Filed by sedaredgar.com - TransGlobe Energy Corporation

2008 Capital Budget

($ million)

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

March 6, 2008 (except as to discontinued operations and subsequent events which are as of February 10, 2009)

The following restated and amended discussion and analysis (the “Restated 2007 MD&A”) is management’s opinion of TransGlobe Energy Corporation’s (“TransGlobe” or the “Company”) historical financial and operating results as at March 6, 2008 (except as to the treatment of discontinued operations and subsequent events which are as of February 10, 2009). The Restated MD&A should be read in conjunction with the audited consolidated financial statements and the notes thereto of the Company for the years ended December 31, 2007 and 2006, as amended and restated as at February 10, 2009 (the “Restated 2007 Financial Statements”). The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada in the currency of the United States (except where indicated as being another currency). The effect of significant differences between Canadian and United States accounting principles is disclosed in Note 16 of the consolidated financial statements. Additional information relating to the Company, including the Company’s Annual Information Form, is available on SEDAR at www.sedar.com. The Company’s annual report on Form 40-F may be found in the Electronic Data Gathering, Analysis and Retrieval (EDGAR) database at www.sec.gov.

As was announced on April 30, 2008, the Company sold its Canadian oil and natural gas interests to a third party for the purchase price of C$56.7 million, before normal closing adjustments. By reason of this disposition, the Company is required, as part of normal course compliance with Canadian GAAP, to restate the results of its prior periods, including in respect of its results for the 12-month period ended December 31, 2007. The specific purpose of such restatement is to account for the Canadian operations as discontinued operations. The Company has similarly restated the results of its prior, comparative periods in respect of its financial statements filed for the three months ended March 31, 2008, the three and six months ended June 30, 2008 and the three and nine months ended September 30, 2008.

As was also recently announced, the Company has entered into an agreement with a syndicate of underwriters respecting the purchase for resale, on a bought deal basis, of 5,798,000 common shares (“Common Shares”) of the Company at C$3.45 per Common Share (the “Offering”) to raise gross proceeds of approximately C$20.0 million. In order to comply with Canadian generally accepted accounting standards, the Company is required to file the Restated 2007 Financial Statements in conjunction with filing the preliminary prospectus for the Offering, and incorporate the Restated 2007 Financial Statements in such preliminary prospectus. Accordingly, the Restated 2007 Financial Statements and the Restated 2007 MD&A have been filed as at today's date - rather than being filed in conjunction with the filing of the audited financial statements for the 12-month period ended December 31, 2008.

No attempt has been made in this Restated 2007 MD&A to modify or update other events occurring or disclosures presented in the MD&A as originally filed, except as required to reflect the effects of the restatements discussed in the foregoing.

This Management’s Discussion and Analysis (MD&A) may include certain statements that may be deemed to be “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. All statements in this annual report, other than statements of historical facts that address future production, reserve potential, exploration drilling, exploitation activities and events or developments that the Company expects, are forward-looking statements. Although TransGlobe believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements. Factors that could cause actual results to differ materially from those expressed in forward-looking statements include, but are not limited to, oil and gas prices, well production performance, exploitation and exploration successes, continued availability of capital and financing, and general economic, market or business conditions.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

($000s, except per-share, price and volume amounts)		%			%
	2007	Change		2006	Change	2005
Total Operations
Average production volumes (Boepd)*	5,651	11		5,093	2	4,991
Average sales volumes (Boepd)*	5,692	12		5,077	2	4,959
Average price ($/Boe)	65.80	12		58.92	18	49.92

Oil and gas sales	136,709	25		109,190	21	90,350

Oil and gas sales, net of royalties and other	87,911	25		70,097	19	58,911

Cash flow from operations**	52,141	12		46,763	23	38,077
Cash flow from operations per share
- Basic	0.87			0.80		0.66
- Diluted	0.86			0.77		0.63

Net income	12,802	(51	)	26,195	32	19,850
Net income per share
- Basic	0.21			0.45		0.34
- Diluted	0.21			0.43		0.33
Total assets	204,219	75		116,473	35	86,286

Long-term debt	51,958			-		-
Reserves***
Total Proved (MMBoe)	11.9	27		9.3	19	7.8
Total Proved plus Probable (MMBoe)	16.4	41		11.7	11	10.5

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

($000s, except per-share, price and volume amounts)		%			%
	2007	Change		2006	Change		2005
Continuing Operations
Average production volumes (Boepd)*
Average sales volumes (Boepd)*	4,258	5		4,046	(1	)	4,092
Average price ($/Boe)	72.17	14		63.10	24		51.09

Oil and gas sales	112,171	20		93,189	22		76,300

Oil and gas sales, net of royalties and other	67,628	19		56,836	20		47,384

Cash flow from continuing operations**	36,070	(1	)	36,501	28		28,584
Cash flow from continuing operations per share
- Basic	0.61			0.62			0.49
- Diluted	0.60			0.60			0.47

Net income from continuing operations	8,380	(64	)	23,332	72		13,542
Net income from continuing operations per share
- Basic	0.14			0.40			0.23
- Diluted	0.14			0.39			0.22

Reserves***
Total Proved (MMBoe)	9.4	34		7.0	32		5.3
Total Proved plus Probable (MMBoe)	12.6	58		8.0	18		6.8

In 2007, production per day increased 11% over the previous year, mainly from increases realized in Canada and the newly acquired Egyptian properties effective September 25, 2007. During the year, TransGlobe spent $37.0 million on exploration and development activities and drilled 26 successful wells.

TransGlobe replaced 222% of production in 2007 and increased proved reserves by 2.6 MMBoe, including the Egypt Acquisition that closed in September.

