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TransGlobe Energy Corporation Announces Fourth Quarter and Year-End 2009 Financial and Operating Results

CALGARY, ALBERTA--(Marketwire - March 11, 2010) - TransGlobe Energy Corporation ("TransGlobe" or the "Company") (TSX:TGL)(NASDAQ:TGA) is pleased to announce its financial and operating results for the three months and year ended December 31, 2009. All dollar values are expressed in United States dollars unless otherwise stated. The conversion to barrels of oil equivalent ("Boe") of natural gas to oil is made on the basis of six thousand cubic feet of natural gas being equivalent to one barrel ("Bbl") of crude oil. With the sale of TransGlobe's Canadian assets on April 30, 2008 the results from the Canadian segment of operations are presented as "discontinued operations" in this document. HIGHLIGHTS 2009 - Production increased to 8,980 barrels of oil per day ("Bopd") from an average 7,342 Bopd in 2008, a growth rate of 22%; - Year-end 2009 Proved ("1P") reserves increased 53% to 19.2 million barrels ("MMBbl"), representing a production replacement for the year of 301%; - Year-end 2009 Proved plus Probable ("2P") reserves increased 22% to 24.2 MMBbl, representing a production replacement for the year of 234%; - Finding and development costs in 2009 of $3.77/Bbl (1P) and $5.17/Bbl (2P) with recycle ratios of 3.65 and 2.66, respectively; and - Return to positive earnings in Q4 with improved prices and a 53% increase in Proved reserves at year-end. 2010 - Achieved a record monthly production average of 9,921 Bopd in February 2010; - New exploration project added in Arab Republic of Egypt's ("Egypt") prolific Western Desert; - First successful fracture completion in the Arta field results in a 280 Bopd well; - Increased budget and guidance for 2010, powered by new production and improved oil price differentials at West Gharib; and - Oil-bearing interval encountered in the Cretaceous section of the Safwa #1 well in the East Ghazalat Block. 2009 Results Summary TransGlobe experienced substantial growth in reserves and production, primarily in our operated Egyptian properties. Company production increased to 8,980 Bopd from an average 7,342 Bopd in 2008, a growth rate of 22%. Year-end 2009 Proved reserves increased 53% to 19.2 MMBbl, representing a production replacement for the year of 301%. Proved plus Probable reserves increased 22% to 24.2 MMBbl, representing a production replacement for the year of 234%. The Company delivered excellent finding and development costs from low cost 2009 reserve additions attributed to the waterflood projects at Hana and Hoshia at year-end, combined with development drilling on the Hana West pool. In 2009, TransGlobe's finding and development costs were $3.77/Bbl of 1P reserves and $5.17/Bbl of 2P reserves. Positive earnings were reported in the fourth quarter of 2009 due to lower depletion rates which result from increased Proved reserves. With the 125% increase in proved reserves at West Gharib at year-end 2009, the per barrel depletion and depreciation ("DD&A") rate for Egypt was $8.96/Bbl in the fourth quarter, compared with an average DD&A rate of $20.82/Bbl during the first three quarters of 2009. 2010 Results To-Date and Outlook In January 2010, the selling price for West Gharib oil increased by 11% against dated Brent which will increase netbacks for 2010. The West Gharib oil is priced at a discount to dated Brent oil. The 2010 pricing is expected to be Brent less 8% to 10% versus the 2009 pricing of Brent less 24%. For example, the West Gharib sales price for a $65.00/Bbl Brent reference price is expected to be in the $59.00/Bbl range for 2010. The improved discount to Brent is a function of improved oil prices for heavier crude in 2010 and an improved West Gharib oil quality. In January 2010, the Company entered into a farm-out agreement to earn a 50% interest in the East Ghazalat Concession located in the prolific Western Desert of Egypt. The Company will pay 100% of three exploration wells to a maximum of $9.0 million. The addition of the East Ghazalat exploration project increases TransGlobe's land holding in Egypt to 3.9 million acres in three areas. In February 2010, the Arta #9 vertical well was successfully fracture ("frac") stimulated in the Nukhul formation, increasing oil production from 25 Bopd to 280 Bopd. This is the first frac stimulation the Company has carried out in the Nukhul. An expanded frac program on three to five existing vertical producers and a multi-stage frac on the Arta #12 horizontal well is now planned for the next two months. The results of the Arta frac stimulations could lead to a much larger, resource-type play. A Nukhul development fairway has been identified encompassing four producing fields and three undrilled prospects on TransGlobe lands. More than 50 potential drilling locations are located on these structures. The activity in West Gharib is expected to increase from 12 to 20 wells in 2010. A second drilling rig and an additional completion rig are currently being sourced. In February 2010, TransGlobe's production averaged 9,921 Bopd (a 15% increase over Q4 2009) with the addition of new producers at West Gharib and the successful frac stimulation at Arta #9. The Company has raised guidance for 2010 to reflect increased production and the improved pricing differential at West Gharib along with an expanded 2010 capital budget. Production for 2010 is expected to average between 10,000 Bopd and 10,500 Bopd, representing a 750 Bopd increase (8%) over the mid-point of previous guidance (9,500 Bopd). Funds flow from operations in 2010 is expected to be $67.0 million ($1.02/share), representing an increase of 22% over previous guidance (based on the mid-point of production guidance and a dated Brent oil price of $65.00/Bbl). The Company has increased the 2010 capital budget by $6.5 million to $63.0 million. The 2010 capital program has been expanded to accelerate the emerging Nukhul/Thebes project at West Gharib. The increased budget is expected to be funded from funds flow from operations and cash. A conference call to discuss TransGlobe's 2009 fourth quarter and year-end results presented in this news release will be held Thursday, March 11, 2009 at 2:30 PM Mountain Time (4:30 PM Eastern Time) and is accessible to all interested parties by dialing 1-416-340-8527 or toll-free 1-877-240-9772 (see also TransGlobe's news release dated March 4, 2010). The webcast may be accessed at http://events.digitalmedia.telus.com/transglobe/031110/index.php. TransGlobe Energy Corporation's Annual General and Special Meeting of Shareholders Tuesday, May 11, 2010 at 3:00 PM Mountain Time Calgary Petroleum Club, 319 - 5th Avenue S.W., Calgary, Alberta, Canada /T/ FINANCIAL AND OPERATING RESULTS Three Months Ended December 31 Year Ended December 31 % % Financial 2009 2008 Change 2009 2008 Change ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil and gas sales 50,044 29,285 71 167,798 233,695 (28) Oil and gas sales, net of royalties and other 28,788 18,272 58 102,805 132,393 (22) Derivative gain (loss) on commodity contracts (684) 12,460 (105) (4,213) 3,005 (240) Operating expense 7,387 5,783 28 24,765 21,561 15 General and administrative expense 3,922 3,010 30 11,427 10,213 12 Depletion, depreciation and accretion expense 6,955 9,245 (25) 47,579 38,056 25 Income taxes 6,887 3,673 88 21,853 32,148 (32) Cash flow from operating activities 12,594 11,252 12 36,799 57,793 (36) Funds flow from operations(1) 9,703 6,134 58 45,064 59,267 (24) Basic per share 0.15 0.10 0.70 0.99 Diluted per share 0.15 0.10 0.70 0.98 Net income (loss) 2,516 7,640 (67) (8,417) 31,523 (127) Basic per share 0.04 0.14 (0.13) 0.53 Diluted per share 0.04 0.13 (0.13) 0.52 Capital expenditures 7,541 13,730 (45) 35,546 44,714 (21) Acquisitions - 381 (100) - 62,392 (100) Long-term debt (including current portion) 49,799 57,230 (13) 49,799 57,230 (13) Common shares outstanding Basic (weighted average) 65,357 59,500 10 64,443 59,692 8 Diluted (weighted average) 66,908 60,948 10 64,443 60,704 6 Total assets 228,882 228,238 - 228,882 228,238 - ---------------------------------------------------------------------------- (1) Funds flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital. Operating ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total production (Boepd) (6:1)(1) 8,656 6,893 26 8,980 7,342 22 Total sales (Boepd) (6:1)(1) 8,656 6,893 26 8,980 7,342 22 Oil and liquids (Bopd) 8,656 6,893 26 8,980 6,974 29 Average price ($ per Bbl) 62.84 46.03 37 51.19 88.69 (42) Gas (Mcfpd) - - - - 2,212 (100) Average price ($ per Mcf) - - - - 8.92 (100) Operating expense ($ per Boe) 9.28 9.12 2 7.56 8.02 (6) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Financial from Continuing Operations (excludes Canadian Operations) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil sales 50,044 29,151 72 167,798 222,538 (25) Oil sales, net of royalties and other 28,788 17,765 62 102,805 123,231 (17) Operating expense 7,387 5,857 26 24,765 19,333 28 Depletion and depreciation expense 6,955 9,245 (25) 47,579 35,378 34 Cash flow from operating activities 12,593 11,010 14 36,606 51,090 (28) Funds flow from continuing operations(1) 9,703 5,579 74 45,064 52,359 (14) Basic per share 0.15 0.09 0.70 0.88 Diluted per share 0.15 0.09 0.70 0.86 Net income (loss) 2,516 7,482 (66) (8,417) 23,173 (136) Basic per share 0.04 0.13 (0.13) 0.39 Diluted per share 0.04 0.12 (0.13) 0.38 Capital expenditures 7,541 13,924 (46) 35,546 43,857 (19) ---------------------------------------------------------------------------- (1) Funds flow from continuing operations is a non-GAAP measure that represents cash generated from continuing operating activities before changes in non-cash working capital. Operating from Continuing Operations (excludes Canadian Operations) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total production from continuing operations (Bopd) (6:1) 8,656 6,893 26 8,980 6,858 31 Total sales (Bopd) (6:1) 8,656 6,893 26 8,980 6,858 31 Oil and liquids (Bopd) 8,656 6,893 26 8,980 6,858 31 Average price ($ per Bbl) 62.84 45.97 37 51.19 88.66 (42) Operating expense ($ per Bbl) 9.28 9.65 (4) 7.56 7.70 (2) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ OPERATIONS UPDATE ARAB REPUBLIC OF EGYPT West Gharib, Arab Republic of Egypt (100% working interest, TransGlobe operated) Operations and Exploration Three wells were drilled during the fourth quarter, resulting in oil wells at Arta #12 and Hana West #8. The third well at Abu Ghaylun #2 was plugged back and completed as a water source well for the Hoshia waterflood. Subsequent to year-end, three additional wells were drilled resulting in a total of three oil wells, one at each of Hana #20, North Hoshia #2 and Hoshia #8. Drilling commenced at Hana #21 in early March. The Arta #12 horizontal well reached at total depth of 5,217 feet with a 1,519 foot horizontal section in the Nukhul reservoir. The well was placed on production during the first week of December at an initial rate of 30 Bopd of 19 degrees API oil, with no water cut. A multi-staged frac stimulation program is being designed to improve access to the reservoir and potentially increase production rates. The stimulation program is expected to be completed in late March/early April, subject to the availability of multi-stage packer equipment for the horizontal. We believe this will be the first multi-staged frac conducted in a horizontal well in Egypt. The Company recently completed a successful frac stimulation of a vertical producer at Arta #9 as a precursor to the planned multi-stage frac stimulation of Arta #12 horizontal well. Arta #9 production increased to 280 Bopd following the frac treatment. It was previously producing approximately 25 Bopd. Three to five additional Arta vertical wells have been identified as candidates for similar frac treatments. The Hana West #8 well was drilled to a total depth of 6,971 feet and cased as a multi-zone oil well. The well was completed in the lower Rudeis formation and placed on production at an initial rate of 730 Bopd on December 27, 2009. The well also encountered an extension to the main Hana pool (Kareem/Markha formation) and a new oil pool in the Shagar formation. The Hana #20 well reached a total depth of 5,505 feet in eight days on January 3, 2010, making it the fastest well ever drilled in the Hana field. The well was completed in the Kareem/Markha formation and placed on production in mid-January at 800 Bopd. The North Hoshia #2 well was drilled to a total depth of 5,430 feet, targeting the Nukhul and Thebes formations in the North Hoshia pool. Cores were taken in the Nukhul and Thebes formations to better understand the emerging Nukhul/Thebes play in the Arta/East Arta/North Hoshia/Hoshia areas. The well was completed as a Nukhul oil well in early March. It is expected that North Hoshia #2 will produce similar to North Hoshia #1 which is producing 30 - 50 Bopd. The North Hoshia producers (#1 and #2) could be candidates for fracture stimulation. The Hoshia #8 step-out appraisal well was drilled to a total depth of 3,920 feet and cased as a multi-zone (Rudeis/Nukhul) oil well. The well will initially be completed in the Nukhul formation. Following Hoshia #8, the drilling rig was moved to the northern end of the Hana field to drill a step-out appraisal well at Hana #21. In addition to the emerging Nukhul project, the Hana and Hoshia waterflood projects demonstrated good production responses in the fourth quarter consistent with the Company's detailed reservoir simulation models. Significant 1P and 2P reserves were assigned for the Hana and Hoshia water flood projects at year-end. Water injection has been increased in both pools and will be expanded during 2010, as the water source injection system is brought on line to supplement the injection of produced water. At Hana West, the #3 well was recompleted as a water injector, with the injection of produced water commencing in November of 2009. Work has commenced on a new reservoir simulation model for the Hana West pool. Based on analogous reservoirs, it is expected that the Hana West pool will be a good waterflood candidate to increase recoverable reserves. With the recent Nukhul success at Arta, North Hoshia and Hoshia, the Company has expanded the 2010 capital program to add a second drilling rig to the West Gharib project in the second quarter of 2010. The additional drilling and fracture stimulation programs will increase the 2010 budget and forecast as discussed in the Management Strategy and Outlook for 2010 section. Production Production from West Gharib averaged 5,815 Bopd to TransGlobe during the fourth quarter, up slightly (68 Bopd or 1%) from the previous quarter. With the addition of Hana West #8 and Hana #20 at year-end and Arta #9 in February 2010, production has increased to 6,840 Bopd in January and to 7,078 Bopd in February (22% increase from Q4) resulting in new production records for West Gharib. /T/ Quarterly West Gharib Production (Bopd) 2009 ---------------------------------------------------------------------------- Q-4 Q-3 Q-2 Q-1 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Gross production rate 5,815 5,747 6,384 5,364 TransGlobe working interest 5,815 5,747 6,384 5,364 TransGlobe net (after royalties) 3,775 3,732 4,132 3,491 TransGlobe net (after royalties and tax)(1) 2,951 2,918 3,234 2,726 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Under the terms of the West Gharib Production Sharing Concession, royalties and taxes are paid out of the government's share of production sharing oil. /T/ East Ghazalat Block, Arab Republic of Egypt (50% working interest) On January 25, 2010, TransGlobe announced the signing of a farm-out agreement with Vegas Oil & Gas SA ("Vegas") to earn a 50% interest in the East Ghazalat Concession in the Western Desert of Egypt, subject to the approval of the Egyptian Government. The East Ghazalat Concession is operated by Vegas, a privately owned oil and gas company with extensive Egypt experience and success. The 858 km2 East Ghazalat Concession is located in the prolific Abu Gharadiq basin of Egypt's Western Desert, approximately 250 km west of Cairo. East Ghazalat was awarded to Vegas on June 5, 2007 and is currently in the first, three-year exploration period. There are two additional exploration period extensions of two years each. TransGlobe has committed to pay 100% of three exploration wells to a maximum of $9.0 million to earn a 50% working interest in the East Ghazalat Concession. To date, the operator has acquired 450 km of 3-D seismic to complement the existing 1,548 km of 2-D seismic and 218 km of 3-D seismic. Operations and Exploration Drilling commenced on the first of three planned exploration wells on January 14, 2010. The first exploration well Gawad #1 was drilled to total depth of 9,418 feet and subsequently abandoned. The second exploration well, Safwa #1 (formerly known as Rabwa #1), is currently being cased as a potential oil well. An oil-bearing interval in the Cretaceous section of the Safwa #1 well was logged and oil samples were recovered during wireline testing. The well will be perforated and tested prior to moving the drilling rig to the Sahab prospect. The third exploration well, Sahab #1, is targeting a Jurassic/Paleozoic prospect with an internally estimated petroleum initially in place ("PIIP") of 64 MMBbl in the P-mean case with an upside of 140 MMBbl in the P10 case. Nuqra Block 1, Arab Republic of Egypt (71.43% working interest, TransGlobe operated) Operations and Exploration TransGlobe has identified several prospects for drilling in late 2010 which are similar to the Al Baraka field located immediately west of the Nuqra Concession. The operator of the Al Baraka field recently announced a test of 1,300 Bopd from Al Baraka #4 well, representing a significant improvement from the previously reported production rates of 200 Bopd/well. The Company continues to discuss rig-sharing possibilities with the adjacent operators to facilitate a late 2010 drilling program. YEMEN EAST- Masila Basin Block 32, Republic of Yemen (13.81% working interest) Operations and Exploration The Tasour #26 infill development well was drilled and completed as a producing oil well during the quarter. Production Production from Block 32 averaged 5,174 Bopd (715 Bopd to TransGlobe) during the fourth quarter, representing an 6% decrease from the previous quarter primarily due to natural declines which were partially offset by new production from the Tasour #26 development well. Production averaged 5,075 Bopd (701 Bopd to TransGlobe) during January and 4,982 Bopd (688 Bopd to TransGlobe) during February. /T/ Quarterly Block 32 Production (Bopd) 2009 ---------------------------------------------------------------------------- Q-4 Q-3 Q-2 Q-1 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Gross production rate 5,174 5,501 6,188 6,257 TransGlobe working interest 715 760 855 864 TransGlobe net (after royalties) 437 464 656 606 TransGlobe net (after royalties and tax)(1) 346 367 597 523 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Under the terms of the Block 32 PSA, royalties and taxes are paid out of the government's share of production sharing oil. /T/ Block 72, Republic of Yemen (33% working interest) Operations and Exploration The Block 72 joint venture partnership entered the second, 30-month exploration period in January 2009 which carries a commitment of one exploration well. The Block 72 joint venture partnership has entered into a letter of intent to farm-out a portion of their interests in Block 72 to a third party, subject to a formal farm-in agreement and approval by the Ministry of Oil and Minerals ("MOM"). TransGlobe would reduce its working interest to 20% in the Block. The farm-out will allow the Company to allocate more of its 2010 budget to projects in Egypt. The partnership has approved a firm exploration well for 2010, which is targeting a fractured basement prospect on the northern portion of the Block. It is expected the well will be drilled in the second half of 2010. Block 84, Republic of Yemen (33% working interest) Operations and Exploration The PSA for Block 84 is awaiting final resolution. YEMEN WEST- Marib Basin Block S-1, Republic of Yemen (25% working interest) Operations and Exploration The Block S-1 and Block 75 joint venture partnerships initially approved a 2010 budget to drill up to eight horizontal development wells on Block S-1 and one exploration well on Block 75. Subsequent to year-end, the partners have added a Block S-1 exploration well to the 2010 program. It is expected that the ten-well drilling program will extend into 2011 as the start of drilling is now scheduled for April/May of 2010. Discussions with the MOM regarding a potential development project to produce and sell known deposits of gas from the An Naeem discovery on Block S-1 have not progressed. It appears less likely that project will be approved in the near term. Production Production from Block S-1 averaged 8,504 Bopd (2,126 Bopd to TransGlobe) during the fourth quarter, representing a decrease of 10% from the prior quarter due to natural declines and increasing gas production for re-injection. Production averaged 9,040 Bopd (2,260 Bopd to TransGlobe) during January and 8,624 Bopd (2,156 Bopd to TransGlobe) during February. /T/ Quarterly Block S-1 Production (Bopd) 2009 ---------------------------------------------------------------------------- Q-4 Q-3 Q-2 Q-1 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Gross field production rate 8,504 9,428 9,520 10,240 TransGlobe working interest 2,126 2,357 2,380 2,560 TransGlobe net (after royalties) 867 1,254 1,230 1,777 TransGlobe net (after royalties and tax)(1) 585 985 901 1,603 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Under the terms of the Block S-1 PSA royalties and taxes are paid out of the government's share of production sharing oil. /T/ Block 75, Republic of Yemen (25% working interest) Operations and Exploration The Production Sharing Agreement ("PSA") for Block 75 was ratified and signed into law effective March 8, 2008. The Block 75 3-D seismic acquisition program was completed in August and processed by year-end 2009. The new 3-D is currently being interpreted and mapped. One exploration well is planned for 2010 as part of the Block S-1/75 drilling program. The Block 75 exploration well is currently scheduled for the fourth quarter of 2010. MANAGEMENT'S DISCUSSION AND ANALYSIS March 9, 2010 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, 2009 and 2008, together with the notes related thereto. 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 otherwise noted). The effect of significant differences between Canadian and United States accounting principles is disclosed in Note 19 of the consolidated financial statements. 