Annual Report to Shareholders
For the Year Ended December 31, 2009
FIVE YEAR SUMMARY OF SELECTED FINANCIAL DATA
The selected financial data set forth below are derived from the accompanying financial statements,
which form part of this Annual Report on Form 10-K. The financial statements have been prepared in
accordance with generally accepted accounting principles (GAAP) applicable in Canada. See Item 7
Managements Discussion and Analysis of Financial Condition and Results of Operations and Note 21
to our financial statements in this Annual Report on Form 10-K for a detailed description of the
differences between GAAP applicable in Canada and GAAP applicable in the U.S. as it relates to the
Company.
The following table shows selected financial information for the years indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(stated in thousands of US dollars, except per share amounts) |
|
Results of Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
23,658 |
|
|
|
50,670 |
|
|
|
26,689 |
|
|
|
36,320 |
|
|
|
15,965 |
|
Net loss from continuing operations |
|
|
(37,731 |
) |
|
|
(38,476 |
) |
|
|
(33,433 |
) |
|
|
(25,677 |
) |
|
|
(15,983 |
) |
Net loss from continuing operations
per share basic and diluted |
|
|
(0.13 |
) |
|
|
(0.15 |
) |
|
|
(0.14 |
) |
|
|
(0.11 |
) |
|
|
(0.08 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
281,763 |
|
|
|
346,875 |
|
|
|
266,516 |
|
|
|
278,144 |
|
|
|
270,477 |
|
Long-term debt |
|
|
36,934 |
|
|
|
37,855 |
|
|
|
9,812 |
|
|
|
2,737 |
|
|
|
4,000 |
|
Asset retirement obligations long term |
|
|
195 |
|
|
|
1,928 |
|
|
|
739 |
|
|
|
484 |
|
|
|
100 |
|
Long term obligation |
|
|
1,900 |
|
|
|
1,900 |
|
|
|
1,900 |
|
|
|
1,900 |
|
|
|
1,900 |
|
Shareholders equity |
|
|
208,029 |
|
|
|
257,427 |
|
|
|
197,287 |
|
|
|
228,386 |
|
|
|
204,767 |
|
Common shares outstanding (in thousands) |
|
|
282,559 |
|
|
|
279,381 |
|
|
|
244,874 |
|
|
|
241,216 |
|
|
|
220,779 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow provided by (used in) operating activities |
|
|
(12,290 |
) |
|
|
17,053 |
|
|
|
5,489 |
|
|
|
14,352 |
|
|
|
9,870 |
|
Capital investments (continuing operations) |
|
|
(26,373 |
) |
|
|
(21,063 |
) |
|
|
(28,585 |
) |
|
|
(12,296 |
) |
|
|
(36,741 |
) |
All information has been revised as originally presented to conform with the presentation of the
discontinued operations 2009 respecting the sale by the Company of all of its oil and gas
exploration and production operations in the United States. See Note 19 to our financial
statements under Item 8 in this Annual Report on Form 10-K.
RECONCILIATION TO U.S. GAAP
Our financial statements have been prepared in accordance with GAAP applicable in Canada, which
differ in certain respects from those principles that we would have followed had our financial
statements been prepared in accordance with GAAP in the U.S. The differences between Canadian and
U.S. GAAP, which affect our financial statements, are described in detail in Note 21 to our
financial statements in this Annual Report on Form 10-K.
1
Had we followed U.S. GAAP certain selected financial information reported above, in accordance with
Canadian GAAP, would have been reported as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(stated in thousands of US dollars, except per share amounts) |
|
Results of Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
17,152 |
|
|
|
55,335 |
|
|
|
27,281 |
|
|
|
35,628 |
|
|
|
18,831 |
|
Net loss from continuing operations |
|
|
(32,679 |
) |
|
|
(47,911 |
) |
|
|
(23,080 |
) |
|
|
(35,477 |
) |
|
|
(13,773 |
) |
Net loss from continuing operations
per share basic and diluted |
|
|
(0.12 |
) |
|
|
(0.19 |
) |
|
|
(0.10 |
) |
|
|
(0.15 |
) |
|
|
(0.07 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
262,717 |
|
|
|
292,847 |
|
|
|
251,627 |
|
|
|
252,893 |
|
|
|
254,335 |
|
Long-term debt |
|
|
38,005 |
|
|
|
40,392 |
|
|
|
10,412 |
|
|
|
2,737 |
|
|
|
4,000 |
|
Asset retirement obligations long term |
|
|
195 |
|
|
|
1,928 |
|
|
|
739 |
|
|
|
484 |
|
|
|
100 |
|
Long term obligation |
|
|
1,900 |
|
|
|
1,900 |
|
|
|
1,900 |
|
|
|
1,900 |
|
|
|
1,900 |
|
Shareholders equity |
|
|
179,663 |
|
|
|
199,741 |
|
|
|
170,545 |
|
|
|
189,829 |
|
|
|
188,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow provided by (used in) operating activities |
|
|
(12,441 |
) |
|
|
16,639 |
|
|
|
11,501 |
|
|
|
13,340 |
|
|
|
5,042 |
|
Capital investments (continuing operations) |
|
|
(26,223 |
) |
|
|
(20,649 |
) |
|
|
(28,319 |
) |
|
|
(11,280 |
) |
|
|
(31,913 |
) |
All information has been revised as originally presented to conform with the presentation of the
discontinued operations 2009 respecting the sale by the Company of all of its oil and gas
exploration and production operations in the United States. See Note 21 to our financial
statements under Item 8 in this Annual Report on Form 10-K.
2
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
TABLE OF CONTENTS
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7 |
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9 |
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10 |
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10 |
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21 |
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25 |
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27 |
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27 |
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THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR
ENDED DECEMBER 31, 2009. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE
WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP) IN CANADA. THE IMPACT OF SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND U.S. GAAP ON THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 21 TO
THE CONSOLIDATED FINANCIAL STATEMENTS.
OUR DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES,
RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON OUR WORKING INTEREST BASIS AFTER
ROYALTIES. ALL TABULAR AMOUNTS ARE EXPRESSED IN THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE AND
PRODUCTION DATA INCLUDING REVENUES AND COSTS PER BOE.
3
IVANHOE ENERGYS BUSINESS
Ivanhoe Energy is an independent international heavy oil development and production company focused
on pursuing long term growth in its reserve base and production. Ivanhoe Energy plans to utilize
technologically innovative methods designed to significantly improve recovery of heavy oil
resources, including the application of HTLTM Technology and EOR techniques. In
addition, the Company seeks to expand its reserve base and production through conventional
exploration and production of oil and gas. Our core operations are currently carried out in China,
Mongolia, Canada and Ecuador, with business development opportunities worldwide. In late 2009, the
Company, through a wholly owned subsidiary, acquired PanAsian Petroleum Inc., and acquired a
production-sharing contract covering the 16,839 square kilometer Block XVI exploration area in the
Nyalga basin Mongolia.
Ivanhoe Energys proprietary, patented heavy oil upgrading technology upgrades the quality of heavy
oil and bitumen by producing lighter, more valuable crude oil, along with by-product energy which
can be used to generate steam or electricity. The HTLTM Technology has the potential to
substantially improve the economics and transportation of heavy oil. There are significant
quantities of heavy oil throughout the world that have not been developed, much of it stranded due
to the lack of on-site energy, transportation issues, or poor heavy-light price differentials. In
remote parts of the world, the considerable reduction in viscosity of the heavy oil through the
HTLTM process will allow the oil to be transported economically by pipelines. In
addition to a dramatic improvement in oil quality, an HTLTM facility can yield large
amounts of surplus energy for production of the steam and electricity used in heavy oil production.
The thermal energy from the HTLTM process would provide heavy oil producers with an
alternative to increasingly volatile prices for natural gas that now is widely used to generate
steam. Yields of the low-viscosity, upgraded product can be greater than 85% by volume, and high
conversion of the heavy residual fraction is achieved. In addition to the liquid upgraded oil
product, a small amount of valuable by-product gas is produced, and usable excess heat is generated
from the by-product coke.
HTLTM can virtually eliminate cost exposure to natural gas and diluent, solve the
transport challenge, and capture a substantial portion of the heavy to light oil price differential
for oil producers. HTLTM accomplishes this at a much smaller scale and at lower per
barrel capital costs compared with established competing technologies, using readily available
plant and process components. As HTLTM facilities are designed for installation near the
wellhead, they eliminate the need for diluent and make large, dedicated upgrading facilities
unnecessary.
EXECUTIVE OVERVIEW OF 2009 RESULTS
In July 2009 the Company disposed of its U.S. operations and used the proceeds for its ongoing
projects. To properly reflect this sale in the Companys 2009 financial statements the results of
the U.S. operations have been segregated from ongoing operations and separately disclosed as
Discontinued Operations.
In 2009 the Companys oil revenues from continuing operations decreased from $48.4 million in 2008
to $25.0 million in 2009 due primarily to the decline in oil prices between the two years. These
results relate specifically to China producing properties which also experienced a decrease in
operating costs from $21.5 million to $10.2 million between 2008 and 2009. This decrease in costs
relates to a reduction in the Windfall Levy (a windfall profits tax as defined below), and is also
driven by the decline in oil prices between 2008 and 2009. General and Administrative costs
increased significantly due to several factors including the Company adding key personnel to
advance its first HTLTM projects and bolster our executive leadership, the redeployment
of many of the U.S. staff from their previous duties at our U.S. operations to focus on advancing
our heavy oil business development strategy and one-time legal and related fees (see Item 3 to Part
I of this Form 10K).
The 2009 results for discontinued operations was a loss of $23.9 million, including the write-off
of a $29.6 million future income tax asset that could no longer be utilized.
In the first half of 2009, in response to the deteriorating global economy and restricted capital
markets, the Company focused on husbanding capital while continuing to selectively advance its
heavy oil projects in Canada and Ecuador and develop its HTLTM technology. As a result
both Tamarack and Pungarayacu development activities continued to advance, albeit at a more
deliberate pace, and the Technology Group created a major technical breakthrough in the
HTLTM process, reducing the amount of oil recycled through a plant by up to 80 percent.
In the second half of the year, as economic conditions moderated somewhat, the Company completed
two key transactions: 1) the acquisition of what we believe to be a high quality exploration block
in Mongolias Nyalga basin, and 2) a divestiture of our U.S. operations. These transactions
continued to build the Company in line with our stated strategies as we redeployed capital from our
U.S. conventional operations into our heavy oil projects and built our conventional asset base in
our Asian operations.
Oil and Gas
Integrated
Projects in this segment will have two primary components. The first consists of conventional
exploration and production activities together with enhanced oil recovery techniques such as steam
assisted gravity drainage. The second component consists of the deployment of the HTLTM
Technology which will be used to upgrade heavy oil at facilities located in the field to produce
lighter, more valuable crude. The Companys two flagship projects currently report in this segment
- a heavy oil project in Alberta (Tamarack) and a heavy oil property in Ecuador (Pungarayacu).
4
Conventional
The Company explores for, develops and produces conventional crude oil and natural gas in China and
Mongolia, having divested its U.S. operations. In China, the Companys development and production
activities are conducted at the Dagang oil field located in Hebei Province and its exploration
activities are conducted on the Zitong block located in Sichuan Province. In Mongolia the Company
is conducting early phase exploration activities in the Nyalga basin, southeast of the capital
Ulaanbaatar. The Companys California and Texas exploration, development and production activities
were sold to Seneca South Midway LLC.
Business and Technology Development
The Companys technology development activities made major strides in 2009. The Feed Stock Test
Facility in San Antonio, Texas was commissioned in the first quarter and immediately took up its
dual roles of supporting business development and continuing to advance the technology. This
facility was a key part of the major technical advancement that eliminated the need to recycle oil
through
HTLTM facilities, greatly reducing capital costs per barrel of throughput. In addition,
the facility also began processing test runs for various heavy oils to support business plans and
development opportunities.
Business development successes include the disposition of the Companys U.S. operations,
facilitating capital redeployment from the strategically non-core, conventional U.S. arena into our
core heavy-oil and conventional Asian operations. The PanAsian merger was also a large advance for
our conventional oil and gas strategy, accessing significant exploration opportunities in the Asian
arena. Additional opportunities in the Middle East, North and South America are currently being
pursued.
Corporate
The Companys corporate segment consists of costs associated with the board of directors, executive
officers, corporate debt, financings and other corporate activities.
Summary table of financial data
The following table sets forth certain selected consolidated data for the past three years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Oil revenues |
|
$ |
24,968 |
|
|
$ |
48,370 |
|
|
$ |
31,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations |
|
$ |
(37,731 |
) |
|
$ |
(38,476 |
) |
|
$ |
(33,433 |
) |
Net loss from continuing operations
per share basic and diluted |
|
$ |
(0.13 |
) |
|
$ |
(0.15 |
) |
|
$ |
(0.14 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss and comprehensive loss |
|
$ |
(61,652 |
) |
|
$ |
(34,193 |
) |
|
$ |
(39,207 |
) |
Net loss per share basic and diluted |
|
$ |
(0.22 |
) |
|
$ |
(0.13 |
) |
|
$ |
(0.16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average production (Boe/d) |
|
|
1,276 |
|
|
|
1,339 |
|
|
|
1,325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revenue (loss) from operations per Boe |
|
$ |
(6.98 |
) |
|
$ |
7.59 |
|
|
$ |
(1.75 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow provided by (used in) operating
activities from continuing operations |
|
$ |
(14,993 |
) |
|
$ |
10,780 |
|
|
$ |
1,168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow provided by (used in) operating activities |
|
$ |
(12,290 |
) |
|
$ |
17,053 |
|
|
$ |
5,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital investments (continuing operations) |
|
$ |
(26,373 |
) |
|
$ |
(21,063 |
) |
|
$ |
(28,585 |
) |
5
FINANCIAL RESULTS YEAR TO YEAR CHANGE IN NET LOSS
The following provides a summary analysis of our net loss for each of the three years ended
December 31, 2009 and a summary of year-over-year variances for the year ended December 31, 2009
compared to 2008 and for the year ended December 31, 2008 compared to 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Favorable |
|
|
|
|
|
|
Favorable |
|
|
|
|
|
|
|
|
|
|
(Unfavorable) |
|
|
|
|
|
|
(Unfavorable) |
|
|
|
|
|
|
2009 |
|
|
Variances |
|
|
2008 |
|
|
Variances |
|
|
2007 |
|
Summary of Net Loss by Significant
Components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Revenues: |
|
$ |
24,968 |
|
|
|
|
|
|
$ |
48,370 |
|
|
|
|
|
|
$ |
31,365 |
|
Production volumes |
|
|
|
|
|
$ |
(2,384 |
) |
|
|
|
|
|
$ |
398 |
|
|
|
|
|
Oil prices |
|
|
|
|
|
|
(21,018 |
) |
|
|
|
|
|
|
16,607 |
|
|
|
|
|
Realized gain (loss) on derivative instruments |
|
|
124 |
|
|
|
4,554 |
|
|
|
(4,430 |
) |
|
|
(4,096 |
) |
|
|
(334 |
) |
Operating costs |
|
|
(10,191 |
) |
|
|
11,324 |
|
|
|
(21,515 |
) |
|
|
(8,515 |
) |
|
|
(13,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative, less
stock based compensation |
|
|
(18,002 |
) |
|
|
(6,198 |
) |
|
|
(11,804 |
) |
|
|
(4,127 |
) |
|
|
(7,677 |
) |
Business and technology development,
less stock based compensation |
|
|
(9,343 |
) |
|
|
(3,458 |
) |
|
|
(5,885 |
) |
|
|
2,715 |
|
|
|
(8,600 |
) |
Net interest |
|
|
(301 |
) |
|
|
283 |
|
|
|
(584 |
) |
|
|
(548 |
) |
|
|
(36 |
) |
Current income tax provision |
|
|
(1,757 |
) |
|
|
(1,103 |
) |
|
|
(654 |
) |
|
|
(654 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on derivative instruments |
|
|
(1,459 |
) |
|
|
(7,577 |
) |
|
|
6,118 |
|
|
|
10,777 |
|
|
|
(4,659 |
) |
Foreign Exchange Loss |
|
|
(5,220 |
) |
|
|
(3,693 |
) |
|
|
(1,527 |
) |
|
|
(1,226 |
) |
|
|
(301 |
) |
Depletion and depreciation |
|
|
(19,868 |
) |
|
|
5,893 |
|
|
|
(25,761 |
) |
|
|
(5,121 |
) |
|
|
(20,640 |
) |
Stock based compensation |
|
|
(3,849 |
) |
|
|
(833 |
) |
|
|
(3,016 |
) |
|
|
135 |
|
|
|
(3,151 |
) |
Provision for impairment of intangible asset and
development costs |
|
|
(1,903 |
) |
|
|
13,151 |
|
|
|
(15,054 |
) |
|
|
(15,054 |
) |
|
|
|
|
Impairment of oil and gas properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,130 |
|
|
|
(6,130 |
) |
Write off of deferred financing costs |
|
|
|
|
|
|
2,621 |
|
|
|
(2,621 |
) |
|
|
(2,621 |
) |
|
|
|
|
Future income tax recovery |
|
|
9,600 |
|
|
|
9,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations (net of tax) |
|
|
(23,921 |
) |
|
|
(28,204 |
) |
|
|
4,283 |
|
|
|
10,057 |
|
|
|
(5,774 |
) |
Other |
|
|
(530 |
) |
|
|
(417 |
) |
|
|
(113 |
) |
|
|
157 |
|
|
|
(270 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss |
|
$ |
(61,652 |
) |
|
$ |
(27,459 |
) |
|
$ |
(34,193 |
) |
|
$ |
5,014 |
|
|
$ |
(39,207 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our net loss for 2009 was $61.7 million ($0.22 per share) compared to our net loss in 2008 of $34.2
million ($0.13 per share). The decrease in our net loss from 2008 to 2009 of $27.5 million was due
to a decrease of $18.8 million in combined oil and gas revenues and realized gain on derivative
instruments, a $9.7 million increase in general and administrative and business and technology
development expenses excluding stock based compensation and a $28.2 million increase in loss from
discontinued operations. These were offset by decreases in operating costs of $11.3 million, a
$13.2 million expense decrease arising from the impairment of assets and a $9.6 million increase in
future income tax recovery.