Cash flow from operations increased by 12% in 2007 compared with 2006, mainly as a result of higher realized prices, larger production volumes in Canada, and from the September 2007 acquisition of Egyptian assets (the “Egypt Acquisition”), offset by higher royalties, operating costs and taxes paid.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Net income for 2007 decreased 51% from 2006 mainly due to higher depletion, depreciation and accretion costs resulting from the write-down necessitated by two dry wells drilled in the Nuqra Block in Egypt, higher per-unit-of-production charges in Canada and Yemen, as well as a $7.1 million non-cash unrealized derivative loss on commodity contracts.

On September 25, 2007, TransGlobe Petroleum International Inc.(“TGPI”), a wholly-owned subsidiary of TransGlobe Energy Corporation, acquired all the shares of Dublin International Petroleum (Egypt) Limited (“Dublin”) and Drucker Petroleum Inc. (“Drucker”) for US$59 million, plus working capital adjustments, as at July 1, 2007. Dublin and Drucker together hold a 70% working interest in the West Gharib Production Sharing Concession (“PSC”). TransGlobe has assumed operatorship of the West Gharib PSC on September 25, 2007.

The West Gharib PSC is located onshore in the western Gulf of Suez rift basin of Egypt. The eight approved West Gharib development leases encompass 178 square kilometers (approximately 44,059 acres) and are valid for 20 years, expiring between 2019 and 2026. One additional development lease at East Hoshia, was subsequently approved by the Egyptian General Petroleum Corporation (“EGPC”) on January 31, 2008. Eight of the nine development leases (excluding the Hana development lease) are encumbered with a 25% financial interest through an investment agreement between Dublin and a private company. The 25% financial interest is non-voting but otherwise is treated as a 25% participating interest partner.

On February 5, 2008, TGPI acquired all the shares of GHP Exploration (“GHP”) for US$40.2 million, plus working capital adjustments, as at September 30, 2007. GHP holds a 30% working interest in the West Gharib PSC.

With the acquisition of GHP, the Company holds a 100% working interest in the West Gharib PSC, with an effective working interest of 100% in the Hana development lease and an effective working interest of 75% in the eight non-Hana development leases.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

In 2008, TransGlobe’s strategy is to focus on expanding its international asset base. Historically, TransGlobe has experienced higher growth rates and a higher return on investment from its international properties. To enhance this trend, the Company will allocate all its capital and human resources to explore and develop its international properties and to increase its international asset base. Accordingly, management has decided to divest of the Canadian assets and re-deploy the capital into new international ventures.

The production forecast for 2008 is an average of between 6,900 and 7,100 Boepd, including the recent acquisition of an additional 900 Bopd of production in the West Gharib PSC. A number of projects are underway that are anticipated to increase oil production during 2008. The 2008 forecast incorporates the divestment at April 1, 2008 of TransGlobe’s Canadian production totalling approximately 1,400 Boepd. TransGlobe is planning to participate in a total of 28 exploration and development wells in Egypt and Yemen during the year. Also included in the forecast are anticipated production increases from development wells in West Gharib. However, the Company has not included any assumptions of production increases from exploration success or development drilling in Yemen. The Company will update its 2008 forecast quarterly or upon completion of significant facilities and/or developments.

This outlook was developed using the above production forecast, a dated Brent oil price of $80.00/Bbl and a natural gas price of C$7.00/Mcf.

* % growth based on mid-point of guidance.
** Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

While production is forecast to grow by 24% year-over-year, cash flow is only increasing by 6% mainly as a result of higher interest charges resulting from an elevated debt level and lower average netbacks received from the West Gharib medium-gravity oil production.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Variations in production and commodity prices during 2008 could significantly change this outlook. An estimate of the price sensitivity on the production forecast is shown below. During January and February 2008, the dated Brent oil price averaged $93.52/Bbl, and the price for natural gas averaged approximately C$7.23/Mcf. For each dollar of change in dated Brent oil prices, the Company’s annual cash flow changes by approximately $0.4 million.

Total capital expenditures of $58.6 million will be applied to the drilling of up to 18 (16 development and 2 exploration) wells in Egypt and up to 12 wells in Yemen, evenly divided into development wells and exploration wells. The Company attaches a significantly higher risk to the exploratory wells. The 2008 capital budget is expected to be funded from cash flow and working capital. The Company may use additional debt or equity financing in the future to accelerate existing projects or to finance new opportunities.

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

		%		%
	2007	Change	2006	Change	2005
Dated Brent average oil price ($/Bbl)	72.60	12	64.88	19	54.57
WTI average oil price ($/Bbl)	72.27	9	66.09	17	56.46
Edmonton Par average oil price (C$/Bbl)	77.06	5	73.30	6	69.29
AECO average gas price (C$/MMBtu)	6.45	(1)	6.51	(25)	8.73
U.S./Canadian Dollar year-end exchange rate	0.9913	(15)	1.1654	-	1.1630
U.S./Canadian Dollar average exchange rate	1.0740	(5)	1.1343	(6)	1.2114

World crude oil prices continued to increase significantly in 2007, with global demand for oil remaining strong and outpacing supply increases. As well, geopolitical concerns, mainly in Iraq, Nigeria and Venezuela continued to affect supply uncertainties.

In 2007, TransGlobe sold approximately 95% of its crude oil at dated Brent minus the selling price differentials and the remaining 5% at the Edmonton Par price less quality differentials.

Demand for natural gas was relatively weak during the year and natural gas prices remained relatively flat over 2006. In 2007, TransGlobe sold its natural gas at AECO Index-based pricing and fixed pricing.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

In 2007, the Company had continuing operations in two geographic areas, segmented into Egypt and Yemen and discontinued operations in Canada. The MD&A for the continuing operations will follow. Please refer to “Operating Results from Discontinued Operations” for the MD&A on the Canadian segment.

