Edgar Filing: TRANSGLOBE ENERGY CORP

Dated Brent average oil price ($/Bbl)

U.S./Canadian Dollar average exchange rate

2012 Annual Report

CONTENTS



MESSAGE TO SHAREHOLDERS	Page 3
MANAGEMENT’S DISCUSSION AND ANALYSIS	Page 4
MANAGEMENT’S REPORT	Page 23
REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS	Page 25
CONSOLIDATED FINANCIAL STATEMENTS	Page 26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	Page 30
SUPPLEMENTARY INFORMATION
Financial / Reserves / Production and Sales Volumes	Page 52
Share Information	Page 53
Summary of International Production Sharing Concessions	Page 54
Reserves and Estimated Future Net Reserves	Page 56

TransGlobe Energy Corporation’s

Annual General Meeting of Shareholders

Wednesday, May 8, 2013

3:00 PM

Mountain Time

Bow Glacier Room located in the

Centennial Place West Conference Centre

3rd Floor, 250 5th Street S.W.

Calgary, Alberta, Canada



2		2012

MESSAGE TO THE SHAREHOLDERS

I am pleased to report the results of 2012 to the shareholders.

TransGlobe Energy Corporation ("TransGlobe" or the "Company") recorded substantial growth in reserves and production, primarily in our operated Egyptian properties. Production increased from an average 12,132 Bopd in 2011 to 17,496 Bopd in 2012, a growth rate of 44 percent. Year-end 2012 Proved reserves ("1P") increased 16 percent to 32.8 MMBbl representing a production replacement for the year of 172 percent. Proved plus Probable reserves ("2P") increased 10 percent to 48.7 MMBbl, representing a production replacement for the year of 170 percent. The Proved plus Probable plus Possible reserves ("3P") increased to 62.4 MMBbl, an increase of 4 percent. A significant portion of the 2011 3P reserves were converted to 1P and 2P reserves during 2012. The new fields discovered in 2010 at Arta and East Arta in Arab Republic of Egypt ("Egypt") commenced secondary recovery (water flooding) in 2012 which provided the most significant reserves increases. Development drilling on the recently acquired West Bakr fields also contributed to increased reserves in 2012. Further increases can be expected from additional delineation drilling on these projects.

TransGlobe continued its acquisition program in 2012 by adding two new projects at South Alamein (100%) and at South Mariut (60%) in the Western Desert area of Egypt. The acquisitions closed in mid-2012 and exploration drilling commenced in late 2012 on South Mariut with South Alamein expected to commence drilling in 2013. TransGlobe management believes the potential exists to dramatically increase production and reserves at South Alamein because a discovery already exists on the lands. South Alamein also has a large exploration inventory for future drilling. TransGlobe expects to develop an oil discovery on the block to achieve production in 2013 and then proceed with further exploration drilling. The South Mariut block is a higher risk exploration opportunity in an untested basin. The first well on South Mariut was unsuccessful. The Company has two additional, independent exploration targets to drill on South Mariut.

TransGlobe was successful in winning four new blocks of land in the 2012 Egyptian Bid Round. The most significant block, NW Gharib, surrounds our West Gharib and West Bakr lands. The Company already has 3-D seismic over much of the NW Gharib block and has identified a large number of drilling targets that are similar to the Arta/East Arta producing fields. The other three blocks that were awarded to TransGlobe have significant exploration potential identified on older 2-D seismic. These blocks will see extensive 3-D seismic surveys prior to drilling.

TransGlobe's management will continue to maintain focus on risk management across an increasing portfolio of exploration and development opportunities. The portfolio ranges from development / low exploration risk projects which have a short investment cycle time, to medium / high risk exploration prospects on other projects. This portfolio allows the Company to allocate capital on a risk/reward basis across many investment opportunities and to continue to grow while maintaining a conservative financial position. The benefits of this approach were directly evident in the production and reserve increases of the past ten years.

The expanded land position TransGlobe built in 2012 will allow for continued reserve and production growth for the next five years. The Company is well funded to grow with a stable production base.

During 2012 Egypt and Republic of Yemen ("Yemen") continued to see unrest as they transition to democracy. The outcome of this process is difficult to predict. The Company closely monitors the situation and has increased communication with our stakeholders. There have been no significant changes to field operations or government interaction in Egypt. The Company markets all of our oil through Egyptian General Petroleum Corporation ("EGPC"), primarily to foreign buyers. EGPC has been delaying payments to oil companies for oil sales during 2011 and 2012 due to economic factors related to fuel subsidies in Egypt. The Company's accounts receivable for oil sales has increased in size due to increased volumes and increased prices, although the months of aging has remained relatively steady at eight to nine months. Management is actively working with EGPC to receive payments for oil sales and to reduce the aging on the EGPC receivable during 2013. The government of Egypt is undertaking reforms to the subsidy system that should help to stabilize EGPC's financial position. TransGlobe maintains a strong balance sheet with low debt levels and a significant cash position. This allows the Company to persist and grow through the economic difficulties of the current situation in Egypt.

Yemen is still in an unsettled political situation. The government export pipeline that transports our Block S-1 oil was damaged several times during 2012 by tribal groups which forced a shut-in of all the producers from the western area of Yemen. As of March 2013 the pipeline has not been repaired and it is difficult to predict when it will be. TransGlobe's Yemen assets now represent a small portion of Company's portfolio. Therefore management has decided to explore the possibility of selling these assets since they are unlikely to significantly influence the Company's future production and reserves.

The 2013 guidance for average production of 21,000 to 24,000 Bopd is a 29% increase over the 2012 average. This can be achieved because the oil discoveries and acquisitions have positioned the Company for consistent year-over-year growth. We will continue with our successful strategy of the past 17 years, focusing on building a portfolio of projects that have many drilling opportunities and that can be quickly brought into production. This strategy has produced exceptional growth in reserves, production and cost efficient additions to shareholder value and we believe it will continue to do so in the future.

Robert Halpin, Chairman of the Board of Directors will be retiring in May, 2013. Robert became Chairman in 1997 and has been a dedicated supporter of the Company. His leadership and passion for the industry will be missed. On behalf of the Board of Directors and staff we wish Robert a long, happy and healthy retirement.

Signed by:

“Ross G. Clarkson”

Ross G. Clarkson

President and Chief Executive Officer

March 5, 2013



2012		3

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 5, 2013

The following discussion and analysis is management’s opinion of TransGlobe’s historical financial and operating results and should be read in conjunction with the message to shareholders and the audited consolidated financial statements of the Company for the years ended December 31, 2012 and 2011, together with the notes related thereto (the "Consolidated Financial Statements"). The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board in the currency of the United States (except where otherwise noted). Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com. The Company’s annual report on Form 40-F may be found on EDGAR at www.sec.gov.

READER ADVISORIES

Forward-Looking Statements

Certain statements or information contained herein may constitute forward-looking statements or information under applicable securities laws, including, but not limited to, management’s assessment of future plans and operations, anticipated increases to the Company's reserves and production, the possible sale of the Company's assets in Yemen, collection of accounts receivable from the Egyptian Government, drilling plans and the timing thereof, commodity price risk management strategies, adapting to the current political situations in Egypt and Yemen, reserve estimates, management’s expectation for results of operations for 2013, including expected 2013 average production, funds flow from operations, the 2013 capital program for exploration and development, the timing and method of financing thereof, method of funding drilling commitments, and commodity prices and expected volatility thereof. Statements relating to "reserves" are deemed to be forward‑looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

Forward-looking statements or information relate to the Company’s future events or performance. All statements other than statements of historical fact may be forward-looking statements or information. Such statements or information are often but not always identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, and similar expressions.

Forward-looking statements or information necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, economic and political instability, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. The recovery and reserve estimates of the Company's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company.

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

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) and at the Company's website (www.trans-globe.com). Furthermore, the forward-looking statements or information contained herein are made as at the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

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



4		2012

MANAGEMENT STRATEGY AND OUTLOOK

The 2013 outlook provides information as to management’s expectation for results of operations for 2013. Readers are cautioned that the 2013 outlook may not be appropriate for other purposes. The Company’s expected results are sensitive to fluctuations in the business environment and may vary accordingly. This outlook contains forward-looking statements that should be read in conjunction with the Company’s disclosure under “Forward-Looking Statements”, outlined on the first page of this MD&A.

2013 Outlook Highlights


•	Production is expected to average between 21,000 Bopd and 24,000 Bopd, a 20% to 37% increase over the 2012 average production;


•	Exploration and development spending is budgeted to be $129.0 million excluding acquisitions, a 152% increase from 2012, to be funded from funds flow from operations and cash-on-hand; and


•	Funds flow from operations is estimated at $161.0 million, representing an increase of 5% from 2012, using mid-point production guidance and an average oil price assumption of $100.00 per barrel Dated Brent oil price.

2013 Updated Production Outlook

Production for 2013 is expected to average between 21,000 and 24,000 Bopd, representing a 20% to 37% increase over the 2012 average production of 17,496 Bopd. The spread in the estimated production is due to a number of variables outside of the Company’s control such as Government approvals relating to the start of South Alamein production, development drilling results in Egypt and the repair of the export pipeline for Block S-1 in Yemen.



Production Forecast
	2013 Guidance	2012 Actual	% Change
Barrels of oil per day	21,000 – 24,000	17,496	20 - 37

2013 Updated Funds Flow From Operations Outlook

Funds flow from operations is estimated at $161.0 million ($2.13/share) based on an annual average Dated Brent oil price of $100/Bbl and using the mid-point of the production guidance. Variations in production and commodity prices during 2013 could significantly change this outlook. An increase or decrease in the average Dated Brent oil price of $10/Bbl for the year would result in a corresponding change in anticipated 2013 funds flow by approximately $17.0 million or $0.23/share.




Funds Flow Forecast
($ millions)	2013 Guidance	2012 Actual	% Change
Funds Flow from operations	161.0	153.5	5
Brent oil price ($ per bbl)	100.00	111.56	(10	)



2013 Capital Budget
($ millions)	2013
Egypt	124.0
Yemen	5.0
Total	129.0

The 2013 capital program is split 58:42 between development and exploration, respectively. The Company plans to participate in 51 wells in 2013. It is anticipated that the Company will fund its 2013 capital budget from funds flow from operations and working capital.

The Company will begin to explore the possibility of selling its Yemen assets in 2013, since these assets are unlikely to significantly influence the Company's future production and reserves.

Additional Measures

Funds Flow from Operations

This document contains the term “funds flow from operations”, which should not be considered an alternative to or more meaningful than “cash flow from operating activities” as determined in accordance with IFRS. Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital. Management considers this a key measure as it demonstrates TransGlobe’s ability to generate the cash flow necessary to fund future growth through capital investment. Funds flow from operations may not be comparable to similar measures used by other companies.



2012		5

Reconciliation of Funds Flow from Operations



($000s)	2012	2011
Cash flow from operating activities	93,992	63,630
Changes in non-cash working capital	59,506	56,346
Funds flow from operations*	153,498	119,976
* Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Consolidated Statements of Earnings and Comprehensive Income. Cash interest paid is reported as a financing activity on the Consolidated Statements of Cash Flows.

Debt-to-funds flow ratio

Debt-to-funds flow is a measure that is used to set the amount of capital in proportion to risk. The Company’s debt-to-funds flow ratio is computed as long-term debt, including the current portion, plus convertible debentures over funds flow from operations for the trailing twelve months. Debt-to-funds flow may not be comparable to similar measures used by other companies.

Netback

Netback is a measure that represents sales net of royalties (all government interests, net of income taxes), operating expenses and current taxes. 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 may not be comparable to similar measures used by other companies.

TRANSGLOBE’S BUSINESS

TransGlobe is a Canadian-based, publicly traded, oil exploration and production company whose activities are concentrated in two main geographic areas: the Arab Republic of Egypt (“Egypt”) and the Republic of Yemen (“Yemen”).

BUSINESS ACQUISITIONS

On June 7, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of a wholly-owned subsidiary of EP Energy LLC, which holds, through wholly-owned subsidiaries, a non-operated 50% working interest in the South Alamein Production Sharing Concession ("PSC") in Egypt and an operated 60% working interest in the South Mariut PSC in Egypt. The transaction was structured as an all-cash deal, effective April 1, 2012, funded through working capital and the proceeds of the issuance of convertible debentures. Total consideration for the transaction was $22.9 million, which represents an initial $15.0 million base purchase price plus $7.9 million in consumable drilling equipment inventory (which is classified as exploration and evaluation assets), working capital and other closing adjustments.

On July 26, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of Cepsa Egypt SA B.V. (“Cepsa Egypt”), a wholly-owned subsidiary of Compania Espanola De Petroleos, S.A.U. (“Cepsa”). Cepsa Egypt holds an operated 50% working interest in the South Alamein PSC in Egypt. In conjunction with the EP Energy LLC business combination that was completed in the second quarter of 2012, this transaction brought the Company’s working interest in the South Alamein concession to 100%. The transaction was structured as an all-cash deal, effective July 1, 2012, funded through working capital. Total consideration for the transaction was $4.5 million, which represents an initial $3.0 million base purchase price plus $1.5 million in consumable drilling equipment inventory (which is classified as exploration and evaluation assets), working capital and other closing adjustments.



6		2012

SELECTED ANNUAL INFORMATION



($000s, except per share, price and volume	2012	% Change	2011	% Change	2010
amounts)	2012	% Change	2011	% Change	2010
Operations
Average sales volumes (Bopd)	17,496	44	12,132	22	9,960
Average price ($/Bbl)	99.01	(3)	101.58	37	73.97
Oil and gas sales	633,992	41	449,794	67	268,901
Oil and gas sales, net of royalties	317,666	28	247,754	58	157,220
Cash flow from operating activities	93,992	48	63,630	12	56,969
Funds flow from operations*	153,498	28	119,976	59	75,460
- Basic per share	2.09		1.65		1.14
- Diluted per share	2.03		1.60		1.10
Net earnings	87,734	8	81,392	101	40,565
- Basic per share	1.20		1.12		0.61
- Diluted per share	1.16		1.09		0.59
Total assets	653,425	24	525,806	52	345,625
Cash and cash equivalents	82,974	89	43,884	(24)	57,782
Convertible debentures	98,742	—	—	—	—
Total long-term debt, including current portion	16,885	(71)	57,609	(33)	86,420
Debt-to-funds flow ratio**	0.8		0.5		1.1
Reserves
Total Proved (MMBbl)***	32.8	16	28.2	37	20.5
Total Proved plus Probable (MMBbl)***	48.7	10	44.2	45	30.4
* 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.
** Debt-to-funds flow ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures over funds flow from operations for the trailing 12 months, and may not be comparable to measures used by other companies.
*** As determined by the Company's independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports dated January 18, 2013 and January 10, 2012 with effective dates of December 31, 2012 and December 31, 2011, respectively. The reports of DeGolyer 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.

In 2012 compared with 2011, TransGlobe,


•	Increased Proved reserves by 16% to 32.8 MMBbl and Proved plus Probable reserves by 10% to 48.7 MMBbl, representing production replacements of 172% and 170%, respectively, primarily from the development of its operated West Gharib and West Bakr concessions in Egypt;


•	Increased total sales volumes by 44%, as a result of a 56% increase in sales volumes from Egypt offset by a 43% decline in sales volumes in Yemen;


•	Increased funds flow from operations by 28% primarily due to increased production;

•

Increased net earnings to $87.7 million due to an increase in net sales revenue of $69.9 million, which was partially offset by a combined increase of $51.5 million in operating costs, current income taxes, depletion and depreciation expense, general and administrative expenses and finance costs. The increase in finance costs is due to the issuance of the convertible debentures in February 2012, whereas the other increased costs were the result of increased activity due to the Company's growth through the acquisitions completed in 2012, along with the first full year of operations at West Bakr;


•	Issued convertible unsecured subordinated debentures with an aggregate principal amount of $97.9 million; and


•	Decreased long-term debt by $40.7 million which assisted in maintaining a strong debt-to-funds flow ratio of 0.8 at December 31, 2012 (0.5 at December 31, 2011).



2012		7

2012 TO 2011 NET EARNINGS VARIANCES



			$ Per Share
	$000s		Diluted		% Variance
2011 net earnings	81,392		1.09
Cash items
Volume variance	195,595		2.57		241
Price variance	(11,397	)	(0.15	)	(14	)
Royalties	(114,286	)	(1.52	)	(140	)
Expenses:
Production and operating	(15,705	)	(0.21	)	(19	)
Cash general and administrative	(7,765	)	(0.10	)	(10	)
Exploration	1,193		0.02		1
Current income taxes	(14,586	)	(0.19	)	(18	)
Realized foreign exchange gain (loss)	(142	)	—		—
Realized derivative gain (loss)	630		0.01		1
Issue costs for convertible debentures	(4,630	)	(0.06	)	(6	)
Interest on long-term debt	(4,212	)	(0.06	)	(5	)
Other income	(15	)	—		—
Total cash items variance	24,680		0.31		31
Non-cash items
Unrealized derivative loss	52		—		—
Unrealized foreign exchange loss	557		0.01		1
Depletion and depreciation	(11,865	)	(0.16	)	(15	)
Unrealized loss on financial instruments	(425	)	(0.01	)	(1	)
Gain on acquisition	(13,187	)	(0.17	)	(16	)
Impairment loss	12,071		0.16		15
Stock-based compensation	(1,440	)	(0.02	)	(2	)
Deferred income taxes	(3,917	)	(0.05	)	(5	)
Deferred lease inducement	(108	)	—		—
Amortization of deferred financing costs	(76	)	—		—
Total non-cash items variance	(18,338	)	(0.24	)	(23	)
2012 net earnings	87,734		1.16		8

Net earnings increased to $87.7 million in 2012 compared to $81.4 million in 2011, which was mostly due to a significant increase in production volumes, which was partially offset by higher royalties and income taxes and increases in operating costs, depletion and depreciation expense, general and administrative expenses and finance costs. The increase in finance costs is due to the issuance of the convertible debentures in February 2012, whereas the other increased costs were the result of increased activity due to the Company's growth through the acquisitions completed in 2012, along with the first full year of operations at West Bakr.