Our net loss for 2008 was $34.2 million ($0.13 per share) compared to our net loss in 2007 of $39.2
million ($0.16 per share). The decrease in our net loss from 2007 to 2008 of $5.0 million was due
to an increase of $12.9 million in combined oil and gas revenues and realized loss on derivative
instruments, a $10.8 million increase in unrealized gain on derivative instruments and a $10.1
million increase in gain from discontinued operations. These were offset by an increase in
operating costs of $8.5 million, a $1.4 million increase in general and administrative and business
and technology development expenses excluding stock based compensation and a $8.9 million expense
increase arising from the impairment of assets.
6
Significant variances in our net losses are explained in the sections that follow.
Revenues and Operating Costs
Asia
|
|
|
Oil Prices 2009 vs. 2008 |
Oil and gas prices decreased 46% per Boe in 2009 contributing to a $21.0 million decrease in
revenue as compared to 2008. We realized an average of $53.60 per Boe during 2009, which was a
decrease of $45.13 per Boe from 2008 prices. We expect crude oil prices and natural gas prices to
remain volatile in 2010.
|
|
|
Oil Prices 2008 vs. 2007 |
Oil and gas prices increased 52% per Boe in 2008 contributing to a $16.6 million increase in
revenue as compared to 2007. We realized an average of $98.73 per Boe during 2008, which was an
increase of $33.87 per Boe from 2007 prices.
|
|
|
Realized Gain (Loss) on Derivatives |
The increased revenues from higher oil and gas price in 2008 were offset by the realized loss on
derivatives resulting from settlements from our costless collar derivative instruments. As
benchmark prices rise above the ceiling price established in the contract the Company is required
to settle monthly (see further details on these contracts below under Unrealized Gain (Loss) on
Derivative Instruments). Changes in these realized settlement gains (losses) by segment are
detailed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
Favorable |
|
|
Year Ended |
|
|
Favorable |
|
|
Year Ended |
|
December 31, |
|
|
(Unfavorable) |
|
|
December 31, |
|
|
(Unfavorable) |
|
|
December 31, |
|
2009 |
|
|
Variances |
|
|
2008 |
|
|
Variances |
|
|
2007 |
|
$ |
124 |
|
|
$ |
4,554 |
|
|
$ |
(4,430 |
) |
|
$ |
(4,096 |
) |
|
$ |
(334 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a comparison of changes in production volumes for the year ended December 31, 2009
when compared to the same period in 2008 and for the year ended December 31, 2008 when compared to
the same period for 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
Years Ended December 31, |
|
|
|
Net Boes |
|
|
Percentage |
|
|
Net Boes |
|
|
Percentage |
|
|
|
2009 |
|
|
2008 |
|
|
Change |
|
|
2008 |
|
|
2007 |
|
|
Change |
|
China: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dagang |
|
|
452,573 |
|
|
|
471,817 |
|
|
|
-4 |
% |
|
|
471,817 |
|
|
|
464,206 |
|
|
|
2 |
% |
Daqing |
|
|
13,231 |
|
|
|
18,096 |
|
|
|
-27 |
% |
|
|
18,096 |
|
|
|
19,379 |
|
|
|
-7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
465,804 |
|
|
|
489,913 |
|
|
|
-5 |
% |
|
|
489,913 |
|
|
|
483,585 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes 2009 vs. 2008 |
Net production volumes during 2009 decreased by 5%, or 24 Mboe, when compared to 2008, resulting in
decreased revenues of $2.4 million. The reduction was attributed to the normal field decline
partially offset by the productivity increases from adding new perforations, fracture stimulations
and water flood response. In addition, the Dagang project reached cost recovery effective September
1, 2009, at which time the Companys working interest changed from 82% to 49%. It is anticipated
that the gross production rates for 2010 will be similar to those averaged in 2009. In Dagang, at
the end of 2009, there were 38 wells producing at a rate of 1,660 Bopd, compared to 43 producing
wells at the end of 2008 at 1,700 Bopd.
|
|
|
Production Volumes 2008 vs. 2007 |
Net production volumes during 2008 increased by 1%, or 6 Mboe, when compared to 2007, resulting in
increased revenues of $0.4 million. The normal field decline was offset by the production from five
new development wells that were completed and put on production in the second half of 2007, as well
as productivity increases from adding new perforations, fracture stimulations and water flood
response.
7
|
|
|
Operating Costs 2009 vs. 2008 |
Operating costs in China, including engineering support costs and Windfall Levy, decreased 50% or
$22.05 per Boe for 2009 when compared to 2008. The majority of the decrease relates to an 81% per
Boe drop in the Windfall Levy as oil prices decreased substantially from 2008. Field operating
costs decreased $4.58 per Boe. Effective January 1, 2009 the Dagang field reached Commercial
Production status as defined by the Production Sharing Contract with China National Petroleum
Company. The effect of this change is that the Company no longer pays 100% of operating costs but
now pays only its proportionate interest. In addition, cost recovery was reached in Dagang
effective September 1, 2009. During 2009 the effect of these two changes resulted in the Company
paying 82% of operating costs for the first eight months, representing its share based on the
commercial production declaration and 49% for the final four months, representing the post cost
recovery share. Had the Company paid these lower proportionate shares in 2008, field operating
costs would have decreased $0.68 per Boe or 4%, from 2008 levels. Road and lease maintenance costs,
which are weather related, and decreased well workover costs were the main contributing factors to
the decrease. These were offset by increases in oil treatment costs as total fluid volumes
increased in 2009.
In March 2006, the Ministry of Finance of the Peoples Republic of China (PRC) issued the
Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation Business (the
Windfall Levy Measures). According to the Windfall Levy Measures, effective as of March 26, 2006,
enterprises exploiting and selling crude oil in the PRC are subject to a windfall gain levy (the
Windfall Levy) if the monthly weighted average price of crude oil is above $40 per barrel. The
Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the weighted
average sales price exceeding $40 per barrel. The cost associated with Windfall Levy has been
included in operating costs in our financial statements. With oil prices decreasing in 2009, the
Windfall Levy decreased $17.14 per Boe when compared to 2008.
During 2010 the Company has been placed on a production quota at our Dagang project. We therefore
expect operating costs in 2010 to increase on a per barrel basis as compared to 2009. The general
overall increase is anticipated to be slightly offset with improved maintenance methods currently
being implemented in the field.
|
|
|
Operating Costs 2008 vs. 2007 |
Operating costs in China, including engineering and support costs and Windfall Levy, increased 63%
or $17.03 per Boe for 2008 when compared to 2007. Field operating costs increased $3.62 per Boe
mainly as a result of a higher percentage of field office costs allocated to operations versus
capital as capital activity has decreased. In addition there were more service rig days worked and
higher power costs resulting from greater water injection in 2008 when compared to 2007. These
increases were offset by decreases resulting from road access costs, insurance coverage and lower
project management salaries. As oil prices have increased, the amount of the Windfall Levy also
increased significantly, resulting in $13.46 per Boe increase in 2008 when compared to 2007.
* * *
Production and operating information including oil and gas revenue, operating costs and depletion,
on a per Boe basis, are detailed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production: |
|
|
|
|
|
|
|
|
|
|
|
|
Boe |
|
|
465,804 |
|
|
|
489,913 |
|
|
|
483,585 |
|
Boe/day for the period |
|
|
1,276 |
|
|
|
1,339 |
|
|
|
1,325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Boe
|
|
|
|
Oil and gas revenue |
|
$ |
53.60 |
|
|
$ |
98.73 |
|
|
$ |
64.86 |
|
|
|
|
|
|
|
|
|
|
|
Field operating costs |
|
|
17.02 |
|
|
|
21.70 |
|
|
|
18.08 |
|
Windfall Levy |
|
|
4.00 |
|
|
|
21.14 |
|
|
|
7.68 |
|
Engineering and support costs |
|
|
0.86 |
|
|
|
1.08 |
|
|
|
1.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21.88 |
|
|
|
43.92 |
|
|
|
26.88 |
|
|
|
|
|
|
|
|
|
|
|
Net operating revenue |
|
|
31.72 |
|
|
|
54.81 |
|
|
|
37.98 |
|
Depletion |
|
|
38.70 |
|
|
|
47.22 |
|
|
|
39.73 |
|
|
|
|
|
|
|
|
|
|
|
Net revenue (loss) from operations |
|
$ |
(6.98 |
) |
|
$ |
7.59 |
|
|
$ |
(1.75 |
) |
|
|
|
|
|
|
|
|
|
|
8
General and Administrative
Changes in general and administrative expenses, before and after considering increases in non-cash
stock based compensation, by segment for the year ended December 31, 2009 when compared to the same
period for 2008 and for the year ended December 31, 2008 when compared to the same period for 2007
were as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 vs. |
|
|
2008 vs. |
|
|
|
2008 |
|
|
2007 |
|
Favorable (unfavorable) variances: |
|
|
|
|
|
|
|
|
Oil Activities: |
|
|
|
|
|
|
|
|
Canada |
|
$ |
498 |
|
|
$ |
(1,627 |
) |
Ecuador |
|
|
(1,611 |
) |
|
|
(658 |
) |
Asia |
|
|
(810 |
) |
|
|
(141 |
) |
Corporate |
|
|
(5,518 |
) |
|
|
(2,023 |
) |
|
|
|
|
|
|
|
|
|
|
(7,441 |
) |
|
|
(4,449 |
) |
Less: stock based compensation |
|
|
1,243 |
|
|
|
322 |
|
|
|
|
|
|
|
|
|
|
$ |
(6,198 |
) |
|
$ |
(4,127 |
) |
|
|
|
|
|
|
|
|
|
|
General and Administrative 2009 vs. 2008 |
Canada
The Company acquired working interests in two leases located in Alberta, Canada in July 2008.
Certain general and administrative costs, including salaries and benefits, related to Canada are
now being capitalized.
Ecuador
In the fourth quarter of 2008, the Company signed a contract to explore and develop Block 20.
General and administrative costs incurred prior to signing this contract were minimal, costs
incurred subsequent to signing this contract include setting up an office in Ecuador including
local staff as well as redeploying personnel and office costs who previously worked on the business
segment in our discontinued operations.
Asia
General and administrative expenses related to the China operations increased $0.8 million for 2009
as compared to 2008. The increase mainly results from a lower amount of general and administrative
expenses allocated to capital projects in 2009.
Corporate
General and administrative costs related to Corporate activities increased: $4.5 million for legal
and related fees (see Item 3 to Part I of this Form 10K), corporate aircraft costs, and a
reallocation of personnel to Corporate previously allocated to our U.S. business segment. These
increases were offset by decreases related to salary and benefit related items such as a one-time
severance charge in 2008, reallocation of certain executive salaries to business development
activities at the beginning of the third quarter 2008, a reduction in salary for an executive that
resigned in the second quarter of 2008.
|
|
|
General and Administrative 2008 vs. 2007 |
Canada
As noted elsewhere in this Annual Report, the Company acquired working interests in two leases
located in Alberta, Canada in July 2008. General and administrative costs related to Canada in 2008
consist of hiring key staff, reallocation of existing resources and some initial office setup
costs. In prior periods, some of these costs were recorded in the Business and Technology
Development segment.
Ecuador
As noted elsewhere in this Annual Report, in the fourth quarter of 2008 the Company signed a
contract to explore and develop Block 20. General and administrative costs related to Ecuador in
2008 consist of travel costs, contract services, hiring key staff, reallocation of existing
resources and some initial office setup costs.
9
Asia
General and administrative expenses related to the China operations increased $0.1 million for 2008
as compared to 2007 mainly resulting from increases in consulting and audit fees, rent and facility
costs.
Corporate
General and administrative costs related to Corporate activities increased $2.0 million for 2008
when compared to 2007. The overall increase was mainly due to the following increases; $0.6 million
provision for uncollectible accounts, corporate aircraft costs of $1.0 million, and increases in
third party recruiting fees of $0.5 million.
Business and Technology Development
Changes in business and technology development costs, before and after considering increases in
non-cash stock based compensation, for the year ended December 31, 2009 when compared to 2008 and
for the year ended December 31, 2008 when compared to 2007 were as follows:
|
|
|
Business and Technology Development 2009 vs. 2008 |
Business and technology development expenses increased $3.0 million (including changes in stock
based compensation) in 2009 when compared to 2008, mainly as a result of a reallocation of certain
executive salaries to business development activities at the beginning of the third quarter 2008,
the start up of the FTF, the establishment of an office in Houston in 2008 and several project
financing initiatives in the first quarter of 2009.
|
|
|
Business and Technology Development 2007 vs. 2006 |
Business and technology development expenses decreased $3.2 million (including changes in stock
based compensation) in 2008 when compared to 2007, mainly as a result of a decrease in CDF
operating costs due to several heavy oil upgrading runs in the first and second quarters of 2007.
These decreases were offset by increases in compensation costs as the Company assembled a core
HTLTM technology team.
Foreign Exchange Loss
The increase in foreign exchange loss period over period is mainly a result of the unrealized loss
on Canadian dollar denominated long-term debt.
Net Interest
|
|
|
Net Interest 2009 vs. 2008 |
Interest expense decreased $0.5 million for 2009 when compared to 2008 mainly due to a decrease in
our long term debt resulting from a $3.0 million repayment on our loan for our China operations in
the fourth quarter of 2008 and pay off of a short term Corporate note payable in the third quarter
of 2008.
|
|
|
Net Interest 2008 vs. 2007 |
Interest expense increased $0.7 million for 2008 when compared to 2007 partially due to borrowings
under a new loan for our China operations in the fourth quarter of 2007 and a short term loan that
was outstanding from May 2008 to August 2008. Interest income also increased slightly in 2008 when
compared to 2007 due to cash deposits from the July 2008 private placement.