With the Egypt Acquisition completed late in the third quarter of 2007, production of 1,607 Bopd from the West Gharib PSC is included in TransGlobe’s results (September 25, 2007 to December 31, 2007). Calculated as an annual average, the added production from this acquisition totaled 432 Bopd for 2007. The average selling price during that period for this production was $68.13/Bbl, which represents a gravity/quality adjustment of approximately $17.86/Bbl to an average dated Brent price for the period of $85.99/Bbl.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Yemen operating results are generated from two non-operated Blocks: Block 32 (13.81087% working interest) and Block S-1 (25% working interest).

Net operating income in Yemen increased 1% in 2007 primarily as a result of an oil sales increase over the prior year of 9%. While oil prices grew by 15% over the prior year, sales volumes dropped by 5% primarily as a result of lower sales from Block 32 due to natural declines associated with the Tasour field.

Royalty and current income tax expenses increased 13% mainly due to higher commodity prices. Royalties as a percentage of revenue (royalty rate) increased to 40% in 2007 compared to 39% in 2006 while current income tax as a percentage of revenue increased to 11% compared to 10% in 2006.

Operating expenses on a Boe basis increased 35% to $7.40/Bbl in 2007 compared with $5.49 in 2006.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Cash flow from operations increased in the reporting period by $0.6 million (4%) compared with the third quarter of 2007 mainly as a result of a 31% increase in sales volumes and a 13% hike in average commodity prices, offset by increased royalties, taxes and operating costs.

Net income decreased 114% in the fourth quarter of 2007 compared with the prior quarter mainly as a result of a derivative loss on commodity contracts of $6.8 million ($0.11 per diluted share).

Comparing the second quarter of 2007 with the first quarter of that year, net income decreased 61% due to the write-off in the second quarter of Egypt capital related to the costs of drilling two dry holes at Nuqra ($0.06 per diluted share).

TransGlobe uses financial derivatives as part of its risk management approach to manage commodity price fluctuations and stabilize cash flows for future exploration and development programs. The Company has fair valued these financial derivative contracts. As at December 31, 2007, the estimated fair value of these contracts is a liability of $7.1 million, which results in an unrealized loss of $7.1 million being recorded to the income statement for the year ended December 31, 2007 (2006 - $0.1 million). The estimated fair market value at December 31, 2007 was based on a dated Brent oil price of $96.02/Bbl.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Period	Volume	Type	Dated Brent
			Pricing
			Put - Call
Crude Oil
May 1, 2007-December 31, 2007	15,000 Bbls/month	Financial Collar	$57.50-$79.80
September 1, 2007-August 31, 2008	15,000 Bbls/month	Financial Collar	$60.00-$78.55
January 1, 2008-December 31, 2008	12,000 Bbls/month	Financial Collar	$60.00-$81.20
January 1, 2009-December 31, 2009	12,000 Bbls/month	Financial Collar	$60.00-$82.10
November 1, 2007-March 31, 2008	5,000 Bbls/month	Financial Collar	$65.00-$89.35
September 1, 2008-January 31, 2009	11,000 Bbls/month	Financial Collar	$60.00-$88.80
February 1, 2009-December 31, 2009	6,000 Bbls/month	Financial Collar	$60.00-$86.10
January 1, 2010-August 31, 2010	12,000 Bbls/month	Financial Collar	$60.00-$84.25
Natural Gas
April 1, 2007-October 31, 2007	2,500 GJ/day	Physical	C$6.97

The hedging program was expanded significantly in September 2007 to protect the cash flows from the added risk of commodity price exposure following a marked increase in TransGlobe’s debt levels resulting from the Egypt Acquisition.

General and administrative expenses (“G&A”) increased 44% in 2007 (29% increase on a Boe basis) compared with 2006 mainly as a result of increased staffing levels and higher fees caused by compliance requirements (Sarbanes-Oxley). With higher production levels in 2008, G&A costs per Boe are expected to decrease.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

In Egypt, depletion, depreciation and accretion expense (“DD&A”) increased to $7.2 million in 2007 due to $4.1 million in dry-hole costs related to the Nuqra Block written off during the year. As well, production from the West Gharib PSC resulted in a $3.1 million charge to DD&A in 2007. The DD&A of $3.1 million is due to the fact that DD&A is depleted on proved reserves, while the purchase price for the Egypt Acquisition was based on proved plus probable reserves.

In Yemen, DD&A on a Boe basis increased 11% in 2007 compared with 2006 primarily as a result of less reserve additions in Yemen than in the prior year.

In Egypt and Yemen, unproven property costs of $9.2 million and $5.0 million, respectively, were excluded from costs subject to depletion and depreciation.

Current income tax expense in 2007 represents income taxes incurred and paid under the laws of Egypt pursuant to the West Gharib PSC and Yemen pursuant to the PSAs on Block 32 and Block S-1. The increase in Egypt is the result of the addition of the West Gharib concession in 2007. The income tax in Egypt as a percent of Egypt revenue was 16% in 2007. The year-over-year increase in Yemen is primarily the result of higher revenue from that country. The income tax expense in Yemen as a percent of Yemen revenue was 11% in 2007 and 10% in 2006.

In Egypt, the Company drilled two wells in the West Gharib area and two exploration wells in the Nuqra Block. Late in the third quarter, the Company acquired the shares two private companies (Dublin and Drucker) that hold a working interest in the West Gharib PSC and valued the property, plant and equipment of the acquired companies at $54.8 million. Goodwill of $4.3 million was recorded. Subsequent to year-end, TransGlobe increased its interest in the PSC by a further 30% through the corporate acquisition of GHP Exploration (West Gharib) Ltd.