BUSINESS ENVIRONMENT

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

The average price of Dated Brent oil was relatively unchanged in 2012 compared with 2011. All of the Company’s production is priced based on Dated Brent and shared with the respective governments through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost recovery barrels) which are assigned 100% to the Company. The contracts provide for cost recovery per quarter up to a maximum percentage of total revenue. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, the Contractor's share of excess ranges between 0% and 30% depending on the contract. In Yemen, the excess is treated as production sharing oil. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost recovery or cost oil ranges from 25% to 30% in Egypt and 50% to 60% in Yemen. The balance of the production after maximum cost recovery is shared with the respective governments (production sharing oil). Depending on the contract, the government receives 70% to 86% of the production sharing oil or profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of production sharing oil increases when production exceeds pre-set production levels in the respective contracts. During times of increased oil prices, the Company receives less cost oil and may receive more production sharing oil. For reporting purposes, the Company records the respective government’s share of production as royalties and taxes (all taxes are paid out of the Government’s share of production).



8		2012

During the political change in Egypt, business processes and operations have generally proceeded as normal. The Company continues to expand its footprint in Egypt as evidenced by the closing of recent business acquisitions. While exploration and development activities have generally been uninterrupted, the Company has continued to experience delays in the collection of accounts receivable from the Egyptian Government due to the economic impact caused by the instability in the country. The Company is in continual discussions with the Egyptian Government to determine solutions to the delayed cash collections, and expects to recover the accounts receivable balance in full. The Company collected $157.0 million in accounts receivable from the Egyptian Government during 2012, including $76.1 million in the fourth quarter.

SELECTED QUARTERLY FINANCIAL INFORMATION



	2012				2011
($000s, except per share,
price and volume amounts)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Average sales volumes (Bopd)	19,148	17,124	16,978	16,720	12,054	13,406	11,826	11,218
Average price ($/Bbl)	98.70	96.88	95.84	104.78	99.12	104.00	105.57	97.06
Oil sales	173,864	152,624	148,078	159,426	109,919	128,265	113,615	97,995
Oil sales, net of royalties	92,281	74,540	73,633	77,212	60,609	71,769	62,513	52,863
Cash flow from operating activities	65,250	2,368	24,603	1,771	2,330	3,456	54,354	3,490
Funds flow from operations*	46,839	35,397	35,174	36,088	26,469	37,980	30,597	24,930
Funds flow from operations per share
- Basic	0.63	0.49	0.48	0.49	0.36	0.52	0.42	0.35
- Diluted	0.57	0.47	0.43	0.48	0.35	0.51	0.40	0.34
Net earnings	34,836	11,774	30,149	10,975	30,519	26,110	21,874	2,889
Net earnings - diluted	32,156	11,774	20,821	10,975	30,519	26,110	21,874	2,889
Net earnings per share
- Basic	0.48	0.16	0.41	0.15	0.42	0.36	0.30	0.04
- Diluted	0.39	0.16	0.25	0.15	0.41	0.35	0.29	0.04
Total assets	653,425	635,529	620,937	648,012	525,806	465,262	420,956	404,184
Cash and cash equivalents	82,974	45,732	72,230	127,313	43,884	105,007	122,659	86,353
Convertible debentures	98,742	102,920	95,043	105,835	—	—	—	—
Total long-term debt, including current portion	16,885	31,878	37,855	57,910	57,609	57,303	56,998	56,731
Debt-to-funds flow ratio**	0.8	1.0	1.0	1.2	0.5	0.5	0.6	0.7
* 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.
** Debt-to-funds flow ratio is measure that represents total long-term debt (including the current portion) plus convertible debentures over funds flow from operations from the trailing 12 months and may not be comparable to measures used by other companies.

During the fourth quarter of 2012, TransGlobe has:


•	Experienced a significant increase in cash flow from operating activities compared with prior quarters due to increased collections on accounts receivable (collected $76.1 million in Egypt and $12.4 million in Yemen in Q4-2012);


•	Maintained a strong financial position, reporting a debt-to-funds flow ratio of 0.8 at December 31, 2012;


•	Reported net earnings of $34.8 million;


•	Achieved record quarterly funds flow from operations of $46.8 million, an increase of 77% from Q4-2011, which was principally due to a 59% increase in sales volumes; and


•	Spent $19.8 million on capital programs, which was funded entirely with funds flow from operations.

The accounting for the convertible debentures continued to have a significant impact on important components of the Company's financial statements. The Company reported an increase in net earnings of $23.1 million from the third quarter of 2012, $12.1 million of which was due to:


•	The recording of an unrealized gain on convertible debentures of $2.9 million recognized in the fourth quarter of 2012, combined with an unrealized loss of $4.4 million recognized on the convertible debentures in the third quarter of 2012; and


•	An earnings increase of $4.8 million from Q3-2012 to Q4-2012 related to foreign exchange on the convertible debentures.



2012		9

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties and Other (Bopd)

Sales Volumes

Netback



Consolidated
	2012		2011
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	633,992	99.01	449,794	101.58
Royalties	316,326	49.40	202,040	45.63
Current taxes	88,603	13.84	74,017	16.71
Production and operating expenses	52,367	8.18	36,662	8.28
Netback	176,696	27.59	137,075	30.96



Egypt
	2012		2011
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	600,536	98.51	391,884	100.61
Royalties	303,651	49.81	176,033	45.20
Current taxes	84,935	13.93	66,630	17.11
Production and operating expenses	43,247	7.09	27,407	7.04
Netback	168,703	27.68	121,814	31.26

The netback per Bbl in Egypt decreased 11% in 2012 compared with 2011, which is a result of oil prices decreasing by 2% combined with higher royalty and tax rates principally associated with production from West Bakr. In 2012, the average selling price was $13.05/Bbl lower than the average Dated Brent oil price for the year of $111.56/Bbl which is a result of a gravity/quality adjustment as well as a contracted discounted price for West Bakr crude in 2012.

Royalties and taxes as a percentage of revenue increased to 65% in 2012, compared with 62% in 2011. This increase is due to the fact that 2011 included only West Gharib production, whereas 2012 includes West Gharib and West Bakr production. West Bakr production is subject to higher Government take in accordance with the West Bakr PSC and a lower contracted price as compared to West Gharib.

Production and operating expenses on a per Bbl basis remained consistent in 2012 compared with 2011.



Yemen
	2012		2011
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	33,456	108.82	57,910	108.60
Royalties	12,675	41.23	26,007	48.77
Current taxes	3,668	11.93	7,387	13.85
Production and operating expenses	9,120	29.66	9,255	17.36
Netback	7,993	26.00	15,261	28.62

In Yemen, the Company experienced a 9% netback reduction on a per Bbl basis in 2012 compared with 2011. Operating expenses on a per Bbl basis increased substantially (71%) in 2012 compared to 2011 as a result of production being shut-in on Block S-1 from the beginning of the year until July 27, 2012, and again from November 11, 2012 to the end of the year. While production volumes were down, the Company continued to incur the majority of the operating costs on Block S-1 which significantly increased operating expenses per Bbl.

Partially offsetting the increased operating expenses per Bbl was a decrease of 15% in royalties and taxes on a per Bbl basis. The Block S-1 operating costs incurred during the shut-in period from the beginning of 2012 through to July 27, 2012 accumulated in cost recovery pools, which allowed the Company to achieve full cost recovery in accordance with the PSC during the time that Block S-1 was producing in the year. Cost recovery is paid out through a reduction of Government take, which has resulted in a decrease in royalties and taxes on a per Bbl basis in 2012 compared to 2011.



10		2012

DERIVATIVE COMMODITY CONTRACTS

TransGlobe uses hedging arrangements from time to time as part of its risk management strategy to manage commodity price fluctuations and stabilize cash flows for future exploration and development programs. The hedging program is actively monitored and adjusted as deemed necessary to protect the cash flows from the risk of commodity price exposure.

As there are no outstanding derivative commodity contracts at December 31, 2012, no assets or liabilities have been recognized on the Consolidated Balance Sheet for the current year. As at December 31, 2012, no production is hedged in future periods.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)



	2012				2011
(000s, except Bbl amounts)	$		$/Bbl		$		$/Bbl
G&A (gross)	27,545		4.30		17,946		4.05
Stock-based compensation	4,502		0.70		3,062		0.69
Capitalized G&A and overhead recoveries	(3,841	)	(0.60	)	(2,115	)	(0.48	)
G&A (net)	28,206		4.40		18,893		4.26

G&A expenses (net) increased 49% (3% on a per Bbl basis) in 2012 compared with 2011. The increase is principally due to increased staffing, administration and insurance costs associated with West Bakr, along with increased costs associated with acquisitions completed in 2012 (South Alamein and South Mariut).

The increase in stock-based compensation is due partly to an increase in the total value of new options granted during 2012 as compared to those granted during 2011, combined with an increase in the number of options granted and the expense recorded on share appreciation rights in 2012 compared with 2011.

FINANCE COSTS

Finance costs for the year ended December 31, 2012 increased to $13.9 million compared with $5.0 million in 2011. Finance costs include interest on long-term debt and convertible debentures, issue costs on convertible debentures and amortization of transaction costs associated with long-term debt. The overall increase in finance costs is due to higher debt levels associated with the convertible debentures combined with the costs of issuing the convertible debentures.



(000s)	2012		2011
Interest expense	$	8,006	$	3,794
Issue costs for convertible debentures	4,630		—
Amortization of deferred financing costs	1,265		1,189
Finance costs	$	13,901	$	4,983

The Company had $18.5 million ($16.9 million net of unamortized deferred financing costs) of long-term debt outstanding at December 31, 2012 (December 31, 2011 - $60.0 million). The long-term debt that was outstanding at December 31, 2012 bore interest at LIBOR plus an applicable margin that varies from 3.75% to 4.75% depending on the amount drawn under the facility.

In February 2012, the Company sold, on a bought-deal basis, C$97.8 million ($97.9 million) aggregate principal amount of convertible unsecured subordinated debentures with a maturity date of March 31, 2017. Transaction costs of $4.6 million relating to the issuance of the convertible debentures were expensed in the year ended December 31, 2012. The debentures are convertible at any time and from time to time into common shares of the Company at a price of C$15.10 per common share. The debentures are not redeemable by the Company on or before March 31, 2015 other than in limited circumstances in connection with a change of control of TransGlobe. After March 31, 2015 and prior to March 31, 2017, the debentures may be redeemed by the Company at a redemption price equal to the principal amount plus accrued and unpaid interest, provided that the weighted-average trading price of the common shares for the 20 consecutive trading days ending five trading days prior to the date on which notice of redemption is provided is not less than 125 percent of the conversion price (or C$18.88 per common share). Interest of 6% is payable semi-annually in arrears on March 31 and September 30. The first semi-annual interest payment was made on September 30, 2012 which included 39 days prior to March 31, 2012. At maturity or redemption, the Company has the option to settle all or any portion of principal obligations by delivering to the debenture holders sufficient common shares to satisfy these obligations.



2012		11

DEPLETION AND DEPRECIATION (“DD&A”)



	2012		2011
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Egypt	44,442	7.29	31,035	7.97
Yemen	2,095	6.81	3,585	6.72
Corporate	409	—	461	—
	46,946	7.33	35,081	7.92

In Egypt, DD&A decreased 9% on a per Bbl basis in the year ended December 31, 2012 compared to 2011. This decrease is mostly due to proved plus probable reserve additions during the third and fourth quarters of 2012.

In Yemen, DD&A increased 1% on a per Bbl basis in the year ended December 31, 2012 compared to 2011. This increase is mostly due to a smaller reserve base over which capital costs are being depleted compared to 2011.

CAPITAL EXPENDITURES



($000s)	2012	2011
Egypt	50,220	63,177
Yemen	1,239	5,495
Acquisitions	27,259	74,814
Corporate	192	1,447
Total	78,910	144,933

In Egypt, total capital expenditures in 2012 were $50.2 million (2011 - $63.2 million). During 2012, the Company drilled 24 wells in West Gharib (13 at Arta, seven at East Arta, three at Hoshia and one at Fadl). The Company also drilled seven wells at West Bakr and two wells at East Ghazalat. Production was constrained at West Gharib during 2012 due to volume constraints at the processing facility. As a result, the capital cost per well drilled at West Gharib was lower in 2012 as the Company chose not to proceed with the completion and equipping of some of the new wells. The wells are scheduled for completion in 2013, now that some of the production constraints have been removed.

On June 7, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of a wholly-owned subsidiary of EP Energy LLC which holds, through wholly-owned subsidiaries, a non-operated 50% interest in the South Alamein PSC in Egypt and an operated 60% working interest in the South Mariut PSC in Egypt. The transaction was structured as an all-cash deal, effective April 1, 2012, funded through working capital and the proceeds of the issuance of convertible debentures. Total consideration for the transaction was $22.9 million, which represents a $15.0 million base purchase price plus $7.9 million in working capital and other closing adjustments.

On July 26, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of Cepsa Egypt, a wholly-owned subsidiary of Cepsa. Cepsa Egypt holds an operated 50% working interest in the South Alamein PSC in Egypt. As a result, the Company now holds a 100% working interest in the South Alamein concession through two wholly-owned subsidiaries. The Cepsa transaction was structured as an all-cash deal, effective July 1, 2012, funded through working capital. Total consideration for the transaction was $4.5 million, which represents a $3.0 million base purchase price plus $1.5 million in consumable drilling inventory (which is classified as exploration and evaluation assets), working capital and other closing adjustments.



12		2012

FINDING AND DEVELOPMENT COSTS/FINDING, DEVELOPMENT AND NET ACQUISITION COSTS

National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), specifies how finding and development (“F&D”) costs should be calculated. NI 51-101 requires that exploration and development costs incurred in the year along with the change in estimated future development costs be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisitions and dispositions on both reserves and costs. TransGlobe believes that the provisions of NI 51-101 do not fully reflect TransGlobe’s on-going reserve replacement costs. Since acquisitions can have a significant impact on TransGlobe’s annual reserves replacement cost, to not include these amounts could result in an inaccurate portrayal of TransGlobe’s cost structure. Accordingly, TransGlobe has also reported finding, development and acquisition (“FD&A”) costs that will incorporate acquisitions, net of any dispositions during the year.



Proved
($000s, except volumes and $/Bbl amounts)	2012		2011		2010
Total capital expenditure	51,651		70,119		65,342
Acquisitions	27,305		39,497		—
Dispositions	—		—		—
Net change from previous year’s future capital	(4,706	)	(6,165	)	4,776
	74,250		103,451		70,118
Reserve additions and revisions (MBbl)
Exploration and development	10,999		4,672		4,845
Acquisitions, net of dispositions	—		7,448		—
Total reserve additions (MBbl)	10,999		12,120		4,845
Average cost per Bbl
F&D	4.27		13.45		14.47
FD&A	6.75		8.54		14.47
Three-year weighted average cost per Bbl
F&D	8.77		8.76		8.06
FD&A	8.86		7.85		8.10
Note: The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.



Proved Plus Probable
($000s, except volumes and $/Bbl amounts)	2012	2011		2010
Total capital expenditure	51,651	70,119		65,342
Acquisitions	27,305	39,497		—
Dispositions	—	—		—
Net change from previous year’s future capital	1,191	(14,256	)	42,546
	80,147	95,360		107,888
Reserve additions and revisions (MBbl)
Exploration and development	10,888	6,612		9,895
Acquisitions, net of dispositions	—	11,586		—
Total reserve additions (MBbl)	10,888	18,198		9,895
Average cost per Bbl
F&D	4.46	7.07		10.90
FD&A	7.36	5.24		10.90
Three-year weighted average cost per Bbl
F&D	7.42	8.04		8.00
FD&A	7.27	6.79		7.83
Note: The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

RECYCLE RATIO



	Three-Year
Proved	Weighted
	Average	2012	2011	2010
Netback ($/Bbl)*	22.85	22.08	26.24	20.07
Proved F&D costs ($/Bbl)	8.77	4.27	13.45	14.47
Proved FD&A costs ($/Bbl)	8.86	6.75	8.54	14.47
F&D Recycle ratio	2.61	5.17	1.95	1.39
FD&A Recycle ratio	2.58	3.27	3.07	1.39
* Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Bbl of production.