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 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. Such statements relate to possible future events. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Although TransGlobe's forward-looking statements are based on the beliefs, expectations, opinions and assumptions of the Company's management on the date the statements are made, such statements are inherently uncertain and provide no guarantee of future performance. Actual results may differ materially from TransGlobe's expectations as reflected in such forward-looking statements as a result of various factors, many of which are beyond the control of the Company. These factors include, but are not limited to, unforeseen changes in the rate of production from TransGlobe's oil and gas properties, changes in price of crude oil and natural gas, adverse technical factors associated with exploration, development, production or transportation of TransGlobe's crude oil and natural gas reserves, changes or disruptions in the political or fiscal regimes in TransGlobe's areas of activity, changes in tax, energy or other laws or regulations, changes in significant capital expenditures, delays or disruptions in production due to shortages of skilled manpower, equipment or materials, economic fluctuations, and other factors beyond the Company's control. TransGlobe does not assume any obligation to update forward-looking statements, except as required by law, if circumstances or management's beliefs, expectations or opinions should change and investors should not attribute undue certainty to, or place undue reliance on, any forward-looking statements. Please consult TransGlobe's public filings at www.sedar.com and www.sec.gov for further, more detailed information concerning these matters. Use of Barrel of Oil Equivalents The calculation of barrels of oil equivalent ("Boe") is based on a conversion rate of six thousand cubic feet of natural gas ("Mcf") to one barrel ("Bbl") of crude oil. Boe's may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Non-GAAP Measures Funds Flow from Operations This document contains the term "funds flow from operations" and "funds flow from continuing operations", which should not be considered an alternative to or more meaningful than "cash flow from operating activities" as determined in accordance with Generally Accepted Accounting Principles ("GAAP"). Funds flow from operations and funds flow from continuing operations are non-GAAP measures that represent 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 and funds flow from continuing operations may not be comparable to similar measures used by other companies. /T/ Reconciliation of Funds Flow from Operations and Funds Flow from Continuing Operations Year Ended December 31 ---------------------------------------------------------------------------- ($000s) 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Cash flow from operating activities 36,799 57,793 Changes in non-cash working capital from continuing operations 8,458 1,269 Changes in non-cash working capital from discontinued operations (193) 205 ---------------------------------------------------------------------------- Funds flow from operations 45,064 59,267 Less: Funds flow from discontinued operations - 6,908 ---------------------------------------------------------------------------- Funds flow from continuing operations 45,064 52,359 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Debt-to-funds flow ratio Debt-to-funds flow is a non-GAAP measure that is used to assess 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, 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 non-GAAP 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 continuing activities are concentrated in two main geographic areas, the Arab Republic of Egypt ("Egypt") and the Republic of Yemen ("Yemen"). Egypt and Yemen include the Company's exploration, development and production of crude oil. TransGlobe disposed of its Canadian oil and gas operations in 2008 to reposition itself as a 100% oil, Middle East/North Africa growth company. /T/ SELECTED ANNUAL INFORMATION ($000s, except per share, price and volume amounts) 2009 % Change 2008 % Change 2007 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Operations Average production volumes (Boepd) 8,980 22 7,342 30 5,651 Average sales volumes (Boepd) 8,980 22 7,342 29 5,692 Average price ($/Boe) 51.19 (41) 86.96 32 65.80 Oil and gas sales 167,798 (28) 233,695 71 136,709 Oil and gas sales, net of royalties and other 102,805 (22) 132,393 51 87,911 Cash flow from operating activities 36,799 (36) 57,793 8 53,618 Funds flow from operations(1) 45,064 (24) 59,267 14 52,141 Funds flow from operations per share - Basic 0.70 0.99 0.87 - Diluted 0.70 0.98 0.86 Net (loss) income (8,417) (127) 31,523 146 12,802 Net (loss) income per share - Basic (0.13) 0.53 0.21 - Diluted (0.13) 0.52 0.21 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Continuing Operations Average production volumes (Bopd) 8,980 31 6,858 61 4,258 Average sales volumes (Bopd) 8,980 31 6,858 61 4,258 Average price from continuing operations ($/Bbl) 51.19 (42) 88.66 23 72.17 Oil sales 167,798 (25) 222,538 98 112,171 Oil sales, net of royalties and other 102,805 (17) 123,231 82 67,628 Cash flow from operating activities 36,606 (28) 51,090 37 37,418 Funds flow from continuing operations(1) 45,064 (14) 52,359 44 36,285 Funds flow from continuing operations per share - Basic 0.70 0.88 0.61 - Diluted 0.70 0.86 0.60 Net (loss) income (8,417) (136) 23,173 177 8,380 Net (loss) income per share - Basic (0.13) 0.39 0.14 - Diluted (0.13) 0.38 0.14 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total assets 228,882 - 228,238 12 204,219 Cash and cash equivalents 16,177 112 7,634 (40) 12,729 Total long-term debt, including current portion 49,799 (13) 57,230 1 56,685 Debt-to-funds flow ratio(2) 1.1 1.0 1.1 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Reserves Total proved (MMboe) 19.2 53 12.6 6 11.9 Total proved plus probable (MMBoe) 24.2 22 19.8 21 16.4 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Funds flow from operations and funds flow from continuing operations are non-GAAP measures that represent cash generated from operating activities and continuing operating activities, respectively, before changes in non-cash working capital. (2) Debt-to-funds flow ratio is a non-GAAP measure that represents total current and long-term debt over funds flow from operations for the trailing 12 months. /T/ In 2009 compared with 2008, TransGlobe, - Increased Proved reserves by 6.6 MMBbl, representing a production replacement of 301%, primarily from the development of its operated West Gharib Concession in Egypt; - Increased total production by 22%, as a result of a 90% increase in production from Egypt offset by the loss of production from the sale of Canadian operations and declining production in Yemen; - Funds flow decreased by 24% (down 14% from continuing operations) primarily due to a 41% decrease in realized oil prices, offset by increased production and lower royalties and taxes; - Realized an operating loss of $8.4 million due to decreased revenues coupled by an unrealized derivative loss versus a gain in 2008 and a 34% increase in depreciation and depletion due to increased production; and - Decreased debt by $8.0 million resulting in a debt-to-funds flow ratio of 1.1 at December 31, 2009 (December 31, 2008 - 1.0). /T/ 2009 TO 2008 NET INCOME (LOSS) VARIANCES $000s $ Per Share Diluted Variance% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 2008 net income 31,523 0.52 ---------------------------------------------------------------------------- Cash items Volume variance 39,295 0.60 125 Price variance (94,035) (1.46) (298) Royalties 34,314 0.53 109 Expenses: Operating (5,432) (0.08) (17) Realized derivative loss 6,010 0.09 19 Cash general and administrative (1,033) (0.02) (3) Current income taxes 10,377 0.16 33 Realized foreign exchange loss 948 0.01 3 Interest on long-term debt 2,387 0.04 8 Other income (126) - - Cash flow from discontinued operations (6,908) (0.11) (22) ---------------------------------------------------------------------------- Total cash items variance (14,203) (0.24) (43) ---------------------------------------------------------------------------- Non-cash items Unrealized derivative loss (13,228) (0.21) (42) Depletion, depreciation and accretion (12,201) (0.20) (40) Stock-based compensation (181) - (1) Amortization of deferred financing costs 1,315 0.02 4 Non-cash income from discontinued operations (1,442) (0.02) (5) ---------------------------------------------------------------------------- Total non-cash items variance (25,737) (0.41) (84) ---------------------------------------------------------------------------- 2009 net loss (8,417) (0.13) (127) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Despite record production in 2009, net income decreased by $39.9 million from 2008, resulting in a $8.4 million loss. This is mainly as a result of a 41% decrease in realized oil prices, an unrealized derivative loss (versus a gain in 2008) and a 34% increase in depreciation and depletion due to increased production. BUSINESS ENVIRONMENT The Company's financial results are significantly influenced by fluctuations in commodity prices, including price differentials. The following table shows select market benchmark prices and foreign exchange rates: /T/ Year Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Dated Brent average oil price ($/Bbl) 61.51 96.99 U.S./Canadian Dollar average exchange rate 1.1415 1.0671 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ The average price of Dated Brent oil was 37% lower in 2009 versus 2008. Financial market instability and a worldwide recession resulted in a steep decline in the price of Dated Brent oil in Q4-2008, with lower price levels continuing into 2009. Oil prices partially recovered in the latter half of 2009 and Dated Brent averaged $74.56/Bbl in Q4-2009 a 36% increase over the same period last year. The global financial crisis, which developed in late 2008 and continued throughout 2009, has increased the risk associated with timely access to debt, capital, and banking markets, along with market instability which may have an impact on TransGlobe's ability to obtain additional funding in the future. To mitigate this risk, management has been adjusting operational and financial risk strategies and continues to monitor the 2010 capital budget and the Company's long-term plans. The Company has designed its 2010 budget to be flexible allowing spending to be adjusted as commodity prices change and forecasts are reviewed. SIGNIFICANT ACQUISITIONS AND DISPOSITIONS Corporate Acquisition On February 5, 2008, the Company acquired all the shares of GHP Exploration (West Gharib) Ltd. ("GHP") for total consideration of $40.2 million, plus transaction costs and working capital adjustments, effective September 30, 2007. This acquisition was funded by bank debt and cash on hand. GHP holds a 30% working interest in the West Gharib Concession area in the Egypt. With the acquisition of GHP, the Company held 100% working interest in the West Gharib Production Sharing Concession ("PSC"), with a working interest of 100% in the Hana development lease and an effective working interest of 75% in the eight non-Hana development leases. TransGlobe is the operator of the West Gharib Concession. Property Acquisition On August 18, 2008, TransGlobe completed an oil and gas property acquisition in Egypt for the remaining 25% financial interest in the eight non-Hana development leases in the West Gharib Concession. The total cost of the acquisition was $18.0 million. In addition, the Company could pay up to a maximum of $7.0 million if incremental reserve thresholds are reached in the East Hoshia (up to $5.0 million) and in the South Rahmi (up to $2.0 million) development leases, to be evaluated annually. As at December 31, 2009, no additional fees are due in 2010. Following this acquisition, TransGlobe now holds 100% working interest in the West Gharib Concession in Egypt. Discontinued Operations TransGlobe sold the Canadian segment of its operations on April 30, 2008 to allow the Company to focus on the development of its Middle East/North Africa assets. The sale price of the Canadian assets was C$56.7 million, subject to normal closing adjustments. Accordingly, the Canadian segment has been reclassified as discontinued operations in the Consolidated Financial Statements. This is further discussed in the MD&A section entitled "Operating Results From Discontinued Operations". /T/ SELECTED QUARTERLY FINANCIAL INFORMATION 2009 2008 ---------------------------------------------------------------------------- ($000s, except per share, price and volume amounts) Q-4 Q-3 Q-2 Q-1 Q-4 Q-3 Q-2 Q-1 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Operations Average sales volumes (Boepd) 8,656 8,864 9,619 8,788 6,893 6,935 7,706 7,845 Average price ($/Boe) 62.84 57.41 48.62 35.88 46.18 104.55 110.21 84.63 Oil and gas sales 50,044 46,818 42,557 28,379 29,285 66,707 77,283 60,419 Oil and gas sales, net of royalties and other 28,788 28,495 26,462 19,060 18,272 36,577 41,629 35,915 Cash flow from operating activities 12,594 1,264 15,052 7,889 11,252 20,652 9,573 16,316 Funds flow from operations (1) 9,703 12,603 14,117 8,641 6,134 16,775 18,485 17,873 Funds flow from operations per share - Basic 0.15 0.19 0.22 0.14 0.10 0.28 0.31 0.30 - Diluted 0.15 0.19 0.22 0.14 0.10 0.27 0.31 0.30 Net (loss) income 2,516 (1,618) (4,361) (4,954) 7,640 24,790 (5,365) 4,458 Net (loss) income per share - Basic 0.04 (0.02) (0.07) (0.08) 0.14 0.41 (0.09) 0.07 - Diluted 0.04 (0.02) (0.07) (0.08) 0.13 0.41 (0.09) 0.07 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Continuing Operations Average sales volumes (Bopd) 8,656 8,864 9,619 8,788 6,893 6,935 7,283 6,322 Average price ($/Bbl) 62.84 57.41 48.62 35.88 45.97 104.55 112.59 90.49 Oil sales 50,044 46,818 42,557 28,379 29,151 66,707 74,616 52,064 Oil sales, net of royalties and other 28,788 28,495 26,462 19,060 17,765 36,577 39,541 29,348 Cash flow from continuing operating activities 12,593 1,137 14,774 8,102 11,010 20,483 8,078 11,519 Funds flow from continuing operations (1) 9,703 12,603 14,117 8,641 5,579 16,775 16,841 13,164 Funds flow from continuing operations per share - Basic 0.15 0.19 0.22 0.14 0.09 0.28 0.28 0.22 - Diluted 0.15 0.19 0.22 0.14 0.09 0.27 0.28 0.22 Net (loss) income 2,516 (1,618) (4,361) (4,954) 7,482 24,787 (11,449) 2,353 Net (loss) income per share - Basic 0.04 (0.02) (0.07) (0.08) 0.13 0.41 (0.19) 0.04 - Diluted 0.04 (0.02) (0.07) (0.08) 0.12 0.41 (0.19) 0.04 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total assets 228,882 228,964 229,658 238,145 228,238 234,501 205,535 249,401 Cash and cash equivalents 16,177 14,804 23,952 22,041 7,634 8,593 11,673 11,935 Total long-term debt, including current portion 49,799 52,686 52,551 57,347 57,230 57,127 42,197 95,601 Debt-to-funds flow ratio(2) 1.1 1.3 1.2 1.1 1.0 0.9 0.7 1.6 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Funds flow from operations and funds flow from continuing operations are non-GAAP measures that represent cash generated from operating activities and continuing operating activities, respectively, before changes in non-cash working capital. (2) Debt-to-funds flow ratio is a non-GAAP measure that represents total current and long-term debt over funds flow from operations for the trailing 12 months. /T/ During the fourth quarter of 2009, TransGlobe: - Funded capital programs entirely with funds flow from operations; - Increased production by 26% compared with Q4-2008 due to drilling successes in the West Gharib Concession in Egypt; - Increased funds flow from continuing operations by 74% from Q4-2008 due to a 36% increase in commodity prices and a 26% increase in sales volumes; - Net income decreased $5.1 million from Q4-2008 despite higher prices and volumes, primarily due to an unrealized derivative gain decreasing from $11.8 million in Q4-2008 to $0.4 million; and - Net income increased by $4.1 million from Q3-2009 primarily due to a 51% decrease in depletion and depreciation ("DD&A") as a result of the West Gharib reserve additions at the end of 2009. /T/ OPERATING RESULTS AND NETBACK Daily Volumes, Working Interest, Before Royalties and Other Year Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Egypt - Oil sales Bopd 5,828 3,072 (1) Yemen - Oil sales Bopd 3,152 3,786 ---------------------------------------------------------------------------- Total continuing operations - daily sales volumes Bopd 8,980 6,858 ---------------------------------------------------------------------------- Canada - Oil and liquids sales(2) Bopd - 115 - Gas sales(2) Mcfpd - 2,212 ---------------------------------------------------------------------------- Canada Boepd - 484 ---------------------------------------------------------------------------- Total Company - daily sales volumes Boepd 8,980 7,342 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Egypt includes the operating results of GHP for the period February 5, 2008 to December 31, 2008 and the property acquisition for the period from August 18, 2008 to December 31, 2008. In those periods, production averaged 1,037 Bopd and 369 Bopd, respectively, for yearly averages of 938 Bopd and 137 Bopd, respectively. (2) Canada includes the operating results for the period January 1, 2008 to April 30, 2008. In that period, production from the Canadian assets averaged 1,463 Boepd for a yearly average of 484 Boepd. Three Months Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Egypt - Oil sales Bopd 5,815 3,405 Yemen - Oil sales Bopd 2,841 3,488 ---------------------------------------------------------------------------- Total continuing operations - daily sales volumes Bopd 8,656 6,893 ---------------------------------------------------------------------------- Total Company - daily sales volumes Boepd 8,656 6,893 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Netback from Continuing Operations Year Ended December 31 ---------------------------------------------------------------------------- Consolidated 2009 2008 ---------------------------------------------------------------------------- (000s, except per Bbl amounts) $ $/Bbl $ $/Bbl ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil sales 167,798 51.19 222,538 88.66 Royalties and other 64,993 19.83 99,307 39.56 Current taxes 21,853 6.67 32,230 12.84 Operating expenses 24,765 7.56 19,333 7.70 ---------------------------------------------------------------------------- Netback 56,187 17.13 71,668 28.56 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended December 31 ---------------------------------------------------------------------------- Consolidated 2009 2008 ---------------------------------------------------------------------------- (000s, except per Bbl amounts) $ $/Bbl $ $/Bbl ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil sales 50,044 62.84 29,151 45.97 Royalties and other 21,256 26.69 11,386 17.95 Current taxes 6,887 8.65 3,673 5.79 Operating expenses 7,387 9.28 5,857 9.24 ---------------------------------------------------------------------------- Netback 14,514 18.22 8,235 12.99 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Egypt Year Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Bbl amounts) $ $/Bbl $ $/Bbl ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil sales 98,801 46.45 86,778 77.18 Royalties and other 34,684 16.30 35,410 31.49 Current taxes 13,980 6.57 14,627 13.01 Operating expenses 14,703 6.91 6,972 6.20 ---------------------------------------------------------------------------- Netback 35,434 16.67 29,769 26.48 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Bbl amounts) $ $/Bbl $ $/Bbl ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil sales 30,536 57.08 11,892 37.96 Royalties and other 10,715 20.03 4,111 13.12 Current taxes 4,322 8.08 1,698 5.42 Operating expenses 5,008 9.36 3,022 9.65 ---------------------------------------------------------------------------- Netback 10,491 19.61 3,061 9.77 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ In Egypt, the netback per Bbl decreased 37% in 2009 compared with 2008, mainly as a result of oil prices decreasing by 40%. The oil price decrease was partially offset by lower realized royalty and tax rates. In 2009, the average realized oil price for the West Gharib crude had a gravity/quality adjustment of approximately $15.06/Bbl (24%) to the average Dated Brent oil price versus a $19.82/Bbl (20%) differential in 2008. In 2010, the Company expects these differentials to narrow to the 10% range. - Royalties and taxes as a percentage of revenue decreased to 49% in 2009, compared with 58% in 2008. Royalty and tax rates fluctuate in Egypt due to changes in the cost oil whereby the PSC allows for recovery of operating and capital costs through a reduction in government take. - Operating expenses for 2009 increased 11% on a per Bbl basis, due to an increased number of workovers and higher staffing levels. /T/ Yemen Year Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Bbl amounts) $ $/Bbl $ $/Bbl ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil sales 68,997 59.97 135,760 97.97 Royalties and other 30,309 26.34 63,897 46.11 Current taxes 7,873 6.84 17,603 12.70 Operating expenses 10,062 8.75 12,361 8.92 ---------------------------------------------------------------------------- Netback 20,753 18.04 41,899 30.24 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Bbl amounts) $ $/Bbl $ $/Bbl ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil sales 19,508 74.64 17,259 53.78 Royalties and other 10,541 40.33 7,275 22.67 Current taxes 2,565 9.81 1,975 6.15 Operating expenses 2,379 9.10 2,835 8.83 ---------------------------------------------------------------------------- Netback 4,023 15.40 5,174 16.12 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ In Yemen, the netback per Bbl decreased 40% in 2009 compared with 2008, primarily as a result of the 39% decrease in oil prices. - Royalties and taxes as a percentage of revenue decreased to 55% in 2009 compared with 60% in 2008. Royalty and tax rates fluctuate in Yemen due to changes in the amount of cost oil, whereby the Block 32 and Block S-1 Production Sharing Agreements ("PSAs") allow for the recovery of operating and capital costs through a reduction in the Ministry of Oil and Minerals' take of oil production. - In Q4-2009, royalty rate increased to 54% from 42% in the same quarter of last year, as a result of higher oil prices and a provision accrual for a one-time historical cost recovery adjustment of an estimated $1.1 million. - Operating expenses on a per Bbl basis remained flat year over year. DERIVATIVE COMMODITY