In Yemen, the Company drilled five wells and re-entered one well on Block S-1; drilled five wells on Block 32; one well on Block 72; and commenced a 3-D seismic program on Block 72 to be completed in the first quarter of 2008. The construction and commissioning of the expanded An Nagyah Central Production Facility (“CPF”) was completed, with all An Nagyah oil now being processed through the CPF.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

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

Canadian National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities, specifies how finding and development (F&D) costs should be calculated. Canadian National Instrument 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 reserve and costs. TransGlobe believes that the provisions of Canadian National Instrument 51-101 do not fully reflect TransGlobe’s ongoing reserve replacement costs. Since acquisitions can have a significant impact on TransGlobe’s annual reserve 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 all acquisitions net of any dispositions during the year.

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.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

The recycle ratio measures the efficiency of TransGlobe’s capital program by comparing the cost of finding and developing proved reserves with the netback from production. The ratio is calculated by dividing the netback by the proved finding and development costs or finding, development and acquisition costs on a Boe basis. Netback is defined as net sales less operating, general and administrative (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Boe of production.

As at December 31, 2007 TransGlobe had 59,626,539 common shares issued and outstanding.

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. TransGlobe’s capital programs are funded principally by cash provided from operating activities.

The following table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2007 and 2006:

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Funding for the Company’s capital expenditures and the Egypt Acquisition in the third quarter of 2007 was provided by cash flow from operations, working capital and long-term debt.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2007, the Company had working capital of $5.5 million (2006 - $4.4 million). Accounts receivable grew primarily as a result of the Egypt Acquisition. Accounts payable remained consistent: lower drilling activity in Yemen and Canada was offset by the addition of the accounts payable added to the Company’s balance sheet with the Egypt Acquisition.

During the year, the Company increased its borrowing base from $25.0 million to $50.0 million under the Revolving Credit Agreement and established a new Term Loan of $13.0 million. At December 31, the Revolving Credit Agreement was fully drawn and $8.0 million was drawn against the Term Loan.

The Company expects to fund its approved 2008 exploration and development program of $58.6 million through the use of working capital and cash flow. The use of additional debt or equity financing during 2008 may also be utilized to accelerate existing projects or to finance new opportunities. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources.

Subsequent to year-end, the Company increased its Term Loan of $8.0 million to $48.0 million. The Company plans to repay a portion of the long-term debt with any proceeds resulting from the disposition of the Canadian assets in 2008.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

As part of its normal business, the Company entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity, some of which are reflected as liabilities in the Consolidated Financial Statements at year-end. The principal commitments of the Company are in the form of debt repayments, lease commitments relating corporate offices and equipment, abandonment obligations, and minimum work commitments under various international agreements.

Additional discussion of Company’s debt repayment obligations and significant commitments can be found in notes 5 and 13 to the Consolidated Financial Statements. A discussion of the Company’s derivative commodity contracts can be found in the Commodity Contracts section of the MD&A.

The following table includes the Company’s expected future payment commitments as at December 31, 2007 and estimated timing of such projects.

($000s)	Payment Due by Period^1,2
		Less than	1-3	4-5	More than
	Total	1 year	years	years	5 years
Long-term debt:
Term Loan Agreement	8,000	4,727	3,273	-	-
Revolving Credit Agreement	50,000	-	50,000	-	-
Office and equipment leases	1,189	372	796	21	-
Abandonment obligations³	3,563	346	684	2,047	486
Minimum work commitments⁴	13,700	-	5,300	8,400	-

Total	76,452	5,445	60,053	10,468	486

The following applies to the Canadian operations only. The sale of the Canadian operations closed April 30, 2008. The Canadian operations have been accounted for as discontinued operations in accordance with Canadian GAAP on a retroactive basis and the results at December 31, 2007 and 2006 and for the years then ended have been restated accordingly.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Net operating income in Canada increased 57% in 2007 primarily as a result of a 39% increase in production and a commodity price increase of 10% per Boe.

Royalty costs increased 12% on a Boe basis. Royalties as a percentage of revenue in 2007 were consistent with the prior year at 17%. The Alberta government discontinued the Alberta Royalty Tax Credit program effective January 1, 2007. As a result, the Company’s royalties increased by C$0.5 million in 2007.

Operating expenses per Boe remained consistent in 2007 with those recorded for 2006.

On October 25, 2007, the Government of Alberta announced changes to the royalty program in Alberta. The proposed changes are scheduled to become effective January 1, 2009 and are not expected to impact TransGlobe’s cash flow in 2008.

In Canada, DD&A on a Boe basis increased 16% in 2007 compared to 2006 primarily as a result of increased finding and development costs in Canada.

In Canada, unproven property costs of $3.9 million were excluded from costs subject to depletion and depreciation.

The future income expense relates to a non-cash expense for taxes to be incurred in the future as Canadian tax pools reverse.

No income tax was paid in Canada in 2007. At December 31, 2007, the Company has C$54 million in Canadian tax pools.

In Canada, the Company drilled a total of 18 (7.2 net) wells in Central Alberta. The Company also carried out completion and testing work on thirteen wells, completed facility work in Nevis to optimize production, and acquired lands on several new prospects.

On February 5, 2008, TransGlobe Energy Corporation announced the closing of the acquisition of privately-held GHP Exploration (West Gharib) Ltd. (“GHP”). TransGlobe acquired all the shares of GHP for $40.2 million, plus working capital adjustments, effective September 30, 2007. The acquisition is funded from bank debt and cash on hand. GHP holds a 30% interest in the West Gharib Concession area in Egypt.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Also on February 5, 2008, the Company increased its Term Loan Agreement of $8.0 million to $48.0 million. The Term Loan repayment terms increased to $4.8 million per quarter, commencing June 30, 2008.

