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
FINANCIAL AND OPERATING RESULTS
Three Months Ended December 31 Year Ended December 31
% %
Financial 2009 2008 Change 2009 2008 Change
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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 -
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(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
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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)
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Financial from Continuing Operations (excludes Canadian Operations)
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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)
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(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)
----------------------------------------------------------------------------
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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)
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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.
Quarterly West Gharib Production (Bopd)
2009
----------------------------------------------------------------------------
Q-4 Q-3 Q-2 Q-1
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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
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(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.
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.
Quarterly Block 32 Production (Bopd)
2009
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Q-4 Q-3 Q-2 Q-1
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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
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(1) Under the terms of the Block 32 PSA, royalties and taxes are paid out of
the government's share of production sharing oil.
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.
Quarterly Block S-1 Production (Bopd)
2009
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Q-4 Q-3 Q-2 Q-1
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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
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(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.
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.
Reconciliation of Funds Flow from Operations and Funds Flow from Continuing
Operations
Year Ended December 31
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($000s) 2009 2008
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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
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Funds flow from operations 45,064 59,267
Less: Funds flow from discontinued operations - 6,908
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Funds flow from continuing operations 45,064 52,359
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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.
SELECTED ANNUAL INFORMATION
($000s, except per share,
price and volume amounts) 2009 % Change 2008 % Change 2007
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Total Operations
Average production volumes
(Boepd) 8,980 22 7,342 30 5,651
Average sales volumes
(Boepd) 8,980 22 7,342 29 5,692
Average price ($/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.
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).
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)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Despite record production in 2009, net income decreased by $39.9
million from 2008, resulting in a $8.4 million loss. This is mainly
as a result of a 41% decrease in realized oil prices, an unrealized
derivative loss (versus a gain in 2008) and a 34% increase in
depreciation and depletion due to increased production.
BUSINESS ENVIRONMENT
The Company's financial results are significantly influenced by
fluctuations in commodity prices, including price differentials.
The following table shows select market benchmark prices and
foreign exchange rates:
Year Ended December 31
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dated Brent average oil price ($/Bbl) 61.51 96.99
U.S./Canadian Dollar average exchange rate 1.1415 1.0671
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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".
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.
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.
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
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.
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:
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
----------------------------------------------------------------------------
At December 31, 2009, all of the derivative commodity contracts
were classified as current liabilities.
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Plus Probable
Year Ended December 31
----------------------------------------------------------------------------
($000s, except volumes and $/Boe amounts) 2009 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total capital expenditure 35,546 43,292 37,015
Acquisitions - 58,946 68,716
Dispositions - (57,295) -
Net change from previous year's future capital 4,112 (8,602) (6,587)
----------------------------------------------------------------------------
39,658 36,341 99,144
----------------------------------------------------------------------------
Reserve additions and revisions (MBoe)
Exploration and development 7,670 5,200 1,537
Acquisitions, net of dispositions - 709 5,264
----------------------------------------------------------------------------
Total reserve additions (Mboe) 7,670 5,909 6,801
----------------------------------------------------------------------------
Average cost per Boe
F&D 5.17 6.67 19.79
FD&A 5.17 6.15 14.58
Three-year weighted average cost per Boe
F&D 7.27 12.35 19.88
FD&A 8.59 12.14 16.81
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in
estimated future development costs generally will not reflect total
finding and development costs related to reserves additions for that
year.
RECYCLE RATIO
Three Year
Proved Weighted Average 2009 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Netback ($/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.
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.
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.
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
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.
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.
($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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
As part of its normal business, the Company entered into
arrangements and incurred obligations that will impact the
Company's future operations and liquidity. The principal
commitments of the Company are as follows:
($000s) Payment Due by Period(1,2)
----------------------------------------------------------------------------
Recognized 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.
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.
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
-- 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.
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
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.
2010 Funds Flow From Operations Outlook
This outlook was developed using the above production forecast
and a Dated Brent oil price of $65.00/Bbl.
2010 Funds Flow From Operations Outlook
($ 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.