Unrealized Gain (Loss) on Derivative Instruments
As required by the Companys lenders, the Company entered into a costless collar derivative to
minimize variability in its cash flow from the sale of approximately 50% of the Companys estimated
production from its Dagang field in China over a three-year period starting September 2007. This
derivative had a ceiling price of $84.50 per barrel and a floor price of $55.00 per barrel using
the WTI as the index traded on the NYMEX. In December the Company paid off the lenders outstanding
loan balance and this derivative was subsequently cancelled.
10
The Company is required to account for these contracts using mark-to-market accounting. As
forecasted benchmark prices exceed the ceiling prices set in the contract, the contracts have
negative value or a liability. These benchmark prices reached record highs at the beginning of the
third quarter of 2008 before steadily declining at the end of the fourth quarter to a level that
was the lowest dating back several years. The low benchmark prices continued into the first half of
2009 and recovered in the last half of the year. Changes
in these unrealized settlement (losses) and gains by segment are detailed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
Favorable |
|
|
Year Ended |
|
|
Favorable |
|
|
Year Ended |
|
December 31, |
|
|
(Unfavorable) |
|
|
December 31, |
|
|
(Unfavorable) |
|
|
December 31, |
|
2009 |
|
|
Variances |
|
|
2008 |
|
|
Variances |
|
|
2007 |
|
$ |
(1,459 |
) |
|
$ |
(7,577 |
) |
|
$ |
6,118 |
|
|
$ |
10,777 |
|
|
$ |
(4,659 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and Depreciation
The primary expense in this classification is depletion of the carrying values of our oil and gas
properties in our China cost centers over the life of their proved oil and gas reserves as
determined by independent reserve evaluators. For more information on how we calculate depletion
and determine our proved reserves see Critical Accounting Principles and Estimates Oil and Gas
Reserves and Depletion in this Item 7.
|
|
|
Depletion and Depreciation 2009 vs. 2008 |
Asia
Chinas depletion rate decreased $8.52 per Boe for 2009 when compared to 2008, resulting in a $5.1
million decrease in depletion expense for 2009. The decrease in the rates from year to year was
mainly due to an increase in total estimated proved reserves at our Dagang project due to reduced
decline rates and improved recovery rates. A decrease of $1.1 million in depletion expense from
year to year was related to decreased production.
Business and Technology Development
Depreciation in this segment decreased by $1.0 million in 2009 when compared to 2008 due to the
Company the CDF only being depreciated for the first two quarters in 2009, offset by the
commencement of depreciation on the FTF carrying balance.
|
|
|
Depletion and Depreciation 2008 vs. 2007 |
Asia
Chinas depletion rate increased $7.50 per Boe for 2008 when compared to 2007, resulting in a $3.7
million increase in depletion expense for 2008. The increase in the rates from year to year was
mainly due to an impairment of the drilling and completion costs associated with the second Zitong
exploration well in the fourth quarter of 2007. The remaining increase of $0.2 million was related
to increased production.
Business and Technology Development
Depreciation of the CDF is calculated using the straight-line method over its current useful life
which is based on the existing term of the agreement with Aera Energy LLC to use their property to
test the CDF. A formal study was conducted in 2008 whereby the estimated salvage value of the
property was decreased and the asset retirement obligation was increased resulting in an increased
depreciable base.
Provision for Impairment of Intangible Asset and Development Costs
During the third quarter of 2009, the Company determined that the completion and subsequent
improvements to its technology showpiece the FTF in San Antonio diminished the business purpose of
the CDF to nil. Consequently, the abandonment process commenced and the Company has impaired the
net carrying value of the costs associated with the CDF as at September 30, 2009. The carrying
value, net of depreciation, for the CDF, of $0.9 million, was reduced to nil with a corresponding
reduction in our results of operations. In addition, the Company had $1.0 million in deferred costs
on its balance sheet related to the pursuit of projects in the Middle East. In the fourth quarter
of 2009, the entire carrying value of these costs were reduced to nil with a corresponding
reduction in our results of operations.
The Company has been pursuing a GTL project for an extended period of time and had not been able to
obtain a definitive agreement or appropriate financing. As a result the Company impaired the entire
carrying value of the costs associated with GTL as at December 31, 2008. The carrying value for GTL
development costs of $5.1 million and intangible GTL license costs of $10.0 million have been
reduced to nil with a corresponding reduction in our results of operations. This impairment does
not affect the Companys intention to continue to pursue the current GTL project in Egypt.
11
In 2007, we had no write downs of our intangible assets or development costs.
Write-off of Deferred Financing Costs
The Company incurred professional fees and expenses associated with the pursuit of corporate
financing initiatives by the Companys Chinese subsidiary, Sunwing Energy. In the fourth quarter of
2008 this financing initiative was postponed indefinitely and therefore the associated costs were
written down to nil with a corresponding reduction in our results of operations.
Provision for Impairment of Oil and Gas Properties
As discussed below in this Item 7 in Critical Accounting Principles and Estimates Impairment of
Proved Oil and Gas Properties, we evaluate each of our cost centers proved oil and gas properties
for impairment on a quarterly basis. If as a result of this evaluation, a cost centers carrying
value exceeds its expected future net cash flows from its proved and probable reserves then a
provision for impairment must be recognized in the results of operations.
|
|
|
Impairment of Oil and Gas Properties 2008 vs. 2007 |
We did not impair our oil and gas properties in 2009 or 2008, compared to $6.1 million impairment
of our China oil and gas properties in 2007.
Provision for/Recovery of Income Taxes
Asia
There was a $1.4 million current tax provision for the year ended December 31, 2009 comprised of
$0.4 million for the tax year 2009 and a net adjustment of $1.0 million for 2008, as compared to a
$0.6 million provision for the same period in 2008. In April 2009, the Chinese State Tax
Administration Bureau issued changes to the minimum depreciation and amortization periods for oil
and gas companies. The minimum period changed form 6 to 8 years and was effective January 1, 2008.
Consequently, when submitting the final 2008 tax return in the second quarter 2009 an additional
$1.0 million tax payable was calculated.
Business and Technology Development
Prior to the Company selling its U.S. operating segment in July 2009, as further described in Note
14 to the accompany financial statements, the Company had future tax assets arising from net
operating losses carry-forwards generated by this business segment. These future income tax assets
were partially offset by certain future income tax liabilities in the U.S. and by a valuation
allowance. As at June 30, 2009, as a result of the pending sale of the business segment, the
Company was no longer able to offset these tax assets and liabilities but was required to present
these future income tax assets as assets from discontinued operations and a future income tax
liability both in the amount of $29.6 million in the June 30, 2009 balance sheet. The future income
tax assets classified as Assets from discontinued operations were ultimately included in the
$23.4 million loss on disposition as described in Note 19. Revisions were made to the future income
tax liability during the third quarter of 2009 based on revised projections of taxable income and
utilization of net operating loss carryforwards. As at December 31, 2009, the Companys future
income tax liability is $20.0 million in the accompanying balance sheet.
Net Income (Loss) from Discontinued Operations
The following applies to the U.S operations only. The sale of the U.S. operations closed July 17,
2009. The U.S. operations have been accounted for as discontinued operations in accordance with
Canadian GAAP on a retroactive basis and the results as at December 31, 2008 and for the three
years ended December 31, 2008 have been amended accordingly.
12
The operating results for this discontinued operation for the periods noted were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue |
|
$ |
5,455 |
|
|
$ |
18,120 |
|
|
$ |
12,270 |
|
Gain (loss) on derivative instruments |
|
|
189 |
|
|
|
278 |
|
|
|
(5,594 |
) |
Interest income |
|
|
8 |
|
|
|
98 |
|
|
|
152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,652 |
|
|
|
18,496 |
|
|
|
6,828 |
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
2,132 |
|
|
|
5,137 |
|
|
|
4,319 |
|
General and administrative |
|
|
139 |
|
|
|
2,413 |
|
|
|
1,972 |
|
Depletion and depreciation |
|
|
3,772 |
|
|
|
6,143 |
|
|
|
5,884 |
|
Interest expense and financing costs |
|
|
173 |
|
|
|
520 |
|
|
|
427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,216 |
|
|
|
14,213 |
|
|
|
12,602 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) before disposition |
|
|
(564 |
) |
|
|
4,283 |
|
|
|
(5,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on disposition (net of tax of $29.6 million
for 2009, nil for 2008 and 2007) |
|
|
(23,357 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) from discontinued operations |
|
$ |
(23,921 |
) |
|
$ |
4,283 |
|
|
$ |
(5,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and Operating Costs |
Prices and gain/loss on derivatives
From the U.S. operations, we realized an average of $44.03 per Boe during 2009, which was a
decrease of $44.64 per Boe and accounted for $5.5 million of our decreased revenues, and we
realized an average of $88.67 per Boe during 2008, which was an increase of $26.96 per Boe and
accounted for $5.5 million of our increased revenues.
The increased revenues from higher oil and gas prices in 2008 were offset by the realized loss on
derivatives resulting from settlements from our costless collar derivative instruments. As
benchmark prices rise above the ceiling price established in the contract the Company is required
to settle monthly (see further details on these contracts below under Unrealized Gain (Loss) on
Derivative Instruments). The Company realized a net loss on these settlements in 2008 of $5.2
million, which compares to a realized net loss in 2007 of $1.3 million.
Production Volumes
From the U.S. Operations we produced 124 Mboe compared to 204 Mboe produced in 2008. This decrease
was due to the sale of these U.S. operations midway through 2009. There was a 3% increase in U.S.
production volume for 2008 as compared to 2007 and accounted for $0.3 million of our increased
revenues. The overall changes to the U.S. production volumes were mainly due to the 2008 first
quarter drilling program at South Midway. In addition, an increase in production in 2008 was due to
increased steaming in the first two months of 2008 and abnormal downtimes in the steaming
operations in 2007 due the absence of our two steam generators for extended period of time. The
purchase of a second steam generator and the retrofit of an existing generator allowed for a full
steaming program in 2008.
Operating Costs
Field operating costs decreased $7.92 per Boe in 2009 mainly due management redeploying technical
personnel assigned to this segment to other segments in anticipation of the sale of these
operations.
Field operating costs increased $4.21 per Boe in 2008 mainly due to an increase in steaming
operations at South Midway. Both steam generators were down in the latter part of the first quarter
and through the second quarter of 2007. In addition, the price of natural gas has been
significantly higher in 2008 when compared to 2007.
|
|
|
General and Administrative Expenses |
General and administrative expenses decreased significantly in 2009 when compared to 2008, in part
because these U.S. Operations were sold midway through 2009 and in part due to non-field assets and
personnel being transferred to the parent company.
13
General and administrative expenses increased $0.4 million in 2008 as compared to 2007. The
increase in 2008 was mainly resulting from a lower allocation to capital and operations, provision
for uncollectible accounts related to certain joint interest billings, offset by reallocation of
staff to business and technology development.
Interest expense increased for 2008 and 2007 when compared to prior years due to additional draws
on our loan facility.
|
|
|
Unrealized Gain (Loss) on Derivative Instruments |
As required by the Companys lenders, the Company entered into costless collar derivatives to
minimize variability in its cash flow from the sale of approximately 75% of the Companys estimated
production from its South Midway Property in California and Spraberry Property in West Texas over a
two-year period starting November 2006 and a six-month period starting November 2008. The
derivatives have a ceiling price of $65.20, and $70.08, per barrel and a floor price of $63.20, and
$65.00, per barrel, respectively, using WTI as the index traded on the NYMEX.
The Company is required to account for these contracts using mark-to-market accounting. As
forecasted benchmark prices exceed the ceiling prices set in the contract, the contracts have
negative value or a liability. These benchmark prices reached record highs at the beginning of the
third quarter of 2008 before steadily declining at the end of the fourth quarter to a level that is
the lowest dating back several years. For the year ended December 31, 2008, the Company had $5.5
million unrealized gains in these derivative transactions. This compares to an unrealized net loss
in 2007 of $4.3 million.
|
|
|
Depletion and Depreciation |
The depletion rates for 2009, 2008 and 2007 were all within $1.00 of each other. Any fluctuation
between years was due to production variances.
Financial Condition, Liquidity and Capital Resources
Sources and Uses of Cash
The following table sets forth a summary of our cash flows from continuing and discontinued
operations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Net cash provided by (used in) operating activities |
|
$ |
(12,290 |
) |
|
$ |
17,053 |
|
|
$ |
5,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
$ |
6,396 |
|
|
$ |
(49,321 |
) |
|
$ |
(22,287 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
$ |
(11,875 |
) |
|
$ |
70,751 |
|
|
$ |
14,275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
$ |
(17,753 |
) |
|
$ |
27,909 |
|
|
$ |
(2,523 |
) |
As reflected in the accompanying unaudited consolidated financial statements, we have losses from
operations, negative cash flows from operations and have a substantial accumulated deficit.
Historically, we have principally used external sources to fund operations, to fund acquisitions of
oil and gas properties and projects, to service long-term liabilities and to develop our technology
and major projects. The main source of funds historically has been public and private equity and
debt markets. The Companys cash flow from operating activities will not be sufficient to meet its
operating and capital obligations, and as such, the Company intends to finance its operating and
capital projects from a combination of strategic investors in its projects and/or public and
private debt and equity markets, either at a parent company level or at a project level.
Principal factors that could affect our ability to obtain funds from external sources include:
|
|
|
Inability to attract strategic investors to our projects, |
|
|
|
Volatility in the public debt and private and equity markets, |
|
|
|
Increases in interest rates or credit spreads, as well as limitations on the
availability of credit, that affect our ability to borrow under future potential credit
facilities on a secured or unsecured basis, and |
|
|
|
A decrease in the market price for our common stock. |
14
Our operating activities used $12.3 million in cash for the year ended December 31, 2009 compared
to $17.1 million and $5.5 million provided in the same periods in 2008 and 2007. The decrease in
cash from operating activities for the year ended December 31, 2009 was mainly due to the
significant decrease in oil and gas production prices offset by an increase in expenses. The
increase in cash from operating activities for the year ended December 31, 2008 was mainly due to a
50% increase in oil and gas production prices offset by an increase in expenses, as well as an
increase in changes in non-cash working capital when compared to 2007.
Our investing activities used $6.4 million in cash for the year ended December 31, 2009 compared to
$49.3 million for the same period in 2008 and $22.3 million for 2007. For 2009, the main reason for
the differences is $35.3 million cash provided by discontinued operations which is mainly the
proceeds from the sale of these operations. For 2008, the main reason for the differences is the
$22.3 million paid as part of the cost of the acquisition of the100% working interests in two
leases located in the Athabasca oil sands region in the Province of Alberta, Canada (see Note 18 in
the accompanying financial statements for more details). In addition the Company received $9.0
million in proceeds from a recovery of development costs in 2007, compared to nil in 2008 and 2009.
There was also an increase in capital asset expenditures of $5.3 million for 2009 as compared to
2008 and a decrease of $7.5 million for 2008 when compared to 2007.
Changes in capital investments by segment are detailed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended |
|
|
For the Year Ended |
|
|
|
December 31, |
|
|
December 31, |
|
|
|
|
|
|
|
|
|
|
|
(Increase) |
|
|
|
|
|
|
|
|
|
|
(Increase) |
|
|
|
2009 |
|
|
2008 |
|
|
Decrease |
|
|
2008 |
|
|
2007 |
|
|
Decrease |
|
Oil and Gas Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
12,756 |
|
|
$ |
6,484 |
|
|
$ |
(6,272 |
) |
|
$ |
6,484 |
|
|
$ |
|
|
|
$ |
(6,484 |
) |
Ecuador |
|
|
5,380 |
|
|
|
1,369 |
|
|
|
(4,011 |
) |
|
|
1,369 |
|
|
|
|
|
|
|
(1,369 |
) |
Asia |
|
|
6,049 |
|
|
|
8,378 |
|
|
|
2,329 |
|
|
|
8,378 |
|
|
|
23,488 |
|
|
|
15,110 |
|
Business and Technology Development |
|
|
2,093 |
|
|
|
4,832 |
|
|
|
2,739 |
|
|
|
4,832 |
|
|
|
5,097 |
|
|
|
265 |
|
Corporate |
|
|
95 |
|
|
|
|
|
|
|
(95 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,373 |
|
|
$ |
21,063 |
|
|
$ |
(5,310 |
) |
|
$ |
21,063 |
|
|
$ |
28,585 |
|
|
$ |
7,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
As noted above, two leases located in Canada were acquired in the third quarter of 2008. Capital
investments during both years consisted of seismic/ERT, environmental work and capitalized
interest.
