for the three months and year ended December 31, 2021 is incorporated by reference into this news release.

NON-GAAP AND OTHER FINANCIAL MEASURES

Throughout the 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.

Non-GAAP financial measures

Capital Expenditures

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.

		Years Ended December 31
($000s)		2021			2020			2019
Net cash used in investing activities		(19,221	)		(11,042	)		(37,109	)
Proceeds from asset dispositions		–			–			(114	)
Changes in non-cash working capital		(7,601	)		3,544			291
Capital expenditures		(26,822	)		(7,498	)		(36,932	)

 

		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	)

 

Funds flow from operations

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.

		Years Ended December 31
($000s)		2021			2020			2019
Cash flow generated by operating activities		44,962			31,709			44,836
Changes in non-cash working capital		(131	)		(1,266	)		2,035
Funds flow from operations1		44,831			30,443			46,871

 

¹ Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss). Cash interest paid is reported as a financing activity on the Consolidated Statements of Cash Flows.

		2021												2020
($000s)		Q-4			Q-3			Q-2			Q-1			Q-4			Q-3			Q-2			Q-1
Cash flow (used in) generated by operating activities		(1,956	)		27,026			23,832			(3,940	)		14,180			(3,349	)		24,551			(3,672	)
Changes in non-cash working capital		17,225			(14,645	)		(6,732	)		4,021			(6,978	)		3,672			(27,315	)		29,355
Funds flow from operations1		15,269			12,381			17,100			81			7,202			323			(2,764	)		25,683

 

¹ Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss). Cash interest paid is reported as a financing activity on the Consolidated Statements of Cash Flows.

Net debt

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.

		Years Ended December 31
($000s)		2021			2020			2019
Long-term debt, including the current portion		3,040			21,464			37,041
Current assets		(54,170	)		(53,864	)		(65,786	)
Current liabilities, excluding the current portion of long-term debt		33,138			23,618			33,592
Net debt		(17,992	)		(8,782	)		4,847

 

		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

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.

($000s)		2021			2020
Petroleum and natural gas sales		303,956			188,771
Overlift		(14,723	)		–
Petroleum and natural gas sales, excluding overlift		289,233			188,771

 

¹ Petroleum and natural gas sales, excluding overlift are equal for all periods disclosed prior to 2021.

Netback

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.

Non-GAAP financial ratios

Netback per boe

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 in the “Netback” section within this MD&A.

Funds flow from operations per share

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.

Supplementary Financial Measures

“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.

Production Disclosure

Production Summary (WI before royalties and taxes):
	Feb – 22	Jan – 22	Q4 – 21	Q3 – 21	Q2 – 21	Q1 – 21	Q4 – 20
Egypt (bbls/d)	10,047	10,094	10,065	11,276	10,727	10,238	10,268
Eastern Desert of Egypt (bbls/d)	9,993	10,094	9,770	10,653	9,917	10,052	10,132
Heavy Crude (bbls/d)	9,184	9,227	9,225	10,014	9,736	9,419	9,490
Light and Medium Crude (bbls/d)	809	867	545	639	181	633	642
Western Desert of Egypt (bbls/d)	54	–	295	623	810	186	136
Light and Medium Crude (bbls/d)	54	–	295	623	810	186	136
Canada (boe/d)	2,345	2,197	2,698	2,066	2,350	1,983	2,116
Light and Medium Crude (bbls/d)	853	817	1,176	601	687	564	618
Natural Gas (Mcf/d)	4,329	4,462	4,832	4,734	4,834	4,259	4,454
Associated Natural Gas Liquids (bbls/d)	770	636	716	677	857	710	755
Total (boe/d)	12,392	12,291	12,763	13,342	13,077	12,221	12,384

 

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

Tailwind Associates (Investor Relations)
Darren Engels
+1 403 618 8035
[email protected]
http://www.tailwindassociates.ca

Canaccord Genuity (Nomad & Joint-Broker)
Henry Fitzgerald-O’Connor
James Asensio
+44(0) 20 7523 8000

Shore Capital (Joint Broker)
John More
Toby Gibbs
+44(0) 20 7408 4090

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/117144