2012		13



	Three-Year
Proved Plus Probable	Weighted
	Average	2012	2011	2010
Netback ($/Bbl)*	22.85	22.08	26.24	20.07
Proved plus Probable F&D costs ($/Bbl)	7.42	4.46	7.07	10.90
Proved plus Probable FD&A costs ($/Bbl)	7.27	7.36	5.24	10.90
F&D Recycle ratio	3.08	4.95	3.71	1.84
FD&A Recycle ratio	3.14	3.00	5.01	1.84
* Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, G&A (excluding non-cash items), realized foreign exchange (gain) loss, cash finance costs and current income tax expense per Bbl of production.

The recycle ratio variances between 2012 and 2011 are driven primarily by changes in F&D and FD&A costs on a per Bbl basis, combined with a reduction in netback per Bbl. In 2011, FD&A costs per Bbl were less than F&D costs per Bbl as a result of the West Bakr acquisition, which added reserves at a cost of $5.47/Bbl on a Proved basis and $4.20/Bbl on a Proved plus Probable basis including future capital costs. The Company completed two acquisitions during 2012, neither of which contributed reserves on a Proved or Proved plus Probable basis. As such, FD&A costs per Bbl are higher than F&D costs per Bbl in 2012.

Due to the nature of international projects, the Company considers the three-year weighted average recycle ratios to provide a more useful measure of the Company's ability to successfully add reserves on an economic basis. The three-year weighted average ratios are consistent with Company expectations and with prior periods.

The recycle ratio measures the efficiency of TransGlobe’s capital program by comparing the cost of finding and developing both proved reserves and proved plus probable reserves with the netback from production. The ratio is calculated by dividing the netback by the proved and proved plus probable finding and development cost on a per Bbl basis.



Recycle Netback Calculation
($000s, except volumes and per Bbl amounts)	2012		2011		2010
Net earnings	87,734		81,392		40,565
Adjustments for non-cash items:
Depletion, depreciation and amortization	46,946		35,081		28,140
Stock-based compensation	4,502		3,062		2,360
Deferred income taxes	(528	)	(4,445	)	1,894
Amortization of deferred financing costs	1,265		1,189		836
Amortization of deferred lease inducement	458		350		—
Unrealized (gain) loss on commodity contracts	125		177		(816	)
Unrealized foreign exchange (gain) loss	(141	)	416		—
Unrealized (gain) loss on financial instruments	425		—		—
Impairment of exploration and evaluation assets	76		12,147		—
Gain on acquisition	—		(13,187	)	—
Recycle netback*	140,862		116,182		72,979
Sales volumes (MBbl)	6,380		4,428		3,635
Recycle netback per Bbl*	22.08		26.24		20.07
* Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Bbl of production.

OUTSTANDING SHARE DATA

As at December 31, 2012, the Company had 73,793,638 common shares issued and outstanding and 5,110,001 options issued and outstanding, which are exercisable in accordance with their terms into a maximum of 5,110,001 common shares of the Company.

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 necessary to maintain and increase production and reserves, to acquire strategic oil and gas assets and to repay debt. TransGlobe’s capital programs are funded principally by cash provided from operating activities. A key measure that TransGlobe uses to evaluate the Company’s overall financial strength is debt-to-funds flow from operations (calculated on a 12-month trailing basis). TransGlobe’s debt-to-funds flow from operations ratio, a key short-term leverage measure, remained strong at 0.8 times at December 31, 2012 (December 31, 2011 - 0.5). This was within the Company’s target range of no more than 2.0 times.



14		2012

The following table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2012 and 2011:



Sources and Uses of Cash
($000s)	2012		2011
Cash sourced
Funds flow from operations*	153,498		119,976
Transfer from restricted cash	1,445		1,161
Issue of convertible debentures	97,851		—
Exercise of options	3,333		1,946
Issuance of common shares, net of share issuance costs	—		71,583
Other	639		772
	256,766		195,438
Cash used
Capital expenditures	51,651		70,118
Deferred financing costs	440		—
Acquisitions	27,259		73,836
Repayment of long-term debt	41,550		30,000
Finance costs	11,367		3,550
Other	592		315
	132,859		177,819
	123,907		17,619
Changes in non-cash working capital	(84,817	)	(31,517	)
Increase (decrease) in cash and cash equivalents	39,090		(13,898	)
Cash and cash equivalents – beginning of year	43,884		57,782
Cash and cash equivalents – end of year	82,974		43,884
* 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.

Funding for the Company’s capital expenditures was provided by funds flow from operations. The Company funded its 2012 exploration and development program of $51.4 million and contractual commitments through the use of working capital and cash generated by operating activities. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks including timely collections of accounts receivable from the Egyptian Government may impact capital resources.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2012, the Company had working capital of $262.2 million (December 31, 2011 - $140.0 million). The increase to working capital in 2012 is due almost entirely to increases in accounts receivable and cash, combined with a decrease in accounts payable. The majority of the Company’s accounts receivable are due from Egyptian General Petroleum Company ("EGPC"), and the recent political changes in the country have increased the Company’s credit risk. The Company is in continual discussions with EGPC and the Egyptian Government to determine solutions to the delayed cash collections, and expects to recover the entire accounts receivable balance in full. During the fourth quarter of 2012, collections of accounts receivable outpaced billings, resulting in a decrease in accounts receivable from Q3-2012 to Q4-2012 of $22.5 million. Subsequent to December 31, 2012, the Company collected $40.5 million of the receivables that were outstanding in Egypt at year end.

In February 2012, the Company sold, on a bought-deal basis, C$97.8 million ($97.9 million) aggregate principal amount of convertible unsecured subordinated debentures with a maturity date of March 31, 2017. Transaction costs of $4.6 million relating to the issuance of the convertible debentures were expensed during the year ended December 31, 2012. The debentures are convertible at any time and from time to time into common shares of the Company at a price of C$15.10 per common share. The debentures are not redeemable by the Company on or before March 31, 2015 other than in limited circumstances in connection with a change of control of TransGlobe. After March 31, 2015 and prior to March 31, 2017, the debentures may be redeemed by the Company at a redemption price equal to the principal amount plus accrued and unpaid interest, provided that the weighted-average trading price of the common shares for the 20 consecutive trading days ending five trading days prior to the date on which notice of redemption is provided is not less than 125 percent of the conversion price (or C$18.88 per common share). Interest of 6% is payable semi-annually in arrears on March 31 and September 30. The first semi-annual interest payment was made on September 30, 2012 which includes 39 days prior to March 31, 2012. At maturity or redemption, the Company has the option to settle all or any portion of principal obligations by delivering to the debenture holders sufficient common shares to satisfy these obligations.

At December 31, 2012, TransGlobe had $71.0 million available under a Borrowing Base Facility of which $18.5 million was drawn. As repayments on the Borrowing Base Facility are not expected to commence until 2014, the entire balance is presented as a long-term liability on the Consolidated Balance Sheets. Repayments will be made as required according to the scheduled reduction of the facility.



($000s)	December 31, 2012		December 31, 2011
Bank debt	18,450		60,000
Deferred financing costs	(1,565	)	(2,391	)
Long–term debt (net of deferred financing costs)	16,885		57,609



2012		15

COMMITMENTS AND CONTINGENCIES

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



($000s)		Payment Due by Period ^{1 2}
	Recognized
	in Financial	Contractual	Less than			More than
	Statements	Cash Flows	1 year	1-3 years	4-5 years	5 years
Accounts payable and accrued liabilities	Yes - Liability	48,587	48,587	—	—	—
Long-term debt	Yes - Liability	18,450	—	18,450	—	—
Convertible debentures	Yes - Liability	98,742	—	—	98,742	—
Office and equipment leases ³	No	14,728	6,819	2,324	2,072	3,513
Minimum work commitments ⁴	No	4,350	4,350	—	—	—
Total		184,857	59,756	20,774	100,814	3,513
¹ Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
² Payments denominated in foreign currencies have been translated at December 31, 2012 exchange rates.
³ Office and equipment leases includes all drilling rig contracts.
⁴ Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

Pursuant to the PSC for Block 75 in Yemen, the Contractor (Joint Interest Partners) has a remaining minimum financial commitment of $3.0 million ($0.8 million to TransGlobe) for one exploration well in the first exploration period, which has been extended to March 9, 2014.

Pursuant to the August 18, 2008 asset purchase agreement for a 25% financial interest in eight development leases on the West Gharib Concession in Egypt, the Company has committed to paying the vendor a success fee to a maximum of $2.0 million if incremental reserve thresholds are reached in the South Rahmi development lease, to be evaluated annually. Based on the Company's annual Reserve Report effective December 31, 2012, no additional fees are due in 2013.

Pursuant to the June 7, 2012 share purchase agreement for a 60% operated interest in the South Mariut concession in Egypt, the Contractor (Joint Interest Partners) has a minimum financial commitment of $9.0 million ($5.4 million to TransGlobe) for three exploration wells ($3.0 million each) which were commitments from the original exploration period and were carried into the first three-year extension period, which expires on April 5, 2013. The Company issued three $3.0 million letters of credit to guarantee performance under this extension period and finished drilling the first of three planned wells subsequent to December 31, 2012 which has reduced the letters of credit to $6.0 million ($3.6 million to TransGlobe). There is a further two-year extension available under the terms of the PSC.

Pursuant to the June 7, 2012 and July 26, 2012 share purchase agreements for a combined 100% operated interest in the South Alamein PSC in Egypt, the Company has a commitment to drill one well (all financial commitments have been met) prior to the termination of the final two-year extension period, which expires on April 5, 2014.

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

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2012.

OFF BALANCE SHEET ARRANGEMENTS

The Company has certain lease arrangements, all of which are reflected in the Commitments and Contingencies table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet as of December 31, 2012.

RISKS

TransGlobe’s results are affected by a variety of business risks and uncertainties in the international petroleum industry including but not limited to:


•	Financial risks including market risks (such as commodity price, foreign exchange and interest rates), credit risks and liquidity risks;


•	Operational risks including capital, operating and reserves replacement risks;


•	Safety, environmental and regulatory risks; and


•	Political risks.

Many of these risks are not within the control of management, but the Company has adopted several strategies to reduce and minimize the effects of these risks:



16		2012

Financial Risk

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

To mitigate these risks, the Company raised C$75.0 million (US$75.6 million), before fees and expenses, in a public offering of common shares that closed on February 1, 2011. The Company also raised C$97.8 million (US$97.9 million), before fees and expenses, through a public sale of convertible debentures. The amount raised was comprised of an original issuance in the amount of C$85.0 million (US$85.0 million) that closed on February 22, 2012, along with an over-allotment option in the amount of C$12.8 million (US$12.9 million) that was exercised by the underwriters and closed on February 29, 2012. The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future funds flows from operations, working capital and availability under existing banking arrangements will be adequate to support these financial liabilities, as well as its capital programs.

The ongoing political instability in Egypt and Yemen could present challenges to the Company if the issues persist over an extended period of time. Continued instability could reduce the Company’s ability to access debt, capital and banking markets. To mitigate potential financial risk factors, management regularly evaluates operational and financial risk strategies and continues to monitor the 2013 capital budget and the Company’s long-term plans. The Company has designed its 2013 budget to be flexible allowing spending to be adjusted for any unforeseen events and changes in commodity prices.

Market Risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The market price movements that the Company is exposed to include oil prices (commodity price risk), foreign currency exchange rates and interest rates, all of which could adversely affect the value of the Company’s financial assets, liabilities and financial results.

Commodity price risk

The Company’s operational results and financial condition are dependent on the commodity prices received for its oil production.

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

Foreign currency exchange risk

As the Company’s business is conducted primarily in U.S. dollars and its financial instruments are primarily denominated in U.S. dollars, the Company’s exposure to foreign currency exchange risk relates to certain cash and cash equivalents, accounts receivable, convertible debentures, accounts payable and accrued liabilities denominated in Canadian dollars and Egyptian pounds. When assessing the potential impact of foreign currency exchange risk, the Company believes 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would result in a decrease in the net earnings for the year ended December 31, 2012 of approximately $10.1 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would increase net earnings by $8.3 million for the same period. The Company does not utilize derivative instruments to manage this risk.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds on an expedited basis, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2012 was $3.7 million in equivalent U.S. dollars.

Interest rate risk

Fluctuations in interest rates could result in a change in the amount the Company pays to service variable-interest, U.S.-dollar-denominated debt. No derivative contracts were entered into during 2012 to mitigate this risk. When assessing interest rate risk applicable to the Company’s variable-interest, U.S.-dollar-denominated debt, the Company believes 1% volatility is a reasonable measure. The effect of interest rates increasing by 1% would decrease the Company’s net earnings by $0.5 million for the year ended December 31, 2012. The effect of interest rates decreasing by 1% would increase the Company’s net earnings by $0.5 million for year ended December 31, 2012.

Credit Risk

Credit risk is the risk of loss if counter-parties do not fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to accounts receivable, the majority of which are in respect of oil operations and derivative commodity contracts. The Company is and may in the future be exposed to third-party credit risk through its contractual arrangements with its current or future joint interest partners, marketers of its petroleum production and other parties, including the governments of Egypt and Yemen. Significant changes in the oil industry, including fluctuations in commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect the Company’s ability to realize the full value of its accounts receivable. The Company currently has, and historically has had, a significant account receivable outstanding from the Government of Egypt. While the Government of Egypt does make payments on these amounts owing, the timing of these payments has historically been longer than normal industry standard. Despite these factors, the Company expects to collect this account receivable in full, although there can be no assurance that this will occur. In the event the Government of Egypt fails to meet its obligations, or other third-party creditors fail to meet their obligations to the Company, such failures could individually or in the aggregate have a material adverse effect on the Company, its cash flow from operating activities and its ability to conduct its ongoing capital expenditure program. The Company has not experienced any material credit loss in the collection of accounts receivable to date.



2012		17

In Egypt, the Company sold all of its 2012 and 2011 production to one purchaser. In Yemen, the Company sold all of its 2012 Block 32 production to one purchaser, and all of its 2011 Block 32 production to another purchaser. Block S-1 production was sold to one purchaser in 2012 and 2011. Management considers such transactions normal for the Company and the international oil industry in which it operates.

Liquidity Risk

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

To mitigate these risks, the Company raised C$75.0 million (US$75.6 million), before fees and expenses, in a public offering that closed on February 1, 2011. The Company also raised C$97.8 million (US$97.9 million), before fees and expenses, through a public sale of convertible debentures in February 2012. The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future funds flows from operations, working capital and availability under existing banking arrangements will be adequate to support these financial liabilities, as well as its capital programs.

Although the Company's Egyptian PSCs clearly state that the Company may transfer funds out of Egypt at its discretion, there is no certainty that in the future exchange controls will not be implemented that would prevent the Company from transferring funds abroad. In Egypt, the Government has imposed monetary and currency exchange control measures that include restrictions on the free disposition of funds deposited with banks and tight restrictions on transferring funds abroad, with certain exceptions for transfers related to foreign trade and other authorized transactions approved by the country's central bank. The Egyptian central bank may require prior authorization and may or may not grant such authorization for the Company's foreign subsidiaries to make dividend payments to the Company and there may be a tax imposed with respect to the expatriation of the proceeds from the Company's foreign subsidiaries.

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

Operational Risk

The Company’s future success largely depends on its ability to exploit its current reserve base and to find, develop or acquire additional oil reserves that are economically recoverable. Failure to acquire, discover or develop these additional reserves will have an impact on cash flows of the Company.

Third parties operate some of the assets in which TransGlobe has interests. As a result, TransGlobe may have limited ability to exercise influence over the operations of these assets and their associated costs. The success and timing of these activities may be outside of the Company’s control.

To mitigate these operational risks, as part of its capital approval process, the Company applies rigorous geological, geophysical and engineering analysis to each prospect. The Company utilizes its in-house expertise for all international ventures or employs and contracts professionals to handle each aspect of the Company’s business. The Company retains independent reserve evaluators to determine year-end Company reserves and estimated future net revenues.

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

Safety, Environmental and Regulatory Risk

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

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

Political Risk

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

While the recent civil unrest in Egypt and Yemen has created uncertainty regarding the Company's political risk, management believes that the Company is well positioned to adapt to this situation due to its increasing production, manageable debt levels, positive cash generation from operations and the availability of cash and cash equivalents. However, if the political issues in Egypt and Yemen continue for an extended period of time, the Company may be forced to reduce its capital spending including drilling and/or completing fewer wells than anticipated, which will have a negative effect on current and future production volumes and cash flows.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with IFRS requires that management make appropriate decisions with respect to the selection of accounting policies and in formulating estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses.



18		2012

The following is included in the MD&A to aid the reader in assessing the critical accounting policies and practices of the Company. The information will also aid in assessing the likelihood of materially different results being reported depending on management's assumptions and changes in

prevailing conditions which affect the application of these policies and practices. Significant accounting policies are disclosed in Note 3 of the Consolidated Financial Statements.

Oil and Gas Reserves

TransGlobe's Proved and Probable oil and gas reserves are 100% evaluated and reported on by independent reserve evaluators to the Reserves Committee comprised of independent directors. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts.

Property and equipment and intangible exploration and evaluation assets

Recognition and measurement

Exploration and evaluation ("E&E") costs related to each license/prospect are initially capitalized within "intangible exploration and evaluation assets." Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable expenses, including remuneration of production personnel and supervisory management, and the projected costs of retiring the assets (if any), but do not include pre-licensing costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to earnings as incurred and presented as exploration expenses on the Consolidated Statements of Earnings and Comprehensive Income.