Ecuador
The increase of investment activities in 2009 is due to the signing of a contract in October 2008
to explore and develop Ecuadors Pungarayacu heavy-oil field using our HTLTM Technology
including the completion of environmental assessment activities, the receipt of environmental
permits and licenses in May 2009 and preliminary costs related to the start of appraisal drilling
activities in the third quarter ended September 30, 2009. The first well was spud during the fourth
quarter 2009.
15
Asia
Capital asset expenditures decreased $2.3 million in 2009 as compared to the 2008. Expenditures in
the Dagang field decreased $2.6 million in 2009 compared to 2008 period as fewer fracture
stimulations, and an associated decrease in field office cost allocations, were performed in 2009
versus 2008. Expenditures in the Sichuan project decreased slightly from 2008 levels by $0.7
million for 2009 compared to 2008 due to lower personnel costs and less seismic interpretation
costs. Drilling is to commence in the second quarter of 2010 with expected completed drilling,
completion and evaluation of the prospects finalized in late 2010.
The decrease in investment in this segment in 2008 compared to 2007 was the result of a $9.6
million decrease in capital spending at Zitong and a $5.5 million decrease in capital spending at
Dagang. Spending at Zitong during 2008 was limited to expenditures relating to the commencement of
the second phase of the exploration program which were relatively minor compared to the drilling
and completion costs incurred during 2007 for completing the first phase of the program which was
concluded in December 2007. At Dagang, we spud five new development wells in 2007 compared to 2008
where we only completed a series of fracture stimulation projects.
Business and Technology Development
The decrease in capital spending during 2009 when compared to 2008 was due to the timing of costs
relating to the construction and delivery of the FTF. Additionally, in 2009 there were
modifications to the FTF to provide the capacity for longer-term runs and enhance the facilitys
intellectual property development capabilities.
The decrease in capital spending during 2008 when compared to 2007 was due to the timing of costs
relating to the construction and delivery of the FTF.
Discontinued Operations
There was minimal capital activity in 2009. The $1.5 million increase in U.S. capital spending in
2008 compared to 2007 was mainly due to the eight well drilling program at South Midway in 2008
compared to the cost of a new steam generator in 2007.
Financing activities for 2009 consisted mainly of the final debt payments of long-term notes and
the repayment of a note associated with discontinued operations. Financing activities for the year
ended December 31, 2008 consisted mainly of an equity private placement in the third quarter of
2008. In July 2008, the Company completed a Cdn.$88.0 million private placement consisting of
29,334,000 special warrants (Special Warrants) at Cdn.$3.00 per Special Warrant (the Offering).
Each Special Warrant entitled the holder to one common share of the Company upon exercise of the
Special Warrant. In August 2008, all of the Special Warrants were exercised for 29,334,000 common
shares. The net proceeds from the Offering of the Special Warrants was approximately Cdn.$83.4
million.
In addition, in April 2008, the Company obtained a loan from a third party finance company in the
amount of Cdn.$5.0 million bearing interest at 8% per annum. At the lenders option the principal
and accrued and unpaid interest was converted in August 2008 into the Companys common shares at a
conversion price of Cdn.$2.24 per share.
These cash inflows were offset by $2.6 million in professional fees and expenses associated with
the pursuit of corporate financing initiatives by the Companys Chinese subsidiary, Sunwing Energy
and the payment at maturity on December 31, 2008 of a promissory note to Talisman in the principal
amount of Cdn.$12.5 million plus accrued interest.
Financing activities for the year ended December 31, 2007 consisted of three draws totaling $13.0
million ($12.4 million net of financing costs) on two separate loan facilities, one associated with
our discontinued operations. This increase in borrowings was offset by scheduled debt payments of
$2.5 million. Financing activities in 2007 also consisted of $4.0 million received from the
exercise of warrants compared to 2006 when there were no warrants exercised but there was a $25.3
million private placement of common shares.
Outlook for 2010
Our 2010 capital program budget ranges from approximately $100.0 million to $125.0 million and will
encompass the following: a) continued advancement of the Tamarack and Pungarayacu heavy oil
developments, b) exploration drilling in the Zitong prospect in Sichuan province, China, and c)
selected engineering and development costs related to the enhancement of our proprietary
HTLTM oil upgrading technology, d) minor maintenance in the Dagang oil field, Hebei
province China. Managements plans for financing its 2010 requirements and beyond include a recent
Special Warrant private placement, as outlined in Note 20 to the accompanying
financial statements and, for the longer term, the potential for alliances or other arrangements
with strategic partners as well as future traditional project financing, debt and mezzanine
financing or the sale of equity securities.
16
Discussions with potential strategic partners are focused primarily on national oil companies and
other sovereign or government entities from Asian and Middle Eastern countries that have approached
the Company and expressed interest in participating in the Companys heavy oil activities in
Ecuador, Canada and around the world. However, no assurances can be given that we will be able to
enter into one or more alternative business alliances with other parties or raise additional
capital. If we are unable to enter into such business alliances or obtain adequate additional
financing, we will be required to curtail our operations, which may include the sale of assets.
In addition to Tamarack and Pungarayacu, the Company will continue to pursue ongoing discussions
related to other HTL heavy oil opportunities in Canada, North and South America, the Middle East
and North Africa.
Contractual Obligations and Commitments
The table below summarizes the contractual obligations that are reflected in our 2009 consolidated
balance sheets and/or disclosed in the accompanying Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year |
|
|
|
(stated in thousands of U.S. dollars) |
|
|
|
Total |
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
2013 |
|
|
After 2013 |
|
Consolidated Balance Sheets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long term debt |
|
$ |
36,934 |
|
|
$ |
|
|
|
$ |
36,934 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Asset retirement obligation |
|
|
948 |
|
|
|
753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
195 |
|
Long term obligation |
|
|
1,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,900 |
|
|
|
|
|
Other Commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest payable |
|
|
3,535 |
|
|
|
2,305 |
|
|
|
1,230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease commitments |
|
|
3,121 |
|
|
|
1,448 |
|
|
|
1,109 |
|
|
|
438 |
|
|
|
126 |
|
|
|
|
|
Zitong exploration commitment |
|
|
20,830 |
|
|
|
20,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nyalga exploration commitment |
|
|
3,350 |
|
|
|
|
|
|
|
850 |
|
|
|
500 |
|
|
|
2,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
70,618 |
|
|
$ |
25,336 |
|
|
$ |
40,123 |
|
|
$ |
938 |
|
|
$ |
4,026 |
|
|
$ |
195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We have excluded our normal purchase arrangements as they are discretionary and/or being performed
under contracts which are cancelable immediately or with a 30-day notification period.
Critical Accounting Principles and Estimates
Our accounting principles are described in Note 2 to the Consolidated Financial Statements. We
prepare our Consolidated Financial Statements in conformity with GAAP in Canada, which conform in
all material respects to U.S. GAAP except for those items disclosed in Note 21 to the Consolidated
Financial Statements. For U.S. readers, we have detailed the differences and have also provided a
reconciliation of the differences between Canadian and U.S. GAAP in Note 21 to the Consolidated
Financial Statements.
The preparation of our financial statements requires us to make estimates and judgments that affect
our reported amounts of assets, liabilities, revenue and expenses. On an ongoing basis we evaluate
our estimates, including those related to asset impairment, revenue recognition, fair market value
of derivatives, allowance for doubtful accounts and contingencies and litigation. These estimates
are based on information that is currently available to us and on various other assumptions that we
believe to be reasonable under the circumstances. Actual results could vary from those estimates
under different assumptions and conditions.
We have identified the following critical accounting policies that affect the more significant
judgments and estimates used in preparation of our consolidated financial statements.
Full Cost Accounting We follow Canadian Institute of Chartered Accountants (CICA) Handbook
Accounting Guideline 16 Oil and Gas Accounting Full Cost (AcG 16) in accounting for our oil
and gas properties. Under the full cost method of accounting, all exploration and development costs
associated with lease and royalty interest acquisition, geological and geophysical activities,
carrying charges for unproved properties, drilling both successful and unsuccessful wells,
gathering and production facilities and equipment, financing, administrative costs directly related
to capital projects and asset retirement costs are capitalized on a country-by-country cost center
basis.
The other generally accepted method of accounting for costs incurred for oil and gas properties is
the successful efforts method. Under
this method, costs associated with land acquisition and geological and geophysical activities are
expensed in the year incurred and the costs of drilling unsuccessful wells are expensed upon
abandonment.
17
As a consequence of following the full cost method of accounting, we may be more exposed to
potential impairments if the carrying value of a cost centers oil and gas properties exceeds its
estimated future net cash flows than if we followed the successful efforts method of accounting.
Impairment may occur if a cost centers recoverable reserve estimates decrease, oil and natural gas
prices decline or capital, operating and income taxes increase to levels that would significantly
affect its estimated future net cash flows. See Impairment of Proved Oil and Gas Properties
below.
Oil and Gas Reserves The process of estimating quantities of reserves is inherently uncertain and
complex. It requires significant judgments and decisions based on available geological,
geophysical, engineering and economic data. These estimates may change substantially as additional
data from ongoing development activities and production performance becomes available and as
economic conditions impacting oil and gas prices and costs change. Our reserve estimates are based
on current production forecasts, prices and existing economic conditions, operating methods and
government regulations. Reserve numbers and values are only estimates and you should not assume
that the present value of our future net cash flows from these estimates is the current market
value of our estimated proved oil and gas reserves.
Reserve estimates are critical to many accounting estimates and financial decisions including:
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determining whether or not an exploratory well has found economically recoverable
reserves. Such determinations involve the commitment of additional capital to develop the
field based on current estimates of production forecasts, prices and other economic
conditions. |
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calculating our unit-of-production depletion rates. Proved reserves are used to
determine rates that are applied to each unit-of-production in calculating our depletion
expense. |
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assessing our proved oil and gas properties for impairment on a quarterly basis.
Estimated future net cash flows used to assess impairment of our oil and gas properties are
determined using proved and probable reserves(1). See Impairment of Proved Oil
and Gas Properties below. |
Management is responsible for estimating the quantities of proved oil and natural gas reserves and
preparing related disclosures. Estimates and related disclosures are prepared in accordance with
SEC requirements set out in the definitions in Regulation S-X and the rules in Regulation S-K,
generally accepted industry practices in the U.S. as promulgated by the Society of Petroleum
Engineers, and the standards of the COGE Handbook modified to reflect SEC requirements.
For details on our reserve estimation process please refer section titled Internal Control over
Reserve Reporting in Item 1 and 2 of this Form 10-K.
The estimated discounted future net cash flows from estimated proved reserves included in the
Supplementary Financial Information are based on prices and costs as of the date of the estimate.
Actual future prices and costs may be materially higher or lower. Actual future net cash flows will
also be affected by factors such as actual production levels and timing, and changes in
governmental regulation or taxation, and may differ materially from estimated cash flows.
(1) Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically
produciblefrom a given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations.
Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves but which, together with proved reserves, are as likely as not to be recovered.
Depletion As indicated previously, our estimate of proved reserves are critical to calculating our
unit-of-production depletion rates.
Another critical factor affecting our depletion rate is our determination that an impairment of
unproved oil and gas properties has occurred. Costs incurred on an unproved oil and gas property
are excluded from the depletion rate calculation until it is determined whether proved reserves are
attributable to an unproved oil and gas property or upon determination that an unproved oil and gas
property has been impaired. An unproved oil and gas property would likely be impaired if, for
example, a dry hole has been drilled and there are no firm plans to continue drilling on the
property. Also, the likelihood of partial or total impairment of a property increases as the
expiration of the lease term approaches and there are no plans to drill on the property or to
extend the term of the lease. We assess each of our unproved oil and gas properties for impairment
on a quarterly basis. If we determine that an unproved oil and gas property has been totally or
partially impaired we include all or a portion of the accumulated costs incurred for that unproved
oil and gas property in the calculation of our unit-of-production depletion rate.
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Our depletion rate is also affected by our estimates of future costs to develop the proved
reserves. We estimate future development costs using quoted prices, historical costs and trends. It
is difficult to predict prices for materials and services required to develop a field particularly
over a period of years with rising oil and gas prices during which there is generally increased
competition for a limited number of suppliers. We update our estimates of future costs to develop
our proved reserves on a quarterly basis.
Impairment of Proved Oil and Gas Properties We evaluate each of our cost centers proved oil and
gas properties for impairment on a quarterly basis. The basis for calculating the amount of
impairment is different for Canadian and U.S. GAAP purposes.
For Canadian GAAP, AcG 16 requires recognition and measurement processes to assess impairment of
oil and gas properties (ceiling test). In the recognition of an impairment, the carrying
value(1) of a cost center is compared to the undiscounted future net cash flows of that
cost centers proved reserves using estimates of future oil and gas prices and costs plus the cost
of unproved properties that have been excluded from the depletion calculation. If the carrying
value is greater than the value of the undiscounted future net cash flows of the proved reserves
plus the cost of unproved properties excluded from the depletion calculation, then the amount of
the cost centers potential impairment must be measured. A cost centers impairment loss is
measured by the amount its carrying value exceeds the discounted future net cash flows of its
proved and probable reserves using estimates of future oil and gas prices and costs plus the cost
of unproved properties that have been excluded from the depletion calculation and which contain no
probable reserves. The net cash flows of a cost centers proved and probable reserves are
discounted using a risk-free interest rate adjusted for political and economic risk on a
country-by-country basis. The amount of the impairment loss is recognized as a charge to the
results of operations and a reduction in the net carrying amount of a cost centers oil and gas
properties.
For U.S. GAAP, we follow the requirements of the SECs Regulation S-X Article 4-10(c)4 for
determining the limitation of capitalized costs. Accordingly, the carrying value(1) of a
cost centers oil and gas properties cannot exceed the (a) present value of estimated future net
revenues computed by applying average, first-day-of-the-month price during the 12-month period
before the end of the year prices of oil and gas reserves (with consideration of price changes only
to the extent provided by contractual arrangements) to estimated future production of proved oil
and gas reserves as of the date of the latest balance sheet presented, less estimated future
expenditures (based on current costs) to be incurred in developing and producing the proved
reserves computed using a discount factor of ten percent and assuming continuation of existing
economic conditions plus (b) the cost of properties not being amortized (e.g. major development
projects) and (c) the lower of cost or fair value of unproven properties included in the costs
being amortized less (d) income tax effects related to the difference between the book and tax
basis of the properties referred to in (b) and (c) above. If unamortized capitalized costs within a
cost center exceed this limit, the excess is charged as a provision for impairment in the statement
of operations. Amounts thus required to be written off shall not be reinstated for any subsequent
increase in the cost center ceiling. Unproved properties and major development projects are
assessed on a quarterly basis for possible impairments or reductions in value. If a reduction in
value has occurred, the impairment is transferred to the carrying value of proved oil and gas
properties.