CONTRACTS TransGlobe uses hedging arrangements as part of its risk management strategy to manage commodity price fluctuations and to stabilize cash flows for future exploration and development programs. The hedging program was expanded significantly in 2007 due to a marked increase in debt levels and again in 2009 to protect the cash flows from the added risk of commodity price exposure and in order to comply with the covenants set forth by the Company's lending institutions. The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheets with any change in the unrealized positions recorded to income. The fair values of these transactions are based on an approximation of the amounts that would have been paid to, or received from, counter-parties to settle the transactions outstanding as at the Consolidated Balance Sheet date with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates. From a corporate perspective, the weak oil prices in 2009 had a negative impact on the Company's revenue; however, these prices resulted in only $0.9 million of realized loss recorded on the derivative commodity contracts compared with $6.9 million of realized losses in 2008. The mark-to-market valuation of TransGlobe's future derivative commodity contracts decreased from a $2.8 million asset at December 31, 2008 to a $0.5 million liability at December 31, 2009 due to the strengthening of commodity prices since December 31, 2008, thus resulting in a $3.3 million unrealized loss on future derivative commodity contracts being recorded in the year. /T/ Year Ended December 31 ---------------------------------------------------------------------------- ($000s) 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Realized cash loss on commodity contracts(1) (891) (6,901) Unrealized (loss) gain on commodity contracts(2) (3,322) 9,906 ---------------------------------------------------------------------------- Total derivative (loss) gain on commodity contracts (4,213) 3,005 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Realized cash loss represents actual cash settlements or receipts under the respective contracts. (2) The unrealized (loss) gain on derivative commodity contracts represents the change in fair value of the contracts during the year. /T/ If the Dated Brent oil prices in 2010 are consistent with the estimated Dated Brent forward curve prices at the end of 2009, the derivative liability will be realized over the year. However, a 10% decrease in Dated Brent oil prices would result in a $0.9 million decrease in the derivative commodity contract liability, thus decreasing the unrealized loss by the same amount. Conversely, a 10% increase in Dated Brent oil prices would increase the unrealized loss on commodity contracts by $0.7 million. The following commodity contracts are outstanding at December 31, 2009: /T/ Dated Brent Pricing Period Volume Type Put-Call ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Crude Oil January 1, 2010- August 31, 2010 12,000 Bbls/month Financial Collar $60.00-$84.25 January 1, 2010- August 31, 2010 9,000 Bbls/month Financial Collar $40.00-$80.00 January 1, 2010- December 31, 2010 10,000 Bbls/month Financial Floor $60.00 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- The total volumes hedged for 2010 are: 2010 ---------------------------------------------------------------------------- Bbls 288,000 Bopd 789 ---------------------------------------------------------------------------- /T/ At December 31, 2009, all of the derivative commodity contracts were classified as current liabilities. /T/ GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Year Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Boe amounts) $ $/Bbl $ $/Boe ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- G&A (gross) 12,550 3.83 11,012 4.10 Stock-based compensation 2,011 0.61 1,830 0.68 Capitalized G&A (3,109) (0.95) (2,583) (0.96) Overhead recoveries (25) (0.01) (46) (0.02) ---------------------------------------------------------------------------- G&A (net) 11,427 3.48 10,213 3.80 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Boe amounts) $ $/Bbl $ $/Bbl ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- G&A (gross) 4,291 5.39 3,652 5.76 Stock-based compensation 518 0.65 584 0.92 Capitalized G&A (868) (1.09) (1,226) (1.93) Overhead recoveries (19) (0.02) - - ---------------------------------------------------------------------------- G&A (net) 3,922 4.93 3,010 4.75 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ G&A increased 12% in 2009, compared with 2008 mostly as a result of higher insurance costs and increased staffing levels in Egypt. On a per Bbl basis, G&A was down 8% from 2008 due to increased production. INTEREST ON LONG-TERM DEBT Interest expense for 2009 decreased to $2.5 million (2008 - $6.2 million), as a result of lower debt levels throughout 2009 coupled with lower interest rates. Interest expense includes interest on long-term debt and amortization of transaction costs associated with long-term debt. In 2009, the Company expensed $0.6 million of transaction costs (2008 - $1.9 million). The Company had $50.0 million of debt outstanding at December 31, 2009 (December 31, 2008 - $58.0 million). The long-term debt bears interest at the Eurodollar Rate plus three percent. /T/ DEPLETION AND DEPRECIATION ("DD&A") Year Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Bbl amounts) $ $/Bbl $ $/Bbl Egypt 37,942 17.84 23,052 20.50 Yemen 9,436 8.20 11,993 8.65 Corporate 201 - 333 - ---------------------------------------------------------------------------- 47,579 14.52 35,378 14.09 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Bbl amounts) $ $/Bbl $ $/Bbl ---------------------------------------------------------------------------- Egypt 4,792 8.96 6,608 21.09 Yemen 2,105 8.05 2,599 8.10 Corporate 58 - 38 - ---------------------------------------------------------------------------- 6,955 8.73 9,245 14.74 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ In Egypt, DD&A increased 65% in 2009, due to DD&A charges on increased production from the West Gharib PSC in Egypt. Property and equipment are depleted based on proved reserves; therefore, the 13% decrease on a Bbl basis of Egypt DD&A was due to a 125% increase in proved reserves in Egypt at the end of 2009. As a result of the reserve increases, the Q4-2009 DD&A in Egypt was down to $8.96/Bbl, compared with an average DD&A rate of $20.82/Bbl during the first three quarters of 2009. In Yemen, DD&A, on a per Bbl basis for the year ended December 31, 2009, decreased 5% over 2008 due to decreased capital spending and reserve additions on Block S-1 and Block 32 at year-end 2009. In Egypt, unproven properties of $9.8 million (2008 - $10.0 million) relating to Nuqra ($7.9 million) and West Gharib ($1.9 million) were excluded from the costs subject to depletion and depreciation. In Yemen, unproven property costs of $10.8 million (2008 - $7.2 million) relating to Block 72, Block 75 and Block 84 were excluded from the costs subject to depletion and depreciation. /T/ CAPITAL EXPENDITURES Year Ended December 31 ---------------------------------------------------------------------------- ($000s) 2009 2008 ---------------------------------------------------------------------------- Egypt 28,349 34,797 Yemen 7,013 8,819 Corporate 184 241 ---------------------------------------------------------------------------- 35,546 43,857 Acquisition - 54,602 ---------------------------------------------------------------------------- Total 35,546 98,459 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ In Egypt, total capital expenditures for the year ended December 31, 2009 were down 19% from 2008, due to a reduced capital program in response to lower oil prices in 2009. The Company drilled 13 wells, resulting in eight oil wells (six in Hana West, one in East Hoshia and one in Arta), one dry hole in East Hoshia and four water source wells as part of the waterflood projects at Hana and Hoshia. In Yemen, total capital expenditures in the year ended December 31, 2009 were $7.0 million (2008 - $8.8 million). The Company drilled two oil wells on Block 32 and completed a 3-D seismic acquisition program on Block 75. FINDING AND DEVELOPMENT COSTS/FINDING, DEVELOPMENT AND NET ACQUISITION COSTS Canadian 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 ongoing 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 all acquisitions net of any dispositions during the year. Proved /T/ Year Ended December 31 ---------------------------------------------------------------------------- ($000s, except volumes and $/Boe amounts) 2009 2008 2007 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total capital expenditure 35,546 43,292 37,015 Acquisitions - 58,946 62,821 Dispositions - (57,295) - Net change from previous year's future capital 1,816 (6,479) (2,467) ---------------------------------------------------------------------------- 37,362 38,464 97,369 ---------------------------------------------------------------------------- Reserve additions and revisions (MBoe) Exploration and development 9,921 3,129 1,634 Acquisitions, net of dispositions - 118 2,953 ---------------------------------------------------------------------------- Total reserve additions (MBoe) 9,921 3,247 4,587 ---------------------------------------------------------------------------- Average cost per Boe F&D 3.77 11.77 21.14 FD&A 3.77 11.85 21.23 Three-year weighted average cost per Boe F&D 7.40 14.97 15.77 FD&A 9.75 16.62 17.25 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Proved Plus Probable /T/ Year Ended December 31 ---------------------------------------------------------------------------- ($000s, except volumes and $/Boe amounts) 2009 2008 2007 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total capital expenditure 35,546 43,292 37,015 Acquisitions - 58,946 68,716 Dispositions - (57,295) - Net change from previous year's future capital 4,112 (8,602) (6,587) ---------------------------------------------------------------------------- 39,658 36,341 99,144 ---------------------------------------------------------------------------- Reserve additions and revisions (MBoe) Exploration and development 7,670 5,200 1,537 Acquisitions, net of dispositions - 709 5,264 ---------------------------------------------------------------------------- Total reserve additions (Mboe) 7,670 5,909 6,801 ---------------------------------------------------------------------------- Average cost per Boe F&D 5.17 6.67 19.79 FD&A 5.17 6.15 14.58 Three-year weighted average cost per Boe F&D 7.27 12.35 19.88 FD&A 8.59 12.14 16.81 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Note: The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. /T/ RECYCLE RATIO /T/ Three Year Proved Weighted Average 2009 2008 2007 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Netback ($/Boe)(i) 19.45 13.75 22.05 25.10 Proved F&D costs ($/Boe) 7.40 3.77 11.77 21.14 Proved FD&A costs ($/Boe) 9.75 3.77 11.85 21.23 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- F&D Recycle ratio 2.63 3.65 1.87 1.19 FD&A Recycle ratio 1.99 3.65 1.86 1.18 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (i) Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Boe of production. Three Year Proved Plus Probable Weighted Average 2009 2008 2007 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Netback ($/Boe)(i) 19.45 13.75 22.05 25.10 Proved plus Probable F&D costs ($/Boe) 7.27 5.17 6.67 19.79 Proved plus Probable FD&A costs ($/Boe) 8.59 5.17 6.15 14.58 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- F&D Recycle ratio 2.67 2.66 3.31 1.27 FD&A Recycle ratio 2.26 2.66 3.59 1.72 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (i) Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Boe of production. /T/ Despite a 38% decrease in netback, the 2009 proved recycle ratios increased from 2008 mainly as a result of probable reserves being converted to proved, mainly as a result of waterflood simulation and field response at Hoshia and Hana and the development of Hana West pool. The proved plus probable ratios decreased from 2008 mainly due to a lower netback per Bbl in 2009 compared to 2008. The increase in the 2008 proved and proved plus probable recycle ratios, from 2007, was mainly as a result of higher reserve additions. 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 cost on a per Boe basis. /T/ Year Ended December 31 ---------------------------------------------------------------------------- ($000s, except volumes and per Boe amounts) 2009 2008 2007 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net income (8,417) 31,523 12,802 Adjustments for non-cash items: Depletion, depreciation and accretion 47,579 38,056 31,172 Stock-based compensation 2,011 1,830 1,086 Future income taxes - (82) 45 Amortization of deferred financing costs 569 1,884 153 Unrealized loss (gain) on commodity contracts 3,322 (9,906) 7,098 Gain on sale - (4,012) - Settlement of asset retirement obligations - (25) (215) ---------------------------------------------------------------------------- Netback(i) 45,064 59,268 52,141 Sales volumes (MBoe) 3,278 2,687 2,078 ---------------------------------------------------------------------------- Netback per Boe(i) 13.75 22.05 25.10 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (i) Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Boe of production. /T/ OUTSTANDING SHARE DATA As at December 31, 2009, the Company had 65,398,639 common shares issued and outstanding. In the first quarter of 2009, the Company issued 5,798,000 common shares at C$3.45 per common share for gross proceeds of C$20.0 million (US$16.3 million). The Company has received regulatory approval to purchase, from time to time, as it considers advisable, up to 6,116,905 common shares under a Normal Course Issuer Bid, which commenced September 7, 2009 and will terminate September 6, 2010. During the year ended December 31, 2009, the Company did not repurchase any common shares. During the year ended December 31, 2008, the Company repurchased and cancelled 300,000 common shares at an average price of C$3.87 (US$3.66) per share. In 2008, the excess of the purchase price over the book value in the amount of $0.9 million was charged to retained earnings. 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 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. A key measure that TransGlobe uses to measure the Company's overall financial strength is debt-to-funds flow from operating activities (calculated on a 12-month trailing basis). TransGlobe's debt-to-funds flow from operating activities ratio, a key short-term leverage measure, remained strong at 1.1 times at December 31, 2009. This was within the Company's target range of no more than 2.0 times. The following table illustrates TransGlobe's sources and uses of cash during the years ended December 31, 2009 and 2008: Sources and Uses of Cash /T/ Year Ended December 31 ---------------------------------------------------------------------------- ($000s) 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Cash sourced Funds flow from continuing operations(i) 45,064 52,359 Increase in long-term debt - 55,000 Exercise of options - 514 Issuance of common shares, net of share issuance costs 15,374 - Other - 201 ---------------------------------------------------------------------------- 60,438 108,074 Cash used Capital expenditures 35,546 43,857 Bank financing costs - 1,339 Acquisitions - 62,392 Repayment of long-term debt 8,000 55,000 Repurchase of common shares - 1,135 Options surrendered for cash payments 13 256 ---------------------------------------------------------------------------- 43,559 163,979 ---------------------------------------------------------------------------- Net cash from continuing operations 16,879 (55,905) Net cash from discontinued operations 193 53,098 Changes in non-cash working capital (8,529) (2,288) ---------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents 8,543 (5,095) Cash and cash equivalents - beginning of year 7,634 12,729 ---------------------------------------------------------------------------- Cash and cash equivalents - end of year 16,177 7,634 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (i) Funds flow from continuing operations is a non-GAAP measure that represents cash generated from continuing operating activities before changes in non-cash working capital. /T/ Funding for the Company's capital expenditures and long-term debt repayment was provided by funds flow from operations and the proceeds from the issuance of common shares. The Company expects to fund its 2010 exploration and development program of $63.0 million and contractual commitments through the use of working capital and cash generated by operating activities. The use of new financing during 2010 may also be utilized to accelerate existing projects, retire existing debt or to finance new opportunities. Fluctuations in commodity prices, foreign exchange rates, interest rates and various other risks may impact capital resources. Working capital is the amount by which current assets exceed current liabilities. At December 31, 2009, the Company had negative working capital of $11.8 million (December 31, 2008 - $24.0 million). The decrease in working capital in 2009 is due to the re-classing of long-term debt to current as the current Revolving Credit facility expires in September 2010. Accounts receivable have mainly increased in Egypt due to increased production and increased prices at the end of 2009 versus 2008. These receivables are not considered to be impaired. However, to mitigate this risk, the Company has insured the receivable balance. Since year end, the collection period for the Egypt receivables has decreased. At December 31, 2009, TransGlobe had a $60.0 million Revolving Credit Agreement of which $50.0 million was drawn. Amounts drawn under the Revolving Credit Agreement are due September 25, 2010. The Company is in discussion on a new credit facility and expects to enter into a new facility in the second quarter of 2010. /T/ ($000s) December 31, 2009 December 31, 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Revolving Credit Agreement 50,000 58,000 Unamortized transaction costs (201) (770) ---------------------------------------------------------------------------- 49,799 57,230 ---------------------------------------------------------------------------- Current portion of long-term debt 49,799 - ---------------------------------------------------------------------------- Long-term debt - 57,230 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 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: /T/ ($000s) Payment Due by Period(1,2) ---------------------------------------------------------------------------- Recognized Less in Financial Contractual than More than Statements Cash Flows 1 year 1-3 years 4-5 years 5 years ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Accounts payable and accrued liabilities Yes-Liability 14,800 14,800 - - - Long-term debt: Revolving Credit Agreement Yes-Liability 50,000 50,000 - - - Derivative commodity contracts Yes-Liability 514 514 - - - Office and equipment leases No 1,504 738 766 - - Minimum work commit- ments(3) No 20,586 10,353 4,953 5,280 - ---------------------------------------------------------------------------- Total 87,404 76,405 5,719 5,280 - ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Payments exclude ongoing operating costs related to certain leases, interest on long-term debt and payments made to settle derivatives. (2) Payments denominated in foreign currencies have been translated at December 31, 2009 exchange rates. (3) Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations. /T/ Pursuant to the Concession Agreement for Nuqra Block 1 in Egypt, the Contractor (Joint Venture Partners) has a minimum financial commitment of $5.0 million ($4.4 million to TransGlobe) and a work commitment of two exploration wells in the second exploration extension. The second, 36-month extension period commenced on July 18, 2009. The Contractor has met the second extension financial commitment of $5.0 million in the prior periods. At the request of the government, the Company provided a $4.0 million production guarantee from the West Gharib Concession prior to entering the second extension period. TransGlobe has signed a farm-out agreement and has committed to pay 100% of three exploration wells to a maximum of $9.0 million to earn a 50% working interest in the East Ghazalat Concession in the Western Desert of Egypt, subject to the approval of the Egyptian Government. Pursuant to the Production Sharing Agreement ("PSA") for Block 72 in Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $2.0 million ($0.7 million to TransGlobe) during the second exploration period. The second, 30-month, exploration period commenced on January 12, 2009. Pursuant to the PSA for Block 75 in Yemen, the Contractor (Joint Venture Partners) has a remaining minimum financial commitment of $3.0 million ($0.8 million to TransGlobe) for one exploration well. The first, 36-month exploration period commenced March 8, 2008. The Company issued a $1.5 million letter of credit (expiring November 15, 2011) to guarantee the Company's performance under the first exploration period. The letter is secured by a guarantee granted by Export Development Canada. Pursuant to the bid awarded for Block 84 in Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $4.1 million ($1.4 million to TransGlobe) for the signature bonus and a $16.0 million ($5.3 million to TransGlobe) first exploration period work program, consisting of seismic acquisition and four exploration wells. The first, 42-month exploration period will commence if the PSA is finalized and ratified by the Government of Yemen. 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 $7.0 million if incremental reserve thresholds are reached in the East Hoshia (up to $5.0 million) and South Rahmi (up to $2.0 million) development leases, to be evaluated annually. As at December 31, 2009, no additional fees are due in 2010. 