Tangible assets acquired for use in E&E activities are classified as other assets; however, to the extent that such a tangible asset is consumed in developing an intangible exploration asset, the amount reflecting that consumption is recorded as part of the cost of the intangible exploration and evaluation asset.

Intangible exploration and evaluation assets are not depleted. They are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. The technical feasibility and commercial viability is considered to be determined when proved and/or probable reserves are determined to exist or they can be empirically supported with actual production data or conclusive formation tests. A review of each cash generating unit is carried out at least annually. Intangible exploration and evaluation assets are transferred to petroleum properties as development and production ("D&P") assets upon determination of technical feasibility and commercial viability.

Petroleum properties and other assets are measured at cost less accumulated depletion, depreciation, and amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, including qualifying E&E costs on reclassification from intangible exploration and evaluation assets, and for qualifying assets, where applicable, borrowing costs. When significant parts of an item of property and equipment have different useful lives, they are accounted for as separate items.

Gains and losses on disposal of items of property and equipment are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in earnings immediately.

Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property and equipment are recognized as petroleum properties or other assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in earnings as incurred. Such capitalized property and equipment generally represent costs incurred in developing Proved and/or Probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis.

The carrying amount of any replaced or sold component is derecognized.

Depletion, depreciation and amortization

The depletion, depreciation and amortization of petroleum properties and other assets, and any eventual reversal thereof, are recognized in earnings.

The net carrying value of D&P assets included in petroleum properties is depleted using the unit of production method by reference to the ratio of production in the year to the related proved and probable reserves using estimated future prices and costs. Costs subject to depletion include estimated future development costs necessary to bring those reserves into production. These estimates are reviewed by independent reserve engineers at least annually.

Proved and probable reserves are estimated using independent reserve evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially viable. The specified degree of certainty must be a minimum 90% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and a minimum 50% statistical probability for proved and probable reserves to be considered commercially viable.

Furniture and fixtures are depreciated at declining balance rates of 20% to 30%, whereas vehicles and leasehold improvements are depreciated on a straight-line basis over their estimated useful lives.

Depreciation methods, useful lives and residual values are reviewed at each reporting date.



2012		19

Production Sharing Concessions

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

Financial Instruments

Non-derivative financial instruments

Non-derivative financial instruments comprise investment in cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, convertible debentures payable and long-term debt. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition non-derivative financial instruments are measured as described below.

Financial assets at fair value through profit or loss

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition, such as cash and cash equivalents and convertible debentures payable. Financial instruments are designated at fair value through profit or loss if the Company makes purchase and sale decisions based on their fair value in accordance with the Company's documented risk management strategy. Upon initial recognition, any transaction costs attributable to the financial instruments are recognized through earnings when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in earnings.

Other

Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities, and long-term debt are measured initially at fair value, then at amortized cost using the effective interest method, less any impairment losses.

Derivative financial instruments

The Company enters into certain financial derivative contracts from time to time in order to reduce its exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, the Company's policy is to classify all financial derivative contracts as at fair value through profit or loss and to record on the Consolidated Balance Sheet at fair value. Attributable transaction costs are recognized in earnings when incurred. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not measured at fair value through profit or loss. Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.

CHANGES IN ACCOUNTING POLICIES

New accounting policies

IFRS 7 (revised) "Financial Instruments: Disclosures"

In October 2010, the International Accounting Standards Board ("IASB") issued amendments to IFRS 7 to provide additional disclosure on the transfer of financial assets including the possible effects of any residual risks that the transferring entity retains. These amendments are effective for annual periods beginning after July 1, 2011. In December 2011, the IASB issued further amendments to IFRS 7 to provide additional disclosures about offsetting financial assets and financial liabilities on the entity's balance sheet when permitted. These amendments are effective for annual periods beginning on or after January 1, 2013. The Company has adopted these amendments for the year ended December 31, 2012. These amendments had no material impact to the Consolidated Financial Statements.

IAS 12 (revised) “Income Taxes”

In December 2010, the IASB issued amendments to IAS 12 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset. The amendments introduce a presumption that entities will assess whether the carrying value of an asset will be recovered through the sale of the asset. These amendments are effective for annual periods beginning on or after January 1, 2012; therefore, the Company has adopted them for the year ended December 31, 2012. These amendments had no material impact on the Consolidated Financial Statements.

Future changes to accounting policies

As at the date of authorization of the Consolidated Financial Statements the following Standards and Interpretations which have not yet been applied in the Consolidated Financial Statements have been issued but are not yet effective:



20		2012

IFRS 9 (revised) "Financial Instruments: Classification and Measurement"

In November 2009, the IASB issued IFRS 9 as part of its project to replace IAS 39, "Financial Instruments: Recognition and Measurement". In October 2010, the IASB updated IFRS 9 to include the requirements for financial liabilities. IFRS 9 replaces the multiple rules in IAS 39 with a single approach to determine whether a financial asset is measured at amortized cost or fair value. The approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. IFRS 9 is effective for annual periods beginning on or after January 1, 2015. The Company is currently evaluating the impact of this standard on its Consolidated Financial Statements.

IFRS 10 (new) "Consolidated Financial Statements"

In May 2011, the IASB issued IFRS 10 to replace SIC-12, "Consolidation - Special Purpose Entities", and parts of IAS 27, "Consolidated and Separate Financial Statements". IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 is effective for annual periods beginning on or after January 1, 2013. The Company does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IFRS 11 (new) "Joint Arrangements"

In May 2011, the IASB issued IFRS 11 to replace IAS 31, "Interests in Joint Ventures", and SIC-13, "Jointly Controlled Entities - Non-monetary Contributions by Venturers". IFRS 11 requires entities to follow the substance rather than legal form of a joint arrangement and removes the choice of accounting method. IFRS 11 is effective for annual periods beginning on or after January 1, 2013. The Company does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IFRS 12 (new) "Disclosure of Interests in Other Entities"

In May 2011, the IASB issued IFRS 12, which aggregates and amends disclosure requirements included within other standards. IFRS 12 requires entities to provide disclosures about subsidiaries, joint arrangements, associates and unconsolidated structured entities. IFRS 12 is effective for annual periods beginning on or after January 1, 2013. The Company does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IFRS 13 (new) "Fair Value Measurement"

In May 2011, the IASB issued IFRS 13 to clarify the definition of fair value and provide guidance on determining fair value. IFRS 13 amends disclosure requirements included within other standards and establishes a single framework for fair value measurement and disclosure. IFRS 13 is effective for annual periods beginning on or after January 1, 2013. The Company does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IAS 1 (revised) “Presentation of Financial Statements”

In June 2011, the IASB issued amendments to IAS 1 to require separate presentation for items of other comprehensive income that would be reclassified to profit or loss in the future from those that would not. These amendments are effective for annual periods beginning on or after July 1, 2012. The Company does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IAS 19 (revised) “Employee Benefits”

In June 2011, the IASB issued amendments to IAS 19 to revise certain aspects of the accounting for pension plans and other benefits. The amendments eliminate the corridor method of accounting for defined benefit plans, change the recognition pattern of gains and losses, and require additional disclosures. These amendments are effective for annual periods beginning on or after January 1, 2013. The Company does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IAS 28 (revised) “Investments in Associates and Joint Ventures”

In May 2011, the IASB issued amendments to IAS 28 to prescribe the accounting for investments in associates and set out the requirements for applying the equity method when accounting for investments in associates and joint ventures. These amendments are effective for annual periods beginning on or after January 1, 2013. The Company does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IAS 32 (revised) “Financial Instruments: Presentation”

In December 2011, the IASB issued amendments to IAS 32 to address inconsistencies when applying the offsetting criteria. These amendments clarify some of the criteria required to be met in order to permit the offsetting of financial assets and financial liabilities. These amendments are effective for annual periods beginning on or after January 1, 2014. The Company is currently evaluating the impact of these amendments to its Consolidated Financial Statements.

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2012, an evaluation was carried out under the supervision, and with the participation of the Company's management, including the Chief Executive Officer and Chief Financial Officer, on the effectiveness of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the fiscal year, the design and operation of these disclosure controls and procedures were effective to ensure that all information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.



2012		21

INTERNAL CONTROLS OVER FINANCIAL REPORTING

TransGlobe's management designed and implemented internal controls over financial reporting, as defined under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, of the Canadian Securities Administrators and as defined in Rule 13a-15 under the US Securities Exchange Act of 1934. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS, focusing in particular on controls over information contained in the annual and interim financial statements. Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company's internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission framework on Internal Control - Integrated Framework. Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as at December 31, 2012. No changes were made to the Company's internal control over financial reporting during the year ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.



22		2012

MANAGEMENT'S REPORT

Management’s Responsibility on Financial Statements

The consolidated financial statements of TransGlobe Energy Corporation were prepared by management within acceptable limits of materiality and are in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Management is responsible for ensuring that the financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements.

The consolidated financial statements have been prepared by management in accordance with the accounting policies as described in the notes to the consolidated financial statements. Timely release of financial information sometimes necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. When necessary, such estimates are based on informed judgments made by management.

To ensure the integrity of the consolidated financial statements, we carefully select and train qualified personnel. We also ensure our organizational structure provides appropriate delegation of authority and division of responsibilities. Our policies and procedures are communicated throughout the organization and include a written Code of Conduct that applies to all employees, including the Chief Executive Officer and Chief Financial Officer.

Deloitte LLP, an independent firm of registered Chartered Accountants appointed by the shareholders, have conducted an examination of the corporate and accounting records in order to express their opinion on the consolidated financial statements. The Audit Committee, consisting of five independent directors, has met with representatives of Deloitte LLP and management in order to determine if management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The Board of Directors has approved the consolidated financial statements.

Management’s Report On Internal Control Over Financial Reporting

Management has designed and maintains an appropriate system of internal controls to provide reasonable assurance that all assets are safeguarded and financial records are properly maintained to facilitate the preparation of consolidated financial statements for reporting purposes. Management’s evaluation concluded that the internal control over financial reporting was effective as of December 31, 2012.



Signed by:

“Ross G. Clarkson”	“Randy C. Neely”

Ross G. Clarkson	Randy C. Neely
President & Chief Executive Officer	Vice President, Finance & Chief Financial Officer

March 5, 2013



2012		23

REPORT OF THE INDEPENDENT REGISTERED ACCOUNTANTS

To the Board of Directors and Shareholders of TransGlobe Energy Corporation

We have audited the accompanying consolidated financial statements of TransGlobe Energy Corporation and subsidiaries, which comprise the consolidated balance sheets as at December 31, 2012 and December 31, 2011, and the consolidated statements of earnings and comprehensive income, statements of changes in shareholders’ equity and statements of cash flows for the years ended December 31, 2012 and December 31, 2011, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of TransGlobe Energy Corporation and subsidiaries as at December 31, 2012 and December 31, 2011, and their financial performance and cash flows for the years ended December 31, 2012 and December 31, 2011 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matters

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as at December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 5, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

Independent Registered Chartered Accountants

March 5, 2013

Calgary, Canada



24		2012

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Shareholders of TransGlobe Energy Corporation

We have audited the internal control over financial reporting of TransGlobe Energy Corporation and subsidiaries (the “Company”) as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as at and for the year ended December 31, 2012 of the Company and our report dated March 5, 2013 expressed an unqualified opinion on those financial statements.

Independent Registered Chartered Accountants

March 5, 2013

Calgary, Canada



2012		25

Consolidated Statements of Earnings and Comprehensive Income

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



	Notes	2012			2011
REVENUE
Oil sales, net of royalties	6	$	317,666		$	247,754
Derivative gain (loss) on commodity contracts		(125		)	(807		)
Finance revenue	7	452			467
		317,993			247,414

EXPENSES
Production and operating		52,367			36,662
General and administrative	20, 23	28,206			18,893
Foreign exchange (gain) loss		(105		)	310
Finance costs	7	13,901			4,983
Exploration		368			1,561
Depletion, depreciation and amortization	13	46,946			35,081
Unrealized (gain) loss on financial instruments	17	425			—
Impairment of exploration and evaluation assets	12	76			12,147
Gain on acquisition	4	—			(13,187		)
		142,184			96,450

Earnings before income taxes		175,809			150,964

Income tax expense (recovery) – current	11	88,603			74,017
– deferred	11	(528		)	(4,445		)
		88,075			69,572
NET EARNINGS AND COMPREHENSIVE INCOME FOR THE YEAR		$	87,734		$	81,392

Earnings per share	21
Basic		$	1.20		$	1.12
Diluted		$	1.16		$	1.09

See accompanying notes to the Consolidated Financial Statements.



26		2012

Consolidated Balance Sheets

(Expressed in thousands of U.S. Dollars)



		As at		As at
	Notes	December 31, 2012		December 31, 2011
ASSETS
Current
Cash and cash equivalents	8	$	82,974	$	43,884
Accounts receivable	9	221,017		162,225
Derivative commodity contracts		—		125
Prepaids and other		6,813		7,441
		310,804		213,675
Non-Current
Restricted cash	10	782		2,226
Intangible exploration and evaluation assets	12	48,414		17,453
Property and equipment
Petroleum properties	13	280,895		280,524
Other assets	13	4,350		3,748
Goodwill	14	8,180		8,180
		$	653,425	$	525,806

LIABILITIES
Current
Accounts payable and accrued liabilities	15	$	48,587	$	73,692
		48,587		73,692
Non-Current
Long-term debt	16	16,885		57,609
Convertible debentures	17	98,742		—
Deferred taxes	11	52,363		52,891
Other long-term liabilities		988		1,122
		217,565		185,314

SHAREHOLDERS’ EQUITY
Share capital	19	158,721		154,263
Contributed surplus		11,714		8,538
Retained earnings		265,425		177,691
		435,860		340,492
		$	653,425	$	525,806

See accompanying notes to the Consolidated Financial Statements.

Approved on behalf of the Board:

Signed by:



“Ross G. Clarkson”	“Fred J. Dyment”

Ross G. Clarkson	Fred J. Dyment
President and CEO,	Director
Director



2012		27

Consolidated Statement of Changes in Shareholders’ Equity

(Expressed in thousands of U.S. Dollars)



	Notes	2012			2011

Share Capital
Balance, beginning of year		$	154,263		$	80,106
Stock options exercised	19	3,333			1,946
Share issuance	19	—			75,594
Share issue costs	19	—			(4,011		)
Transfer from contributed surplus on exercise of options	19	1,125			628
Balance, end of year		$	158,721		$	154,263

Contributed Surplus
Balance, beginning of year		$	8,538		$	5,785
Share-based compensation expense	20	4,301			3,381
Transfer to share capital on exercise of options		(1,125		)	(628		)
Balance, end of year		$	11,714		$	8,538

Retained Earnings
Balance, beginning of year		$	177,691		$	96,299
Net earnings and total comprehensive income		87,734			81,392
Balance, end of year		$	265,425		$	177,691

See accompanying notes to the Consolidated Financial Statements.



28		2012

Consolidated Statements of Cash Flows

(Expressed in thousands of U.S. Dollars)



		Year Ended			Year Ended
	Notes	December 31, 2012			December 31, 2011
CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:

OPERATING
Net earnings for the year		$	87,734		$	81,392
Adjustments for:
Depletion, depreciation and amortization	13	46,946			35,081
Deferred lease inducement		458			350
Impairment of exploration and evaluation costs	12	76			12,147
Stock-based compensation	20	4,502			3,062
Finance costs	7	13,901			4,983
Income tax expense		88,075			69,572
Gain on acquisition		—			(13,187		)
Unrealized (gain) loss on commodity contracts		125			177
Unrealized (gain) loss on financial instruments		425			—
Unrealized (gain) loss on foreign currency translation		(141		)	416
Income taxes paid		(88,603		)	(74,017		)
Changes in non-cash working capital	25	(59,506		)	(56,346		)
Net cash generated by (used in) operating activities		93,992			63,630

INVESTING
Additions to intangible exploration and evaluation assets	12	(5,384		)	(6,991		)
Additions to petroleum properties	13	(45,386		)	(61,266		)
Additions to other assets	13	(881		)	(1,861		)
Business acquisitions	4	(27,259		)	(73,836		)
Changes in restricted cash		1,445			1,161
Changes in non-cash working capital	25	(25,311		)	24,690
Net cash generated by (used in) investing activities		(102,776		)	(118,103		)

FINANCING
Issue of common shares for cash	19	3,333			77,540
Issue costs for common shares	19	—			(4,011		)
Financing costs		(440		)	—
Interest paid		(6,737		)	(3,550		)
Issue of convertible debentures	17	97,851			—
Issue costs for convertible debentures	17	(4,630		)	—
Repayments of long-term debt		(41,550		)	(30,000		)
Increase (decrease) in other long-term liabilities		(592		)	772
Changes in non-cash working capital	25	—			139
Net cash generated by (used in) financing activities		47,235			40,890
Currency translation differences relating to cash and cash equivalents		639			(315		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		39,090			(13,898		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		43,884			57,782
CASH AND CASH EQUIVALENTS, END OF YEAR		$	82,974		$	43,884

See accompanying notes to the Consolidated Financial Statements.