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For Canadian GAAP, the carrying value includes all capitalized costs for each cost center,
including costs associated with asset retirement net of estimated salvage values, unproved
properties and major development projects, less accumulated depletion and ceiling test
impairments. This is essentially the same definition according to U.S. GAAP, under Regulation S-X,
except that the carrying value of assets should be net of deferred income taxes and costs of major
development projects are to be considered separately for purposes of the ceiling test calculation. |
Asset Retirement Obligations For Canadian GAAP, we follow CICA Handbook Section 3110, Asset
Retirement Obligations which requires asset retirement costs and liabilities associated with site
restoration and abandonment of tangible long-lived assets be initially measured at a fair value
which approximates the cost a third party would incur in performing the tasks necessary to retire
such assets. The fair value is recognized in the financial statements at the present value of
expected future cash outflows to satisfy the obligation. Subsequent to the initial measurement, the
effect of the passage of time on the liability for the asset retirement obligation (accretion
expense) and the amortization of the asset retirement cost are recognized in the results of
operations. We measure the expected costs required to retire our producing U.S. oil and gas
properties at a fair value, which approximates the cost a third party would incur in performing the
tasks necessary to abandon the field and restore the site. We do not make such a provision for our
oil and gas operations in China as there is no obligation on our part to contribute to the future
cost to abandon the field and restore the site. Asset retirement costs are depleted using the unit
of production method based on estimated proved reserves and are included with depletion and
depreciation expense. The accretion of the liability for the asset retirement obligation is
included with interest expense.
For U.S. GAAP, we follow Financial Accounting Standards Board (FASB) Accounting Standards
Codification Manual (ASC) Topic 410 Asset Retirement and Environmental Obligations (formerly
Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement
Obligations) which conforms in all material respects with Canadian GAAP.
Research and Development We incur various expenses in the pursuit of HTLTM and GTL
projects, including HTLTM Technology for heavy oil processing, throughout the world. For
Canadian GAAP, such expenses incurred prior to signing a MOU, or similar agreements, are considered
to be business and technology development expenses and are charged to the results of operations as
incurred. Upon executing a MOU to determine the technical and commercial feasibility of a project,
including studies for the marketability of the projects products, we assess that the feasibility
and related costs incurred have potential future value, are probable of leading to a definitive
agreement for the exploitation of proved reserves and should be capitalized. If no definitive
agreement is reached, then the capitalized costs, which are deemed to have no future value, are
written down to our results of operations with a corresponding reduction in our investments in
HTLTM or GTL assets.
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Additionally, we incur costs to develop, enhance and identify improvements in the application of
the HTLTM and GTL technologies we license or own. We follow CICA Handbook Section 3064,
Goodwill and Intangible assets, (S.3064) in accounting for the development costs of equipment
and facilities acquired or constructed for such purposes. Development costs are capitalized and
amortized over the expected economic life of the equipment or facilities commencing with the start
up of commercial operations for which the equipment or facilities are intended. We review the
recoverability of such capitalized development costs annually, or as changes in circumstances
indicate the development costs might be impaired, through an evaluation of the expected future
discounted cash flows from the associated projects. If the carrying value of such capitalized
development costs exceeds the expected future discounted cash flows, the excess is written down to
the results of operations with a corresponding reduction in the investments in HTLTM and
GTL assets.
Costs incurred in the operation of equipment and facilities used to develop or enhance
HTLTM and GTL technologies prior to commencing commercial operations are business and
technology development expenses and are charged to the results of operations in the period
incurred.
For U.S. GAAP, we follow ASC Topic 720 Research and Development (formerly SFAS No. 2, Research
and Development). As with Canadian GAAP, costs of equipment or facilities that are acquired or
constructed for research and development activities are capitalized as tangible assets and
amortized over the expected economic life of the equipment or facilities commencing with the start
up of commercial operations for which the equipment or facilities are intended. However, for U.S.
GAAP such facilities must have alternative future uses to be capitalized. As with Canadian GAAP,
expenses incurred in the operation of research and development equipment or facilities prior to
commencing commercial operations are business and technology development expenses and are charged
to the results of operations in the period incurred. The major difference for U.S. GAAP purposes is
that feasibility, marketing and related costs incurred prior to executing a definitive agreement
are considered to be research and development costs and are expensed as incurred.
Intangible Assets Our intangible assets consists of the underlying value of an exclusive,
irrevocable license to deploy, worldwide, the RTPTM Process for petroleum applications
(HTLTM Technology) as well as the exclusive right to deploy the RTPTM Process
in all applications other than biomass and a master license from Syntroleum permitting us to use
the Syntroleum Process in an unlimited number of projects around the world. For Canadian GAAP, we
follow S.3064 whereby intangible assets, acquired individually or with a group of other assets, are
initially recognized and measured at cost. Intangible assets with finite lives are amortized over
their useful lives whereas intangible assets with indefinite useful lives are not amortized unless
it is subsequently determined to have a finite useful life. Intangible assets are reviewed annually
for impairment, or when events or changes in circumstances indicate that the carrying value of an
intangible asset may not be recoverable. If the carrying value of an intangible asset exceeds its
fair value or expected future discounted cash flows, the excess is written down to the results of
operations with a corresponding reduction in the carrying value of the intangible asset. The
HTLTM Technology and the Syntroleum GTL master license have finite lives, which
correlate with the useful lives of the facilities we expect to develop that will use the
technologies. The amount of the carrying value of the technologies we assign to each facility will
be amortized to earnings on a basis related to the operations of the facility from the date on
which the facility is placed into service. We evaluate the carrying values of the HTLTM
Technology and the Syntroleum GTL master license annually, or as changes in circumstances indicate
the intangible assets might be impaired, based on an assessment of its fair market value.
For U.S. GAAP, we follow ASC Topic 350 Intangibles Goodwill and Other (formerly SFAS No. 142,
Goodwill and Other Intangible Assets which conforms in all material respects with Canadian GAAP.
2009 Accounting Changes
In February 2008, the Canadian Institute of Chartered Accountants (CICA) issued Handbook Section
3064, Goodwill and Intangible assets, (S.3064) replacing Handbook Section 3062, Goodwill and
Other Intangible Assets (S.3062) and Handbook Section 3450, Research and Development Costs.
S.3064 is applicable to financial statements relating to fiscal years beginning on or after October
1, 2008. The new section 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 S.3062.
Also in February 2008, the CICA amended portions of Handbook Section 1000, Financial Statement
Concepts, which the CICA concluded permitted deferral of costs that did not meet the definition of
an asset. The amendments apply to annual and interim financial statements relating to fiscal years
beginning on or after October 1, 2008. Upon adoption of S.3064 and the amendments to Section 1000
on January 1, 2009, capitalized amounts that no longer meet the definition of an asset are expensed
retrospectively.
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The Company adopted the new standards on January 1, 2009 with no transitional adjustment to the
consolidated financial statements as a result of having adopted these standards.
In June 2009, the AcSB issued Accounting Revisions Release No. 54, Improving Disclosures About
Financial Instruments Background Information and Basis for Conclusions (Amendments to Financial
Instruments Disclosures, Section 3862), which amended certain disclosure requirements related to
financial instrument disclosure in response to disclosure amendments issued by the International
Accounting Standards Board. This is consistent with the AcSBs strategy to adopt IFRS and to ensure
the current existing disclosure requirements for financial instruments are converged to the extent
possible. The new disclosure standards require disclosure of fair values based on a fair value
hierarchy as well as enhanced discussion and quantitative disclosure related to liquidity risk. The
amended disclosure requirements are effective for annual financial statements relating to fiscal
years ending after September 30, 2009 and as such the Company has included the required disclosure
in Note 12 for the year ending December 31, 2009.
Impact of New and Pending Canadian GAAP Accounting Standards
In January 2009, the Emerging Issues Committee of the CICA (EIC) issued Emerging Issues Committee
abstract 173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities which
provides guidance on the implications of credit risk in determining the fair value of an entitys
financial assets and financial liabilities. The guidance clarifies that an entitys own credit risk
and the credit risk of counterparties should be taken into account in determining the fair value of
financial assets and financial liabilities, including derivative instruments, for presentation and
disclosure purposes. The conclusions of the EIC were effective from the date of issuance of the
abstract and did not have any material impact on the Companys consolidated balance sheet or
statement of operations, comprehensive loss and accumulated deficit. However, the Companys fair
value disclosures in Note 12 incorporated this new guidance.
Also in January 2009, the Accounting Standards Board of the CICA (AcSB) issued Handbook Section
1582, Business Combinations (S.1582) replacing Handbook Section 1581, Business Combinations.
The AcSB revised accounting standards in regards to business combinations with the intent of
harmonizing those standards with IFRS. The revised standards require the acquiring entity in a
business combination to recognize all (and only) the assets acquired and liabilities assumed in the
transaction, establish the acquisition date fair value as the measurement objective for all assets
acquired and liabilities assumed; and require the acquirer to disclose to investors and other users
all of the information they need to evaluate and understand the nature and financial effect of the
business combination. These standards shall be applied prospectively to business combinations with
an acquisition date after the beginning of the first annual reporting period beginning after
January 1, 2011. The Company adopted this standard early on January 1, 2009 with no transitional
adjustment to the consolidated financial statements as a result of adopting this standard. However,
the Company did apply the provisions of this standard to a business combination that occurred in
the fourth quarter of 2009 (see Note 18).
Also in January 2009, the AcSB issued Handbook Section 1601, Consolidated Financial Statements
(S.1601) and Handbook Section 1602, Non-Controlling Interests (S.1602), which replace
Handbook Section 1600, Consolidated Financial Statements (S.1600). S.1601 and S.1602 require
all entities to report non-controlling (minority) interests as equity in consolidated financial
statements. The standards eliminate the diversity that currently exists in accounting for
transactions between an entity and non-controlling interests by requiring they be treated as equity
transactions. These standards shall be applied retrospectively effective for interim and annual
financial statements relating to fiscal years beginning on or after January 1, 2011. The Company
adopted these standards early on January 1, 2009 with no transitional adjustment to the
consolidated financial statements as a result of adopting these standards.
Convergence of Canadian GAAP with International Financial Reporting Standards
Transition to International Financial Reporting Standards
The Canadian Accounting Standards Board (AcSB) announced that Canadian Generally Accepted
Accounting Principles (GAAP) no longer apply for all publically accountable enterprises as of
January 1, 2011. For interim and annual periods beginning on or after January 1, 2011, the Company
will be required to report under International Financial Reporting Standards (IFRS) as set out by
the International Accounting Standards Board (IASB). Comparative IFRS information for the 2010
fiscal year will also have to be reported for interim and annual consolidated financial statements
issued during 2011 and thus the Companys transition date to IFRS will be January 1, 2010. Any
adjustments resulting from a change in policy as a result of the transition to IFRS will be applied
retroactively with corresponding adjustment to the Companys opening retained earnings on January
1, 2010. The Company is
currently evaluating the impact of these new standards. The implementation of IFRS may result in a
significant impact on our accounting policies, measurements and disclosures.
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IFRS Transition Overview
The Company is in the process of evaluating the potential impact of IFRS to its consolidated
financial statements. This will be an ongoing process as the IASB and the AcSB issue new standards
and recommendations and as the Canadian accounting profession interprets those standards and
recommendations. The Companys consolidated financial performance and financial position as
disclosed in the current Canadian GAAP consolidated financial statements may be significantly
different when presented in accordance with IFRS. Additionally, the Company is a foreign private
issuer as defined in Rule 3b-4(c) under the United States Securities Exchange Act of 1934, as
amended. Historically, the Company has voluntarily filed on domestic forms (Forms 10-K, 10-Q and
8-K) with the United States Securities Exchange Commission (SEC) and has presented its
consolidated financial statements using Canadian GAAP in U.S. dollars, with a reconciliation to
U.S. GAAP. The SEC issued Rule 33-8567 which allows foreign private issuers that voluntarily file
on domestic forms to file financial statements prepared under IFRS as issued by the IASB without
reconciliation to U.S. GAAP. Accordingly, upon transition to IFRS on January 1, 2011, the Company
will not provide a reconciliation to U.S. GAAP in its interim or annual consolidated financial
statements.
The Company has identified IFRS versus current Canadian GAAP differences and various policy choices
available under IFRS, but continues to assess the implications of such differences and policy
choices to its financial reporting. At this time, the Company cannot quantify the impact that the
future adoption of IFRS will have on its consolidated financial performance and financial position;
however, the impact may be material. The Company also expects the transition to IFRS to impact
disclosure controls and procedures, and information and technology systems and processes. While
IFRS may also affect internal controls over financial reporting, management does not currently
expect such changes to be significant. Additional information will be provided by the Company in
quarterly reports issued during 2010.
IFRS Conversion Plan
The Company has established a formal project governance structure with oversight by its IFRS
Steering Committee, consisting of senior management. The IFRS Steering Committee provides periodic
updates of the status and effectiveness of the IFRS conversion plan to the Companys senior
executives and Audit Committee.
Key elements of the Companys IFRS conversion plan include, but are not limited to:
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Impact Assessment |
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Selected Key Activities |
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Milestones |
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Progress to Date |
Accounting and Financial Reporting
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Identification of IFRS versus Canadian
GAAP differences (impact assessment)
Design and implement solutions
Evaluate and select one-time and
ongoing accounting policy alternatives
Quantify the effects of the conversion
to IFRS
Prepare mock financial statements and
related note disclosures to comply with IFRS
Engage advisors to assist with conversion
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Assessment and quantification of the
significant effects of the conversion
will be complete by Q3 2010
Final selection of accounting policies
by Q1 2010 with on-going assessment
based on changes to IFRS
Complete mock IFRS financial
statements by Q2 2010
Accumulation of data to establish
opening balance sheet adjustments
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Completed the identification of
significant IFRS differences (impact assessment)
Selection of one-time transition choices is
substantially complete
Evaluation and selection of accounting policies
and alternatives has commenced and will
continue to be assessed up to the date of
transition
Identification and quantification of opening
balance sheet adjustments have commenced
Advisors have commenced validation
of the Companys technical accounting analysis
and impacts |
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Impact Assessment |
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Selected Key Activities |
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Milestones |
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Progress to Date |
Process and Systems
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Assess impact of IFRS accounting standards
on business activities
Identify and addresses IFRS differences
that require changes to financial systems
Identify and address additional data
capture and reporting requirements to
financial systems
Evaluate and select methods to address dual
record keeping during 2010 (IFRS and
Canadian GAAP), for 2010 IFRS comparatives
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Changes to systems and development
of reporting to be complete by Q3 2010
Data capture is ongoing and targeted
for completion during the fourth
quarter of 2010
Method to address dual record keeping
to be identified by Q1 2010
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Project management continues to identify
critical path tasks,
resourcing matters and impact to processes
Commenced identification of data capture
requirements
Identification of dual record-keeping
structure has commenced |
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Training and communication
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Provide training to affected employees,
resources directly involved in the
transition, senior management and
Audit Committee
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Timely training provided to align
with work under transition training
to be substantially completed by Q4
2010
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Detailed training for resources directly
engaged in the transition has commenced and
will be on-going
Communications to senior management and Audit Committee have been
scheduled |
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Communication of progress of conversion
plan to internal and
external stakeholders
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Communicate effects of the transition
during the course of 2010
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On-going communication to external stakeholders
though MD&A disclosure
Periodic project status updates will be
presented to senior management and Audit
Committee |
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Internal control over financial
reporting and disclosure controls
and procedures
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Revise existing control processes and
procedures to address significant changes
to existing accounting
policies
Assess effectiveness
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Complete design and commence
implementation during 2010 and Q1
2011
Assess process changes throughout 2010
Update CEO/CFO officer certification
process for Q4 2010
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IFRS differences with process impacts have been
identified and
design of significant process changes has
commenced |
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Impact of Adoption of IFRS
Adoption of IFRS will initially require retrospective application as of the January 1, 2010
transition date, on the basis that an entity has prepared its financial statements in accordance
with IFRS since its formation. Certain adoptive relief mechanisms are available under IFRS to
assist with difficulties associated with reformulating historical accounting information. The
general relief mechanism is to allow for prospective, rather than retrospective treatment, under
certain conditions as prescribed by IFRS 1, First-time Adoption of International Financial
Reporting Standards. This standard specifies that adjustments arising on the conversion to IFRS
from Canadian GAAP should be recognized in opening retained earnings.