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. OPERATING RESULTS FROM DISCONTINUED OPERATIONS The following applies to the Canadian operations only, the sale of which closed April 30, 2008. The Canadian operations and results have been accounted for as discontinued operations. /T/ Year Ended December 31 ---------------------------------------------------------------------------- 2009 2008 ---------------------------------------------------------------------------- (000s, except per Boe amounts) $ $/Boe $ $/Boe ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net operating results Oil sales - - 2,198 96.75 Gas sales ($ per Mcf) - - 7,226 8.92 NGL sales - - 1,638 84.38 Other sales - - 94 - ---------------------------------------------------------------------------- - - 11,156 63.00 Royalties and other - - 1,994 11.26 Operating expenses - - 2,228 12.58 ---------------------------------------------------------------------------- Netback - - 6,934 39.16 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Depletion, depreciation and accretion - - 2,678 15.12 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Future income taxes - - 82 - ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Capital expenditures - 857 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ OFF BALANCE SHEET ARRANGEMENTS The Company has certain lease agreements, 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, 2009. MANAGEMENT STRATEGY AND OUTLOOK FOR 2010 The 2010 outlook provides information as to management's expectation for results of operations for 2010. Readers are cautioned that the 2010 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" included on the first page of the MD&A. 2010 Outlook Highlights /T/ -- Production is expected to average between 10,000 Bopd and 10,500 Bopd, a 14% increase over the 2009 average production; -- Exploration and development spending is budgeted to be $63.0 million, an 77% increase from 2009 (allocated 77% to Egypt and 23% to Yemen) funded by funds flow from operations and cash on hand; and -- Using the mid-point of production expectations and an average oil price assumption for the year of $65.00/Bbl for Dated Brent oil, funds flow from operations is expected to be $67.0 million. /T/ 2010 Production Outlook Production for 2010 is expected to average between 10,000 Bopd and 10,500 Bopd, representing a 14% increase over the 2009 average production of 8,980 Bopd. This target includes increased production from the Hana, Hana West, Hoshia, Arta and East Arta in Egypt, and production from the development drilling program on Block S-1 in Yemen. Production from Egypt is expected to average approximately 7,550 Bopd during 2010, with the balance of approximately 2,700 Bopd coming from the Yemen properties. Production Forecast /T/ 2010 Guidance 2009 Actual % Change(i) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Barrels of oil per day 10,000-10,500 8,980 14 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (i) % growth based on mid-point of outlook. /T/ 2010 Funds Flow From Operations Outlook This outlook was developed using the above production forecast and a Dated Brent oil price of $65.00/Bbl. 2010 Funds Flow From Operations Outlook /T/ ($ million) 2010 Guidance 2009 Actual % Change(i) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Funds flow from operations(ii) 67.0 45.1 49 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (i) % growth based on mid-point of outlook. (ii) Funds flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital. /T/ Due in part to higher expected prices and higher production, funds flow from operations is expected to increase by 49% in 2010. One of the key factors in the increased funds flow in 2010 is due to a better expected oil price differential, to average Dated Brent benchmark price, in Egypt. In 2009 the Company has been experiencing Egypt price differentials, to average Dated Brent, in the 24% range, while in 2010 we expect these differentials to narrow to the 10% range. Variations in production and commodity prices during 2010 could significantly change this outlook. An increase in the oil price of $10.00/Bbl would increase anticipated funds flow by approximately $10.0 million for the year, while a $10.00/Bbl decrease in the oil price would result in anticipated funds flow decreasing by approximately $7.0 million. 2010 Capital Budget /T/ ($ million) 2010 --------------------------- --------------------------- Egypt 48.7 Yemen 14.1 Corporate 0.2 --------------------------- Total 63.0 --------------------------- --------------------------- /T/ The 2010 capital program is split 68:32 between development and exploration, respectively. The Company plans to participate in 37 wells in 2010. It is anticipated the Company will fund its entire 2010 capital budget from funds flow and working capital. The Company has designed its 2010 budget to be flexible allowing spending to be adjusted as commodity prices change and forecasts are reviewed. RISKS TransGlobe's results are affected by a variety of business risks and uncertainties in the international petroleum industry including but not limited to: /T/ -- 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. /T/ 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: Financial Risks Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on TransGlobe. The global financial crisis, which developed in late 2008 and continued throughout 2009, has increased the risk associated with timely access to debt, capital, and banking markets, along with market instability which may have an impact on TransGlobe's ability to obtain additional funding in the future. To mitigate this risk, management has been adjusting operational and financial risk strategies and continues to monitor the 2010 capital budget and the Company's long-term plans. The Company has designed its 2010 budget to be flexible allowing spending to be adjusted as commodity prices change and forecasts are reviewed. 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. a) Commodity price risk The Company's operational results and financial condition are dependent on the commodity prices received for its oil production. Commodity prices have fluctuated significantly this year. 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 has entered into various financial derivative contracts 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. b) 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, accounts payable and accrued liabilities denominated in Canadian dollars and Egyptian pounds. The Company does not utilize derivatives to manage this risk. 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 or a 10% decrease in the value of the Canadian dollar against the U.S. dollar would result in a decrease to net income of $0.1 million or an increase to net income of $0.1 million, respectively, for the year ended December 31, 2009. The Company maintains Egyptian pound cash balances to offset the Egyptian pound liabilities, and therefore, the Company believes its exposure to Egyptian pound fluctuations is not significant. c) 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 2009 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 income by $0.5 million for the year ended December 31, 2009. The effect of interest rates decreasing by 1% would increase the Company's net income by $0.5 million for year ended December 31, 2009. Credit Risk Credit risk is the risk of loss if counterparties do not fulfill their contractual obligations. The Company's exposure to credit risk primarily relates to 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 venture 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 regular payments on these amounts owing, the timing of these payments has historically been longer than normal industry standard. While the Company has no reason to believe that it will not collect this account receivable in full, 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. To mitigate this risk, the Company has entered into an insurance program on a portion of the receivable balance. The Company assesses the need for this program on a monthly basis. 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 2009 production to one purchaser. In Yemen, the Company sold all of its 2009 Block 32 production to one purchaser and all of its 2009 Block S-1 production to one purchaser. 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 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. Operational Risks 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 Risks 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 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. 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 Risks TransGlobe operates in countries with different 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 other things, 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, and economic and legal sanctions and other uncertainties arising from foreign governments. CRITICAL ACCOUNTING POLICIES AND ESTIMATES 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 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 1 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. Full Cost Accounting for Oil and Gas Activities a) Depletion and Depreciation Expense 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. b) Unproved Properties 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. c) Asset Impairments 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: i) the fair value of reserves; and ii) the costs of unproved properties that have been subject to a separate impairment test. Production Sharing Agreements International operations conducted pursuant to production sharing agreements (PSAs) are reflected in the Consolidated Financial Statements based on the Company's working interest in such operations. Under the PSAs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSA 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 venture 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 our international operations, all government interests, except for income taxes, are considered royalty payments. Our revenue also includes the recovery of costs paid on behalf of foreign governments in international locations. Derivative Financial Instruments and Hedging Activities a) Financial Instruments 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 asset or 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. 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, 2009. 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. b) Derivative Instruments and Hedging Activities 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. The Company does not use hedge accounting. 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 the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts. c) Embedded Derivatives 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 clearly and 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 classified as held for trading or designated at fair value. The Company elected January 1, 2003 as the transition date for embedded derivatives. d) Comprehensive Income Comprehensive income consists of net income and other comprehensive income. 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. Foreign exchange gains and losses arising from the translation of the financial statements of a self-sustaining foreign operation, net of tax, are recorded in comprehensive income. Accumulated other comprehensive income is an equity category comprised of the cumulative amounts of other comprehensive income. Effective May 1, 2008, the Company determined that its foreign operations were integrated as a result of the sale of the Canadian segment and its results were translated prospectively using the temporal method from that date. CHANGES IN ACCOUNTING POLICIES Goodwill and Intangible Assets 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 is applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company adopted 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 adoption of this Standard did not have an impact on the Consolidated Financial Statements. Credit Risk and Fair Value of Financial Assets and Liabilities In January 2009, the CICA issued EIC-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. The EIC provides guidance on how to take into account credit risk of an entity and counterparty when determining the fair value of financial assets and financial liabilities, including derivative instruments. This standard is effective for the Company's fiscal periods ending on or after January 20, 2009 with retrospective application. The application of this EIC did not have a material effect on the Company's Consolidated Financial Statements. Financial Instruments Effective July 1, 2009, the Company prospectively adopted an amendment to CICA 3855, Financial Instruments - Recognition and Measurement, in relation to embedded derivatives. This amendment prohibits the reclassification of a financial asset out of the held-for-trading category when the fair value of the embedded derivative in a combined contract cannot be reasonably measured. The adoption of the amendments to this Standard did not have an impact on the Consolidated Financial Statements. In June 2009, the CICA issued amendments to CICA Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments are effective for annual financial statements for fiscal years ending after September 30, 2009. The amendments are consistent with recent amendments to financial instrument disclosure standards in International Financial Reporting Standards ("IFRS"). The Company included these additional disclosures in its Consolidated Financial Statements for the year ending December 31, 2009. In August 2009, the CICA issued amendments to CICA 3855, Financial Instruments - Recognition and Measurement, in relation to the impairment of assets. The amendments are effective for annual financial statements for fiscal years beginning on or after November 1, 2008. The adoption of the amendments to this standard did not have an impact on the Consolidated Financial Statements. New Accounting Standards a) Business Combinations In December 2008, the CICA issued Section 1582, Business Combinations, which will replace CICA Section 1581 of the same name. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Company is currently evaluating the impact of this change on its Consolidated Financial Statements. b) Non-Controlling Interests In December 2008, the CICA issued Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. These standards currently do not impact the Company as it has full controlling interest of all of its subsidiaries. c) International Financial Reporting Standards ("IFRS") On February 13, 2008 the Canadian Accounting Standards Board has confirmed that effective for interim and annual financial statements related to fiscal years beginning on or after January 1, 2011, IFRS will replace Canada's current GAAP for all publicly accountable profit-oriented enterprises. The adoption of IFRS will require the restatement, for comparative purposes, of amounts reported by the Company for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010. The Company commenced its IFRS transition project in 2008 and has completed the project awareness and engagement phase of the IFRS transition project. Corporate governance over the project has been established and a steering committee and project team have been formed. The steering committee is comprised of members of management and executive and is responsible for final approval of project recommendations and deliverables to the Audit Committee and Board. Communication, training and education are an important aspect of the Company's IFRS conversion project. Internal and external training and education sessions have been carried out and will continue throughout each phase of the project. TransGlobe's IFRS transition project consists of three key phases; the diagnostic assessment phase, the design, planning and solution development phase and finally the implementation phase. In 2009, the Company made significant progress on its IFRS transition project. The Company is completing the diagnostic assessment phase in which the project team has performed comparisons of the differences between Canadian GAAP and IFRS, analyzed accounting policy alternatives and drafted its preliminary IFRS accounting policies. The project team has also presented preliminary accounting assessments on key IFRS transition issues for the steering committee's initial review and evaluation. These assessments include Exploration for and Evaluation of Mineral Resources, Property, Plant and Equipment, Impairments of Assets, Intangible Assets, Leases, Revenue, Inventories, Effects of changes in Foreign Exchange Rates, Borrowing Costs, Interest in Joint Ventures, Earnings per Share, Provisions, Contingent Liabilities and Contingent Assets and Employee Benefits. The Company continues to perform assessments on the remaining IFRS transition issues and has commenced analysis of IFRS financial statement presentation and disclosure requirements. Concurrently, the project team is working on the design, planning and solution development phase. In this phase, the focus is on determining the specific qualitative and quantitative impact the application of IFRS requirement has on the Company. The project team members continue to work with representatives from the various operational areas to develop recommendations including first- time adoption exemptions available upon initial transition to IFRS. The results from the consultations with the various operational areas are used to draft accounting policies. One of the sections in each of the draft accounting policy is the disclosure section which includes the financial statements disclosure as required by IFRS. First-time adoption exemptions were analyzed by the project team and a schedule has been presented for the steering committee to review and evaluate the exemptions. A detailed implementation plan and timeline has been developed, which also includes the development of a training plan. In the first half of 2010, the Company will move into the implementation phase of its project and will work on the development of processes and systems to ensure that IFRS comparative data is captured, and to position it for reporting under IFRS in 2011. In addition, the Company is monitoring the International Accounting Standards Board's ("IASB") active projects and all changes to IFRS prior to January 1, 2011 will be incorporated as required. Expected Accounting Policy Impacts The Company has determined that the most significant impact of IFRS conversion is to property and equipment ("PP&E"). IFRS does not prescribe specific oil and gas accounting guidance other than for costs associated with the exploration and evaluation phase. The Company currently follows full cost accounting as prescribed in Accounting Guideline 16, Oil and Gas Accounting - Full Cost. Transition to IFRS may have a significant impact on how the Company accounts for costs pertaining to oil and gas activities: Pre-exploration and evaluation costs - which are expenditures incurred prior to obtaining the legal right to explore. Currently the Company capitalizes these costs and depletes them at the country level. Under IFRS these costs must be expensed when incurred. Exploration and evaluation ("E&E") costs - Currently these costs are included in the PP&E balance on the Consolidated Balance Sheet, and include undeveloped land and costs relating to pre-commercial exploration of development. These costs are currently not being depleted. Under IFRS these costs will be moved out of the PP&E balance, and reported separately as E&E assets on the balance sheet. E&E costs will not be depleted but assessed for impairment and unrecoverable costs associated with a specific area will be expensed. When a project is determined to be technically feasible and commercially viable, the costs will be moved to PP&E and depletion will commence. Development costs - will continue to be capitalized as PP&E, however depletion will no longer be calculated at the country level but on an area level. TransGlobe has not finalized the areas or the inputs to be used in the deletion calculation. Also the level at which impairment tests are performed and the impairment testing methodology will differ under IFRS. IFRS conversion will also result in other impacts, some of which may be significant in nature. The impact on the Company's Consolidated Financial Statements cannot reasonably be determined at this time. IFRS 1, "First-Time Adoption of International Financial Reporting Standards", permits first time adopters of IFRS a number of exemptions. The Company is in the process of analyzing the full extent these exemptions. The Company expects to utilize the following exemptions, subject to final approval: Business combinations exemption, which allows for an implementation of the IFRS business combination rules on a prospective basis, therefore, business combinations entered into prior to January 1, 2010 will not be retrospectively restated. Foreign currency translation adjustments classified in accumulated other comprehensive income will be deemed zero and reclassified to retained earnings on January 1, 2010, and the retrospective restatement of foreign currency translation under IFRS will not be performed. Share-based payment transactions, TransGlobe intends to use this exemption under which stock options that vest prior to January 1, 2010 are not required to be retrospectively restated. In July 2009, IASB approved an exposure draft which allows additional exemptions for entities adopting IFRS for the first time. The Company expects to utilize the deemed cost for oil and gas asset exemption which would allow the Company to allocate their oil and gas asset balance, as determined under full cost accounting, to the IFRS categories of exploration and evaluation assets and development and producing properties on a cost centre basis. This exemption would relieve the Company from significant adjustments resulting from retrospective adoption of IFRS. Any changes in accounting policies required to address reporting and first-time adoption of IFRS will be made in consideration of the integrity of internal control over financial reporting and disclosure controls and procedures. Throughout 2010, TransGlobe will work to ensure that all changes in accounting polices relating to IFRS have controls and procedures to ensure that information is captured appropriately. TransGlobe has completed its assessment of IT systems requirements in order to ready the Company for IFRS reporting. The IT system modifications will not be significant and will allow for reporting under both Canadian GAAP and IFRS in 2010. DISCLOSURE CONTROLS AND PROCEDURES As of December 31, 2009, 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. INTERNAL CONTROLS OVER FINANCIAL REPORTING TransGlobe's management has designed and implemented internal controls over financial reporting, as defined under National Instrument 52-109 Certification of Disclosures in Issuers' Annual and Interim Filings, of the Canadian Securities Administrators. 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. 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, 2009. 