2012		29

As at December 31, 2012 and December 31, 2011 and for the years then ended

(Expressed in U.S. Dollars)

1. CORPORATE INFORMATION

TransGlobe Energy Corporation is a publicly listed company incorporated in Alberta, Canada and its shares are listed on the Toronto Stock Exchange (“TSX”) and NASDAQ Exchange (“NASDAQ”). The address of its registered office is 2300, 250 – 5th Street SW, Calgary, Alberta, Canada, T2P 0R4. TransGlobe Energy Corporation together with its subsidiaries (“TransGlobe” or the “Company”) is engaged primarily in oil exploration, development and production and the acquisition of properties.

2. BASIS OF PREPARATION

Statement of compliance

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board effective as of December 31, 2012.

These Consolidated Financial Statements were authorized for issue by the Board of Directors on March 5, 2013.

Basis of measurement

The accounting policies used in the preparation of these Consolidated Financial Statements are described in Note 3, Significant Accounting Policies.

The Company prepared these Consolidated Financial Statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due. Accordingly, these Consolidated Financial Statements have been prepared on a historical cost basis, except for cash and cash equivalents, derivative commodity contracts and convertible debentures that have been measured at fair value. The method used to measure fair value is discussed further in Notes 3 and 5.

Functional and presentation currency

In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are presented and expressed in United States (U.S.) dollars, which is the Company’s functional currency. All references to $ are to United States dollars and references to C$ are to Canadian dollars and all values are rounded to the nearest thousand except when otherwise indicated.

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these Consolidated Financial Statements.

Basis of consolidation

Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity, it is exposed to or has rights to variable returns associated with its involvement in the entity, and it has the ability to use that power to influence the amount of returns it is exposed to or has rights to. In assessing control, potential voting rights that currently are exercisable are taken into account. The Consolidated Financial Statements include the financial statements of the Company and its controlled subsidiaries.

The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

All intra-company transactions, balances, income and expenses, unrealized gains and losses are eliminated on consolidation.

Joint Interests

The Company conducts many of its oil and gas production activities through jointly controlled assets and the Consolidated Financial Statements reflect only the Company's proportionate interest in such activities.

Foreign currency translation

The Consolidated Financial Statements are presented in U.S. dollars. The Company's reporting and functional currency is the U.S. dollar as this is the principal currency of the primary economic environment the entity operates in and is normally the one in which it primarily generates and expends cash. Transactions in foreign currencies are translated to the functional currency of the Company at exchange rates at the dates of the transactions.

Monetary assets and liabilities denominated in foreign currencies at the reporting date are re-translated to the functional currency at the exchange rate at that date. The foreign currency gain or loss on monetary items is the difference between its functional currency equivalent at the beginning of the period or when the transaction was entered into if it occurred during the period and the functional currency equivalent translated at the exchange rate at the end of the period.

Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are translated to the functional currency at the exchange rate at the date that the fair value was determined. The foreign currency gain or loss on non-monetary items is the difference in fair value measured in the functional currency between measurement dates.



30		2012

Use of estimates and judgments

Timely preparation of the financial statements in conformity with IFRS as issued by the International Accounting Standards Board requires that management make estimates and assumptions and use judgments that affect the application of accounting policies and the reported amounts of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. The effect of these estimates, assumptions and the use of judgments are explained throughout the notes to the Consolidated Financial Statements. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.

The key sources of estimation uncertainty that have a significant risk of causing material adjustment to the carrying amounts of assets and liabilities are discussed below.

Recoverability of asset carrying values

The recoverability of development and production asset carrying values are assessed at the cash-generating unit ("CGU") level. Determination of what constitutes a CGU is subject to management judgments. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of the Company's petroleum properties, each CGU's carrying value is compared to its recoverable amount, defined as the greater of its fair value less costs to sell and value-in-use. As at December 31, 2012 and December 31, 2011, the recoverable amounts of the Company's CGU's were estimated as their fair value less costs to sell based on the net present value of the after-tax cash flows from the oil reserves of each CGU based on reserves estimated by the Company's independent reserve evaluator.

Key input estimates used in the determination of cash flows from oil reserves include the following:


•	Reserves - Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may result in reserves being restated.


•	Oil prices - The cash flow model uses forward oil price estimates. Commodity prices have fluctuated significantly in recent years, and the forward price estimates used in the cash flow model may not align with actual future oil prices.


•	Discount rate - The discount rate used to determine the net present value of future cash flows is based on the Company's estimated weighted average cost of capital. Changes in the economic environment could change the Company's weighted average cost of capital.

Impairment tests were carried out at December 31, 2012 and were based on fair value less costs to sell calculations, using a discount rate of 15% on future after-tax cash flows and the following forward oil price estimates per the independent reserve evaluator:



	Egypt	Yemen
	Oil	Oil
Year	$/Bbl	$/Bbl
2013	97.76	107.50
2014	95.04	105.83
2015	92.64	103.41
2016	94.40	105.72
2017	93.03	104.63
Thereafter*	2.0%	2.0%
* Percentage change represents the increase in each year after 2017 to the end of the reserve life.

Depletion of petroleum properties

Depletion of petroleum properties is calculated based on total Proved plus Probable reserves as well as estimated future development costs associated with these reserves as determined by the Company's independent reserve evaluator. See above for discussion of estimates and judgments involved in reserve estimation.

Income taxes

The measurement of income tax expense, and the related provisions on the Consolidated Balance Sheets, is subject to uncertainty associated with future recoverability of oil reserves, commodity prices, the timing of future events and changes in legislation, tax rates and interpretations by tax authorities.

Financial instruments

The fair values of financial instruments are estimated based upon market and third party inputs. These estimates are subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance risk.

Share-based payments

The fair value estimates of equity-settled and cash-settled share-based payment awards depend on certain assumptions including share price volatility, risk free interest rate, the term of the awards, and the forfeiture rate which, by their nature, are subject to measurement uncertainty.



2012		31

Cash equivalents

Cash equivalents includes short-term, highly liquid investments that mature within three months of the date of their purchase.

Financial instruments

Non-derivative financial instruments

Non-derivative financial instruments comprise investment in cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, convertible debentures and long-term debt. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition non-derivative financial instruments are measured as described below.

Financial assets and liabilities at fair value through profit or loss

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition, such as cash and cash equivalents and convertible debentures. Financial instruments are designated at fair value through profit or loss if the Company makes purchase and sale decisions based on their fair value in accordance with the Company's documented risk management strategy. Upon initial recognition, any transaction costs attributable to the financial instruments are recognized through earnings when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in earnings.

Other

Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities, restricted cash and long-term debt are measured initially at fair value, then at amortized cost using the effective interest method, less any impairment losses.

Derivative financial instruments

Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity.

Property and equipment and intangible exploration and evaluation assets

Recognition and measurement

Exploration and evaluation ("E&E") costs related to each license/prospect are initially capitalized within "intangible exploration and evaluation assets." Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable expenses, including remuneration of production personnel and supervisory management, and the projected costs of retiring the assets (if any), but do not include pre-licensing costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to earnings as they are incurred and presented as exploration expenses on the Consolidated Statements of Earnings and Comprehensive Income.

Intangible exploration and evaluation assets are not depleted. They are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. The technical feasibility and commercial viability is considered to be determined when proved and/or probable reserves are determined to exist or they can be empirically supported with actual production data or conclusive formation tests. A review of each CGU is carried out at least annually. Intangible exploration and evaluation assets are transferred to petroleum properties as development and production ("D&P") assets upon determination of technical feasibility and commercial viability. The intangible E&E assets being transferred to D&P assets are subject to impairment testing upon transfer.



32		2012

Subsequent costs

The carrying amount of any replaced or sold component is derecognized.

Depletion, depreciation and amortization

The depletion, depreciation and amortization of petroleum properties and other assets are recognized in earnings.

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

Goodwill

Goodwill arises on the acquisition of businesses.

Recognition and measurement

Goodwill represents the excess of the cost of the acquisition over the Company’s interest in the net fair value of the identifiable assets, liabilities and contingent liabilities of the acquiree. When the excess is negative, it is recognized immediately in earnings.

Subsequent measurement

Goodwill is measured at cost less accumulated impairment losses.

Goodwill is not amortized but instead tested for impairment annually, or at any time there are indications of impairment.

Impairment

Financial assets carried at amortized cost

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of the asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in profit or loss. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. Any such reversal is recognized in profit or loss.

Non-financial assets

The carrying amounts of the Company’s non-financial assets are reviewed at each reporting date to determine whether there is any indication of impairment, except for E&E assets and goodwill, which are reviewed when circumstances indicate impairment may exist and at least annually, as discussed in more detail below. If any such indication exists, then the asset’s recoverable amount is estimated.

For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the cash-generating unit or “CGU”). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. The Company’s CGU’s are not larger than a segment. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.



2012		33

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the CGUs and then to reduce the carrying amounts of the other assets in the CGUs on a pro-rata basis.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

For goodwill, the recoverable amount is estimated each year on December 31. An impairment loss in respect of goodwill is calculated by reference to the recoverable amount determined at that time. Costs of exploring for and evaluating petroleum properties are capitalized and the resulting intangible E&E assets are tested for impairment by reference to CGU’s. E&E assets are assessed for impairment when they are reclassified to petroleum properties and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. Any resulting impairment loss is recognized through earnings.

The goodwill acquired in a business combination, for the purpose of impairment testing, is allocated to CGU’s that are expected to benefit from the synergies of the combination. E&E assets are allocated to the CGU’s when they are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to D&P assets (petroleum properties).

An impairment loss in respect of goodwill is not reversed.

Share-based payment transactions

Equity-settled transactions

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which equity instruments are granted and is recognized as an expense over the vesting period, which ends on the date on which the relevant employees become fully entitled to the award. Fair value is determined by using the lattice-based binomial option pricing model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Awards where vesting is conditional upon a market condition are treated as vesting regardless of whether the market condition is satisfied as long as all other conditions are satisfied. An estimated forfeiture rate is taken into consideration when assigning a fair value to options granted such that no expense is recognized for awards that do not ultimately vest.

At each financial reporting date before vesting, the cumulative expense is calculated; representing the extent to which the vesting period has expired and management’s best estimate of the number of equity instruments that will ultimately vest. The movement in cumulative expense since the previous financial reporting date is recognized in earnings, with a corresponding entry in equity.

When the terms of an equity-settled award are modified or a new award is designated as replacing a cancelled or settled award, the cost based on the original award terms continues to be recognized over the remainder of the new vesting period for the incremental fair value of any modification, based on the difference between the fair value of the original award and the fair value of the modified award, both as measured on the date of the modification. No reduction is recognized if this difference is negative.

Cash-settled transactions

The cost of cash-settled transactions is measured at fair value using the lattice-based binomial pricing model and recognized as an expense over the vesting period, with a corresponding liability recognized on the balance sheet.

The grant date fair value of options granted to employees is recognized as compensation expense, within general and administrative expenses, with a corresponding increase in accounts payable and accrued liabilities, over the period that the employees become unconditionally entitled to the options. The amount recognized as an expense is adjusted to reflect the actual number of share options for which the related service and non-market vesting conditions are met. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized through profit or loss.

Provisions

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

Revenue recognition

Revenues associated with the sales of the Company's crude oil are recognized by reference to actual volumes produced and quoted market prices in active markets for identical assets, adjusted according to specific terms and conditions as applicable, when the significant risks and rewards of ownership have been transferred, which is when title passes from the Company to its customer. Crude oil produced and sold by the Company below or above its working interest share in the related resource properties results in production under-liftings or over-liftings. Under-liftings are recorded as inventory and over-liftings are recorded as deferred revenue.



34		2012

Pursuant to the PSCs associated with the Company's operations, the Company and other non-governmental partners (if applicable) pay all operating and capital costs for exploration and development. Each PSC establishes specific terms for the Company to recover these costs (Cost Recovery Oil) and to share in the production sharing oil. Cost Recovery Oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each fiscal year. Production sharing oil is that portion of production remaining after Cost Recovery Oil and is shared between the joint interest partners and the government of each country, varying with the level of production. Production sharing oil that is attributable to the government includes an amount in respect of all income taxes payable by the Company under the laws of the respective country. Revenue represents the Company's share and is recorded net of royalty payments to the respective government. For the Company's international operations, all government interests, except for income taxes, are considered royalty payments. The Company's revenue also includes the recovery of costs paid on behalf of foreign governments in international locations.

Finance revenue and costs

Finance revenue comprises interest income on funds invested. Interest income is recognized as it accrues in earnings, using the effective interest method.

Finance costs comprises interest expense on borrowings, negative changes in the fair value of certain financial assets or liabilities measured at fair value through profit or loss, and impairment losses recognized on financial assets.

Borrowing costs incurred for qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. Qualifying assets are those that necessarily take a substantial period of time to get ready for their intended use or sale. All other borrowing costs are recognized in earnings using the effective interest method.

Foreign currency gains and losses, reported under finance revenue and costs, are reported on a net basis.

Income tax

The Company's contractual arrangements in foreign jurisdictions stipulate that income taxes are paid by the respective government out of its entitlement share of production sharing oil. Such amounts are included in current income tax expense at the statutory rate in effect at the time of production.

The Company determines the amount of deferred income tax assets and liabilities based on the difference between the carrying amounts of the assets and liabilities reported for financial accounting purposes from those reported for tax. Deferred income tax assets and liabilities are measured using the substantively enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. Deferred income tax assets associated with unused tax losses are recognized to the extent it is probable the Company will have sufficient future taxable earnings available against which the unused tax losses can be utilized.

Business combinations

Business combinations are accounted for using the acquisition method as at the acquisition date, which is the date on which control is transferred to the Company. Control is the power to govern the financial and operating policies of an entity so as to obtain the benefits from its activities. In assessing control, the Company takes into consideration potential voting rights that currently are exercisable. Judgment is applied in determining the acquisition date and determining whether control is transferred from one party to another.

The Company measures goodwill at the acquisition date as:


•	the fair value of the consideration transferred; plus


•	the recognized amount of any non-controlling interests in the acquiree; plus


•	if the business combination has been achieved in stages, the fair value of the existing equity interest in the acquiree; less


•	the net recognized amount (generally fair value) of the identifiable assets acquired and liabilities assumed.

When the excess is negative, a bargain purchase gain is recorded immediately in earnings.

Consideration transferred includes the fair values of the assets transferred, liabilities incurred by the Company to the previous owners of the acquiree, and equity interests issued by the Company.

New accounting policies

IFRS 7 (revised) "Financial Instruments: Disclosures"



2012		35

IAS 12 (revised) “Income Taxes”

Future changes to accounting policies

As at the date of authorization of these Consolidated Financial Statements the following Standards and Interpretations which have not yet been applied in these Consolidated Financial Statements have been issued but are not yet effective:

IFRS 9 (revised) "Financial Instruments: Classification and Measurement"

IFRS 10 (new) "Consolidated Financial Statements"

IFRS 11 (new) "Joint Arrangements"

IFRS 12 (new) "Disclosure of Interests in Other Entities"

IFRS 13 (new) "Fair Value Measurement"

IAS 1 (revised) “Presentation of Financial Statements”

IAS 19 (revised) “Employee Benefits”

IAS 28 (revised) “Investments in Associates and Joint Ventures”



36		2012

IAS 32 (revised) “Financial Instruments: Presentation”

4. BUSINESS COMBINATIONS

Cepsa Egypt SA B.V.

This acquisition was accounted for using the acquisition method. The Company consolidated the underlying assets acquired and liabilities assumed as at the acquisition date.

The estimated fair values assigned to the assets acquired and liabilities assumed were based on internal estimates. The consideration paid was equal to the fair values of the net identifiable assets acquired and as a result there was no goodwill or bargain purchase gain recognized on acquisition.

The consideration paid and fair values of the identifiable assets acquired and liabilities assumed by the Company are as follows:



Fair value of net assets acquired (000s)
Property and equipment – intangible exploration and evaluation assets	$	4,235
Property and equipment – other assets	279
Working capital	30
Total cost of acquisition	$	4,544

The fair value of the acquired working capital approximates its carrying value due to its short-term nature.

The Consolidated Financial Statements include the results of operations, working capital and other adjustments recorded for the 158 days remaining in the period ended December 31, 2012 after closing. The business acquired contributed an after-tax loss of $0.7 million to the Consolidated Statement of Earnings and Comprehensive Income for the year ended December 31, 2012, and contributed no revenue since it does not currently have production or sales. Had the transaction closed on January 1, 2012, the incremental after-tax loss reported by the Company is estimated to have been $2.4 million for the year ended December 31, 2012.

Costs related to the acquisition in the amount of $0.1 million were expensed as incurred in 2012 and included in general and administrative expenses in the Consolidated Statement of Earnings and Comprehensive Income.

EP Energy LLC

On June 7, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of a wholly-owned subsidiary of EP Energy LLC, which holds, through wholly-owned subsidiaries, a non-operated 50% working interest in the South Alamein PSC in Egypt and an operated 60% working interest in the South Mariut PSC in Egypt. The transaction was structured as an all-cash deal, effective April 1, 2012, funded through working capital and the proceeds of the issuance of convertible debentures. Total consideration for the transaction was $22.9 million, which represents an initial $15.0 million base purchase price plus $7.9 million in consumable drilling equipment inventory (which is classified as exploration and evaluation assets), working capital and other closing adjustments.