IFRS 1: First-time Adoption of International Financial Reporting Standards (IFRS 1)
The adoption of IFRS requires application of IFRS 1, which provides guidance for an entitys
initial adoption of IFRS. IFRS 1 generally requires an entity to apply all IFRSs effective at the
beginning of its first IFRS reporting period retrospectively. However, IFRS 1 provides certain
mandatory exceptions and permits limited optional exemptions in specified areas of certain IFRS
standards from this general requirement.
The most relevant first time adoption exemptions and elections available under IFRS 1 which will
impact the Company are discussed below:
Oil and Gas Assets
In October 2009, the IASB issued an exemption for oil and gas companies, which follow the full
cost method of accounting for oil and gas operations, to use their Canadian GAAP net book values
of their oil and gas assets for their opening balances when transitioning to IFRS. The oil and
gas assets will need to be categorized separately on the Companys balance sheet as Intangible
Exploration and Evaluation assets in accordance with IFRS 6 Exploration for and Evaluation of
Mineral Resources (IFRS 6) and Oil and Gas Properties and Equipment in accordance with IAS
16 Property, Plant and Equipment (IAS 16) as discussed further below. Oil and Gas Properties
and Equipment are to include development and production assets the Canadian GAAP net book value
of which are to be allocated to Cash Generating Units (CGUs) as defined in IAS 36
Impairment of Assets (IAS 36) based on either proved reserves or proved plus probable
reserves at the discretion of the Company. The opening book values of the CGUs will be subject
to an impairment test as provide for in IAS 36 and any impairment will be charged to opening
retained earnings.
The Company has elected to adopt the deemed cost exemption provided to full cost oil and gas
companies and believes this exemption will significantly decrease the impact to the Companys
opening balance financial statements presented in accordance with IFRS and the effort required
to transition to IFRS.
Property Plant and Equipment (Non-Oil and Gas) and Intangible Assets
IFRS 1 allows an entity to initially measure an item of property, plant and equipment and
intangible assets upon transition to IFRS at fair value as deemed cost as opposed to full
retroactive application of the cost model under IAS 16 and IAS 38 Intangible Assets (IAS
38). Under this option, fair value as deemed cost will become the new cost amount for
qualifying assets at transition.
As stated above the Company will elect to adopt the specific deemed cost exemption as it relates
to its oil and gas assets. However, for the Companys non-oil and gas property plant and
equipment, such as its Feedstock Test Facility, the Company has elected to apply the full
retroactive application of the cost model under IAS 16 in establishing opening balances of its
non-oil and gas property plant and equipment.
The Companys intangible assets consist of HTLTM technology and rights which were
acquired as part of the business combination with Ensyn in April 2005. As stated below under
Business Combinations, the company has elected to apply the requirements of IFRS 3 Business
Combinations (IFRS 3) prospectively and as a result the recorded value of the intangible
assets for Canadian GAAP will be equal to the opening balance upon the transition to IFRS
subject to a fair value less costs to sell or value in use impairment test as required by
IAS 36.
Business Combinations
In the transition to IFRS, entities may elect to apply the requirements of IFRS 3
retrospectively or prospectively from the date of transition to IFRS (or to restate all business
combinations after a selected date). Retrospective application would require an entity to
restate all prior transactions that meet the definition of a business combination under IFRS.
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The Company has elected to rely upon the exemption provided for in IFRS 1 and apply the
requirements of IFRS 3 prospectively and has also decided to early adopt, effective January 1,
2009, Canadian Institute of Chartered Accountants (CICA) Handbook Section 1582 Business
Combinations, Handbook Section 1601 Consolidated Financial Statements, Handbook Section 1602
Non-Controlling Interests for Canadian GAAP purposes as well as the Financial Accounting
Standards Boards FASB 141R Business Combinations for U.S. GAAP purposes as these new
standards are consistent with IFRS 3.
Decommissioning Liabilities (Asset Retirement Obligations)
International Financial Reporting Interpretations Committee (IFRIC) 1 requires that changes in
an existing decommissioning, restoration or similar liability are added to or deducted from the
cost of the related asset and the adjusted cost base are amortized over the remaining useful
life of those assets. Application of IFRIC 1 would require the Company to complete a historical
summary of all such changes that would have been made in relation to a decommissioning liability
from inception of that liability and reflect the cumulative changes in the net book value of the
related asset on transition to IFRS.
However, the exemption available under IFRS 1 would allow an entity to include in the
depreciated cost of the related asset an amount calculated by discounting the decommissioning
liability for that asset at the date of transition to IFRS back to, and depreciating it from,
when the liability was first incurred.
The Company has elected to adopt the exemption available under IFRS 1 with regard to its
decommissioning liabilities.
Share Based Payments
On initial adoption of IFRS, an entity is not required under IFRS 2 Share-Based Payments
(IFRS 2) to recognize share-based payments settled before the entitys IFRS transition date.
Generally, an entity may elect prospective application for stock options granted on or after
November 7, 2002, or for stock options granted after November 7, 2002 that vested before the
later of: (1) the date of transition to IFRS or (2) January 1, 2005.
The Company has elected to apply the transition provisions of IFRS 2 which would require that
IFRS 2 be applied only to equity instruments and liabilities arising from share based payments
(stock options) that are not fully vested on the date of transition to IFRS. This election will
have no impact on opening balances on January 1, 2010 but would affect the expensing of stock
options during 2010 and thereafter as stock options must be expensed on a graded vesting
schedule in accordance with IFRS 2 rather than on a straight line basis as has been applied by
the Company for Canadian GAAP and US GAAP purposes.
IFRS 1 allows for certain other optional exemptions, however, the Company does not expect such
exemptions to be significant to the Companys initial adoption of IFRS.
Impact of New and Pending U.S. GAAP Accounting Standards
In June 2009, the FASB issued guidance now codified as ASC Topic 105, Generally Accepted
Accounting Principles, as the single source of authoritative nongovernmental U.S. GAAP. ASC Topic
105 does not change current U.S. GAAP, but is intended to simplify user access to all authoritative
U.S. GAAP by providing all authoritative literature related to a particular topic in one place. All
existing accounting standard documents will be superseded and all other accounting literature not
included in the FASB Codification will be considered non-authoritative. These provisions of ASC
Topic 105 are effective for interim and annual periods ending after September 15, 2009 and,
accordingly, are effective for our current fiscal reporting period. The adoption of this
pronouncement did not have an impact on the Companys financial position or results of operations,
but did impact our financial reporting process by eliminating all references to pre-codification
standards. On the effective date of this Statement, the Codification superseded all then-existing
non-SEC accounting and reporting standards, and all other non-grandfathered non-SEC accounting
literature not included in the Codification became non-authoritative.
As a result of the Companys implementation of this Codification during 2009, previous references
to new accounting standards and literature are no longer applicable. In these annual financial
statements, the Company has provided reference to both new and old guidance to assist in
understanding the impacts of recently adopted accounting literature, particularly for guidance
adopted since the beginning of the current fiscal year but prior to the ASC.
Also in June 2009, the FASB issued guidance for Amendments to FAS 46R in ASC Topic 810 (formerly
SFAS No. 167) of the Codification, which improves financial reporting by enterprises involved with
variable interest entities. The amendments replace the quantitative-based risks and rewards
calculation for determining which enterprise, if any, has a controlling financial interest in a
variable interest entity with an approach focused on identifying which entity has the power to
direct the activities of a variable interest entity that most significantly impact the entitys
economic performance and: (1) the obligation to absorb losses of the entity; or, (2) the right to
receive benefits from the entity. The amendments are effective as of the beginning of the first
annual reporting period that
begins after November 15, 2009, and shall be applied prospectively. The Company is currently
reviewing the potential impact, if any, this guidance will have on the consolidated financial
statements upon adoption.
25
Also in June 2009, the FASB issued guidance for Accounting for Transfers of Financial Assets, an
Amendment to FAS 140 in ASC Topic 860 (formerly SFAS No. 140, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities-a replacement of FASB Statement
No. 125, as amended by SFAS No. 166, Accounting for Transfers of Financial Assets An Amendment of
FASB Statement No. 140) of the Codification, which is effective for fiscal years beginning after
November 15, 2009, which amends prior principles to require more disclosure about transfers of
financial assets and the continuing exposure, retained by the transferor, to the risks related to
transferred financial assets, including securitization transactions. It eliminates the concept of a
qualifying special-purpose entity, changes the requirements for derecognizing financial assets,
and requires additional disclosures. It also enhances information reported to users of financial
statements by providing greater transparency about transfers of financial assets and an entitys
continuing involvement in transferred financial assets. The Company is currently reviewing the
potential impact, if any, this guidance will have on the Companys consolidated financial
statements upon adoption.
In May 2009, the FASB issued guidance in the ASC Topic 855 Subsequent Events (formerly SFAS No.
165) of the Codification, which establishes the accounting for and disclosure of events that occur
after the balance sheet date but before financial statements are issued or are available to be
issued. It requires the disclosure of the date through which an entity has evaluated subsequent
events and the basis for that date, that is, whether that date represents the date the financial
statements were issued or were available to be issued. The guidance was effective for interim or
annual periods ending after June 15, 2009. The adoption of this guidance did not have a material
impact on the Companys consolidated financial statements. In February 2010, the FASB issued
Accounting Standards Update No. 2010-09 Subsequent Events (Topic 855) Amendments to Certain
Recognition and Disclosure Requirements which provides amendments to Subtopic 855-10 to alleviate
potential conflicts between Subtopic 855-10 and the SECs requirements with regard to subsequent
event disclosures. An entity that is an SEC filer is required to evaluate subsequent events through
the date that the financial statements are issued and is not required to disclose the date through
which subsequent events have evaluated.
In April 2009, the FASB issued guidance in the ASC Topic 820 Fair Value Measurements and
Disclosures (formerly FASB Staff Position (FSP) FAS 157-4) of the Codification on determining
fair value when the volume and level of activity for an asset or liability have significantly
decreased and identifying transactions that are not orderly. The guidance emphasizes that even if
there has been a significant decrease in the volume and level of activity, the objective of a fair
value measurement remains the same. Fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation
or distressed sale) between market participants. The guidance provides a number of factors to
consider when evaluating whether there has been a significant decrease in the volume and level of
activity for an asset or liability in relation to normal market activity. In addition, when
transactions or quoted prices are not considered orderly, adjustments to those prices based on the
weight of available information may be needed to determine the appropriate fair value. The
guidance was effective for interim or annual reporting periods ending after June 15, 2009, and
shall be applied prospectively. The implementation of this guidance did not have a material impact
on the Companys consolidated financial statements.
In April 2009, FASB issued guidance in the ASC Topic 825 Financial Instruments (formerly FSP FAS
107-1 and APB 28-1) of the Codification on interim disclosures about fair value of financial
instruments. The guidance requires disclosures about the fair value of financial instruments for
both interim reporting periods, as well as annual reporting periods. The guidance was effective
for all interim and annual reporting periods ending after June 15, 2009 and shall be applied
prospectively. The implementation of this guidance did not have a material impact on the Companys
consolidated financial statements as at December 31, 2009, other than the additional disclosure in
Note 12.
In March 2008, FASB issued guidance in the ASC Topic 815 Derivatives and Hedging (formerly SFAS
No. 161) of the Codification on improved financial reporting about derivative instruments and
hedging activities by requiring enhanced disclosures to enable investors to better understand the
effects on an entitys financial position, financial performance and cash flows. The guidance was
effective beginning January 1, 2009. Management has complied with the disclosure requirements of
this recent statement see additional disclosures under Commodity Price Risks under Note 12 to
these financial statements.
In February 2008, FASB issued guidance in the Effective Date of FASB Statement No. 157 ASC Topic
820 (formerly FSP FAS 157-2) of the Codification, which amended SFAS No. 157 to delay the effective
date of SFAS No. 157 for non-financial assets and non-financial liabilities until fiscal years
beginning after November 15, 2008, and interim periods within those fiscal years, except for items
that are recognized or disclosed at fair value in the financial statements on a recurring basis.
The implementation of this Topic, which was effective January 1, 2009, did not have a material
impact on the Companys consolidated financial statements.
In December 2007, the FASB issued guidance in ASC Topic 805 Business Combinations (formerly SFAS
No. 141(R), Business Combinations). The standard requires the acquiring entity in a business
combination to recognize all (and only) the assets acquired and liabilities assumed in the
transaction; establishes the acquisition date fair value as the measurement objective for all
assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and
other users all of the information they need to evaluate and understand the nature and financial
effect of the business combination. In April 2009, the FASB issued FSP FAS 141(R)-
1 which amends and clarifies SFAS No. 141(R) to address application issues raised by preparers,
auditors and members of the legal profession on initial recognition and measurement, subsequent
measurement and accounting, and disclosure of assets and liabilities arising from contingencies in
a business combination. This statement shall be applied prospectively. The implementation of SFAS
No. 141(R) and FSP FAS 141(R)-1, effective January 1, 2009, did not have a material impact on the
companys consolidated financial statements.
26
In December 2007, the FASB issued guidance in the ASC Topic 810 Consolidation (formerly SFAS No.
160) of the Codification on the accounting for non-controlling (minority) interests in consolidated
financial statements. This guidance clarifies the classification of non-controlling interests in
consolidated statements of financial position and the accounting for and reporting of transactions
between the reporting entity and holders of such non-controlling interests. This guidance was
effective as of the beginning of an entitys first fiscal year that began on or after December 15,
2008 and was required to be adopted prospectively, except for the reclassification of
non-controlling interests to equity and the recasting of net income (loss) attributable to both the
controlling and non-controlling interests, which were required to be adopted retrospectively. The
Company adopted this guidance effective January 1, 2009, and did not have a material impact on the
consolidated financial statements.
In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the
existing Regulation S-K and Regulation S-X reporting requirements to align with current industry
practices and technological advances. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the
new disclosure requirements require a company to (a) disclose its internal control over reserves
estimation and report the independence and qualification of its reserves preparer or auditor, (b)
file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve
audit and (c) report oil and gas reserves using an average price based upon the prior 12-month
period rather than period-end prices. The provisions of this final ruling became effective for
disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009. The
implementation of this Rule, did not have a material impact on the Companys consolidated financial
statements.
In August 2009, the FASB issued Accounting Standards Update (ASU) 2009 05 Fair Value
Measurements and Disclosures (ASC Topic 820) Measuring Liabilities at Fair Value (ASU 09-05),
which became effective the first reporting period (including interim periods) beginning after
issuance. ASU 09-05 requires entities to measure the fair value of liabilities using one or more of
several prescribed valuation techniques within the ASU when quoted prices in an active market for
the identical liability are not available. The ASU also clarifies that: entities are not required
to include separate inputs or adjustments to other inputs relating to the existence of restrictions
that prevent the transfer of liabilities when estimating their fair value; and quoted prices in
active markets for identical liabilities at the measurement date and the quoted prices for
identical liabilities traded as assets in active markets when adjustments to the quoted prices of
assets are required are Level 1 fair value measurements. The adoption of this standard did not have
a material impact on the Companys financial statements.
Off Balance Sheet Arrangements
At December 31, 2009 and 2008, we did not have any relationships with unconsolidated entities or
financial partnerships, such as structured finance or special purpose entities, which would have
been established for the purpose of facilitating off-balance sheet arrangements or other
contractually narrow or limited purposes. In addition, we do not engage in trading activities
involving non-exchange traded contracts. As such, we are not materially exposed to any financing,
liquidity, market or credit risk that could arise if we had engaged in such relationships. We do
not have relationships and transactions with persons or entities that derive benefits from their
non-independent relationship with us, or our related parties, except as disclosed herein.