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 $7.0 million.
2010 Capital Budget
($ million) 2010
---------------------------
---------------------------
Egypt 48.7
Yemen 14.1
Corporate 0.2
---------------------------
Total 63.0
---------------------------
---------------------------
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:
-- Financial risks including market risks (such as commodity price, foreign
exchange and interest rates), credit risks and liquidity risks;
-- Operational risks including capital, operating and reserves replacement
risks;
-- Safety, environmental and regulatory risks; and
-- Political risks.
Many of these risks are not within the control of management,
but the Company has adopted several strategies to reduce and
minimize the effects of these risks:
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.
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.
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:
-- 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).
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:
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
-------------------------------------------------
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
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
--------------------------------------------------------------------------
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).
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
--------------------------------------------------------------------------
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).
Corporate Year Ended December 31
----------------------------------------------------------------------
(000s) 2009 2008
----------------------------------------------------------------------
Furniture, fixtures and other $ 2,333 $ 2,148
Accumulated depreciation (1,601) (1,400)
----------------------------------------------------------------------
$ 732 $ 748
----------------------------------------------------------------------
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:
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.
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.
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
------------------------------------------------------------------------
------------------------------------------------------------------------
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:
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
------------------------------------------------------------------
------------------------------------------------------------------
7. LONG-TERM DEBT
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
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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:
(000s)
------------------------------------------
2010 (due September 25, 2010) $ 50,000
------------------------------------------
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
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $0.9 million was charged to
retained earnings during the year.
9. STOCK OPTION PLAN
The Company adopted a stock option plan in May 2007 (the
"Plan"). The number of Common Shares that may be issued pursuant to
the exercise of Options awarded under the Plan and all other
Security Based Compensation Arrangements of the Company is 10% of
the common shares outstanding from time to time. All incentive
stock options granted under the Plan have a per-share exercise
price not less than the trading market value of the common shares
at the date of grant. Effective February 1, 2005; all new grants of
stock options vest one-third on each of the first, second and third
anniversaries of the grant date.
The following tables summarize information about the stock
options outstanding and exercisable at December 31:
2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Weighted- Weighted-
Number Average Number Average
(000s, except per of Exercise Price of Exercise Price
share amounts) Options (C$) 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
-----------------------------------------------------------------------
-----------------------------------------------------------------------
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 - $1.8
million). The fair value of all common stock options granted is
estimated on the date of grant using the lattice-based binomial
option pricing model. The weighted average fair value of options
granted during the year and the assumptions used in their
determination are as noted below:
Year Ended December 31
---------------------------------------------------------------------------
2009 2008
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Weighted average fair market value
per option (C$) 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%
---------------------------------------------------------------------------
---------------------------------------------------------------------------
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
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
----------------------------------------------------------------------
----------------------------------------------------------------------
11. INCOME TAXES
The Company's future Canadian income tax assets are as
follows:
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 $ - $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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:
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
----------------------------------------------------------------------
----------------------------------------------------------------------
12. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in operating non-cash working capital consisted of the
following:
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)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
13. ACCUMULATED OTHER COMPREHENSIVE INCOME
The balance of accumulated other comprehensive income consists
of the following:
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
-----------------------------------------------------------------------
-----------------------------------------------------------------------
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:
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
-------------------------------------------------------------------------
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:
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
--------------------------------------------------------------------------
--------------------------------------------------------------------------
The Company's debt-to-funds flow ratio is computed as
follows:
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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:
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
------------------------------------------------------------------
------------------------------------------------------------------
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.
(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
--------------------------------------------------------------
--------------------------------------------------------------
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:
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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:
(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.
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
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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:
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)
-----------------------------------------------------------------------
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:
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)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Consolidated Balance Sheets
Had the Company followed U.S. GAAP, the balance sheet would have
been reported as follows:
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
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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.
Contacts: TransGlobe Energy Corporation Scott Koyich Investor
Relations 403.262.9888 investor.relations@trans-globe.com
www.trans-globe.com
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