On April 15, 2008, the Company entered into an agreement with a third party for the sale of its Canadian oil and natural gas interests. The sale price of the assets was C$56.7 million, subject to normal closing adjustments. The sale closed on April 30, 2008. The Canadian operations have been accounted for as discontinued operations in accordance with Canadian GAAP on a retroactive basis and the consolidated financial statements as at December 31, 2007 and 2006 and for the years then ended, have been restated accordingly. Results of the Canadian operations have been included in the financial statements up to the closing date of the sale (the date control was transferred to the purchaser). The Company used the cash proceeds from the sale and cash on hand to repay $55.0 million of debt.

On August 18, 2008, TransGlobe completed an oil and gas property acquisition in Egypt for the 25% financial interest in the eight non-Hana development leases. The total cost of the acquisition was $18.5 million, subject to closing adjustments to the effective date of June 1, 2008. This property acquisition was funded from bank debt of $15.0 million on cash on hand. In addition, the Company could pay up to an additional $7.0 million if incremental reserve thresholds are reached in the East Hoshia (up to $5.0 million) and in South Rahmi (up to $2.0 million) development leases. The value of the net assets acquired has been assigned to property and equipment. As a result of this property acquisition, TransGlobe now holds a 100% working interest in the West Gharib Concession in Egypt.

On February 4, 2009, the Company announced it has entered into an agreement with a syndicate of underwriters, under which the members of the syndicate have agreed to purchase for resale, on a bought deal basis, 5,798,000 common shares of the Company at C$3.45 per Common Share to raise gross proceeds of approximately C$20.0 million. Closing of the Offering, which is subject to customary conditions and regulatory approvals, including approval of the Toronto Stock Exchange and the NASDAQ, is expected to occur on or about February 24, 2009. TransGlobe has also granted the underwriters an over-allotment option to purchase, on the same terms, up to an additional 869,700 Common Shares. This option is exercisable, in whole or in part, by the underwriters, in their sole discretion, at any time up to 30 days after closing. The maximum gross proceeds raised under the Offering will be approximately C$23.0 million, should the over-allotment option be exercised in full.

The preparation of financial statements in accordance with generally accepted accounting principles 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. The following is included in 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 1 of the Consolidated Financial Statements.

TransGlobe’s proved and probable oil and gas reserves are 100% evaluated and reported on by independent reserve evaluators. 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.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

TransGlobe follows the Canadian Institute of Chartered Accountants’ guideline on full cost accounting in the oil and gas industry to account for oil and gas properties. Under this method, all costs associated with the acquisition of, exploration for, and the development of natural gas and crude oil reserves are capitalized on a country-by-country cost centre basis and costs associated with production are expensed. The capitalized costs are depleted, depreciated and amortized using the unit-of-production method based on estimated proved reserves. Reserve estimates can have a significant impact on earnings, as they are a key component in the calculation of depletion, depreciation and amortization. A downward revision in a reserve estimate could result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserve estimates (see asset impairment discussion below), the excess must be written off as an expense charged against earnings. In the event of a property disposition, proceeds are normally deducted from the full cost pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20% or greater.

Certain costs related to unproved properties and major development projects are excluded from costs subject to depletion and depreciation until the earliest of a portion of the property becomes capable of production, development activity ceases or impairment occurs. These properties are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.

Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized costs in each cost centre do not exceed their fair value. An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than carrying amount, the impairment loss is limited to an amount by which the carrying amount exceeds the sum of:

The Company has recorded a future income tax asset in 2007 and 2006. This future income tax asset is an estimate of the expected benefit that will be realized by the use of deductible temporary differences in excess of carrying value of the Company’s Canadian property and equipment against future estimated taxable income. These estimates may change substantially as additional information from future production and other economic conditions such as oil and gas prices and costs become available.

The determination of the Company’s income tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at year-end exchange rates and revenues and expenses are translated using average annual exchange rates. Translation gains and losses relating to the self-sustaining operations are included as a separate component of shareholders’ equity.

Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Income and Retained Earnings.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

Derivative financial instruments are used by the Company to manage its exposure to market risks relating to commodity prices. The Company’s policy is not to utilize derivative financial instruments for speculative purposes.

Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded at fair values where instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net income. Realized gains or losses from financial derivatives related to commodity prices are recognized in revenues as they occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimation of the fair value of certain derivative financial instruments requires considerable judgment. The estimation of the fair value of commodity price instruments requires sophisticated financial models that incorporate forward price and volatility data. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when identified and a reasonable estimate of the fair value can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion in the Consolidated Statement of Income. Amounts recorded for asset retirement obligations are based on estimates of reserves and on retirement costs which will not be incurred for several years. Actual payment to settle the obligations may differ from estimated amounts.

The following accounting pronouncements had an impact on the financial statements of the Company in 2007:

Effective January 1, 2007, the Company adopted the new recommendations of the Canadian Institute of Chartered Accountants (CICA) under CICA Handbook Section 1530, Comprehensive Income, Section 1651, Foreign Currency Translation, Section 3251, Equity, Section 3855, Financial Instruments – Recognition and Measurement, Section 3861, Financial Instruments Disclosure and Presentation and Section 3865, Hedges. These new Handbook Sections provide requirements for the recognition and measurement of financial instruments in the balance sheet, reporting gains or losses in the financial statements and the use of hedge accounting.