Related Party Transactions
The Company has entered into agreements with a number of entities which are related or controlled
through common directors or shareholders. These entities provide access to an aircraft, the
services of administrative and technical personnel, and office space or facilities in Vancouver,
London and Singapore. The Company is billed on a cost recovery basis in most cases. For the year
ended December 31, 2009 the costs incurred in the normal course of business with respect to the
above arrangements amounted to $3.8 million ($3.0 million for 2008 and $3.3 million for 2007), and
have been measured at their exchange amount and are recorded in general and administrative and
business and technology expense in the statement of operations. As at December 31, 2009 amounts
included in accounts payable and accrued liabilities on the balance sheet under these arrangements
were $0.1 million ($0.1 million at December 31, 2008).
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to normal market risks inherent in the oil and gas business, including equity market
risk, commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We
recognize these risks and manage our operations to minimize our exposures to the extent
practicable.
27
NON-TRADING
Equity Market Risks
We currently have limited production in China, which have not generated sufficient cash from
operations to fund our exploration and development activities. Historically, we have relied on the
equity markets as the primary source of capital to fund our expansion and growth opportunities.
Based on our current plans, we estimate that we will need
approximately $100.0 to $125.0 million to
fund our capital investment programs for 2010.
We can give no assurance that we will be successful in obtaining financing as and when needed.
Factors beyond our control, such as the recent credit crisis, may make it difficult or impossible
for us to obtain financing on favorable terms or at all. Failure to obtain any required financing
on a timely basis may cause us to postpone our development plans, forfeit rights in some or all of
our projects or reduce or terminate some or all of our operations.
Commodity Price Risk
Commodity price risk related to crude oil prices is one of our most significant market risk
exposures. Crude oil prices and quality differentials are influenced by worldwide factors such as
the recent credit crisis, OPEC actions, political events and supply and demand fundamentals. To a
lesser extent we are also exposed to natural gas price movements. Natural gas prices are generally
influenced by oil prices, North American supply and demand and local market conditions. Based on
the Companys 2010 estimated worldwide crude oil production levels, a $1.00/Bbl change in the price
of oil, would increase or decrease net income and cash from operations for 2010 by $0.2 million.
We periodically engage in the use of derivatives to minimize variability in our cash flow from
operations and currently have costless collar contracts put in place as part of our bank loan
facilities The Company entered into a costless collar derivative to minimize variability in its
cash flow from the sale of approximately 50% of the Companys estimated production from its Dagang
field in China over a three-year period starting September 2007. This derivative had a ceiling
price of $84.50 per barrel and a floor price of $55.00 per barrel using WTI as the index traded on
the NYMEX. See Note 12 to the Consolidated Financial Statements.
On December 31, 2009, the Company had no open positions on the derivatives mentioned above as it
had paid off the bank loan and settled all outstanding derivative contracts.
Decreases in oil and natural gas prices would negatively impact our results of operations as a
direct result of a reduction in revenues but may also do so in the ceiling test calculation for the
impairment of our oil and gas properties. On a quarterly basis, we compare the value of our proved
and probable reserves, using estimated future oil and gas prices(1), to the carrying
value of our oil and gas properties. The ceiling test calculation is sensitive to oil and gas
prices and in a period of declining prices could result in a charge to our results of operations as
we experienced in 2001 when we recorded a $14.0 million provision for impairment for Canadian GAAP
and an additional $10.0 million for U.S. GAAP mainly due to a decline in oil and gas prices.
Decreases in oil and gas prices from those used in our ceiling test calculation as at December 31,
2009 as discussed above in Critical Accounting Principles and Estimates Impairment of Proved Oil
and Gas Properties may result in additional impairment provisions of our oil and gas properties.
(1) |
|
The recoverable value of probable reserves is included only for the measurement of the
impairment of the carrying value of oil and gas properties as required under Canadian GAAP but not
for U.S. GAAP. Additionally, there are differences for U.S. GAAP see Critical Accounting
Principles and Estimates for the difference between Canadian and U.S. GAAP in calculating the
impairment provision for oil and gas properties. |
Foreign Currency Rate Risk
Foreign currency risk refers to the risk that the value of a financial commitment, recognized asset
or liability will fluctuate due to changes in foreign currency rates. The main underlying economic
currency of the Companys cash flows is the U.S. dollar. This is because the Companys major
product, crude oil, is priced internationally in U.S. dollars. Accordingly, the Company does not
expect to face foreign exchange risks associated with its production revenues. However, some of the
Companys cash flow stream relating to certain international operations is based on the U.S. dollar
equivalent of cash flows measured in foreign currencies. The majority of the operating costs
incurred in the Chinese operations are paid in Chinese renminbi. The majority of costs incurred in
the administrative offices in Vancouver and Calgary, as well as some business development costs,
are paid in Canadian dollars. In addition, with the recent property acquisition in Alberta (see
Note 18) the Companys Canadian dollar expenditures increased during the last half of 2008 and 2009
when compared to prior periods, along with an increase in cash and debt balances denominated in
Canadian dollars. Disbursement transactions denominated in Chinese renminbi and Canadian dollars
are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date.
Foreign currency gains and losses also come about when monetary assets and liabilities, mainly
short term payables and receivables, denominated in foreign currencies are translated at the end of
each month. The estimated impact of a 10% strengthening or weakening of the Chinese renminbi, and
Canadian dollar, as of December 31,
2009 on net loss and accumulated deficit for the year ended December 31, 2009 is a $4.6 million
increase, and a $4.4 million decrease, respectively. To help reduce the Companys exposure to
foreign currency risk it seeks to maximize the expenditures and contracts denominated in U.S.
dollars and minimize those denominated in other currencies, except for its Canadian activities
where it attempts to hold cash denominated in Canadian dollars in order to manage its currency risk
related to outstanding debt and current liabilities denominated in Canadian dollars.
28
Interest Rate Risk
Interest rate risk refers to the risk that the value of a financial instrument or cash flows
associated with the instrument will fluctuate due to the changes in market interest rates. Interest
rate risk arises from interest-bearing borrowings which have a variable interest rate. During 2009,
the Company had a bank loan facility (as noted above this loan facility was repaid in full in
December 2009) and a convertible note with fluctuating interest rates. The Company estimates that
its net loss and accumulated deficit for the year ended December 31, 2009 would have changed $0.2
million for every 1% change in interest rates as of December 31, 2009. The Company is not currently
actively attempting to mitigate this interest rate risk given the limited amount and term of its
borrowings and the current global interest rate environment.
Credit Risk
The Company is exposed to credit risk with respect to its cash held with financial institutions,
accounts receivable, derivative contracts and advance balances. The Company believes its exposure
to credit risk related to cash held with financial institutions is minimal due to the quality of
the institutions where the cash is held and the nature of the deposit instruments. Most of the
Companys accounts receivable balances relate to oil sales to foreign national petroleum companies
and are exposed to typical industry credit risks. In addition, accounts receivable balances consist
of costs billed to joint venture partners where the Company is the operator and advances to
partners for joint operations where the Company is not the operator. The Company manages its credit
risk by entering into sales contracts only with established entities and reviewing its exposure to
individual entities on a regular basis.
Currently, all of the Companys revenues come from CNPC and 80%-95% of the outstanding receivable
balances as at December 31, 2009 and 2008, respectively, are due from this same customer.
Included in the Companys trade receivable balance are debtors with a carrying amount of nil as of
the year ended December 31, 2009 which are past due at the reporting date for which the Company has
not provided an allowance, as there has not been a significant change in credit quality and the
amounts are still considered recoverable. In addition, the Company recorded an allowance for the
entire outstanding amount of $0.2 million related to an amount owed to the Company by a two
separate joint interest partners in the fourth quarter of 2009. These provisions were recorded in
General and Administrative expense in the accompanying Statement of Operations and Comprehensive
Loss. There were no other changes to the allowance for credit losses account during the three-month
period ended December 31, 2009 and no other losses associated with credit risk were recorded during
this same period.
Liquidity Risk
Liquidity risk is the risk that suitable sources of funding for the Companys business activities
may not be available, which means it may be forced to sell financial assets or non-financial
assets, refinance existing debt, raise new debt or issue equity. The Companys present plans to
generate sufficient resources to assure continuation of its operations and achieve its capital
investment objectives include alliances or other arrangements with entities with the resources to
support the Companys projects as well as project financing, debt financing or the sale of equity
securities. However, the availability of financing, in particular project funding, is dependent in
part on our ability to fund our projects using the credit and equity markets. Despite the Companys
recent successful financing efforts (see Note 20 to the Financial Statements included in Item 8 of
this Form 10-K), the terms and availability of equity and debt capital, have been materially
restricted and financing may not be available when it is required or on commercially acceptable
terms.
TRADING
We do not enter into contracts for trading or speculative purposes. As such, we are not materially
exposed to any financing, liquidity, market or credit risk that could arise if we had entered into
such contracts.
29
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements and Related Information
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Page |
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31 |
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|
Consolidated Financial Statements |
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|
|
|
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32 |
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33 |
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34 |
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35 |
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36 |
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77 |
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77 |
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30
REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
To the Board of Directors and Shareholders of
Ivanhoe Energy Inc.:
We have audited the accompanying consolidated balance sheets of Ivanhoe Energy Inc. and
subsidiaries (the Company) as of December 31, 2009 and 2008, and the related consolidated
statements of operations and comprehensive loss, shareholders equity, and cash flows for each of
the three years in the period ended December 31, 2009. These financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of Ivanhoe Energy Inc. and subsidiaries as of December 31, 2009
and 2008, and the results of their operations and their cash flows for each of the three years in
the period ended December 31, 2009 in conformity with accounting principles generally accepted in
Canada.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the Companys internal control over financial reporting as of December 31,
2009, based on the criteria established in Internal ControlIntegrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March
12, 2010 expressed an unqualified opinion on the Companys internal control over financial
reporting.
(signed) Deloitte & Touche LLP
Independent Registered Chartered Accountants
Calgary, Canada
March 12, 2010
31
IVANHOE ENERGY INC.
Consolidated Balance Sheets
(stated in thousands of U.S. Dollars, except share amounts)
|
|
|
|
|
|
|
|
|
|
|
As at December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
(Note 19) |
|
Assets |
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents (Note 12) |
|
$ |
21,512 |
|
|
$ |
38,477 |
|
Accounts receivable (Note 12) |
|
|
5,021 |
|
|
|
3,802 |
|
Note receivable (Note 12) |
|
|
225 |
|
|
|
|
|
Prepaid and other current assets |
|
|
771 |
|
|
|
637 |
|
Restricted cash |
|
|
2,850 |
|
|
|
850 |
|
Derivative instruments (Note 12) |
|
|
|
|
|
|
1,459 |
|
Assets of discontinued operations (Note 19) |
|
|
|
|
|
|
2,727 |
|
|
|
|
|
|
|
|
|
|
|
30,379 |
|
|
|
47,952 |
|
|
|
|
|
|
|
|
|
|
Oil and gas properties and development costs, net (Note 3) |
|
|
158,392 |
|
|
|
143,974 |
|
Intangible assets HTLTM technology (Note 4) |
|
|
92,153 |
|
|
|
92,153 |
|
Long term assets |
|
|
839 |
|
|
|
152 |
|
Assets of discontinued operations (Note 19) |
|
|
|
|
|
|
62,644 |
|
|
|
|
|
|
|
|
|
|
$ |
281,763 |
|
|
$ |
346,875 |
|
|
|
|
|
|
|
|
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities (Note 12) |
|
$ |
10,779 |
|
|
$ |
9,219 |
|
Income tax payable (Note 14) |
|
|
530 |
|
|
|
650 |
|
Debt current portion (Notes 5 and 12) |
|
|
|
|
|
|
412 |
|
Asset retirement obligations current portion (Note 6) |
|
|
753 |
|
|
|
|
|
Liabilities of discontinued operations current
portion (Note 19) |
|
|
|
|
|
|
6,074 |
|
|
|
|
|
|
|
|
|
|
|
12,062 |
|
|
|
16,355 |
|
|
|
|
|
|
|
|
|
|
Long term debt (Note 5 and 12) |
|
|
36,934 |
|
|
|
37,855 |
|
Asset retirement obligations (Note 6) |
|
|
195 |
|
|
|
1,928 |
|
Long term obligation (Note 7) |
|
|
1,900 |
|
|
|
1,900 |
|
Future income tax liability (Note 14) |
|
|
22,643 |
|
|
|
29,600 |
|
Liabilities of discontinued operations (Note 19) |
|
|
|
|
|
|
1,810 |
|
|
|
|
|
|
|
|
|
|
|
73,734 |
|
|
|
89,448 |
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 7) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders Equity: |
|
|
|
|
|
|
|
|
Share capital, issued 282,558,593 common shares
December 31, 2008 279,381,187 common shares |
|
|
422,322 |
|
|
|
413,857 |
|
Purchase warrants (Notes 8 and Note 18) |
|
|
19,427 |
|
|
|
18,805 |
|
Contributed surplus |
|
|
20,029 |
|
|
|
16,862 |
|
Convertible note (Note 8) |
|
|
2,086 |
|
|
|
2,086 |
|
Accumulated deficit |
|
|
(255,835 |
) |
|
|
(194,183 |
) |
|
|
|
|
|
|
|
|
|
|
208,029 |
|
|
|
257,427 |
|
|
|
|
|
|
|
|
|
|
$ |
281,763 |
|
|
$ |
346,875 |
|
|
|
|
|
|
|
|
(See accompanying Notes to the Consolidated Financial Statements)
Approved by the Board:
|
|
|
(signed) Robert M. Friedland
|
|
(signed) Brian F. Downey |
Director
|
|
Director |
32
IVANHOE ENERGY INC.
Consolidated Statements of Operations and Comprehensive Loss
(stated in thousands of U.S. Dollars, except share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
(Note 19) |
|
|
(Note 19) |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
24,968 |
|
|
$ |
48,370 |
|
|
$ |
31,365 |
|
Gain (loss) on derivative instruments |
|
|
(1,335 |
) |
|
|
1,688 |
|
|
|
(4,993 |
) |
Interest income |
|
|
25 |
|
|
|
612 |
|
|
|
317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,658 |
|
|
|
50,670 |
|
|
|
26,689 |
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
10,191 |
|
|
|
21,515 |
|
|
|
13,000 |
|
General and administrative |
|
|
21,693 |
|
|
|
14,252 |
|
|
|
9,803 |
|
Business and technology development |
|
|
9,501 |
|
|
|
6,453 |
|
|
|
9,625 |
|
Depletion and depreciation |
|
|
19,868 |
|
|
|
25,761 |
|
|
|
20,640 |
|
Foreign exchange loss |
|
|
5,220 |
|
|
|
1,527 |
|
|
|
301 |
|
Interest expense and financing costs |
|
|
856 |
|
|
|
1,309 |
|
|
|
623 |
|
Provision for impairment of intangible asset and development costs
(Notes 3 and 4) |
|
|
1,903 |
|
|
|
15,054 |
|
|
|
|
|
Write off of deferred financing costs (Note 13) |
|
|
|
|
|
|
2,621 |
|
|
|
|
|
Provision for impairment of oil and gas properties (Note 3) |
|
|
|
|
|
|
|
|
|
|
6,130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69,232 |
|
|
|
88,492 |
|
|
|
60,122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes |
|
|
(45,574 |
) |
|
|
(37,822 |
) |
|
|
(33,433 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Provision for) recovery of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(1,757 |
) |
|
|
(654 |
) |
|
|
|
|
Future |
|
|
9,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,843 |
|
|
|
(654 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations |
|
|
(37,731 |
) |
|
|
(38,476 |
) |
|
|
(33,433 |
) |
Net income (loss) from discontinued operations (net of tax
of $29.6 million for 2009, nil for 2008 and 2007) (Notes 13 and 14) |
|
|
(23,921 |
) |
|
|
4,283 |
|
|
|
(5,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss and Comprehensive Loss |
|
$ |
(61,652 |
) |
|
$ |
(34,193 |
) |
|
$ |
(39,207 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per share |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations, basic and diluted |
|
$ |
(0.13 |
) |
|
$ |
(0.15 |
) |
|
$ |
(0.14 |
) |
Net income (loss) from discontinued operations, basic and diluted |
|
|
(0.09 |
) |
|
|
0.02 |
|
|
|
(0.02 |
) |
|
|
|
|
|
|
|
|
|
|
Net loss per share, basic and diluted |
|
$ |
(0.22 |
) |
|
$ |
(0.13 |
) |
|
$ |
(0.16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of Shares (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted |
|
|
279,722 |
|
|
|
258,815 |
|
|
|
242,362 |
|
|
|
|
|
|
|
|
|
|
|
(See accompanying Notes to the Consolidated Financial Statements)
33
IVANHOE ENERGY INC.