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. /T/ CONSOLIDATED FINANCIAL STATEMENTS Consolidated Statements of Income (Loss) and Retained Earnings (Unaudited - Expressed in thousands of U.S. Dollars, except per share amounts) Three months ended Year ended December 31 December 31 2009 2008 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- REVENUE Oil sales, net of royalties and other $ 28,788 $ 17,765 $102,805 $123,231 Derivative gain (loss) on commodity contracts (Note 16) (684) 12,460 (4,213) 3,005 Other income 28 25 44 170 ---------------------------------------------------------------------------- 28,132 30,250 98,636 126,406 ---------------------------------------------------------------------------- EXPENSES Operating 7,387 5,857 24,765 19,333 General and administrative 3,922 3,010 11,427 10,213 Foreign exchange gain (92) (112) (1,032) (84) Interest on long-term debt 557 1,095 2,461 6,163 Depletion and depreciation (Note 4) 6,955 9,245 47,579 35,378 ---------------------------------------------------------------------------- 18,729 19,095 85,200 71,003 ---------------------------------------------------------------------------- Income before income taxes 9,403 11,155 13,436 55,403 Income taxes - current (Note 11) 6,887 3,673 21,853 32,230 ---------------------------------------------------------------------------- NET INCOME (LOSS) FROM CONTINUING OPERATIONS 2,516 7,482 (8,417) 23,173 NET INCOME FROM DISCONTINUED OPERATIONS (Note 5) - 158 - 8,350 ---------------------------------------------------------------------------- NET INCOME (LOSS) 2,516 7,640 (8,417) 31,523 Retained earnings, beginning of period 77,497 80,914 88,430 57,787 Repurchase of common shares (Note 8) - (124) - (880) ---------------------------------------------------------------------------- RETAINED EARNINGS, END OF PERIOD $ 80,013 $ 88,430 $ 80,013 $ 88,430 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net income (loss) from continuing operations per share (Note 14) Basic $ 0.04 $ 0.13 $ (0.13) $ 0.39 Diluted $ 0.04 $ 0.12 $ (0.13) $ 0.38 Net income from discontinued operations per share (Note 14) Basic $ - $ 0.01 - $ 0.14 Diluted $ - $ 0.01 - $ 0.14 Net income (loss) per share (Note 14) Basic $ 0.04 $ 0.14 $ (0.13) $ 0.53 Diluted $ 0.04 $ 0.13 $ (0.13) $ 0.52 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. Consolidated Statements of Comprehensive Income (Loss) (Unaudited - Expressed in thousands of U.S. Dollars) Three months ended Year ended December 31 December 31 2009 2008 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net income (loss) $ 2,516 $ 7,640 $( 8,417) $ 31,523 Other comprehensive (loss) income: Foreign currency translation adjustment - - - (886) ---------------------------------------------------------------------------- COMPREHENSIVE INCOME (LOSS) $ 2,516 $ 7,640 $( 8,417) $ 30,637 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. Consolidated Balance Sheets (Unaudited - Expressed in thousands of U.S. Dollars) As at As at December 31, 2009 December 31, 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ASSETS Current Cash and cash equivalents $ 16,177 $ 7,634 Accounts receivable 35,296 28,701 Derivative commodity contracts (Note 16) - 2,336 Prepaid expenses 1,620 822 Assets of discontinued operations (Note 5) 312 764 ---------------------------------------------------------------------------- 53,405 40,257 ---------------------------------------------------------------------------- Derivative commodity contracts (Note 16) - 472 Goodwill (Note 6) 8,180 8,180 Property and equipment (Note 4) 167,297 179,329 ---------------------------------------------------------------------------- $228,882 $228,238 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- LIABILITIES Current Accounts payable and accrued liabilities $ 14,717 $ 15,852 Income taxes payable 79 79 Derivative commodity contracts (Note 16) 514 - Current portion of long-term debt (Note 7) 49,799 - Liabilities of discontinued operations (Note 5) 83 342 ---------------------------------------------------------------------------- 65,192 16,273 Long-term debt (Note 7) - 57,230 ---------------------------------------------------------------------------- 65,192 73,503 ---------------------------------------------------------------------------- Commitments and contingencies (Note 17) SHAREHOLDERS' EQUITY Share capital (Note 8) 66,106 50,532 Contributed surplus (Note 10) 6,691 4,893 Accumulated other comprehensive income (Note 13) 10,880 10,880 Retained earnings 80,013 88,430 ---------------------------------------------------------------------------- 163,690 154,735 ---------------------------------------------------------------------------- $228,882 $228,238 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. Consolidated Statements of Cash Flows (Unaudited - Expressed in thousands of U.S. Dollars) Three months ended Year ended December 31 December 31 2009 2008 2009 2008 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES: OPERATING Net income (loss) $ 2,516 $ 7,640 $ (8,417) $ 31,523 Net income from discontinued operations - 158 - 8,350 ---------------------------------------------------------------------------- Net income (loss) from continuing operations 2,516 7,482 (8,417) 23,173 Adjustments for: Depletion and depreciation 6,955 9,245 47,579 35,378 Amortization of deferred financing costs 112 103 569 1,884 Stock-based compensation (Note 9) 518 584 2,011 1,830 Unrealized (gain) loss on commodity contracts (398) (11,835) 3,322 (9,906) Changes in non-cash working capital (Note 12) 2,890 5,431 (8,458) (1,269) ---------------------------------------------------------------------------- Cash provided by continuing operations 12,593 11,010 36,606 51,090 Cash provided by discontinued operations 1 242 193 6,703 ---------------------------------------------------------------------------- 12,594 11,252 36,799 57,793 ---------------------------------------------------------------------------- FINANCING Increase in long-term debt (Note 7) - - - 55,000 Repayments of long-term debt (Note 7) (3,000) - (8,000) (55,000) Deferred financing costs - - - (1,339) Repurchase of common shares (Note 8) - - - (1,135) Options surrendered for cash payments (Note 8) - - (13) (256) Issue of common shares for cash (Note 8) 186 - 16,578 512 Issue costs for common shares (1) - (1,204) - Changes in non-cash working capital (Note 12) (640) 809 (1,515) 1,515 ---------------------------------------------------------------------------- (3,455) 809 5,846 (703) ---------------------------------------------------------------------------- INVESTING Exploration and development expenditures (7,541) (13,924) (35,546) (43,857) Acquisitions (Note 3) - (381) - (62,392) Changes in non-cash working capital (Note 12) (225) 1,441 1,444 (2,737) ---------------------------------------------------------------------------- Cash used by continuing operations (7,766) (12,864) (34,102) (108,986) Cash (used) provided by discontinued operations - (419) - 46,600 ---------------------------------------------------------------------------- (7,766) (13,283) (34,102) (62,386) ---------------------------------------------------------------------------- Effect of exchange rate changes on cash and cash equivalents - 263 - 201 ---------------------------------------------------------------------------- NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS 1,373 (959) 8,543 (5,095) CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 14,804 8,593 7,634 12,729 ---------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, END OF PERIOD $ 16,177 $ 7,634 $ 16,177 $ 7,634 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Supplemental Disclosure of Cash Flow Information Cash interest paid $ 445 $ 992 $ 1,892 $ 4,279 Cash taxes paid 6,887 3,673 21,853 32,230 Cash is comprised of cash on hand and balances with banks 14,274 6,634 14,274 6,634 Cash equivalents 1,903 1,000 1,903 1,000 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. /T/ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As at December 31, 2009 and 2008 and for the years then ended (Expressed in U.S. Dollars) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The Consolidated Financial Statements include the accounts of TransGlobe Energy Corporation and subsidiaries ("TransGlobe" or the "Company"), and are presented in accordance with Canadian generally accepted accounting principles ("Canadian GAAP" or "Cdn. GAAP"). Information prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") is included in Note 19. In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are expressed in United States (U.S.) dollars. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars. Nature of Business and Principles of Consolidation The Company is engaged primarily in oil and gas exploration, development and production and the acquisition of properties. Such activities are concentrated in three geographic areas: /T/ -- West Gharib area, East Ghazalat area and Nuqra Block 1 within the Arab Republic of Egypt ("Egypt"); -- Block 32, Block S-1, Block 72, Block 75 and Block 84 within the Republic of Yemen ("Yemen"); and -- The Western Canadian Sedimentary Basin within Canada, until this area was sold in April 2008 (Note 5). /T/ Joint Ventures Investments in unincorporated joint ventures are accounted for using the proportionate consolidation method, whereby the Company's proportionate share of revenues, expenses, assets and liabilities are included in the accounts. Foreign Currency Translation The accounts of the integrated Canadian operations are translated using the temporal method, whereby monetary assets and liabilities are translated at year end exchange rates, non-monetary assets and liabilities at the historical rates and revenues and expenses at the rates for the period, except depreciation, depletion and accretion expense, which is translated on the same basis as the related assets. Translation gains and losses relating to the integrated Canadian operations are included in net income. Prior to May 1, 2008, the Canadian operations were considered to be self-sustaining and translated using the current rate method. Under the current rate method, assets and liabilities are translated at the period-end exchange rates, while revenues and expenses are translated using rates for the period and gains and losses are included as a separate component of shareholders' equity. Revenue Recognition Revenues associated with the sales of the Company's crude oil, natural gas and natural gas liquids owned by the Company are recognized when title passes from the Company to its customer. Crude oil and natural gas produced and sold by the Company below or above its working interest share in the related resource properties results in production underliftings or overliftings. Underliftings are recorded as inventory and overliftings are recorded as deferred revenue. International operations conducted pursuant to production sharing agreements (PSA's) are reflected in the Consolidated Financial Statements based on the Company's working interest in such operations. Under the PSA's, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSA 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 venture 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 our international operations, all government interests, except for income taxes, are considered royalty payments. Our revenue also includes the recovery of costs paid on behalf of foreign governments in international locations. Income Taxes The Company uses the liability method to account for income taxes. Under this method, future income taxes are based on the difference between assets and liabilities reported for financial accounting purposes from those reported for income tax. Future 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. 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 income tax expense at the statutory rate in effect at the time of production. Flow Through Shares The Company has financed a portion of its prior years' exploration and development activities in Canada through the issue of flow through shares. Under the terms of these share issues, the tax attributes of the related expenditures are renounced to subscribers. To recognize the foregone tax benefits, share capital is reduced and a future income tax liability is recorded for the income tax amount related to the renounced deductions. Net (Loss) Income Per Share Basic net (loss) income per share is calculated using the weighted average number of shares outstanding during the year. Diluted net (loss) income per share is calculated by giving effect to the potential dilution that would occur if stock options were exercised. Diluted net (loss) income per share is calculated using the treasury stock method. The treasury stock method 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. Cash and Cash Equivalents Cash and cash equivalents include cash on deposit with banks and short-term investments such as treasury bills with original maturity of less than 90 days. Property and Equipment The Company follows the full cost method of accounting for oil and gas operations whereby all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Depreciation, Depletion, Amortization and Impairment Capitalized costs within each country are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves as determined by independent reserve evaluators. Gas reserves and production are converted into equivalent units using the energy equivalency conversion method of 6,000 cubic feet of natural gas to one barrel of oil. Depletion and depreciation is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred in developing proved reserves, net of estimated salvage value. Costs of acquiring and evaluating unproved properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred. Proceeds from the sale of oil and gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would alter the rate of depletion and depreciation by more than 20% in a particular country, in which case a gain or loss on disposal is recorded. An impairment loss is recognized in net income if the carrying amount of a country (cost centre) is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves and the cost, less impairment, of unproved properties exceeds the carrying value. If the carrying value is assessed to not be recoverable, the calculation compares the carrying value to the sum of the discounted cash flows expected from the production of proved and probable reserves and the cost, less impairment, of unproved properties. Should the carrying value exceed this sum, an impairment loss is recognized. Furniture and fixtures are depreciated at declining balance rates of 20% to 30%. Asset Retirement Obligations ("ARO") The fair value of the statutory, contractual or legal liability associated with the retirement and reclamation of tangible long-lived assets is recognized when incurred. The asset retirement cost, equal to the estimated fair value of the ARO, is capitalized as part of the cost of the related long-lived asset. Asset retirement costs for the crude oil assets are amortized using the unit-of-production method. The ARO liabilities are carried on the Consolidated Balance Sheets at their discounted present value and are accreted over time for the change in present value, with the accretion charge included in depreciation, depletion and accretion. Actual expenditures incurred are charged against the accumulated obligation. Stock-based Compensation The Company records compensation expense in the Consolidated Financial Statements for stock options granted to employees and directors using the fair value method. From 2006 onward, the fair values are determined using the lattice-based binomial option pricing model and for years 2005 and prior, the Black-Scholes option pricing model was used. Compensation costs are recognized over the vesting period. The Company estimates forfeitures at the grant date and revises the estimate as necessary if subsequent information indicates that actual forfeitures differ significantly from the original estimate. Derivative Financial Instruments and Hedging Activities a) Financial Instruments All financial instruments are initially measured in the consolidated 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 asset or 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. 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, 2009. The Company has elected to classify all derivatives as held-for trading, which are measured at fair value with changes being recognized in net income. b) Derivative Instruments and Hedging Activities 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. The Company does not use hedge accounting. 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 the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts. c) Embedded Derivatives 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 clearly and 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 classified as held for trading or designated at fair value. The Company elected January 1, 2003 as the transition date for embedded derivatives. d) Comprehensive Income Comprehensive income consists of net income and other comprehensive income. 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. Foreign exchange gains and losses arising from the translation of the financial statements of a self-sustaining foreign operation, net of tax, are recorded in comprehensive income. Accumulated other comprehensive income is an equity category comprised of the cumulative amounts of other comprehensive income. Effective May 1, 2008, the Company determined that its foreign operations were integrated as a result of the sale of the Canadian segment and its results were translated prospectively using the temporal method from that date. Goodwill Goodwill, which represents the excess of cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed, is assessed at least annually for impairment. To assess impairment, the fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit's assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit's goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impaired amount. Goodwill is not amortized. Measurement Uncertainty Timely preparation of the financial statements in conformity with Canadian generally accepted accounting principles requires that Management make estimates and assumptions and use judgment regarding 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. Amounts recorded for depletion, depreciation and amortization, asset retirement costs and obligations, goodwill, stock-based compensation, future income taxes, and amounts used for ceiling test and impairment calculations are based on estimates of oil and natural gas reserves and future costs required to develop those reserves. By their nature, these estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material. 2. CHANGES IN ACCOUNTING POLICIES Goodwill and Intangible Assets 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 is applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company adopted 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 adoption of this Standard did not have an impact on the Consolidated Financial Statements. Credit Risk and Fair Value of Financial Assets and Liabilities In January 2009, the CICA issued EIC-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. The EIC provides guidance on how to take into account credit risk of an entity and counterparty when determining the fair value of financial assets and financial liabilities, including derivative instruments. This standard is effective for the Company's fiscal periods ending on or after January 20, 2009 with retrospective application. The application of this EIC did not have a material effect on the Company's financial statements. Financial Instruments Effective July 1, 2009, the Company prospectively adopted an amendment to CICA 3855, Financial Instruments - Recognition and Measurement, in relation to embedded derivatives. This amendment prohibits the reclassification of a financial asset out of the held-for trading category when the fair value of the embedded derivative in a combined contract cannot be reasonably measured. The adoption of the amendments to this Standard did not have an impact on the Consolidated Financial Statements. In June 2009, the CICA issued amendments to CICA Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments are effective for annual financial statements for fiscal years ending after September 30, 2009. The amendments are consistent with recent amendments to financial instrument disclosure standards in International Financial Reporting Standards ("IFRS"). The Company included these additional disclosures in these Consolidated Financial Statements. In August 2009, the CICA issued amendments to CICA 3855, Financial Instruments - Recognition and Measurement, in relation to the impairment of assets. The amendments are effective for annual financial statements for fiscal years beginning on or after November 1, 2008. The adoption of the amendments to this standard did not have impact on the Consolidated Financial Statements. New Accounting Standards a) Business Combinations In December 2008, the CICA issued Section 1582, Business Combinations, which will replace CICA Section 1581 of the same name. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Company is currently evaluating the impact of this change on its Consolidated Financial Statements. b) Non-Controlling Interests In December 2008, the CICA issued Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. These standards currently do not impact the Company as it has full controlling interest of all of its subsidiaries. c) International Financial Reporting Standards On February 13, 2008 the Canadian Accounting Standards Board has confirmed that effective for interim and annual financial statements related to fiscal years beginning on or after January 1, 2011, IFRS will replace Canada's current GAAP for all publicly accountable profit-oriented enterprises. The Company has determined that the most significant impact of IFRS conversion is to property and equipment. IFRS does not prescribe specific oil and gas accounting guidance other than for costs associated with the exploration and evaluation phase. The Company currently follows full cost accounting as prescribed in Accounting Guideline 16, Oil and Gas Accounting - Full Cost. Conversion to IFRS may have a significant impact on how the Company accounts for costs pertaining to oil and gas activities, in particular those related to the pre-exploration and development phases. In addition, the level at which impairment tests are performed and the impairment testing methodology will differ under IFRS. IFRS conversion will also result in other impacts, some of which may be significant in nature. The Company is in the process of evaluating the impact on the Company's Consolidated Financial Statements. 