Under Section 3855, all financial instruments are initially measured in the balance sheet at fair value. Subsequent measurement of the financial instruments is based on their classification. The Company has classified each financial instrument into one of these five categories: held-for-trading, held-to-maturity investments, loans and receivables, available-for-sale financial assets or other financial liabilities. Loans and receivables, held-to-maturity investments and other financial liabilities are measured at amortized cost using the effective interest rate method. For all financial assets and financial liabilities that are not classified as held-for-trading, the transaction costs that are directly attributable to the acquisition or issue of a financial liability are adjusted to the fair value initially recognized for that financial instrument. These costs are expensed using the effective-interest-rate method and are recorded within interest expense. Held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income. Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive income until the instrument is derecognized or impaired. All derivative instruments are recorded in the balance sheet at fair value unless they qualify for the expected purchase, sale and usage exemption. All changes in their fair value are recorded in income unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

As a result of the adoption of these new standards, the Company has classified its derivative commodity contracts and cash and cash equivalents as held-for-trading, which are measured at fair value with changes being recognized in net income. Accounts receivable are classified as loans and receivables; operating bank loans, accounts payable and accrued liabilities, and long-term debt, including interest payable, are classified as other liabilities, all of which are measured at amortized cost. The classification of all financial instruments is the same at inception and at December 31, 2007. The Company has elected to classify all derivatives and embedded derivatives as held-for trading, which are measured at fair value with changes being recognized in net income, and the Company has maintained its policy not to use hedge accounting. The Company elected January 1, 2003 as the transition date for embedded derivatives.

Section 1530 establishes standards for reporting and presenting comprehensive income which is defined as the change in equity from transactions and other events from non-owner sources. Other comprehensive income refers to items recognized in comprehensive income but that are excluded from net income calculated in accordance with generally accepted accounting principles. Due to the issuance of Section 1530, Section 1650 has been replaced by Section 1651 which establishes new standards for presentation of exchange gains and losses arising from the translation of self-sustaining foreign operation in Other Comprehensive Income. Therefore, the Company has restated prior periods to include cumulative translation adjustment on self-sustaining operations as Other Comprehensive Income.

Section 3251, Equity, which replaces Section 3250, Surplus, establishes standards for the presentation of equity and changes in equity during the reporting period. The main feature of this section is a requirement for an entity to present separately each of the changes in equity during the period, including comprehensive income, as well as components of equity at the end of the period.

The Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have an impact on the Company:

The Accounting Standards Board (AcSB) issued Canadian Institute of Chartered Accountants (CICA) Section 1535, Capital Disclosures. The main features of this section are to establish requirements for an entity to disclose qualitative information about its objectives, policies and processes for managing capital, quantitative data about what it regards as capital, and whether it has complied with any externally imposed capital requirements and, if not, the consequences of such non-compliance. The new requirements are effective for annual and interim periods beginning on or after October 1, 2007, and, upon adoption, are not expected to materially impact the Consolidated Financial Statements.

Effective January 1, 2007, the Company adopted the revised recommendations of Section 1506, Accounting Changes. The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting policies, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007.

The only impact of adopting this section is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862, Financial Instruments Disclosures, and Section 3863, Financial Instruments Presentations, which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company will adopt these standards on January 1, 2008 and it is expected the only effect on the Company will be incremental disclosures regarding the significance of financial instruments for the entity’s financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the entity is exposed.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

In February 2008, the Canadian Institute of Chartered Accountants (“CICA”) issued Section 3064, Goodwill and intangible assets, replacing Section 3062, Goodwill and other intangible assets and Section 3450,

Research and development costs. Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new Section will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. It establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company is currently evaluating the impact of the adoption of this new Section on its Consolidated Financial Statements.

In January 2006, the Accounting Standards Board (“AcSB”) adopted a strategic plan for the direction of accounting standards in Canada. On February 13, 2008, the AcSB has confirmed that effective for interim and annual financial statements related to fiscal years beginning on or after January 1, 2011, International Financial Reporting Standards (IFRS) will replace Canada’s current Generally Accepted Accounting Principles (“GAAP”) for all publicly accountable profit-oriented enterprises. The Company is currently evaluating the impact of this changeover on its consolidated financial statements.

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

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 factors:

TransGlobe mitigates its exposure to financial risks through the use of various financial instruments and physical contracts. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

The Company uses financial derivatives to manage commodity price fluctuations and stabilize cash flows for future exploration and development programs. To mitigate its price risk, the Company entered into a number of costless collar contracts. The Company also enters into physical fixed price gas sales contracts when deemed appropriate.

The Company’s operations are exposed to fluctuations in foreign currency exchange rates. Variations in the foreign currency exchange rate could have a significant positive or negative impact. The Company manages its foreign currency exchange risk by maintaining foreign currency bank accounts and receivable accounts to offset foreign currency payables and planned expenditures.

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 the year to mitigate this risk.

The majority of the accounts receivable are in respect of oil and gas operations. The Company generally extends unsecured credit to these customers and therefore the collection of accounts receivable 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 loss in the collection of accounts receivable to date.

In Egypt, the Company sold all of its 2007 production to one purchaser. In Yemen, the Company sold all of its 2007 Block 32 production to one purchaser and all of its 2007 Block S-1 production to one purchaser. In Canada, the Company sold primarily all of its 2007 gas production to one purchaser and primarily all of its 2007 oil production to another single purchaser.

TransGlobe mitigates operational risk through a number of policies and processes. 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.

To mitigate environmental risks, the Company conducts its operations to ensure compliance with respective government regulations and guidelines,. At this time, it is not possible to predict either the nature of the Kyoto Protocol requirements or impact on the Company.

Security risks are managed through security policies 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.

TransGlobe takes a proactive approach to the identification and management of issues that affect the Company’s reputation and has established policies such as a code of conduct for the Company in order to mange these issues.

TRANSLGOBE ENERGY CORPORATION
MANAGEMENT’S DISCUSSION AND ANALYSIS (Amended and Restated)

As of December 31, 2007, 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, of 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 information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.