This acquisition was accounted for using the acquisition method. The Company consolidated the underlying assets acquired and liabilities assumed as at the acquisition date.

The consideration paid and fair values of the identifiable assets acquired and liabilities assumed by the Company are as follows:



Fair value of net assets acquired (000s)
Property and equipment – intangible exploration and evaluation assets	$	21,984
Property and equipment – other assets	807
Working capital (including cash - $215)	139
Total cost of acquisition	$	22,930

The fair value of the acquired working capital approximates its carrying value due to its short-term nature.



2012		37

The Consolidated Financial Statements include the results of operations, working capital and other adjustments recorded for the 207 days remaining in the year ended December 31, 2012 after closing. The business acquired contributed an after-tax loss of $0.8 million to the Consolidated Statement of Earnings and Comprehensive Income for the year ended December 31, 2012, and contributed no revenue since it does not currently have production or sales. Had the transaction closed on January 1, 2012, the incremental after-tax loss reported by the Company is estimated to have been $1.7 million for the year ended December 31, 2012.

West Bakr Concession

On December 29, 2011, the Company completed the acquisition of a 100% working interest in the West Bakr Concession (“West Bakr”) agreement in the Arab Republic of Egypt from the Egyptian Petroleum Development Co. Ltd. (of Japan) (“EPEDECO”). The transaction was structured as an all-cash deal, effective July 1, 2010, to acquire all the Egyptian assets of EPEDECO, funded through working capital and the Borrowing Base Facility. Total consideration for the transaction was $74.5 million, comprised of $52.6 million cash and $21.9 million payable to EPEDECO (which was subsequently paid in cash in 2012). Total consideration represents an initial $60.0 million base purchase price plus $14.5 million in working capital and other closing adjustments between the effective date and the acquisition closing date.

This acquisition was accounted for using the acquisition method. The Company consolidated the underlying assets acquired and liabilities assumed as at the acquisition date.

The estimated fair values assigned to the assets acquired and liabilities assumed were based on a combination of independent appraisals and internal estimates. The fair values of the net identifiable assets were in excess of the consideration paid and as a result there was a bargain purchase gain recognized immediately in the Consolidated Statement of Earnings and Comprehensive Income of $13.2 million. The bargain purchase gain relates primarily to the impact that the escalation of oil prices from the effective date of the acquisition (July 1, 2010) to the closing date (December 29, 2011) had on the fair value of the petroleum properties acquired.

The consideration paid and fair values of the identifiable assets acquired and liabilities assumed by the Company are as follows:



Fair value of net assets acquired (000s)
Property and equipment - petroleum properties	$	74,500
Working capital (including cash - $684)	35,021
Property and equipment - other assets	314
Deferred taxes	(22,129		)
Total identifiable net assets at fair value	87,706
Bargain purchase gain	(13,187		)
Total cost of acquisition	$	74,519

The fair value of the acquired accounts receivable ($34.2 million) approximate their carrying value due to their short term nature. None of the trade accounts receivable were impaired on the closing of the acquisition as it was expected that the entire balance would be collected in full.

The Consolidated Financial Statements include the results of operations, working capital and other adjustments recorded for the three days remaining in the year ended December 31, 2011 after closing. The Consolidated Statement of Earnings and Comprehensive Income for the year ended December 31, 2011 includes revenue of $1.1 million and after-tax earnings of $0.1 million generated from the assets acquired since the closing date. It is impracticable for the Company to determine the amounts of revenue and profit or loss of the West Bakr assets for the year ended December 31, 2011 in order to disclose proforma information as though the acquisition had occurred as of January 1, 2011 due to the fact that the data was not collected during this period in a manner that would be representative of the economic model of TransGlobe.

Acquisition-related costs in the amount of $0.6 million were expensed as incurred in 2011 and 2010 and included in general and administrative expenses in the Consolidated Statement of Earnings and Comprehensive Income.

5. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair Values of Financial Instruments

The Company has classified its cash and cash equivalents as assets at fair value through profit or loss and its derivative commodity contracts as financial assets or liabilities at fair value through profit or loss, which are both measured at fair value with changes being recognized through earnings. Accounts receivable and restricted cash are classified as loans and receivables; accounts payable and accrued liabilities, and long-term debt are classified as other liabilities, all of which are measured initially at fair value, then at amortized cost after initial recognition.

Carrying value and fair value of financial assets and liabilities are summarized as follows:



	December 31, 2012				December 31, 2011
	Carrying		Fair		Carrying		Fair
Classification (000s)	Value		Value		Value		Value
Financial assets at fair value through profit or loss	$	82,974	$	82,974	$	44,009	$	44,009
Loans and receivables	221,799		221,799		164,451		164,451
Financial liabilities at fair value through profit or loss	98,742		98,742		—		—
Other liabilities	65,472		67,037		131,301		133,692



38		2012

Assets and liabilities at December 31, 2012 that are measured at fair value are classified into levels reflecting the method used to make the measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant inputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement.

The Company’s cash and cash equivalents and derivative commodity contracts are assessed on the fair value hierarchy described above. TransGlobe’s cash and cash equivalents and convertible debentures are classified as Level 1 and derivative commodity contracts as Level 2. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level.

Overview of Risk Management

The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production and financing activities:

• Credit risk

• Market risk

• Liquidity risk

This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these Consolidated Financial Statements.

The Board of Directors oversees management’s establishment and execution of the Company’s risk management framework. Management has implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

Credit risk

Credit risk is the risk of loss if the counter-parties do not fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to cash equivalents and accounts receivable, the majority of which are in respect of oil operations. The Company generally extends unsecured credit to these parties and therefore the collection of these amounts may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any material credit losses in the collection of accounts receivable to-date.

Trade and other receivables are analyzed in the table below. The majority of these receivables are due from the Egyptian Government, and the recent political unrest in the country has increased TransGlobe’s credit risk. Despite these factors the Company still expects to collect in full all outstanding receivables.



(000s)
Trade receivables at December 31, 2012
Neither impaired nor past due	$	51,645
Impaired	—
Not impaired and past due in the following period
Within 30 days	22,043
31-60 days	23,976
61-90 days	23,886
Over 90 days	99,467

The Company manages its credit risk on cash equivalents by investing only in term deposits with reputable international banking institutions.

Market risk

Commodity price risk

The Company’s operational results and financial condition are partially dependent on the commodity prices received for its oil production. As such, the Company uses derivative commodity contracts from time to time as part of its risk management strategy to manage commodity price fluctuations.



2012		39

The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheets, with any change in the unrealized positions recorded to earnings. The Company assesses these instruments on the fair value hierarchy and has classified the determination of fair value of these instruments as Level 2, as the fair values of these transactions are based on an approximation of the amounts that would have been received from counter-parties to settle the transactions outstanding as at the date of the Consolidated Balance Sheets with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates.

As there are no outstanding derivative commodity contracts at December 31, 2012, no assets or liabilities have been recognized on the Consolidated Balance Sheet for the current period.

Foreign currency exchange risk

As the Company’s business is conducted primarily in U.S. dollars and its financial instruments are primarily denominated in U.S. dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, convertible debentures, accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would result in a decrease in the net earnings for the year ended December 31, 2012 of approximately $10.1 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would increase net earnings by $8.3 million for the same period. The Company does not utilize derivative instruments to manage this risk.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2012 was $3.7 million in equivalent U.S. dollars.

Interest rate risk

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable-interest, U.S.-dollar-denominated debt. No derivative contracts were entered into during 2012 to mitigate this risk. When assessing interest rate risk applicable to the Company’s variable-interest, U.S.-dollar-denominated debt the Company believes 1% volatility is a reasonable measure. The effect of interest rates increasing by 1% would decrease the Company’s net earnings, for the year ended December 31, 2012, by $0.5 million. The effect of interest rates decreasing by 1% would increase the Company’s net earnings, for the year ended December 31, 2012, by $0.5 million.

Liquidity risk

The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. The following are the contractual maturities of financial liabilities at December 31, 2012:



(000s)		Payment Due by Period ^{1 2}
	Recognized
	in Financial	Contractual		Less than						More than
	Statements	Cash Flows		1 year		1-3 years		4-5 years		5 years
Accounts payable and accrued liabilities	Yes - Liability	$	48,587	$	48,587	$	—	$	—	$	—
Long-term debt	Yes - Liability	18,450		—		18,450		—		—
Convertible debentures	Yes - Liability	98,742		—		—		98,742		—
Office and equipment leases ³	No	14,728		6,819		2,324		2,072		3,513
Minimum work commitments ⁴	No	4,350		4,350		—		—		—
Total		$	184,857	$	59,756	$	20,774	$	100,814	$	3,513
¹ Payments exclude on going operating costs, finance costs and payments required to settle derivatives.
² Payments denominated in foreign currencies have been translated at December 31, 2012 exchange rates.
³ Office and equipment leases includes all drilling rig contracts.
⁴ Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations. (See note 18)

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

The existing banking arrangement at December 31, 2012 consists of a Borrowing Base Facility of $71.0 million of which $18.5 million is drawn.



40		2012

date on which notice of redemption is provided is not less than 125 percent of the conversion price (or C$18.88 per common share). Interest of 6% is payable semi-annually in arrears on March 31 and September 30. The first semi-annual interest payment was made on September 30, 2012. At maturity or redemption, the Company has the option to settle all or any portion of principal obligations by delivering to the debenture holders sufficient common shares to satisfy these obligations.

Capital disclosures

The Company’s objectives when managing capital are to ensure the Company will have the financial capacity, liquidity and flexibility to fund the ongoing exploration and development of its petroleum assets. The Company relies on cash flow to fund its capital investments. However, due to long lead cycles of some of its developments and corporate acquisitions, the Company’s capital requirements may exceed its cash flow generated in any one period. This requires the Company to maintain financial flexibility and liquidity. The Company sets the amount of capital in proportion to risk and manages to ensure that the total of the long-term debt is not greater than two times the Company’s funds flow from operations for the trailing twelve months. For the purposes of measuring the Company’s ability to meet the above stated criteria, funds flow from operations is defined as cash generated from operating activities before changes in non-cash working capital. Funds flow from operations may not be comparable to similar measures used by other companies.

The Company defines and computes its capital as follows:



(000s)	2012			2011
Shareholders’ equity	$	435,860		$	340,492
Long-term debt, including the current portion (net of unamortized transaction costs)	16,885			57,609
Convertible debentures	98,742			—
Cash and cash equivalents	(82,974		)	(43,884		)
Total capital	$	468,513		$	354,217

The Company’s debt-to-funds flow ratio is computed as follows:



(000s)	2012		2011
Long-term debt, including the current portion (net of unamortized transaction costs)	$	16,885	$	57,609
Convertible debentures	98,742		—
Total debt	115,627		57,609

Cash flow from operating activities	93,992		63,630
Changes in non-cash working capital	59,506		56,346
Funds flow from operations	$	153,498	$	119,976
Ratio	0.8		0.5

The Company’s financial objectives and strategy as described above have remained substantially unchanged over the last two completed fiscal years. These objectives and strategy are reviewed on an annual basis. The Company believes that its ratios are within reasonable limits, in light of the relative size of the Company and its capital management objectives. The Company is also subject to financial covenants in the Borrowing Base Facility that existed as at December 31, 2012. The key financial covenants are as follows:

•

Consolidated Financial Indebtedness to EBITDAX will not exceed 3.0 to 1.0. For the purposes of this calculation, Consolidated Financial Indebtedness shall mean the aggregate of all Financial Indebtedness of the Company. EBITDAX shall be defined as Consolidated Net Earnings before interest, income taxes, depreciation, depletion, amortization, accretion of abandonment liability, unrealized hedging losses and other similar non-cash charges (including expenses related to stock options), minus unrealized hedging gains and all non-cash income added to Consolidated Net Earnings.


•	Current ratio (current assets to current liabilities, excluding the current portion of long-term debt) of greater than 1.0 to 1.0.

The Company was in compliance with all financial covenants at December 31, 2012.

6. OIL REVENUE



(000s)	2012		2011
Oil sales	$	633,992	$	449,794
Less: Royalties	316,326		202,040
Oil sales, net of royalties	$	317,666	$	247,754



2012		41

7. FINANCE REVENUE AND COSTS

Finance revenue relates to interest earned on the Company’s bank account balances and term deposits.

Finance costs recognized in earnings were as follows:



(000s)	2012		2011
Interest expense	$	8,006	$	3,794
Issue costs for convertible debentures	4,630		—
Amortization of deferred financing costs	1,265		1,189
Finance costs	$	13,901	$	4,983

8. CASH AND CASH EQUIVALENTS

Cash is comprised of cash on hand and balances with banks. There were no term deposits with original maturities longer than three months outstanding as at December 31, 2012 or December 31, 2011. As at December 31, 2012, the Company's cash and cash equivalents balance was comprised of cash balances of $32.8 million (2011 - $27.9 million) and cash equivalent balances (term deposits with maturities of less than three months) of $50.2 million (2011 - $16.0 million).

The Company’s exposure to interest rate risk is disclosed in Note 5.

9. ACCOUNTS RECEIVABLE

Accounts receivable is comprised of current trade receivables due from third parties. There were no amounts due from related parties and no loans to management or employees as at December 31, 2012 or December 31, 2011.

The Company’s exposure to credit, currency and interest rate risks related to trade and other receivables is disclosed in Note 5.

10. RESTRICTED CASH

As at December 31, 2012, the Company had restricted cash of $0.8 million (December 31, 2011 - $2.2 million) set aside in a debt service reserve account, as required by the Borrowing Base Facility (Note 16). This represents the aggregate amount of interest for six months on the loan balance outstanding based on the five-year forward interest strip. Amounts are deposited as required to maintain minimum reserve requirements.

11. INCOME TAXES

The Company’s deferred income tax assets and liabilities are as follows:



(000s)	2012			2011
Balance, beginning of year	$	52,891		$	35,207
Expenses related to the origination and reversal of temporary differences for:
Property and equipment	(221		)	(9,261		)
Non-capital losses carried forward	(4,330		)	(2,008		)
Long-term liabilities	(123		)	—
Transactions costs	(951		)	—
Share issue expenses	254			(707		)
Changes in unrecognized tax benefits	4,843			7,531
Deferred income tax expense (recovery) recognized in earnings	(528		)	(4,445		)
Deferred income tax liabilities assumed from business combinations	—			22,129
Balance, end of year	$	52,363		$	52,891

The Company has non-capital losses of $45.0 million (2011 - $28.4 million) that expire between 2027 and 2032. No deferred tax assets have been recognized in respect of these unused tax losses. The Company has additional $5.0 million (2011 - $5.3 million) in unrecognized tax benefits arising in foreign jurisdictions.

Current income taxes represent income taxes incurred and paid under the laws of Yemen pursuant to the PSCs on Block 32 and Block S-1 and under the laws of Egypt pursuant to the PSCs on the West Gharib, West Bakr and East Ghazalat Concessions.



42		2012

Income taxes vary from the amount that would be computed by applying the Canadian statutory income tax rate of 25.0% (2011 – 26.5%) to income before taxes as follows:



(000s)	2012			2011
Income taxes calculated at the Canadian statutory rate	$	43,952		$	40,005
Increases (decreases) in income taxes resulting from:
Non-deductible expenses	3,551			3,667
Gain on acquisition	—			(5,347		)
Changes in unrecognized tax benefits	4,843			7,531
Effect of tax rates in foreign jurisdictions¹	35,787			24,142
Changes in tax rates and other	(58		)	(426		)
Income tax expense	$	88,075		$	69,572
¹ The statutory tax rates in Egypt and Yemen are 40.55% and 35.0%, respectively.

The Company's consolidated effective income tax rate for 2012 was 50.1% (2011 - 46.1%).

12. INTANGIBLE EXPLORATION AND EVALUATION ASSETS



(000s)
Balance at December 31, 2010	$	22,609
Additions	6,991
Impairment loss	(12,147		)
Balance at December 31, 2011	17,453
Additions	5,384
Acquisitions	26,219
Transfer to petroleum properties	(566		)
Impairment loss	(76		)
Balance at December 31, 2012	$	48,414

The impairment loss recognized in 2011 in the amount of $12.1 million relates to Nuqra Block 1 in Egypt and represents all intangible exploration and evaluation asset costs that had been incurred at Nuqra up to December 31, 2011. It was determined that an impairment loss was necessary as no commercially viable quantities of oil had been discovered at Nuqra, and no further exploration and evaluation spending was planned as at December 31, 2011. The 2012 impairment loss of $0.1 million also relates to Nuqra Block 1, and represents the write-down of consumable drilling inventory (which was reported as exploration and evaluation assets) that was determined to be unusable in other drilling locations.