3. ACQUISITIONS Corporate Acquisition GHP Exploration (West Gharib) Ltd. On February 5, 2008, TransGlobe acquired all of the common shares of GHP Exploration (West Gharib) Ltd. ("GHP") for cash consideration of $44.1 million, net of cash acquired. The results of GHP's operations have been included in the consolidated financial statements since that date. GHP holds a 30% interest in the West Gharib Concession area in Egypt. TransGlobe funded the acquisition from bank debt of $40.0 million and cash on hand. The acquisition has been accounted for using the purchase method with TransGlobe as the acquirer, and the purchase price was allocated to the fair value of the assets acquired and the liabilities assumed as follows: /T/ Cost of acquisition (000s) ------------------------------------------------- Cash paid, net of cash acquired $ 44,095 Transaction costs 99 ------------------------------------------------- $ 44,194 ------------------------------------------------- Allocation of purchase price (000s) ------------------------------------------------- Property and equipment $ 36,602 Goodwill 3,602 Working capital, net of cash acquired 3,990 ------------------------------------------------- $ 44,194 ------------------------------------------------- /T/ Property Acquisition 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 on the West Gharib Concession. The total cost of the acquisition was $18.0 million, adjusted to the effective date of June 1, 2008. 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 the South Rahmi (up to $2.0 million) development leases. As at December 31, 2009, no additional fees are due in 2010. The value of the net assets acquired has been assigned to property and equipment. Following this property acquisition, TransGlobe holds 100% working interest in the West Gharib Concession in Egypt. 4. PROPERTY AND EQUIPMENT /T/ Egypt Year Ended December 31 -------------------------------------------------------------------------- (000s) 2009 2008 -------------------------------------------------------------------------- Oil and gas properties $ 184,605 $ 157,635 Furniture and fixtures 3,166 1,373 Accumulated depletion and depreciation (68,692) (30,336) -------------------------------------------------------------------------- $ 119,079 $ 128,672 -------------------------------------------------------------------------- /T/ On February 5, 2008 the Company acquired all common shares of GHP which held a 30% working interest in the West Gharib Concession area in Egypt. On August 18, 2008 the Company acquired an additional 25% financial interest in the eight non-Hana development leases. As a result of these two acquisitions and the Company's prior interest, TransGlobe now holds a 100% working interest in the West Gharib Concession in Egypt. The nine approved West Gharib development leases are valid for 20 years, expiring between 2019 and 2026. The Contractor (Joint Venture Partners) is in the second, three-year extension period of the Nuqra Concession Agreement which expires in July 2012. During the year, the Company capitalized general and administrative costs relating to exploration and development activities of $1.2 million (2008 - $1.9 million). Unproven property costs in the amount of $9.8 million (2008 - $10.0 million) were excluded from costs subject to depletion and depreciation representing costs incurred in Nuqra and undeveloped land in West Gharib. Future development costs for proved reserves included in the depletion calculation for the year ended December 31, 2009 totaled $4.9 million (2008 - $3.3 million). /T/ Yemen Year Ended December 31 -------------------------------------------------------------------------- (000s) 2009 2008 -------------------------------------------------------------------------- Oil and gas properties $ 126,152 $ 119,139 Accumulated depletion and depreciation (78,666) (69,230) -------------------------------------------------------------------------- $ 47,486 $ 49,909 -------------------------------------------------------------------------- /T/ The Company has working interests in five blocks in Yemen: Block 32, Block S-1, Block 72, Block 75 and Block 84. The Block 32 (13.81087%) Production Sharing Agreement ("PSA") continues to 2020, with provision for a five year extension. The Block S-1 (25%) PSA continues to 2023, with provision for a five year extension. At December 31, 2009, the Contractor (Joint Venture Partners) was in the second 30-month exploration period of the Block 72 (33%) PSA which commenced January 2009. The Contractor (Joint Venture Partners) is in the first 36-month exploration period commencing March 8, 2008 of the Block 75 (25%) PSA. The Block 84 (33%) PSA is in the ratification process with the Government of Yemen. During the year, the Company capitalized overhead costs relating to exploration and development activities of $0.2 million (2008 - $0.3 million). Unproven property costs in the amount of $10.8 million in 2009 ($7.2 million in 2008) were excluded in the costs subject to depletion and depreciation representing some of the costs incurred at Block 72, Block 75 and Block 84. Future development costs for proved reserves included in the depletion calculation for the year ended December 31, 2009 totaled $12.3 million (2008 - $12.1 million). /T/ Corporate Year Ended December 31 ---------------------------------------------------------------------- (000s) 2009 2008 ---------------------------------------------------------------------- Furniture, fixtures and other $ 2,333 $ 2,148 Accumulated depreciation (1,601) (1,400) ---------------------------------------------------------------------- $ 732 $ 748 ---------------------------------------------------------------------- /T/ Ceiling Test An impairment test calculation was performed on property and equipment at December 31, 2009 in which the estimated undiscounted future net cash flows based on estimated future prices associated with the proved reserves exceed the carrying amount of oil and gas property and equipment for each cost centre. The following table outlines the oil prices used in the impairment test at December 31, 2009: /T/ Year Egypt Yemen --------------------------------------------------- 2010 73.25 78.43 2011 75.75 80.78 2012 78.33 83.26 2013 81.00 85.84 2014 83.76 88.52 Thereafter(1) 2.0% 2.0% --------------------------------------------------- (1) Percentage change represents the increase in each year after 2014 to the end of the reserve life. /T/ 5. DISCONTINUED OPERATIONS On April 30, 2008, the Company sold its Canadian oil and natural gas interests for C$56.7 million, subject to normal closing adjustments. The Canadian operations have been accounted for as discontinued operations in accordance with Canadian GAAP. 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. Discontinued operations as at December 31, 2009 included property and equipment of $0.3 million. Discontinued operations at December 31, 2008 included current assets of $0.5 million, property and equipment of $0.3 million, and current liabilities of $0.3 million. /T/ Year Ended December 31 ------------------------------------------------------------------------ (000s) 2009 2008 ------------------------------------------------------------------------ ------------------------------------------------------------------------ Revenue Oil and gas sales, net of royalties $ - $ 9,162 Expenses Operating - 2,228 Depletion, depreciation and accretion - 2,678 ------------------------------------------------------------------------ 4,906 Gain on disposition, net of tax - 4,012 ------------------------------------------------------------------------ Income from discontinued operations before taxes - 8,268 Future income tax recovery (expense) - 82 ------------------------------------------------------------------------ Net income from discontinued operations $ - $ 8,350 ------------------------------------------------------------------------ ------------------------------------------------------------------------ /T/ In Canada, the Company capitalized overhead costs relating to exploration and development activities during the nine months ended September 30, 2008 of $0.4 million. Unproven property costs of $1.8 million were excluded from the costs subject to depletion and depreciation for 2008. Depletion, depreciation and accretion was not recorded while the assets were classified as held for sale. 6. GOODWILL Changes in the carrying amount of the Company's goodwill, arising from acquisitions, are as follows: /T/ Year Ended December 31 ------------------------------------------------------------------ (000s) 2009 2008 ------------------------------------------------------------------ ------------------------------------------------------------------ Balance, beginning of year $ 8,180 $ 4,313 Changes during the year - 3,867 ------------------------------------------------------------------ Balance, end of year $ 8,180 $ 8,180 ------------------------------------------------------------------ ------------------------------------------------------------------ /T/ 7. LONG-TERM DEBT /T/ Year Ended December 31 -------------------------------------------------------------------------- (000s) 2009 2008 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Revolving Credit Agreement $ 50,000 $ 58,000 Unamortized transaction costs (201) (770) -------------------------------------------------------------------------- 49,799 57,230 -------------------------------------------------------------------------- Current portion of long-term debt 49,799 - -------------------------------------------------------------------------- $ - $ 57,230 -------------------------------------------------------------------------- -------------------------------------------------------------------------- /T/ As at December 31, 2009, the Company has a $60.0 million Revolving Credit Agreement of which $50.0 million is drawn. The Revolving Credit Agreement expires on September 25, 2010 and is secured by a first floating charge debenture over all assets of the Company, a general assignment of book debts, security pledge of the Company's subsidiaries and certain covenants. The Revolving Credit Agreement bears interest at the Eurodollar Rate plus three percent. During the year ended December 31, 2009, the average effective interest rate was 4.3% (2008 - 7.3%). In the year ended December 31, 2009, the Company incurred $ Nil (2008 - $1.3 million), in fees to draw on its Revolving Credit Agreement. The future debt payments on long-term debt, as of December 31, 2009, are as follows: /T/ (000s) ------------------------------------------ 2010 (due September 25, 2010) $ 50,000 ------------------------------------------ /T/ The Company is in discussion on a new credit facility and expects to enter into a new facility in the second quarter of 2010. 8. SHARE CAPITAL Authorized The Company is authorized to issue an unlimited number of common shares with no par value. Issued /T/ Year Ended December Year Ended December 31, 31, 2009 2008 ------------------------------------------------------------------------- (000s) Shares Amount Shares Amount ------------------------------------------------------------------------- ------------------------------------------------------------------------- Balance, beginning of year 59,500 $ 50,532 59,627 $ 50,128 Share issuance 5,798 16,312 - - Stock options exercised 101 266 173 512 Stock options surrendered for cash payments - (13) - (256) Stock-based compensation on exercise - 213 - 403 Repurchase of common shares - - (300) (255) Share issue costs - (1,204) - - ------------------------------------------------------------------------- Balance, end of year 65,399 $ 66,106 59,500 $ 50,532 ------------------------------------------------------------------------- ------------------------------------------------------------------------- /T/ In the first quarter of 2009, the Company issued 5,798,000 common shares at C$3.45 per common share for gross proceeds of C$20.0 million (net C$18.5 million). The Company has received regulatory approval to purchase, from time to time, as it considers advisable, up to 6,116,905 common shares under a Normal Course Issuer Bid which commenced September 7, 2009 and will terminate September 6, 2010. During the year ended December 31, 2009, the Company did not repurchase any common shares. During the year ended December 31, 2008, the Company repurchased and cancelled 300,000 common shares at an average price of C$3.87 (US$3.66) per share. The excess of the purchase price over the book value in the amount of $0.9 million was charged to retained earnings during the year. 9. STOCK OPTION PLAN The Company adopted a stock option plan in May 2007 (the "Plan"). The number of Common Shares that may be issued pursuant to the exercise of Options awarded under the Plan and all other Security Based Compensation Arrangements of the Company is 10% of the common shares outstanding from time to time. All incentive stock options granted under the Plan have a per-share exercise price not less than the trading market value of the common shares at the date of grant. Effective February 1, 2005; all new grants of stock options vest one-third on each of the first, second and third anniversaries of the grant date. The following tables summarize information about the stock options outstanding and exercisable at December 31: /T/ 2009 2008 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Weighted- Weighted- Number Average Number Average (000s, except per of Exercise Price of Exercise Price share amounts) Options (C$) Options (C$) -------------------------------------------------------------------------- -------------------------------------------------------------------------- Options outstanding, beginning of year 5,600 4.20 2,936 4.78 Granted 815 3.45 3,457 3.77 Exercised (101) 2.92 (173) 2.98 Exercised for cash (80) 3.26 (150) 3.40 Forfeited (756) 3.91 (470) 5.33 -------------------------------------------------------------------------- Options outstanding, end of year 5,478 4.12 5,600 4.20 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Options exercisable, end of year 2,335 4.72 1,758 4.94 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Options Outstanding ---------------------------------------------------------------------------- Weighted- Number Average Weighted- Outstanding at Remaining Average Exercise Prices Dec. 31, 2009 Contractual Exercise Price (C$) (000s) Life (Years) ($C) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 2.41-3.25 1,836 3.9 2.76 3.26-4.08 770 4.7 3.48 4.09-5.18 1,700 3.1 4.71 5.19-5.31 348 2.6 5.21 5.32-6.56 823 1.1 6.07 ---------------------------------------------------------------------------- 5,477 3.2 4.12 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Options Exercisable ---------------------------------------------------------------------- Weighted- Number Average Weighted- Exercisable at Remaining Average Exercise Prices Dec. 31, 2009 Contractual Exercise Price (C$) (000s) Life (Years) (C$) ----------------------------------------------------------------------- 2.41-3.25 559 3.9 2.75 3.26-4.08 - - - 4.09-5.18 779 2.9 4.63 5.19-5.31 214 2.4 5.21 5.32-6.56 783 1.0 6.10 ----------------------------------------------------------------------- 2,335 2.4 4.72 ----------------------------------------------------------------------- ----------------------------------------------------------------------- /T/ Stock-based Compensation Compensation expense of $2.0 million has been recorded in general and administrative expenses in the Consolidated Statements of (Loss) Income and Retained Earnings in 2009 (2008 - $1.8 million). The fair value of all common stock options granted is estimated on the date of grant using the lattice-based binomial option pricing model. The weighted average fair value of options granted during the year and the assumptions used in their determination are as noted below: /T/ Year Ended December 31 --------------------------------------------------------------------------- 2009 2008 --------------------------------------------------------------------------- --------------------------------------------------------------------------- Weighted average fair market value per option (C$) 1.25 1.62 Risk free interest rate (%) 2.54 3.10 Expected life (years) 5 5 Expected volatility (%) 44.06 44.76 Dividend per share 0.00 0.00 Expected forfeiture rate (non- executive employees) (%) 12 12 Early exercise (Year 1/Year 2/Year 3/Year 4/Year 5) 0%/10%/20%/30%/40% 0%/10%/20%/30%/40% --------------------------------------------------------------------------- --------------------------------------------------------------------------- /T/ Options granted vest annually over a three-year period and expire five years after the grant date. During the year, employees exercised 101,000 (2008 - 173,300) stock options. In accordance with Canadian generally accepted accounting principles, the fair value related to these options was $0.2 million (2008 - $0.4 million) at time of grant and has been transferred from contributed surplus to common shares. 10. CONTRIBUTED SURPLUS /T/ Year Ended December 31 ---------------------------------------------------------------------- (000s) 2009 2008 ---------------------------------------------------------------------- ---------------------------------------------------------------------- Contributed surplus, beginning of year $ 4,893 $ 3,562 Stock-based compensation expense 2,011 1,734 Transfer to common shares on exercise of options (213) (403) ---------------------------------------------------------------------- Contributed surplus, end of year $ 6,691 $ 4,893 ---------------------------------------------------------------------- ---------------------------------------------------------------------- /T/ 11. INCOME TAXES The Company's future Canadian income tax assets are as follows: /T/ Year Ended December 31 ------------------------------------------------------------------------- (000s) 2009 2008 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Differences related to: Fixed assets and oil and gas properties $ (227) $ 1,479 Non-capital losses carried forward 2,728 210 Share issue expenses 535 111 ------------------------------------------------------------------------- 3,036 1,800 Valuation allowance for future income tax assets (3,036) (1,800) ------------------------------------------------------------------------- Future income tax asset $ - $ - ------------------------------------------------------------------------- ------------------------------------------------------------------------- /T/ The Company has non-capital losses of $9.4 million that expire between 2028 and 2029. Current income taxes represent income taxes incurred and paid under the laws of Yemen pursuant to the PSA on Block 32 and Block S-1 and Egypt pursuant to the PSC on the West Gharib Concession. Income taxes vary from the amount that would be computed by applying the Canadian statutory income tax rate of 29.0% (2008 - 29.5%) to income before taxes as follows: /T/ Year Ended December 31 ---------------------------------------------------------------------- (000s) 2009 2008 ---------------------------------------------------------------------- ---------------------------------------------------------------------- Income taxes calculated at the Canadian statutory rate $ 3,897 $ 15,017 Increases (decreases) in income taxes resulting from: Permanent differences 540 3,166 Changes in valuation allowance, net of foreign exchange 552 (1,731) Different tax rates in Yemen and Egypt 15,950 13,423 Changes in tax rates and other 914 2,355 ---------------------------------------------------------------------- Current income taxes $ 21,853 $ 32,230 ---------------------------------------------------------------------- ---------------------------------------------------------------------- /T/ 12. SUPPLEMENTAL CASH FLOW INFORMATION Changes in operating non-cash working capital consisted of the following: /T/ Year Ended December 31 ----------------------------------------------------------------------- (000s) 2009 2008 ----------------------------------------------------------------------- ----------------------------------------------------------------------- Operating activities Increase in current assets Accounts receivable $ (6,595) $ (14,292) Prepaid expenses (798) (265) Working capital acquired - 3,925 Increase in current liabilities Accounts payable and accrued liabilities (1,065) 9,284 Income taxes payable - 79 ----------------------------------------------------------------------- $ (8,458) $ (1,269) ----------------------------------------------------------------------- Financing Increase in current liabilities Accounts payable and accrued liabilities $ (1,515) $ 1,515 ----------------------------------------------------------------------- $ (1,515) $ 1,515 ----------------------------------------------------------------------- Investing activities Decrease in current liabilities Accounts payable and accrued liabilities 1,444 (2,737) ----------------------------------------------------------------------- $ 1,444 $ (2,737) ----------------------------------------------------------------------- ----------------------------------------------------------------------- /T/ 13. ACCUMULATED OTHER COMPREHENSIVE INCOME The balance of accumulated other comprehensive income consists of the following: /T/ Year Ended December 31 ----------------------------------------------------------------------- (000s) 2009 2008 ----------------------------------------------------------------------- ----------------------------------------------------------------------- Accumulated other comprehensive income, beginning of year $ 10,880 $ 11,766 Other comprehensive loss: Foreign currency translation adjustment - (886) ----------------------------------------------------------------------- Accumulated other comprehensive income, end of year $ 10,880 $ 10,880 ----------------------------------------------------------------------- ----------------------------------------------------------------------- /T/ 14. PER SHARE AMOUNTS In calculating the net (loss) income per share, net (loss) income from continuing operations per share and net income from discontinued operations per share, basic and diluted, the following weighted average shares were used: /T/ Year Ended December 31 ------------------------------------------------------------------------- (000s) 2009 2008 ------------------------------------------------------------------------- Weighted average number of shares outstanding 64,443 59,692 Dilution effect stock options - 1,012 ------------------------------------------------------------------------- Weighted average number of diluted shares outstanding 64,443 60,704 ------------------------------------------------------------------------- /T/ The treasury stock method 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, 2009, the Company excluded all stock options outstanding because there was a net loss in the year then ended. In calculating the weighted average number of diluted shares outstanding for the year ended December 31, 2008, the Company excluded 3,014,700 options because their exercise price was greater than the annual average common share market price in this period. 