TransGlobe’s Management has designed and implemented internal controls over financial reporting, as defined under Multilateral Instrument 52-109 of the Canadian Securities Administrators. As Public Accounting Oversight Board Release 2007-005, the private companies acquired on September 25, 2007 are excluded from this scope for 2007 but will be included for 2008.

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 Canadian generally accepted accounting principles, including a reconciliation to U.S. generally accepted accounting principles, 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.

As at the date of this report, management is not aware of any change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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 (“COSO”) framework on Internal Control – Integrated Framework. Management has excluded from its assessment the internal control over financial reporting at Dublin and Drucker, which were acquired on September 25, 2007 and whose financial statements constitute 55 percent and 35 percent of net and total assets, respectively, 8 percent of revenues, and 9 percent of net income of the Consolidated Financial Statement amounts as of and for the year ended December 31, 2007. Subject to the foregoing, as at the date of this report management is not aware of any change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Based on this assessment, management believes that the internal controls over financial reporting provide reasonable assurance regarding the preparation and presentation of the Consolidated Financial Statements as at December 31, 2007.

*	The differences in production and sales volumes result from inventory changes.
**	Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non- cash working capital.
***	Working interest before royalties.

*	The differences in production and sales volumes result from inventory changes.
**	Cash flow from continuing operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.
***	Working interest before royalties.

2007 Variances
			$Per Share		%
	$000s		Diluted		Variance
2006 Net Income	26,195		0.43
Cash items
Volume variance	14,772		0.24		56
Price variance	12,747		0.21		49
Royalties	(9,705	)	(0.16	)	(37	)
Expenses:
Operating	(4,161	)	(0.07	)	(16	)
Realized derivative gain (loss)	(881	)	(0.01	)	(3	)
Cash general and administrative	(2,177	)	(0.04	)	(8	)
Current income taxes	(3,501	)	(0.06	)	(13	)
Realized foreign exchange gain (loss)	(17	)	-		-
Settlement of asset retirement obligations	(149	)	-		(1	)
Interest on long-term debt	(1,450	)	(0.02	)	(6	)
Other income	(100	)	-		-
Total cash items variance	5,378		0.09		21
Non-cash items
Unrealized derivative gain (loss)	(7,015	)	(0.12	)	(27	)
Depletion, depreciation and accretion	(12,231	)	(0.19	)	(47	)
Future income taxes	218		-		1
Stock-based compensation (non-cash)	82		-		-
Settlement of asset retirement obligations	149		-		1
Amortization of deferred financing costs	26		-		-
Total non-cash items variance	(18,771	)	(0.31	)	(72	)
2007 Net Income	12,802		0.21		(51	)

	2008	2007	Change*

Barrels of oil equivalent per day	6,900-7,100	5,651	24

2008 Cash Flow From Operations Outlook
($ million)	2008	2007	Change*

Cash flow from operations**	53.0 – 57.0	52.1	6

		2007	2006	% Change
Egypt - Oil sales*	Bopd	432	-	-
Yemen - Oil sales	Bopd	3,826	4,046	(5	)
Total continuing operations
- daily sales volumes	Bopd	4,258	4,046	5
Canada - Oil and liquids sales	Bopd	402	331	22
- Gas sales	Mcfpd	6,193	4,204	47
Canada	Boepd	1,434	1,031	39
Total Company – daily sales volumes	Boepd	5,692	5,077	12

	2007		2006
(000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil sales	10,731	68.13	-	-
Royalties and other	4,202	26.67	-	-
Current income tax	1,735	11.02	-	-
Operating expenses	722	4.59	-	-
Net operating income	4,072	25.85	-	-

	2007					2006
($000s, except per-share, price and
volume amounts)	Q-4		Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Average production volumes (Boepd)*	6,837		5,227	5,353	5,175	5,475	4,952	4,915	5,026
Average sales volumes (Boepd)*	6,837		5,227	5,353	5,341	5,313	4,952	5,522	4,515
Average price ($/Boe)	75.83		67.04	63.68	53.58	55.30	61.88	62.17	55.93

Oil and gas sales	47,699		32,240	31,016	25,754	27,032	28,190	31,238	22,730

Oil and gas sales, net of royalties
and other	29,343		20,764	20,553	17,251	17,647	18,542	18,600	15,308

Cash flow from operations**	13,944		13,373	12,814	12,010	10,448	12,662	12,356	11,297
Cash flow from operations per share
- Basic	0.23		0.22	0.22	0.20	0.18	0.22	0.21	0.19
- Diluted	0.23		0.22	0.21	0.20	0.17	0.21	0.20	0.19

Net income	(719	)	5,198	2,343	5,980	4,726	7,366	7,246	6,857
Net income per share
- Basic	(0.02	)	0.09	0.04	0.10	0.08	0.13	0.12	0.12
- Diluted	(0.01	)	0.08	0.04	0.10	0.08	0.12	0.12	0.11

Proved
($000s, except volumes and per Boe amounts)	2007		2006		2005
Total capital expenditure	37,015		51,555		32,654
Acquisitions (including goodwill and future capital)	62,821		-		-
Net change from previous year’s future capital	(2,467	)	(1,154	)	8,418
	97,369		50,401		41,072
Reserve additions and revisions (MBoe)
Exploration and development	1,634		3,371		2,987
Acquisitions	2,953		-		-
Total reserve additons (Mboe)	4,587		3,371		2,987

Average cost per Boe
F&D	21.14		14.95		13.75
FD&A	21.23		14.95		13.75

Three-year average cost per Boe
F&D	15.77		11.85		9.57
FD&A	17.25		11.85		9.57

Proved Plus Probable
($000s, except volumes and per Boe amounts)	2007		2006		2005
Total capital expenditure	37,015		51,555		32,654
Acquisitions (including goodwill and future capital)	68,716		-		-
Net change from previous year’s future capital	(6,587	)	3,943		9,449
	99,144		55,498		42,103
Reserve additions and revisions (MBoe)
Exploration and development	1,537		3,025		1,879
Acquisitions	5,264		-		-
Total reserve additons (MBoe)	6,801		3,025		1,879