2012		43

13. PROPERTY AND EQUIPMENT



	Petroleum		Other
(000s)	Properties		Assets		Total
Balance at December 31, 2010	$	205,854	$	5,713	$	211,567
Additions	61,266		1,861		63,127
Acquisitions	74,500		314		74,814
Balance at December 31, 2011	341,620		7,888		349,508
Additions	45,386		881		46,267
Acquisitions	—		1,086		1,086
Transfer from exploration and evaluation assets	566		—		566
Balance at December 31, 2012	$	387,572	$	9,855	$	397,427

Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2010	$	27,215	$	2,940	$	30,155
Depletion, depreciation and amortization for the year	33,881		1,200		35,081
Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2011	61,096		4,140		65,236
Depletion, depreciation and amortization for the year	45,581		1,365		46,946
Balance at December 31, 2012	$	106,677	$	5,505	$	112,182



Net Book Value
At December 31, 2011	$	280,524	$	3,748	$	284,272
At December 31, 2012	$	280,895	$	4,350	$	285,245

Future development costs of $56.2 million (2011 - $37.1 million) for Proved and Probable reserves were included in the depletion calculation for the year ended December 31, 2012.

14. GOODWILL

The Company recorded no change in the carrying value of its goodwill during the year ended December 31, 2012. The acquisitions completed during the year ended December 31, 2012 did not result in any acquired goodwill.

Goodwill was assessed for impairment as at December 31, 2012 and December 31, 2011, and no impairment was recognized as a result of these assessments. The after-tax cash flows used to determine the recoverable amounts of the cash-generating units were discounted using an estimated year-end weighted average cost of capital of 15%.

15. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities are comprised of current trade payables and accrued expenses due to third parties. There were no amounts due to related parties as at December 31, 2012 or December 31, 2011.

The Company’s exposure to currency and liquidity risk related to trade and other payables is disclosed in Note 5.

16. LONG-TERM DEBT

The contractual terms of the Company’s interest-bearing loans and borrowings are measured at amortized cost. As at December 31, 2012, the only significant interest-bearing loans and borrowings related to the Borrowing Base Facility are described below. For more information about the Company’s exposure to interest rate, foreign currency and liquidity risk, see Note 5.



	December 31			December 31
(000s)	2012			2011
Bank debt	$	18,450		$	60,000
Deferred financing costs	(1,565		)	(2,391		)
	16,885			57,609
Current portion of long-term debt	—			—
	$	16,885		$	57,609



44		2012

As at December 31, 2012, the Company had a $71.0 million Borrowing Base Facility of which $18.5 million was drawn. The Borrowing Base Facility is secured by a pledge over certain bank accounts, a pledge over the Company’s subsidiaries and a fixed and floating charge over certain assets. The credit facility bears interest at the LIBOR rate plus an applicable margin, which ranges from 3.75% to 4.75% and is dependent on the amount drawn. During the year ended December 31, 2012, the average effective interest rate was 9.7% (2011 – 7.9%). As repayments on the Borrowing Base Facility are not expected to commence until 2014, the entire balance has been presented as a long-term liability on the Consolidated Balance Sheets. Repayments will be made on a semi-annual basis in order to reduce the amount borrowed to an amount no greater than the Borrowing Base. The amount of the Borrowing Base may fluctuate over time and is determined principally by the net present value of the Company’s Proved and Probable reserves over the term of the Borrowing Base Facility, up to a pre-defined commitment amount which is subject to pre-determined semi-annual reductions in accordance with the terms of the Borrowing Base Facility. Accordingly, for each balance sheet date, the timing of repayment is estimated based on the most recent redetermination of the Borrowing Base and repayment schedules may change in future periods.

The estimated future debt payments on long-term debt, as of December 31, 2012 are as follows:



(000s)
2013	$	—
2014	3,950
2015	14,500
2016	—
2017	—
	$	18,450

17. CONVERTIBLE DEBENTURES



(000s)
Balance at December 31, 2011	$	—
Issuance	97,851
Fair value adjustment	425
Foreign exchange adjustment	466
Balance at December 31, 2012	$	98,742

In February 2012, the Company sold, on a bought-deal basis, C$97.8 million ($97.9 million) aggregate principal amount of convertible unsecured subordinated debentures with a maturity date of March 31, 2017. Transaction costs of $4.6 million relating to the issuance of the convertible debentures were expensed in the twelve months ended December 31, 2012. The debentures are convertible at any time and from time to time into common shares of the Company at a price of C$15.10 per common share. The debentures are not redeemable by the Company on or before March 31, 2015 other than in limited circumstances in connection with a change of control of TransGlobe. After March 31, 2015 and prior to March 31, 2017, the debentures may be redeemed by the Company at a redemption price equal to the principal amount plus accrued and unpaid interest, provided that the weighted-average trading price of the common shares for the 20 consecutive trading days ending five trading days prior to the date on which notice of redemption is provided is not less than 125 percent of the conversion price (or C$18.88 per common share). Interest of 6% is payable semi-annually in arrears on March 31 and September 30. The first semi-annual interest payment was made on September 30, 2012. At maturity or redemption, the Company has the option to settle all or any portion of principal obligations by delivering to the debenture holders sufficient common shares to satisfy these obligations.

The convertible debentures are classified as financial instruments at fair value through profit or loss, and as such are measured at fair value with changes in fair value included in earnings. Fair value is determined based on market price quotes from the exchange on which the convertible debentures are traded as at the period end date. As at December 31, 2012 the convertible debentures were trading at a price of C$100.50 for a C$100.00 par value debenture. As a result, the Company has recognized a net expense of $0.4 million for the year ended December 31, 2012. Transaction costs of $4.6 million associated with the issuance of the convertible debentures were recognized through earnings as incurred.

18. COMMITMENTS AND CONTINGENCIES

The Company is subject to certain office and equipment leases (Note 5).

Pursuant to the August 18, 2008 asset purchase agreement for a 25% financial interest in eight development leases on the West Gharib Concession in Egypt, the Company has committed to paying the vendor a success fee up to a maximum of $2.0 million if incremental reserve thresholds are reached in the South Rahmi development lease, to be evaluated annually. Based on the Company's annual Reserve Report effective December 31, 2012, no additional fees are due in 2013.



2012		45

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2012.

19. SHARE CAPITAL

Authorized

The Company is authorized to issue an unlimited number of common shares with no par value.

Issued



	December 31, 2012			December 31, 2011
000’s	Shares	Amount		Shares	Amount
Balance, beginning of year	73,055	$	154,263	67,576	$	80,106
Share issuance				5,000	75,594
Stock options exercised	739	3,333		479	1,946
Share-based compensation on exercise	—	1,125		—	628
Share issue costs	—	—		—	(4,011		)
Balance, end of year	73,794	$	158,721	73,055	$	154,263

20. SHARE-BASED PAYMENTS

The Company adopted a stock option plan in May 2007 (the “Plan”) and reapproved unallocated options issuable pursuant to the Plan in May 2010. The number of Common Shares that may be issued pursuant to the exercise of options awarded under the Plan and all other Security Based Compensation Arrangements of the Company is 10% of the common shares outstanding from time to time. All incentive stock options granted under the Plan have a per-share exercise price not less than the trading market value of the common shares at the date of grant. All grants of stock options currently outstanding vest one-third on each of the first, second and third anniversaries of the grant date. Each tranche of an award with different vesting dates is considered a separate grant for the calculation of fair value and the resulting fair value is amortized over the vesting period of the respective tranches.

The following tables summarize information about the stock options outstanding and exercisable at the dates indicated:



	2012			2011
			Weighted-			Weighted-
	Number		Average	Number		Average
	of		Exercise	of		Exercise
(000s except per share amounts)	Options		Price (C$)	Options		Price (C$)
Options outstanding, beginning of year	4,760		6.81	4,156		3.80
Granted	1,327		11.43	1,134		12.65
Exercised	(739	)	4.49	(479	)	4.06
Forfeited	(238	)	9.82	(51	)	6.28
Options outstanding, end of year	5,110		8.19	4,760		6.81
Options exercisable, end of year	2,713		5.69	2,440		4.31



	Options Outstanding			Options Exercisable
		Weighted-			Weighted-
	Number	Average	Weighted-	Number	Average	Weighted-
Exercise	Outstanding at	Remaining	Average	Exercisable at	Remaining	Average
Prices	December 31, 2012	Contractual	Exercise Price	December 31, 2012	Contractual	Exercise
(C$)	(000s)	Life (Years)	(C$)	(000s)	Life (Years)	Price (C$)
2.27-4.00	1,329	1.2	3.06	1,302	1.2	3.05
4.01-6.00	539	0.8	5.07	463	0.5	5.08
6.01-8.00	679	2.4	7.37	453	2.4	7.37
8.01-10.00	450	3.6	8.98	169	2.9	8.50
10.01-12.00	1,212	4.4	11.60	6	3.5	10.90
12.01-15.12	901	3.3	13.27	320	3.3	13.38
	5,110	2.7	8.19	2,713	1.7	5.69



46		2012

Share–based compensation

Compensation expense of $4.3 million was recorded in general and administrative expenses in the Consolidated Statements of Earnings and Comprehensive Income and Changes in Shareholders’ Equity during year ended December 31, 2012 (2011 - $3.4 million) in respect of equity-settled share-based payment transactions. The fair value of all common stock options granted is estimated on the date of grant using the lattice-based trinomial option pricing model. The weighted average fair value of options granted during the period and the assumptions used in their determination are as noted below:



	2012		2011
Weighted average fair market value per option (C$)	3.98		4.22
Risk free interest rate (%)	1.33	%	1.82	%
Expected volatility (based on actual historical volatility) (%)	53.09	%	50.60	%
Dividend per share	—		—
Expected forfeiture rate (non-executive employees) (%)	8.48	%	9.34	%
Suboptimal exercise factor	1.25		1.25

All options granted vest annually over a three-year period and expire five years after the grant date. During the year ended December 31, 2012, employees exercised 739,000 (2011 – 479,000) stock options. The fair value related to these options was $1.1 million, (2011 - $0.6 million) at time of grant and has been transferred from contributed surplus to share capital. As at December 31, 2012 and December 31, 2011, the entire balance in contributed surplus was related to previously recognized stock-based compensation expense on equity-settled stock options.

Share appreciation rights plan

In addition to the Company’s stock option plan, the Company also issues share appreciation rights (“units”) under the share appreciation rights plan, which was adopted in March 2010. Share appreciation rights are similar to stock options except that the holder does not have the right to purchase the underlying share of the Company and instead receives cash. Units granted under the share appreciation rights plan vest one-third on each of the first, second and third anniversaries of the grant date. Share appreciation rights granted expire five years after the grant date. The following table summarizes information about the share appreciation rights outstanding and exercisable at the dates indicated:



	2012		2011
		Weighted-			Weighted-
	Number	Average	Number		Average
	of	Exercise	Of		Exercise
(000s, except per share amounts)	Units	Price (C$)	Units		Price (C$)
Units outstanding, beginning of year	105	6.04	150		6.61
Granted	48	11.65	—		—
Exercised	—	—	(15	)	7.94
Forfeited	—	—	(30	)	7.94
Units outstanding, end of year	153	7.80	105		6.04
Units exercisable, end of year	70	6.04	35		6.04

For the year ended December 31, 2012, compensation expense of $0.2 million was recorded in general and administrative expenses in the Consolidated Statements of Earnings and Comprehensive Income (2011 – expense recoveries of $0.3 million) in respect of cash-settled, share-based payment transactions. The carrying amount of liabilities for cash-settled arrangements as at December 31, 2012 was $0.5 million (2011 - $0.3 million) and the total fair value of the liability for vested benefits as at December 31, 2012 was $0.4 million (2011 - $0.1 million).

21. PER SHARE AMOUNTS

In calculating the earnings per share, basic and diluted, the following weighted-average shares were used:

In determining diluted earnings per share, the Company assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the year ended December 31, 2012, the Company excluded 2,112,400 stock options (2011 – 1,016,500) as their exercise price was greater than the average common share market price in the year.

The convertible debentures are dilutive in any period in which earnings per share is reduced by the effect of adjusting net earnings for the impact of the convertible debentures, and adjusting the weighted-average number of shares outstanding for the potential shares issuable on conversion of the convertible debentures. The convertible debentures were anti-dilutive for the year ended December 31, 2012.



2012		47

22. RELATED PARTY DISCLOSURES

Details of controlled entities are as follows*:



		Ownership Interest	Ownership Interest
	Country of	2012	2011
	Incorporation	(%)	(%)
TransGlobe Petroleum International Inc.	Turks & Caicos	100	100
TG Holdings Yemen Inc.	Turks & Caicos	100	100
TG West Yemen Inc.	Turks & Caicos	100	100
TransGlobe West Bakr Inc.	Turks & Caicos	100	100
TransGlobe West Gharib Inc.	Turks & Caicos	100	100
TransGlobe GOS Inc.	Turks & Caicos	100	100
TG Holdings Egypt Inc.	Turks & Caicos	100	—
TG South Alamein Inc.	Turks & Caicos	100	—
TG South Mariut Inc.	Turks & Caicos	100	—
TG South Alamein II B.V.	Netherlands	100	—

* Includes only entities that were active as at December 31, 2012.

23. COMPENSATION OF KEY MANAGEMENT PERSONNEL

Key management personnel have been identified as the board of directors and the six executive officers of the Company in 2012 (2011 - four executive officers).

Key management personnel remuneration consisted of the following:



(000s)	2012		2011
Salaries, incentives and short-term benefits	$	3,487	$	2,380
Share-based compensation	2,276		1,522
	$	5,763	$	3,902



48		2012

24. SEGMENTED INFORMATION

The Company has two reportable operating segments: the Arab Republic of Egypt and the Republic of Yemen. The Company, through its operating segments, is engaged primarily in oil exploration, development and production and the acquisition of properties.

In presenting information on the basis of operating segments, segment revenue is based on the geographical location of assets which is also consistent with the location of the segment customers. Segmented assets are also based on the geographical location of the assets. There are no inter-segment sales.

The accounting policies of the operating segments are the same as the Company’s accounting policies. The following is an analysis of reported segment earnings, revenues, operating expenses and depreciation, depletion and amortization expenses analyzed by operating segment and reconciled to the Company’s Consolidated Financial Statements:



	Egypt						Yemen				Total
(000s)	2012			2011			2012		2011		2012			2011
Revenue
Oil sales, net of royalties and other	$	296,885		$	215,851		$	20,781	$	31,903	$	317,666		$	247,754
Gain on acquisition	—			13,187			—		—		—			13,187
Other income	45			6			25		14		70			20
Total segmented revenue	296,930			229,044			20,806		31,917		317,736			260,961

Segmented expenses
Production and operating	43,247			27,407			9,120		9,255		52,367			36,662
Depletion, depreciation and amortization	44,442			31,035			2,095		3,585		46,537			34,620
Income taxes - current	84,935			66,630			3,668		7,387		88,603			74,017
Income taxes - deferred	(1,029		)	(4,606		)	501		161		(528		)	(4,445		)
Impairment loss	76			12,147			—		—		76			12,147
Total segmented expenses	171,671			132,613			15,384		20,388		187,055			153,001
Segmented earnings	$	125,259		$	96,431		$	5,422	$	11,529	130,681			107,960

Non-segmented expenses (income)
Derivative loss (gain) on commodity contracts											125			807
Exploration											368			1,561
General and administrative											28,206			18,893
Foreign exchange loss											(105		)	310
Depreciation and amortization											409			461
Unrealized loss on financial instruments											425			—
Finance revenue											(382		)	(447		)
Finance costs											13,901			4,983
Total non-segmented expenses											42,947			26,568

Net earnings for the year											$	87,734		$	81,392

Capital expenditures
Exploration and development	$	50,220		$	63,177		$	1,239	$	5,495	$	51,459		$	68,672
Asset acquisitions	—			74,814			—		—		—			74,814
Corporate acquisitions											27,259			—
Corporate											192			1,447
Total capital expenditures											$	78,910		$	144,933



2012		49

The carrying amounts of reportable segment assets and liabilities are as follows:



December 31, 2012
(000s)	Egypt		Yemen		Total
Assets
Intangible exploration and evaluation assets	$	33,321	$	15,093	$	48,414
Property and equipment
Petroleum properties	246,702		34,193		280,895
Other assets	2,439		—		2,439
Goodwill	8,180		—		8,180
Other	282,627		5,106		287,733
Segmented assets	573,269		54,392		627,661
Non-segmented assets					25,764
Total assets					$	653,425

Liabilities
Accounts payable and accrued liabilities	$	41,406	$	1,321	$	42,727
Deferred taxes	42,082		10,281		52,363
Segmented liabilities	83,488		11,602		95,090
Non-segmented liabilities					122,475
Total liabilities					$	217,565



December 31, 2011
(000s)	Egypt		Yemen		Total
Assets
Intangible exploration and evaluation assets	$	2,915	$	14,538	$	17,453
Property and equipment
Petroleum properties	244,920		35,604		280,524
Other assets	1,619		—		1,619
Goodwill	8,180		—		8,180
Other	184,545		14,269		198,814
Segmented assets	442,179		64,411		506,590
Non-segmented assets					19,216
Total assets					$	525,806

Liabilities
Accounts payable and accrued liabilities	$	67,170	$	2,226	$	69,396
Deferred taxes	43,112		9,779		52,891
Segmented liabilities	110,282		12,005		122,287
Non-segmented liabilities					63,027
Total liabilities					$	185,314



50		2012

25. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital consisted of the following:



(000s)	2012			2011
Operating Activities
(Increase) decrease in current assets
Accounts receivable	$	(58,792	)	$	(58,803	)
Prepaids and other	(2,207		)	(1,245		)
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	1,493			3,702
	$	(59,506	)	$	(56,346	)



(000s)	2012			2011
Investing Activities
(Increase) decrease in current assets
Prepaids and other	$	2,806		$	(3,330	)
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	(28,117		)	28,020
	$	(25,311	)	$	24,690



(000s)	2012		2011
Financing Activities
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	$	—	$	139
	$	—	$	139



2012		51

SUPPLEMENTARY INFORMATION

(Unaudited – Expressed in thousands of U.S. Dollars, except per share, price and volume amounts)



	Year ended December 31
Financial	2012	2011	2010	2009		2008
Oil and gas sales	633,992	449,794	268,901	167,798		233,695
Oil and gas sales, net of royalties	317,666	247,754	157,220	102,805		132,393
Production and operating expense	52,367	36,662	26,850	24,765		21,561
General and administrative expense	28,206	18,893	15,458	11,427		10,213
Depletion, depreciation and amortization expense	46,946	35,081	28,140	47,579		38,056
Income taxes	88,075	69,572	41,701	21,853		32,148
Cash flow from operating activities	93,992	63,630	56,969	36,799		57,793
Funds flow from operations*	153,498	119,976	75,460	45,064		59,267
Basic per share	2.09	1.65	1.14	0.70		0.99
Diluted per share	2.03	1.60	1.10	0.70		0.98
Netback**
Egypt	168,703	121,814	68,745	35,434		29,769
Yemen	7,993	15,261	21,818	20,753		41,899
Canada	—	—	—	—		6,934
Net earnings (loss)	87,734	81,392	40,565	(8,417	)	31,523
Basic per share	1.20	1.12	0.61	(0.13	)	0.53
Diluted per share	1.16	1.09	0.59	(0.13	)	0.52
Capital expenditures	51,651	70,119	65,342	35,546		44,714
Acquisitions	27,259	73,836	—	—		62,392
Working capital	262,217	139,983	88,229	(11,787	)	23,984
Long-term debt (including current portion)	16,885	57,609	86,420	49,799		57,230
Convertible debentures	98,742
Shareholders’ equity	435,860	340,492	182,190	163,690		154,735
Common shares outstanding
Basic (weighted average)	73,380	72,529	66,328	64,443		59,692
Diluted (weighted average)	75,523	74,937	68,892	64,443		60,704
Total assets	653,425	525,806	345,625	228,882		228,238
* 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.
** Netback is a measure that represents revenue, net of royalties, current income taxes (paid through production sharing) and operating expenses, and may not be comparable to measures used by other companies.
*** Financial information presented for 2008 and 2009 has been prepared in accordance with GAAP. This information has not been restated for differences between GAAP and IFRS.