15. 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 oil and gas 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 company's debt-to-funds flow ratio is less than two or total of the long-term debt is not greater than two times the Company's funds flow from operations for the trailing twelve months. Debt-to-funds flow is a non-GAAP measure and may not be comparable to similar measures used by other companies. For the purposes of measuring the Company's ability to meet the above stated criteria, funds flow from operations is defined as the net income or loss (including net income or loss from discontinued operations) before any deduction for depletion, depreciation and accretion, amortization of deferred financing charges, non-cash stock-based compensation, and non-cash derivative (gain) loss on commodity contracts. Funds flow from operations is a non-GAAP measure and may not be comparable to similar measures used by other companies. The Company defines and computes its capital as follows: /T/ As at As at (000s) December 31, 2009 December 31, 2008 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Shareholders' equity $ 163,690 $ 154,735 Long-term debt, including the current portion 49,799 57,230 Cash and cash equivalents (16,177) (7,634) -------------------------------------------------------------------------- Total capital $ 197,312 $ 204,331 -------------------------------------------------------------------------- -------------------------------------------------------------------------- /T/ The Company's debt-to-funds flow ratio is computed as follows: /T/ 12 Months Trailing ------------------------------------------------------------------------- (000s) December 31, 2009 December 31, 2008 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Long-term debt, including the current portion $ 49,799 $ 57,230 ------------------------------------------------------------------------- Cash flow from operating activities $ 36,799 $ 57,793 Changes in non-cash working capital 8,265 1,474 ------------------------------------------------------------------------- Funds flow from operations $ 45,064 $ 59,267 ------------------------------------------------------------------------- Ratio 1.1 1.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- /T/ 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 its revolving credit agreement. The key financial covenants are as follows: - Interest coverage ratio of greater than 3.5 to 1.0, calculated as EBITDAX to interest expense, for the immediately preceding four consecutive fiscal quarters. For the purposes of the financial covenant calculations EBITDAX shall mean Consolidated Net Income before interest, income taxes, depreciation, depletion, amortization, and accretion, unrealized derivative losses on commodity contracts and stock-based compensation expense. - Indebtedness to EBITDAX of less than 2.0 to 1.0. For the purposes of the financial covenant calculation, indebtedness shall mean the balance of the Revolving Credit Facility, letters of credit and any amounts payable in connection with a realized derivative loss. - 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 is in compliance with all financial covenants at December 31, 2009. 16. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Fair Values of Financial Instruments The Company has classified its cash and cash equivalents as assets held for trading and its derivative commodity contracts as financial assets or liabilities held for trading, which are both measured at fair value with changes being recognized in net income. Accounts receivable are classified as loans and receivables; accounts payable and accrued liabilities, liabilities of discontinued operations, and long-term debt are classified as other liabilities, all of which are measured at amortized cost. Carrying value and fair value of financial assets and liabilities are summarized as follows: /T/ December 31, 2009 ------------------------------------------------------------------ Classification (000s) Carrying Value Fair Value ------------------------------------------------------------------ ------------------------------------------------------------------ Financial assets held-for-trading $ 16,177 $ 16,177 Loans and receivables 35,296 35,296 Financial liabilities held-for-trading 514 514 Other liabilities 64,599 64,800 ------------------------------------------------------------------ ------------------------------------------------------------------ /T/ Assets and liabilities at December 31, 2009 that are measured at fair value are classified into the following 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 risk management contracts have been assessed on the fair value hierarchy described above. TransGlobe's cash and cash equivalents are classified as Level 1 and risk management 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. 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 accounts receivable, the majority of which are in respect of oil operations, and derivative commodity contracts. 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 and an insurance program on a portion of the receivable balance. The Company has not experienced any material credit losses to date. Trade and other receivables from continuing operations are analyzed in the table below. With respect to the trade and other receivables that are not impaired and past due, there are no indications as of the reporting date that the debtors will not meet their payment obligations. /T/ (000s) -------------------------------------------------------------- Trade and other receivables at December 31, 2009 -------------------------------------------------------------- Neither impaired nor past due $ 12,552 Impaired (net of valuation allowance) - Not impaired and past due in the following period: Within 30 days 5,648 31-60 days 4,922 61-90 days 4,930 Over 90 days 7,244 -------------------------------------------------------------- -------------------------------------------------------------- /T/ In Egypt, the Company sold all of its 2009 and 2008 production to one purchaser. In Yemen, the Company sold all of its 2009 and 2008 Block 32 production to one purchaser and all of its 2009 and 2008 Block S-1 production to one purchaser. Management considers such transactions normal for the Company and the international oil industry in which it operates. 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. a) Commodity Price Risk The Company's operational results and financial condition are partially dependent on the commodity prices received for its oil production. Commodity prices have fluctuated significantly during recent years. Any movement in commodity prices would have an effect on the Company's financial condition. Therefore, the Company has entered into various financial derivative contracts to manage fluctuations in commodity prices in the normal course of operations. The following contracts are outstanding at December 31, 2009: /T/ Dated Brent Pricing Put- Period Volume Type Call ------------------------------------------------------------------------- ------------------------------------------------------------------------- Crude Oil ------------------------- January 1, 2010-August 12,000 Financial 31, 2010 Bbls/month Collar $60.00-$84.25 January 1, 2010-August 9,000 Financial 31, 2010 Bbls/month Collar $40.00-$80.00 January 1, 2010-December 10,000 Financial 31, 2010 Bbls/month Floor $60.00 ------------------------------------------------------------------------- ------------------------------------------------------------------------- /T/ The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheet, with any change in the unrealized positions recorded to income. The Company assessed 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 paid to, or received from, counter-parties to settle the transactions outstanding as at the Consolidated Balance Sheet date with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates. When assessing the potential impact of commodity price changes on its financial derivative commodity contracts, the Company believes 10% volatility is a reasonable measure. The effect of a 10% increase in commodity prices on the derivative commodity contracts would increase the net loss, for the year ended December 31, 2009, by $0.9 million. The effect of a 10% decrease in commodity prices on the derivative commodity contracts would decrease the net loss, for the year ended December 31, 2009, by $0.7 million. b) 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, 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 loss for the year ended December 31, 2009, of approximately $0.1 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would increase the net loss by said amount for the same period. The Company does not utilize derivative instruments to manage this risk. c) 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 2009 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 increase the Company's net loss, for the year ended December 31, 2009, by $0.6 million. The effect of interest rates decreasing by 1% would decrease the Company's net loss, for the year ended December 31, 2009, by $0.6 million. 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. 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, 2009: /T/ (000s) Payment Due by Period(1),(2) ------------------------------------------------------------------------- Recognized in Financial Contractual Cash Less than 1 Statements Flows year ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accounts payable and accrued liabilities Yes-Liability $ 14,800 $ 14,800 Long-term debt: Revolving Credit Agreement Yes-Liability 50,000 50,000 Derivative commodity contracts Yes-Liability 514 514 Office and equipment leases No 1,504 738 Minimum work commitments(3) No 20,586 10,353 ------------------------------------------------------------------------- Total $ 87,404 $ 76,405 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (000s) Payment Due by Period(1),(2) ------------------------------------------------------------ More than 1-3 years 4-5 years 5 years ------------------------------------------------------------ ------------------------------------------------------------ Accounts payable and accrued liabilities $ - $ - $ - Long-term debt: Revolving Credit Agreement - - - Derivative commodity contracts - - - Office and equipment leases 766 - - Minimum work commitments(3) 4,953 5,280 - ------------------------------------------------------------ Total $ 5,719 $ 5,280 $ - ------------------------------------------------------------ ------------------------------------------------------------ (1) Payments exclude ongoing operating costs related to certain leases, interest on long-term debt and payments made to settle derivatives. (2) Payments denominated in foreign currencies have been translated at December 31, 2009 exchange rates. (3) Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations. /T/ 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. In addition, the Company raised gross proceeds of $16.3 million in the first quarter of 2009 through a share issuance. The existing banking arrangements at December 31, 2009 consist of a Revolving Credit Facility of $60.0 million of which $50.0 million is drawn. The Company is in discussion on a new credit facility and expects to enter into a new facility in the second quarter of 2010. The table above shows cash outflow for financial derivative instruments based on forward-curve prices for Dated Brent oil of $74.28/Bbl at December 31, 2009. Amounts due may change significantly due to fluctuations in the price of Dated Brent oil. 17. COMMITMENTS AND CONTINGENCIES The Company is subject to certain office and equipment leases (Note 16). Pursuant to the Concession Agreement for Nuqra Block 1 in Egypt, the Contractor (Joint Venture Partners) has a minimum financial commitment of $5.0 million ($4.4 million to TransGlobe) and a work commitment of two exploration wells in the second exploration extension. The second, 36-month extension period commenced on July 18, 2009. The Contractor has met the second extension financial commitment of $5.0 million in the prior periods. At the request of the government, the Company provided a $4.0 million production guarantee from the West Gharib Concession prior to entering the second extension period. TransGlobe has entered into a farm out agreement and has committed to pay 100% of three (3) exploration wells to a maximum of $9.0 million to earn a 50% working interest in the East Ghazalat Concession in the Western Desert of Egypt, subject to the approval of the Egyptian Government. Pursuant to the Production Sharing Agreement ("PSA") for Block 72 in Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $2.0 million ($0.7 million to TransGlobe) during the second exploration period. The second, 30-month exploration period commenced on January 12, 2009. Pursuant to the PSA for Block 75 in Yemen, the Contractor (Joint Venture Partners) has a remaining minimum financial commitment of $3.0 million ($0.8 million to TransGlobe) for one exploration well. The first, 36-month exploration period commenced March 8, 2008. The Company issued a $1.5 million letter of credit (expiring November 15, 2011) to guarantee the Company's performance under the first exploration period. The letter is secured by a guarantee granted by Export Development Canada. Pursuant to the bid awarded for Block 84 in Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $4.1 million ($1.4 million to TransGlobe) for the signature bonus and a $16.0 million ($5.3 million to TransGlobe) first exploration period work program consisting of seismic acquisition and four exploration wells. The first, 42-month exploration period will commence if the PSA is finalized and ratified by the Government of Yemen. 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 $7.0 million if incremental reserve thresholds are reached in the East Hoshia (up to $5.0 million) and South Rahmi (up to $2.0 million) development leases, to be evaluated annually. As at December 31, 2009, no additional fees are due in 2010. 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. 18. SEGMENTED INFORMATION /T/ Egypt --------------------------------------------------------------------------- Year Ended December 31 (000s) 2009 2008 --------------------------------------------------------------------------- --------------------------------------------------------------------------- Revenue Oil sales, net of royalties and other $ 64,117 $ 51,368 Other income - 36 --------------------------------------------------------------------------- Total revenue 64,117 51,404 --------------------------------------------------------------------------- Segmented expenses Operating expenses 14,703 6,972 Depletion and depreciation 37,942 23,052 Income taxes 13,980 14,627 --------------------------------------------------------------------------- Total segmented expenses 66,625 44,651 --------------------------------------------------------------------------- Segmented (loss) income $ (2,508) $ 6,753 --------------------------------------------------------------------------- Non-segmented expenses Derivative loss (gain) on commodity contracts (Note 16) General and administrative Interest on long-term debt Depreciation Foreign exchange (gain) loss Other income --------------------------------------------------------------------------- Total non-segmented expenses --------------------------------------------------------------------------- Net (loss) income from continuing operations Net income from discontinued operations (Note 5) --------------------------------------------------------------------------- Net (loss) income --------------------------------------------------------------------------- --------------------------------------------------------------------------- Capital expenditures Exploration and development $ 28,349 $ 34,797 Property acquisitions - 18,000 --------------------------------------------------------------------------- $ 28,349 $ 52,797 Corporate Corporate acquisitions --------------------------------------------------------------------------- Total capital expenditures --------------------------------------------------------------------------- --------------------------------------------------------------------------- (000s) Dec.31 2009 Dec.31 2008 --------------------------------------------------------------------------- Property and equipment $ 119,079 $ 128,672 Goodwill 8,180 8,180 Other 41,347 27,517 --------------------------------------------------------------------------- Segmented assets $ 168,606 $ 164,369 Non-segmented assets Discontinued operations --------------------------------------------------------------------------- Total assets --------------------------------------------------------------------------- --------------------------------------------------------------------------- Yemen ------------------------------------------------------------------- Year Ended December 31 (000s) 2009 2008 ------------------------------------------------------------------- ------------------------------------------------------------------- Revenue Oil sales, net of royalties and other $ 38,688 $ 71,863 Other income - 1 ------------------------------------------------------------------- Total revenue 38,688 71,864 ------------------------------------------------------------------- Segmented expenses Operating expenses 10,062 12,361 Depletion and depreciation 9,436 11,993 Income taxes 7,873 17,603 ------------------------------------------------------------------- Total segmented expenses 27,371 41,957 ------------------------------------------------------------------- Segmented (loss) income $ 11,317 $ 29,907 ------------------------------------------------------------------- Non-segmented expenses Derivative loss (gain) on commodity contracts (Note 16) General and administrative Interest on long-term debt Depreciation Foreign exchange (gain) loss Other income ------------------------------------------------------------------- Total non-segmented expenses ------------------------------------------------------------------- Net (loss) income from continuing operations Net income from discontinued operations (Note 5) ------------------------------------------------------------------- Net (loss) income ------------------------------------------------------------------- ------------------------------------------------------------------- Capital expenditures Exploration and development $ 7,013 $ 8,819 Property acquisitions - - ------------------------------------------------------------------- $ 7,013 $ 8,819 Corporate Corporate acquisitions ------------------------------------------------------------------- Total capital expenditures ------------------------------------------------------------------- ------------------------------------------------------------------- (000s) Dec.31 2009 Dec.31 2008 ------------------------------------------------------------------- Property and equipment $ 47,486 $ 49,909 Goodwill - - Other 5,877 6,430 ------------------------------------------------------------------- Segmented assets $ 53,363 $ 56,339 Non-segmented assets Discontinued operations ------------------------------------------------------------------- Total assets ------------------------------------------------------------------- ------------------------------------------------------------------- Total ----------------------------------------------------------------------- Year Ended December 31 (000s) 2009 2008 ----------------------------------------------------------------------- ----------------------------------------------------------------------- Revenue Oil sales, net of royalties and other $ 102,805 $ 123,231 Other income - 37 ----------------------------------------------------------------------- Total revenue 102,805 123,268 ----------------------------------------------------------------------- Segmented expenses Operating expenses 24,765 19,333 Depletion and depreciation 47,378 35,045 Income taxes 21,853 32,230 ----------------------------------------------------------------------- Total segmented expenses 93,996 86,608 ----------------------------------------------------------------------- Segmented (loss) income 8,809 36,660 ----------------------------------------------------------------------- Non-segmented expenses Derivative loss (gain) on commodity contracts (Note 16) 4,213 (3,005) General and administrative 11,427 10,213 Interest on long-term debt 2,461 6,163 Depreciation 201 333 Foreign exchange (gain) loss (1,032) (84) Other income (44) (133) ----------------------------------------------------------------------- Total non-segmented expenses 17,226 13,487 ----------------------------------------------------------------------- Net (loss) income from continuing operations (8,417) 23,173 Net income from discontinued operations (Note 5) - 8,350 ----------------------------------------------------------------------- Net (loss) income $ (8,417) $ 31,523 ----------------------------------------------------------------------- Capital expenditures Exploration and development $ 35,362 $ 43,616 Property acquisitions - 18,000 ----------------------------------------------------------------------- 35,362 61,616 Corporate 184 241 Corporate acquisitions - 36,602 ----------------------------------------------------------------------- Total capital expenditures $ 35,546 $ 98,459 ----------------------------------------------------------------------- ----------------------------------------------------------------------- (000s) Dec.31 2009 Dec.31 2008 ----------------------------------------------------------------------- Property and equipment $ 166,565 $ 178,581 Goodwill 8,180 8,180 Other 47,224 33,947 ----------------------------------------------------------------------- Segmented assets 221,969 220,708 Non-segmented assets 6,601 6,766 Discontinued operations 312 764 ----------------------------------------------------------------------- Total assets $ 228,882 $ 228,238 ----------------------------------------------------------------------- ----------------------------------------------------------------------- Egypt ------------------------------------------------------------------------ Three Months Ended December 31 (000s) 2009 2008 ------------------------------------------------------------------------ ------------------------------------------------------------------------ Revenue Oil sales, net of royalties and other $ 19,821 $ 7,782 Other income - 3 ------------------------------------------------------------------------ Total revenue $ 19,821 $ 7,785 ------------------------------------------------------------------------ Segmented expenses Operating expenses 5,008 3,021 Depletion and depreciation 4,792 6,608 Income taxes 4,322 1,698 ------------------------------------------------------------------------ Total segmented expenses $ 14,122 $ 11,327 ------------------------------------------------------------------------ Segmented (loss) income $ 5,699 $ (3,542) ------------------------------------------------------------------------ Non-segmented expenses Derivative gain on commodity contracts (Note 14a) General and administrative Interest on long-term debt Depreciation Foreign exchange (gain) loss Other income ------------------------------------------------------------------------ Total non-segmented expenses ------------------------------------------------------------------------ Net (loss) income from continuing operations Net income from discontinued operations (Note 5) ------------------------------------------------------------------------ Net (loss) income ------------------------------------------------------------------------ ------------------------------------------------------------------------ Capital expenditures Exploration and development 6,858 11,640 Property acquisitions - - ------------------------------------------------------------------------ Corporate - - ------------------------------------------------------------------------ Total capital expenditures $ 6,858 $ 11,640 ------------------------------------------------------------------------ ------------------------------------------------------------------------ Yemen --------------------------------------------------------------------------- Three Months Ended December 31 (000s) 2009 2008 --------------------------------------------------------------------------- Revenue Oil sales, net of royalties and other $ 8,967 $ 9,983 Other income - 1 --------------------------------------------------------------------------- Total revenue $ 8,967 $ 9,984 --------------------------------------------------------------------------- Segmented expenses Operating expenses 2,379 2,836 Depletion and depreciation 2,105 2,599 Income taxes 2,565 1,975 --------------------------------------------------------------------------- Total segmented expenses $ 7,049 7,410 --------------------------------------------------------------------------- Segmented (loss) income $ 1,918 2,574 --------------------------------------------------------------------------- Non-segmented expenses Derivative gain on commodity contracts (Note 14a) General and administrative Interest on long-term debt Depreciation Foreign exchange (gain) loss Other income --------------------------------------------------------------------------- Total non-segmented expenses --------------------------------------------------------------------------- Net (loss) income from continuing operations Net income from discontinued operations (Note 5) --------------------------------------------------------------------------- Net (loss) income --------------------------------------------------------------------------- --------------------------------------------------------------------------- Capital expenditures Exploration and development 668 2,195 Property acquisitions - - --------------------------------------------------------------------------- Corporate - - --------------------------------------------------------------------------- Total capital expenditures $ 668 $ 2,195 --------------------------------------------------------------------------- --------------------------------------------------------------------------- Total ------------------------------------------------------------------------- Three Months Ended December 31 (000s) 2009 2008 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Revenue Oil sales, net of royalties and other $ 28,788 $ 17,765 Other income - 4 ------------------------------------------------------------------------- Total revenue $ 28,788 $ 17,769 ------------------------------------------------------------------------- Segmented expenses Operating expenses 7,387 5,857 Depletion and depreciation 6,897 9,207 Income taxes 6,887 3,673 ------------------------------------------------------------------------- Total segmented expenses 21,171 18,737 ------------------------------------------------------------------------- Segmented (loss) income 7,617 (968) ------------------------------------------------------------------------- Non-segmented expenses Derivative gain on commodity contracts (Note 14a) 684 (12,460) General and administrative 3,922 3,010 Interest on long-term debt 557 1,095 Depreciation 58 38 Foreign exchange (gain) loss (92) (112) Other income (28) (21) ------------------------------------------------------------------------- Total non-segmented expenses 5,101 (8,450) ------------------------------------------------------------------------- Net (loss) income from continuing operations 2,516 7,482 Net income from discontinued operations (Note 5) - 158 ------------------------------------------------------------------------- Net (loss) income 2,516 7,640 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capital expenditures Exploration and development 7,526 13,835 Property acquisitions - - ------------------------------------------------------------------------- Corporate 15 89 ------------------------------------------------------------------------- Total capital expenditures $ 7,541 $ 13,924 ------------------------------------------------------------------------- ------------------------------------------------------------------------- /T/ 19. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES OF AMERICA The Consolidated Financial Statements have been prepared in accordance with Canadian GAAP which differ in certain material respects from those principles that the Company would have followed had its Consolidated Financial Statements been prepared in accordance with U.S. GAAP as described below. Consolidated Statements of Income (Loss) and Retained Earnings (Deficit) Had the Company followed U.S. GAAP, the statement of income (loss) would have been reported as follows: /T/ Year Ended December 31 ----------------------------------------------------------------------- (000s, except per share amounts) 2009 2008 ----------------------------------------------------------------------- ----------------------------------------------------------------------- Net (loss) income from continuing operations for the year under Canadian GAAP $ (8,417) $ 23,173 Adjustments: Impairment of property and equipment and goodwill (Note 19a) - (98,391) Depletion and depreciation (Note 19a) 24,514 611 ----------------------------------------------------------------------- Net income (loss) from continuing operations for the year under U.S. GAAP 16,097 (74,607) Net income from discontinued operations for the year - Canadian and U.S. GAAP - 8,350 ----------------------------------------------------------------------- Net income (loss) for the year under U.S. GAAP 16,097 (66,257) Purchase of common shares - (880) (Deficit) retained earnings, beginning of year - U.S. GAAP (19,760) 47,377 ----------------------------------------------------------------------- Deficit, end of year - U.S. GAAP $ (3,663) $ (19,760) ----------------------------------------------------------------------- ----------------------------------------------------------------------- Net income (loss) from continuing operations per share under U.S. GAAP - Basic $ 0.25 $ (1.25) - Diluted 0.24 (1.25) Net income from discontinued operations per share under U.S. GAAP - Basic - 0.14 - Diluted - 0.14 Net income (loss) per share under U.S. GAAP - Basic 0.25 (1.11) - Diluted 0.24 (1.11) ----------------------------------------------------------------------- /T/ Statement of Other Comprehensive Income (Loss) Had the Company followed U.S. GAAP, the statement of other comprehensive income (loss) would have been reported as follows: /T/ Year Ended December 31 --------------------------------------------------------------------------- (000s) 2009 2008 --------------------------------------------------------------------------- Net income (loss) - U.S. GAAP $ 16,097 $ (66,257) Currency translation adjustment (Note 19d) - (886) --------------------------------------------------------------------------- Other comprehensive income (loss) $ 16,097 $ (67,143) --------------------------------------------------------------------------- --------------------------------------------------------------------------- /T/ Consolidated Balance Sheets Had the Company followed U.S. GAAP, the balance sheet would have been reported as follows: /T/ Year Ended December 31 -------------------------------------------------------------------------- (000s) 2009 2008 -------------------------------------------------------------------------- Cdn. GAAP U.S. GAAP Cdn. GAAP U.S. GAAP -------------------------------------------------------------------------- Current assets $ 53,405 $ 53,405 $ 40,257 $ 40,257 Property and equipment (Note 19a) 167,297 91,596 179,329 79,114 Derivative commodity contracts - - 472 472 Deferred financing costs (Note 19f) - 201 - 770 Goodwill (Note 19a) 8,180 - 8,180 - -------------------------------------------------------------------------- $ 228,882 $ 145,202 $ 228,238 $ 120,613 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Current liabilities $ 65,192 $ 65,393 $ 16,273 $ 16,273 Long-term debt (Note 19f) - - 57,230 58,000 -------------------------------------------------------------------------- 65,192 65,393 73,503 74,273 -------------------------------------------------------------------------- Share capital (Notes 19b, 19c and 19d) 66,106 67,809 50,532 52,235 Contributed surplus (Note 19b) 6,691 4,783 4,893 2,985 Accumulated other comprehensive income 10,880 10,880 10,880 10,880 Retained earnings (deficit) (Notes 19b and 19c) 80,013 (3,663) 88,430 (19,760) -------------------------------------------------------------------------- 163,690 79,809 154,735 46,340 -------------------------------------------------------------------------- $ 228,882 $ 145,202 $ 228,238 $ 120,613 -------------------------------------------------------------------------- -------------------------------------------------------------------------- /T/ The reconciling items between share capital and retained earnings for Canadian and U.S. GAAP are $0.8 million related to escrowed shares, and $1.3 million related to flow through shares. The reconciling items between contributed surplus and deficit for Canadian and U.S. GAAP are $0.3 million for the adoption of stock-based compensation under Canadian GAAP and $2.0 million for the 2005 and 2004 stock-based compensation expense under Canadian GAAP, which was not expensed in 2005. The reconciling item between share capital and contributed surplus is $0.4 million for the transfer of compensation expense related to options exercised in 2005 and prior. a) Full Cost Accounting The full cost method of accounting for crude oil and natural gas operations under Canadian and U.S. GAAP differ in the following respect. Under U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum of the present value, discounted at 10%, of the estimated unescalated future net operating revenue from proved reserves plus unimpaired unproved property costs less future development costs, related production costs and applicable taxes. Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that cash flows from proved reserves are undiscounted and utilize forecasted pricing and before tax to determine whether impairment exists. In Canada, the impaired amount is measured using the fair value of reserves. There are no impairment charges under Canadian GAAP or U.S. GAAP for the year ended December 31, 2009. In 2008, under U.S. GAAP, the unamortized capitalized cost of the Company's Egypt and Yemen oil and gas properties exceeded the full cost ceiling limitation by $79.9 million and $14.6 million, respectively, net of taxes, which were written off for U.S. GAAP purposes (2007 - $6.3 million written off for the Egypt properties). These impairment charges also decreased the depletion and depreciation expense for U.S. GAAP purposes by $24.5 million in 2009 and $0.6 million in 2008. Goodwill was tested for impairment by comparing the fair value of the reporting to the book value of the reporting unit, which resulted in an impairment charge to goodwill of $3.9 million in 2008 (2007 - $4.3 million impairment charge). Because of the volatility of oil and natural gas prices, no assurance can be given that the Company will not experience a writedown in future periods. b) Stock-based Compensation The Company has a stock-based compensation plan as more fully described in Note 9. Under Canadian GAAP, compensation costs have been recognized in the financial statements for stock options granted to employees and directors since January 1, 2002. For U.S. GAAP, effective January 1, 2006, the Company has adopted an accounting standard that required compensation costs related to share-based payment transactions to be recognized as an expense at fair value with re-measurement to fair value each period. The compensation expense as recognized over the period that an employee provides service in exchange for the award with forfeitures estimated and each period end. As permitted, the Company has applied this change using modified prospective application for new awards granted after January 1, 2006 and for the compensation cost of awards that were not vested at December 31, 2005. In 2005 and prior periods, the Company used the intrinsic value method of accounting for stock options granted to employees and directors whereby no costs were recognized in the financial statements per U.S. GAAP. The effect of applying the intrinsic value method in 2005 and prior years to the Company's U.S. GAAP financial statements resulted in a decrease to stock-based compensation in 2005 by $0.7 million (2004 - $1.3 million) and a corresponding decrease to the contributed surplus account. Also, the deficit would decrease by $0.3 million in 2004 with a corresponding decrease to the contributed surplus account relating to the 2004 adoption entry for Canadian GAAP that is not required for U.S. GAAP. Also, the share capital would decrease by $0.4 million for options exercised since the compensation expense was transferred into common shares for Canadian GAAP. This is not required for U.S. GAAP. c) Future Income Taxes The Company records the renouncement of tax deductions related to flow through shares by reducing share capital and recording a future tax liability in the amount of the estimated cost of the tax deductions flowed to the shareholders. U.S. GAAP requires that the share capital on flow through shares be stated at the quoted market value of the shares at the date of issuance. In addition, the temporary difference that arises as a result of the renouncement of the deductions, less any proceeds received in excess of the quoted market value of the shares is recognized in the determination of income tax expense for the period. The effect of applying this provision to the Company's consolidated financial statements would result in an increase in income tax expense and future tax liability by $Nil in 2009, $Nil in 2008, $Nil in 2007, $Nil in 2006, $Nil in 2005, $Nil in 2004, $0.9 million in 2003, $0.1 million in 2002 and $0.3 million in 2000 representing the tax effect of the flow through shares and a corresponding increase to share capital and decrease to future tax liability by $Nil in 2009, $Nil in 2008, $Nil in 2007, $Nil in 2006, $Nil in 2005, $Nil in 2004, $0.9 million in 2003, $0.1 million in 2002 and $0.3 million in 2000 to record the recognition of the benefit of tax losses available to the Company equal to the liability arising from renouncing tax pools to the subscribers. Under U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted tax rates. The effect of this change between Canadian and U.S. GAAP would result in an increase in future income tax expense and future tax liability of $Nil in 2009, $Nil in 2008, $Nil in 2007, $0.2 million in 2006, $0.2 million in 2005, $0.2 million in 2004 and $0.4 million in 2003 representing the higher enacted tax rates over the substantively enacted tax rates and a corresponding reduction in future income tax expense and future tax liability of $Nil in 2009, $Nil in 2008, $Nil in 2007, $0.2 million in 2006, $0.2 million in 2005, $0.2 million in 2004 and $0.4 million in 2003 to record an additional valuation allowance against the increased tax asset. d) Escrowed Shares For U.S. GAAP purposes, escrowed shares would be considered a separate compensatory arrangement between the Company and the holder of the shares. Accordingly, the fair market value of shares at the time the shares are released from escrow will be recognized as a charge to income in that year with a corresponding increase in share capital. The difference in share capital between Canadian GAAP and U.S. GAAP represents the effect of applying this provision in 1995 when 188,000 escrow shares were released resulting in an increase in share capital of $0.8 million with the offset to deficit. e) Accounting for Uncertainty in Income Taxes Effective January 1, 2007, the Company adopted an accounting interpretation providing guidance for accounting for uncertainty in income taxes, which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements. The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under this interpretation, a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management's assessment is that the position is "more likely than not" (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term "tax position" refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. The Interpretation also provides guidance on measurement methodology, derecognition thresholds, financial statement classification and disclosures, recognition of interest and penalties, and accounting for the cumulative-effect adjustment at the date of adoption. Upon adoption, it was determined that there was no effect to TransGlobe. Tax positions for TransGlobe and its subsidiaries are subject to income tax audits by tax jurisdictions throughout the world. For the Company's major tax jurisdictions, examinations of tax returns for certain prior tax periods had not been completed as of December 31, 2009. In this regard, examinations had not been finalized for years beginning after 2007 for the Company's Canadian federal income taxes. For other tax jurisdictions, the earliest years for which income tax examinations had not been finalized were as follows: Egypt - 2008 and Yemen - 2008. f) Deferred Financing Costs The Company has accounted for transaction costs differently for Canadian and U.S. GAAP. Under Canadian GAAP transaction costs are included with the associated financial instrument whereas under U.S. GAAP transaction costs are presented separately as an asset. g) Accounting Policies Adopted for U.S. GAAP Business Combinations Effective January 1, 2009, the Company prospectively adopted the revised guidance on accounting for business combinations. The guidance establishes principles and requirements for how and acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired. The objective of this authoritative guidance is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. Since the Company did not close any business combinations during 2009 the adoption of this standard did not impact the Consolidated Financial Statements. Noncontrolling Interests in Consolidated Financial Statements Effective January 1, 2009, the Company adopted the authoritative guidance as it relates to noncontrolling interests. The guidance changed the accounting for and and reporting for minority interest, which were recharacterized as noncontrolling interests. The objective of this guidance is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements. This standard did not impact the Company as it has full controlling interest of all of its subsidiaries. Derivative Instruments and Hedging Activities Effective January 1, 2009, the Company adopted the authoritative guidance as it relates to disclosures about derivative instruments and hedging activities. This guidance requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. This standard did not impact the Consolidated Financial Statements. Accounting Standards Codification ("ASC") System In June 2009, the FASB issued SFAS No. 168, the FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles which has been primarily coded into ASC Topic 105, Generally Accepted Accounting Standards. This standard which became effective for financial statements issued for interim and annual periods ending after September 15, 2009. The standard established the ASC as the single authoritative source of U.S. GAAP and superseded existing literature of the FASB, Emerging Issues Task Force, American Institute of CPAs and other sources. The ASC did not change GAAP but organized the literature into accounting topics. Adoption of the ASC did not affect the Company's accounting. Oil and Gas Reporting As of December 31, 2009, TransGlobe is required to prospectively adopt the new reserves requirements that arise from the completion of the SEC's project, Modernization of Oil and Gas Reporting. The new rules include provisions that permit the use of new technologies to establish proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Additionally, oil and gas reserves are reported using an average price based upon the prior 12-month period rather than year-end prices. The new rules affected the reserve estimate used in the calculation of DD&A and the ceiling test for U.S. GAAP purposes. h) New Accounting Pronouncements Variable Interest Entities In June 2009, authoritative guidance was released which required the enterprise to qualitatively assess if it is the primary beneficiary of the VIE and, if so, the VIE must be consolidated. This standard is effective for years beginning after November 15, 2009. The Company does not expect that this standard will have a material impact on the Consolidated Financial Statements. Transfers of Financial Assets In June 2009, authoritative guidance was released which changes how companies account for transfers of financial assets and eliminates the concept of qualifying special-purpose entities. This standard is effective for years beginning after November 15, 2009. The Company is currently assessing the impact of this requirement on the Consolidated Financial Statements.

TransGlobe Energy Corporation Scott Koyich Investor Relations 403.262.9888 investor.relations@trans-globe.com www.trans-globe.com

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