Average cost per Boe
F&D	19.79		18.35		22.41
FD&A	14.58		18.35		22.41

Three-year average cost per Boe
F&D	19.88		12.83		8.19
FD&A	16.81		12.83		8.19

	Three
Proved	Year
	Average	2007	2006	2005
Netback ($/Boe)	23.86	25.10	25.23	21.04
Proved F&D costs ($/Boe)	15.77	21.14	14.95	13.75
Proved FD&A costs ($/Boe)	17.25	21.23	14.95	13.75
F&D Recycle ratio	1.51	1.19	1.69	1.53
FD&A Recycle ratio	1.38	1.18	1.69	1.53

	Three
Proved Plus Probable	Year
	Average	2007	2006	2005
Netback ($/Boe)	23.86	25.10	25.23	21.04
Proved plus Probable F&D costs ($/Boe)	19.88	19.79	18.35	22.41
Proved plus Probable FD&A costs ($/Boe)	16.81	14.58	18.35	22.41
F&D Recycle ratio	1.20	1.27	1.38	0.94
FD&A Recycle ratio	1.42	1.72	1.38	0.94

($000s)	December 31, 2007		December 31, 2006
Revolving Credit Agreement	50,000		-
Term Loan Agreement	8,000		-
	58,000		-
Unamortized transaction costs	(1,315	)	-
	56,685		-

Current portion of long-term debt	4,727		-
Long-term debt	51,958		-

1.	Payments exclude ongoing operating costs related to certain leases, interest on long-term debt and payments made to settle derivative contracts.

2.	Payments denominated in foreign currencies have been translated at December 31, 2007 exchange rate.

3.	The abandonment obligation represents management’s probability weighted, undiscounted best estimate of the cost and timing of future dismantlement, site restoration and abandonment obligations based on engineering estimates and in accordance with existing legislation and industry practice.

4.	Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

Canada
	2007		2006
(000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil sales	5,147	66.82	3,178	58.45
Gas sales ($ per Mcf)	15,018	6.64	9,478	6.18
NGL sales	3,954	56.49	3,266	49.24
Other sales	419	-	79	-
	24,538	46.85	16,001	42.51
Royalties and other	4,255	8.12	2,740	7.28
Operating expenses	4,212	8.04	2,999	7.97
Net operating income	16,071	30.69	10,262	27.26

($000s, except per Boe amounts)	2007		2006
	$	$/Boe	$	$/Boe

Canada	11,604	22.17	7,136	18.96

	2007					2006
($000s, except per-share, price and
volume amounts)	Q-4		Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Average production volumes (Boepd)*	5,333		3,830	3,964	3,892	4,208	3,986	3,836	4,051
Average sales volumes (Boepd)*	5,333		3,830	3,964	3,892	4,208	3,986	4,443	3,541
Average price ($/Boe)	83.14		74.72	69.72	57.14	58.25	66.88	67.05	59.64

Oil and gas sales	40,788		26,326	25,041	20,016	22,550	24,525	27,110	19,004

Oil and gas sales, net of royalties
and other	23,600		15,793	15,632	12,603	13,985	15,473	15,121	12,257

Cash flow from operations**	9,334		9,257	9,073	8,406	7,649	10,276	9,709	8,867
Cash flow from operations per share
- Basic	0.16		0.16	0.15	0.14	0.13	0.18	0.17	0.15
- Diluted	0.15		0.15	0.15	0.14	0.13	0.17	0.16	0.15

Net (loss) income	(2,302	)	4,166	1,416	5,100	4,018	6,947	6,318	6,049
Net income (loss) per share
- Basic	(0.04	)	0.07	0.02	0.09	0.07	0.12	0.11	0.10
- Diluted	(0.04	)	0.07	0.02	0.08	0.07	0.11	0.10	0.10

	2008	2009	2010
Bbls	323,000	221,000	96,000
Bopd	885	605	263

	2007				2006
(000s, except per Boe amounts)	$		$/Boe		$		$/Boe
G&A (gross)	7,971		3.84		5,914		3.19
Stock-based compensation	1,086		0.52		1,168		0.63
Capitalized G&A	(1,947	)	(0.94	)	(1,999	)	(1.08	)
Overhead recoveries	(367	)	(0.18	)	(409	)	(0.22	)
G&A (net)	6,743		3.24		4,674		2.52

	2007		2006
(000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Egypt	3,144	19.96	37	-
Write-off of dryhole costs (Nuqra Block)	4,111	-	-	-
Yemen	12,157	8.71	11,623	7.87
Corporate	156	-	145	-
	19,568	12.59	11,805	7.99

Income taxes
($000s)	2007	2006

Future income tax - Canada	45	263

Capital Expenditures
($000s)	2007	2006	%

Canada	11,653	19,419	(40)

	i)	the fair value of reserves; and
	ii)	the costs of unproved properties that have been subject to a separate impairment test.

•	Financial risks
	o	Crude oil and natural gas prices
	o	Foreign currency exchange and interest rate risk
	o	Credit risk
•	Operational risks
	o	Exploratory success
	o	Cost to find, develop, produce and deliver crude oil and natural gas
	o	Availability of equipment and labour to conduct field activities.
	o	Availability of pipeline capacity
•	Environmental, health, safety and security risks
	o	environmental preservation and safety concerns
	o	the Kyoto Protocol
	o	changes of laws affecting foreign ownership
	o	political risk of operating in foreign jurisdictions
	o	government regulation
•	Reputational risks