Reserves
Total proved (MMBoe)	32.8	28.1	20.5	19.2	12.6
Total proved plus probable (MMBoe)	48.7	44.2	30.4	24.2	19.8

Production and Sales Volumes
Total sales (Boepd) (6:1)*	17,496	12,132	9,960	8,980	7,342
Oil and liquids (Bopd)	17,496	12,132	9,960	8,980	6,974
Average price ($ per Bbl)	99.01	101.58	73.97	51.19	88.69
Gas (Mcfpd)	—	—	—	—	2,212
Average price ($ per Mcf)	—	—	—	—	8.92
Operating expense ($ per Boe)	8.18	8.28	7.39	7.56	8.02
* The differences in production and sales volumes result from inventory changes.
** The calculation of barrels of oil equivalent (“Boe”) is based on a conversion ratio of 6,000 cubic feet of natural gas to 1 barrel of oil to estimate relative energy content and does not represent a value equivalency at the wellhead.
*** As determined by the Company's independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports with effective dates of December 31, 2012, December 31, 2011, December 31, 2010, December 31, 2009 and December 31, 2008. The reports of DeGolyer 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



52		2012



Share Information	2012	2011
TSX: Price per share – TSX (C$)
High	14.26	15.99
Low	8.01	7.04
Close	9.33	8.07
Average daily trading volume	272,767	296,603

NASDAQ: Price per share – NASDAQ (US$)
High	14.46	16.23
Low	7.80	6.80
Close	9.39	7.92
Average daily trading volume	119,352	231,192



2012		53

SUMMARY OF INTERNATIONAL PRODUCTION SHARING CONCESSIONS (“PSC”)

International Land (Egypt and Yemen)

Summary of PSCs



EASTERN DESERT EGYPT
Block	West Gharib	West Bakr	NW Gharib	SE Gharib	SW Gharib
Basin	Gulf of Suez	Gulf of Suez	Gulf of Suez	Gulf of Suez	Gulf of Suez
Year acquired	2007	2011	2012 pending	2012 pending	2012 pending
Status	Development	Development	Pending	Pending	Pending
Operator	TransGlobe	TransGlobe	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	100%	100%	100%	100%	100%
Block Area (acres)	34,856	11,600	162,000	125,653	48,309
Expiry date	2019-2026	2020
Extensions
Exploration	N/A	N/A	3/2/2 years	3/2/2 years	3/2/2 years
Development	+ 5 years	+ 5 years	20 years	20 years	20 years
* The exploration period on Nuqra Block #1 expired in July 2012. Since no commercial discoveries were made during the exploration period, the Company has relinquished this land.



WESTERN DESERT EGYPT
Block	East Ghazalat	South Alamein	South Mariut	South Ghazalat
Basin	Western Desert	Western Desert	Western Desert	Western Desert
Year acquired	2010	2012	2012	2012 pending
Status	Exploration	Exploration	Exploration	Pending
Operator	Vegas	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	50%	100%	60%	100%
Block Area (acres)	112,071	335,832	827,679	465,299
Expiry date	June 2014	April 2014	April 2013
Extensions
Exploration	N/A	N/A	2nd extension	3/2/2 years
			24 months
Development	20 years	20 years	20 years	20 years



YEMEN
Block	32	72	S-1	75
Basin	Masila	Masila	Marib	Marib
Year acquired	1997	2004/2005	1998	2007
Status	Development	Exploration	Development	Exploration
Operator	DNO	Total	OXY	OXY
TransGlobe WI (%)	13.81087%	20%	25%	25%
Block Area (acres)	146,000	450,000	285,000	263,000
Expiry date	Nov 2020	Sept 2013	Oct 2023	March 2014
Extensions
Exploration	N/A	N/A	N/A	2nd Phase
				36 months
Development	+ 5 years	20 + 5 years	+ 5 years	20 + 5 years



54		2012

Summary of PSC Terms

All of the Company’s international blocks are production sharing contracts between the host government and the Contractor (joint interest partners). The government and the Contractor take their share of production based on the terms and conditions of the respective contracts. The Contractors’ share of all taxes and royalties are paid out of the Governments’ share of production.

The PSCs provide for the Government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the Government and the Contractor as defined in the specific PSCs. Each PSC is ring fenced for cost recovery and production sharing purposes. The remaining production sharing oil (total production, less gross royalty, less cost oil) is shared between the government and the Contractor as defined in the specific PSCs.

The following tables summarizes the Company’s international PSC terms for the first production tranche for each block. All the PSCs have different terms for production levels above the first tranche, which are unique to each PSC. The Government’s share of production increases and the Contractor’s share of production decreases as the production volumes go to the next production tranche.

PSC Terms –Egypt and Yemen



EGYPT
Block	West Gharib	West Bakr	East Ghazalat	South Alamein	South Mariut
Production Tranche (MBopd)	0-5 / 5-10	0-50	0-5	0-5	0-5
	10-15
Max. cost oil	30%	30%	25%	30%	35%
Excess cost oil
Contractor	30%	0%	0%	0%	0%
Depreciation per quarter
Operating	100%	100%	100%	100%	100%
Capital	6.25%	5%	5%	5%	5%
Production Sharing Oil:
Contractor	30% / 27.5%	15%	20%	14%	18%
	25%
Government	70% / 72.5%	85%	80%	86%	82%
	75%



YEMEN
Block	32*	72	S-1	75
Production Tranche (MBopd)	0-25	0-25	0-25	0-25
Gross royalty	3%	3%	3%	3%

Max. cost oil	60%	50%	50%	50%

Excess cost oil	Prod. Sharing	Prod. Sharing	Prod. Sharing	Prod. Sharing
Depreciation per quarter
Operating	100%	100%	100%	100%
Capital	12.5%	12.5%	12.5%	12.5%
Production Sharing Oil:
Contractor	33.25%	32.4%	34.2%	34.2%

Government	66.75%	67.6%	65.8%	65.8%

* Block 32 terms will revert to original PSC terms if production exceeds 25,000 Bopd or Proved reserves exceed 30 million barrels. Reserves may be audited every two years by an independent evaluator at the request of the Government of Yemen. At November 2011 Proved reserves were less than 30 million barrels. The next potential reserve audit is November 2013.



2012		55

RESERVES AND ESTIMATED FUTURE NET REVENUES

In 2011 and 2012, DeGolyer and MacNaughton Canada Limited (“DeGolyer”) of Calgary, Alberta, independent petroleum engineering consultants based in Calgary and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company’s Reserve Committee, to independently evaluate 100% of TransGlobe’s reserves as at December 31, 2012 and December 31, 2011.

The reserves data set forth below was prepared by DeGolyer with an effective date of December 31, 2012 and December 31, 2011, respectively. The reserves data summarizes the crude oil reserves of the Company and the net present values of future net revenue for these reserves using forecast prices and costs and constant prices and costs. The Company reports in U.S. currency and therefore the reports have been stated in U.S. dollars. The reports of DeGolyer 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 (the "COGE Handbook") and the reserve definitions contained in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the COGE Handbook.

Total Proved reserves for the Company increased 16% from 28.2 million barrels of oil (“MMBbl”) at December 31, 2011 to 32.8 MMBbl at December 31, 2012, replacing 172% of the 6.4 MMBbl produced during 2012.

Total Proved plus Probable reserves for the Company increased by 10% from 44.2 MMBbl at December 31, 2011 to 48.7 MMBbl at December 31, 2012, replacing 170% of 2012 production.

The Company’s Reserves Committee, comprised of independent directors, has reviewed and recommended acceptance of the 2012 and 2011 year-end reserve evaluations prepared by DeGolyer.

In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows there from are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of crude oil, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development and operating expenditures with respect to the reserves associated with the Company's properties may vary from the information presented herein and such variations could be material. In addition, there is no assurance that the forecast price and cost assumptions contained in the reports prepared by DeGolyer will be attained and variances could be material.

The recovery and reserve estimates of crude oil reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil may be greater than, or less than, the estimates provided herein. Note that columns may not add due to rounding.

The information relating to the Company's reserves contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans and costs related thereto, forecast operating costs and anticipated production. See "Reader Advisories - Forward-Looking Statements".

Possible reserves are those additional reserves that are less certain to be recovered than probable resources. There is a 10% probability that the quantities actually received will equal or exceed the sum of proved plus probable plus possible reserves.

All reserves (gross and net) presented are based on Forecast Pricing.

Reserves



	2012						2011
	Light & Medium
	Crude Oil		Heavy Oil		Total Bbl		Total Bbl
Company	Gross*	Net**	Gross*	Net**	Gross*	Net**	Gross*	Net**
By Category	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)
Proved
Developed producing	3.1	1.7	23.0	10.6	26.1	12.2	19.7	9.2
Developed non-producing	4.2	2.2	1.4	0.8	5.5	3.0	6.5	3.6
Undeveloped	0.1	0.1	1.0	0.4	1.1	0.4	1.9	0.9
Total Proved	7.4	4.0	25.4	11.7	32.8	15.6	28.1	13.7
Probable	5.5	2.8	10.4	4.0	16.0	6.9	16.1	7.0
Proved plus Probable	12.9	6.8	35.8	15.7	48.7	22.5	44.2	20.7
Possible	4.2	2.0	9.5	3.4	13.7	5.4	15.6	6.5
Proved plus Probable plus Possible	17.1	8.8	45.3	19.1	62.4	27.9	59.8	27.1



56		2012



	2012						2011
	Light & Medium
	Crude Oil		Heavy Oil		Total Bbl		Total MBbl
Company	Gross*	Net**	Gross*	Net**	Gross*	Net**	Gross*	Net**
By Area	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)	(MMBbl)
Proved
Egypt	4.4	2.3	25.4	11.7	29.8	14.0	24.3	11.6
Yemen	3.0	1.6	—	—	3.0	1.6	3.8	2.1
Total Proved	7.4	4.0	25.4	11.7	32.8	15.6	28.1	13.7
Proved plus Probable
Egypt	8.0	4.2	35.8	15.7	43.9	19.9	38.4	17.7
Yemen	4.9	2.6	—	—	4.9	2.6	5.8	3.0
Total Proved plus Probable	12.9	6.8	35.8	15.7	48.7	22.5	44.2	20.7
Proved plus Probable plus Possible
Egypt	11.2	5.6	45.3	19.1	56.5	24.7	52.9	23.7
Yemen	5.9	3.2	—	—	5.9	3.2	6.9	3.4
Total Proved plus Probable plus Possible	17.1	8.8	45.3	19.1	62.4	27.9	59.8	27.1
* Gross reserves are the Company's working interest share before the deduction of royalties
** Net reserves are the Company's working interest share after the deduction of royalties. Net reserves in Egypt and Yemen include the Company’s share of future cost recovery and production sharing oil after the Government's royalty interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.

Estimated Future Net Revenues

All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Company’s properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

The estimated future net revenues presented below are calculated using the independent engineering evaluator’s price forecast.



	Present Value of Future Net Revenues, After Income Tax
	Independent Evaluator’s Price Forecast
	December 31, 2012					December 31, 2011
	Discounted at					Discounted at
	Undis-					Undis-
($USMM)	counted	5%	10%	15%	20%	counted	5%	10%	15%	20%
Proved
Egypt	717.9	596.3	513.1	453.0	407.6	543.7	471.2	416.9	375.0	341.7
Yemen	63.7	56.2	50.2	45.4	41.4	73.6	64.9	57.8	52.0	47.3
Total Proved	781.6	652.5	563.3	498.4	449.0	617.3	536.1	474.8	427.1	389.0
Proved plus Probable
Egypt	959.9	767.6	641.6	553.4	488.5	801.8	673.8	581.0	510.9	456.4
Yemen	100.4	83.2	70.7	61.4	54.2	129.6	103.9	86.4	73.8	64.5
Total Proved plus Probable	1,060.3	850.8	712.3	614.8	542.7	931.4	777.8	667.4	584.8	520.9
Proved plus Probable plus Possible
Egypt	1,170.9	933.4	775.1	663.5	581.2	1,062.5	862.1	723.0	621.9	545.4
Yemen	126.3	101.5	84.4	72.0	62.7	157.3	124.1	101.7	85.9	74.3
Total Proved plus Probable plus Possible	1,297.3	1,034.9	859.5	735.5	643.9	1,219.7	986.2	824.8	707.8	619.8



2012		57

The following table summarizes the independent evaluator’s price forecast after adjustments for respective differentials used to estimate future net revenues.



	Egypt		Yemen
	Oil		Oil
	$/Bbl		$/Bbl
Year	2012	2011	2012	2011
2013	97.76	90.78	107.50	103.05
2014	95.04	91.25	105.83	103.76
2015	92.64	91.65	103.41	104.54
2016	94.40	91.14	105.72	104.32
2017	93.03	92.96	104.63	106.41
Thereafter (%)*	2.0	2.0	2.0	2.0
* Percentage change represents the increase in each year after 2017 to the end of the reserve life.

The estimated future net revenues presented below are calculated using the average price received as of December 31 of the respective reporting periods. The prices were held constant for the life of the reserves.



	Present Value of Future Net Revenues, After Income Tax
	US millions (“$USMM”)
	Constant Pricing
	December 31, 2012					December 31, 2011
	Discounted at					Discounted at
	Undis-					Undis-
($USMM)	counted	5%	10%	15%	20%	counted	5%	10%	15%	20%
Proved
Egypt	731.1	609.8	525.9	464.8	418.5	568.8	493.7	437.5	393.8	359.1
Yemen	65.7	57.9	51.7	46.6	42.5	83.2	72.6	64.3	57.6	52.3
Total Proved	796.9	667.7	577.6	511.4	460.9	652.0	566.3	501.7	451.5	411.3
Proved plus Probable
Egypt	970.1	781.6	656.2	567.5	501.7	832.1	701.9	606.8	534.8	478.5
Yemen	103.7	85.7	72.7	63.1	55.7	135.6	109.4	91.3	78.4	68.7
Total Proved plus Probable	1,073.8	867.2	728.9	630.7	557.4	967.7	811.3	698.2	613.1	547.1
Proved plus Probable plus Possible
Egypt	1,185.8	951.0	793.0	680.6	597.1	1,095.0	893.7	752.8	649.7	571.3
Yemen	132.7	106.5	88.4	75.4	65.6	164.1	130.5	107.6	91.3	79.2
Total Proved plus Probable plus Possible	1,318.5	1,057.6	881.4	756.0	662.7	1,259.2	1,024.3	860.5	740.9	650.5

The following table summarizes the constant pricing used to estimate future net revenues.



	December 31
Oil $/Bbl	2012	2011
Egypt*	102.60	97.86
Yemen*	108.41	109.71
* The constant price case is based on the average of the reference price received on the first day of each month during the respective year adjusted for respective differentials



58		2012