Consolidated
Statements of Shareholders Equity
(stated in thousands of U.S. Dollars, except share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share Capital |
|
|
Purchase |
|
|
Contributed |
|
|
Convertible |
|
|
Accumulated |
|
|
|
|
|
|
Shares |
|
|
Amount |
|
|
Warrants |
|
|
Surplus |
|
|
Note |
|
|
Deficit |
|
|
Total |
|
|
|
(thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2006 |
|
|
241,216 |
|
|
|
318,725 |
|
|
|
23,955 |
|
|
|
6,489 |
|
|
|
|
|
|
|
(120,783 |
) |
|
|
228,386 |
|
Net loss and comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39,207 |
) |
|
|
(39,207 |
) |
Shares issued for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of purchase warrants (Note
8) |
|
|
2,000 |
|
|
|
4,313 |
|
|
|
(313 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,000 |
|
Exercise of options (Note 9) |
|
|
1,231 |
|
|
|
431 |
|
|
|
|
|
|
|
(52 |
) |
|
|
|
|
|
|
|
|
|
|
379 |
|
Employee bonuses |
|
|
427 |
|
|
|
793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
793 |
|
Expiry of purchase warrants (Note 8) |
|
|
|
|
|
|
|
|
|
|
(564 |
) |
|
|
564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensation calculated
for stock option grants (Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,936 |
|
|
|
|
|
|
|
|
|
|
|
2,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
|
244,874 |
|
|
|
324,262 |
|
|
|
23,078 |
|
|
|
9,937 |
|
|
|
|
|
|
|
(159,990 |
) |
|
|
197,287 |
|
Net loss and comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34,193 |
) |
|
|
(34,193 |
) |
Shares issued for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Private placements,
net of share issue costs (Note 8) |
|
|
29,334 |
|
|
|
82,451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82,451 |
|
Exercise of convertible debt (Note 8) |
|
|
2,291 |
|
|
|
4,862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,862 |
|
Exercise of options (Note 9) |
|
|
2,666 |
|
|
|
1,792 |
|
|
|
|
|
|
|
(587 |
) |
|
|
|
|
|
|
|
|
|
|
1,205 |
|
Employee bonuses |
|
|
216 |
|
|
|
490 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
490 |
|
Convertible note issued (Note 8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,086 |
|
|
|
|
|
|
|
2,086 |
|
Expiry of purchase warrants (Note 8) |
|
|
|
|
|
|
|
|
|
|
(4,273 |
) |
|
|
4,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensation calculated
for stock option grants (Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,239 |
|
|
|
|
|
|
|
|
|
|
|
3,239 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008 |
|
|
279,381 |
|
|
|
413,857 |
|
|
|
18,805 |
|
|
|
16,862 |
|
|
|
2,086 |
|
|
|
(194,183 |
) |
|
|
257,427 |
|
Net loss and comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(61,652 |
) |
|
|
(61,652 |
) |
Shares issued for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of a business (Note 18) |
|
|
2,683 |
|
|
|
6,874 |
|
|
|
622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,496 |
|
Services |
|
|
81 |
|
|
|
207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
207 |
|
Exercise of options (Note 9) |
|
|
414 |
|
|
|
1,384 |
|
|
|
|
|
|
|
(492 |
) |
|
|
|
|
|
|
|
|
|
|
892 |
|
Compensation calculated
for stock option grants (Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,659 |
|
|
|
|
|
|
|
|
|
|
|
3,659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2009 |
|
|
282,559 |
|
|
$ |
422,322 |
|
|
$ |
19,427 |
|
|
$ |
20,029 |
|
|
$ |
2,086 |
|
|
$ |
(255,835 |
) |
|
$ |
208,029 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(See accompanying Notes to the Consolidated Financial Statements)
34
IVANHOE ENERGY INC.
Consolidated Statements of Cash Flows
(stated in thousands of U.S. Dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(61,652 |
) |
|
$ |
(34,193 |
) |
|
$ |
(39,207 |
) |
Net (income) loss from discontinued operations |
|
|
23,921 |
|
|
|
(4,283 |
) |
|
|
5,774 |
|
Items not requiring use of cash: |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and depreciation |
|
|
19,868 |
|
|
|
25,761 |
|
|
|
20,640 |
|
Provision for impairment |
|
|
1,903 |
|
|
|
15,054 |
|
|
|
6,130 |
|
Stock based compensation (Note 9) |
|
|
3,849 |
|
|
|
3,016 |
|
|
|
3,151 |
|
Unrealized (gain) loss on derivative instruments |
|
|
1,459 |
|
|
|
(6,118 |
) |
|
|
4,659 |
|
Write off of deferred financing costs (Note 13) |
|
|
|
|
|
|
2,621 |
|
|
|
|
|
Unrealized foreign exchange loss |
|
|
5,109 |
|
|
|
1,762 |
|
|
|
|
|
Future income tax recovery |
|
|
(9,600 |
) |
|
|
|
|
|
|
|
|
Provision for uncollectible accounts |
|
|
174 |
|
|
|
625 |
|
|
|
|
|
Other |
|
|
553 |
|
|
|
519 |
|
|
|
381 |
|
Abandonment costs settled (Note 6) |
|
|
(118 |
) |
|
|
|
|
|
|
|
|
Changes in non-cash working capital items |
|
|
(459 |
) |
|
|
6,016 |
|
|
|
(360 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
operating activities from continuing operations |
|
|
(14,993 |
) |
|
|
10,780 |
|
|
|
1,168 |
|
Net cash provided by (used in)
operating activities from discontinued operations |
|
|
2,703 |
|
|
|
6,273 |
|
|
|
4,321 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
|
(12,290 |
) |
|
|
17,053 |
|
|
|
5,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Capital investments |
|
|
(26,373 |
) |
|
|
(21,063 |
) |
|
|
(28,585 |
) |
Acquisition of oil and gas assets |
|
|
|
|
|
|
(22,308 |
) |
|
|
|
|
Recovery of development costs (Note 3) |
|
|
|
|
|
|
|
|
|
|
9,000 |
|
Advance repayments |
|
|
|
|
|
|
200 |
|
|
|
500 |
|
Increase in restricted cash in escrow |
|
|
(2,000 |
) |
|
|
(850 |
) |
|
|
|
|
Other |
|
|
(587 |
) |
|
|
73 |
|
|
|
(47 |
) |
Changes in non-cash working capital items |
|
|
64 |
|
|
|
(1,035 |
) |
|
|
(1,283 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities from continuing operations |
|
|
(28,896 |
) |
|
|
(44,983 |
) |
|
|
(20,415 |
) |
Net cash provided by (used in)
investing activities from discontinued operations |
|
|
35,292 |
|
|
|
(4,338 |
) |
|
|
(1,872 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
|
6,396 |
|
|
|
(49,321 |
) |
|
|
(22,287 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Shares issued on private placements, net of share issue costs |
|
|
|
|
|
|
82,451 |
|
|
|
|
|
Share issue costs on acquisition |
|
|
(26 |
) |
|
|
|
|
|
|
|
|
Proceeds from exercise of options and warrants |
|
|
893 |
|
|
|
1,205 |
|
|
|
4,379 |
|
Proceeds from debt obligations, net of financing costs |
|
|
|
|
|
|
4,790 |
|
|
|
9,356 |
|
Payments of debt obligations |
|
|
(7,416 |
) |
|
|
(15,750 |
) |
|
|
(2,460 |
) |
Payments of deferred financing costs |
|
|
|
|
|
|
(2,621 |
) |
|
|
|
|
Other |
|
|
(100 |
) |
|
|
(50 |
) |
|
|
|
|
Changes in non-cash working capital items |
|
|
(26 |
) |
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
financing activities from continuing operations |
|
|
(6,675 |
) |
|
|
70,051 |
|
|
|
11,275 |
|
Net cash provided by (used in)
financing activities from discontinued operations |
|
|
(5,200 |
) |
|
|
700 |
|
|
|
3,000 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(11,875 |
) |
|
|
70,751 |
|
|
|
14,275 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange gain (loss) on Cash and Cash Equivalents Held in a Foreign Currency |
|
|
16 |
|
|
|
(10,574 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Cash and Cash Equivalents, for the period |
|
|
(17,753 |
) |
|
|
27,909 |
|
|
|
(2,523 |
) |
Cash and cash equivalents, beginning of period |
|
|
39,265 |
|
|
|
11,356 |
|
|
|
13,879 |
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, end of period |
|
$ |
21,512 |
|
|
$ |
39,265 |
|
|
$ |
11,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period continuing operations |
|
$ |
21,512 |
|
|
$ |
38,477 |
|
|
$ |
9,060 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period discontinued
operations |
|
$ |
|
|
|
$ |
788 |
|
|
$ |
2,296 |
|
|
|
|
|
|
|
|
|
|
|
(See accompanying Notes to the Consolidated Financial Statements)
35
IVANHOE ENERGY INC.
Notes to the Consolidated Financial Statements
(all tabular amounts are expressed in thousands of U.S. Dollars, except share and per share amounts)
1. NATURE OF OPERATIONS
Ivanhoe Energy Inc. (the Company or Ivanhoe Energy), a Canadian company, is an independent
international heavy oil development and production company focused on pursuing long-term growth in
its reserves and production. Ivanhoe Energy plans to utilize technologically innovative methods
designed to significantly improve recovery of heavy oil resources, including the anticipated
commercial application of the patented rapid thermal processing process (RTPTM
Process) for heavy oil upgrading (HTLTM Technology or HTLTM) and
enhanced oil recovery (EOR) techniques. In addition, the Company seeks to expand its reserve base
and production through conventional exploration and production (E&P) of oil and gas. Our core
operations are currently carried out in China, the United States, Canada and Ecuador.
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements have been prepared in accordance with Canadian generally
accepted accounting principles (GAAP). The impact of material differences between Canadian and
U.S. GAAP on the consolidated financial statements is disclosed in Note 21.
The preparation of financial statements requires management to make estimates and assumptions that
affect the reported amounts and other disclosures in these consolidated financial statements.
Actual results may differ from those estimates.
In particular, the amounts recorded for depletion and depreciation of the oil and gas properties
and accretion for asset retirement obligations are based on estimates of reserves and future costs.
By their nature, these estimates, and those related to future cash flows used to assess impairment
of oil and gas properties and development costs as well as intangible assets, are subject to
measurement uncertainty and the impact on the financial statements of future periods could be
material.
Basis of Presentation
The Companys financial statements as at and for the year ended December 31, 2009 have been
prepared in accordance with Canadian GAAP applicable to a going concern, which assumes that the
Company will continue in operation for the foreseeable future and will be able to realize its
assets and discharge its liabilities in the normal course of operations. The Company incurred a net
loss of $61.7 million for the year ended December 31, 2009, and as at December 31, 2009, had an
accumulated deficit of $255.8 million and positive working capital of $18.3 million. The Company
currently anticipates incurring substantial expenditures to further its capital development
programs, particularly those related to the development of an oil sands project in Alberta and the
development of a heavy oil field in Ecuador and exploration drilling in China. The Companys cash
flow from operating activities will not be sufficient to both satisfy its current obligations and
meet the requirements of these capital investment programs. The continued existence of the Company
is dependent upon its ability to obtain capital to fund further development and to meet obligations
to preserve its interests in these properties and to meet the obligations associated with other
potential HTL projects. The Company intends to finance the future payments required for its
capital projects from a combination of strategic investors and/or public and private debt and
equity markets, either at a parent company level or at the project level (see Note 20). Public and
private debt and equity markets may not be accessible now or in the foreseeable future and, as
such, the Companys ability to obtain financing cannot be predicted with certainty at this time.
Without access to financing, the Company may not be able to continue as a going concern. These
consolidated financial statements do not include any adjustments to the amounts and classification
of assets and liabilities that may be necessary should the Company be unable to continue as a going
concern, and these adjustments may be material.
Principles of Consolidation
These consolidated financial statements include the accounts of Ivanhoe Energy and its
subsidiaries, all of which are wholly owned.
The Company conducts a portion of its exploration, development and production activities in its oil
and gas business jointly with others. The Companys accounts reflect only its proportionate
interest in the assets and liabilities of these joint ventures.
All inter-company transactions and balances have been eliminated for the purposes of these
consolidated financial statements.
36
Foreign Currency Translation
The functional currency of the Company is the U.S. Dollar since it is the currency in which the
worldwide petroleum business is denominated and the majority of our transactions occur in this
currency. Monetary assets and liabilities denominated in foreign currencies are converted to the
U.S. Dollar at the exchange rate in effect at the balance sheet date and non-monetary assets and
liabilities at the exchange rates in effect at the time of acquisition or issue. Revenues and
expenses are converted to the U.S. Dollar at rates approximating exchange rates in effect at the
time of the transactions. Exchange gains or losses resulting from the period-end translation of
monetary assets and liabilities denominated in foreign currencies are reflected in the results of
operations.
Cash and Cash Equivalents
Cash and cash equivalents include short-term money market instruments with terms to maturity, at
the date of issue, not exceeding 90 days.
Oil and Gas Properties
Full Cost Accounting
The Company follows the full cost method of accounting for oil and gas operations whereby all
exploration and development expenditures are capitalized on a country-by-country (cost center)
basis. Such expenditures include lease and royalty interest acquisition costs, geological and
geophysical expenses, carrying charges for unproved properties, costs of drilling both successful
and unsuccessful wells, gathering and production facilities and equipment, financing,
administrative costs related to capital projects and asset retirement costs. Proceeds from sales of
oil and gas properties are recorded as reductions in the carrying value of proved oil and gas
properties, unless such amounts would significantly alter the rate of depreciation and depletion,
whereupon gains or losses would be recognized in income. Maintenance and repair costs are expensed
as incurred, while improvements and major renovations are capitalized. The amount of interest costs
capitalized for qualifying assets is intended to be that portion of the interest cost incurred
during the assets acquisition periods that theoretically could have been avoided if expenditures
for the assets had not been made. Unusually significant investments in unproved properties and
major development projects that are not being currently depreciated, depleted, or amortized and on
which exploration or development activities are in progress are assets qualifying for
capitalization of interest cost. Similarly, in a cost center with no production, significant
properties and projects on which exploration or development activities are in progress are assets
qualifying for capitalization of interest costs.
Depletion
The Companys share of costs for proved oil and gas properties accumulated within each cost center,
including a provision for future development costs, are depleted using the unit-of-production
method over the life of the Companys share of estimated remaining proved oil and gas reserves net
of royalties. Costs incurred on an unproved oil and gas property are excluded from the depletion
rate calculation until it is determined whether proved reserves are attributable to an unproved oil
and gas property or upon determination that an unproved oil and gas property has been impaired.
Natural gas reserves and production are converted to a barrels of oil equivalent using a generally
recognized industry standard in which six thousand cubic feet of gas is equal to one barrel of oil.
The conversion ratio is based on an energy equivalency conversion method primarily applicable at
the burner tip and does not represent a value equivalency at the wellhead.
Impairment of Proved Oil and Gas Properties
In the recognition of an impairment, the carrying value of a cost center is compared to the
undiscounted future net cash flows of that cost centers proved reserves using estimates of future
oil and gas prices and costs plus the cost of unproved properties that have been excluded from the
depletion calculation. If the carrying value is greater than the value of the undiscounted future
net cash flows of the proved reserves plus the cost of unproved properties excluded from the
depletion calculation, then the amount of the cost centers potential impairment must be measured.
A cost centers impairment loss is measured by the amount its carrying value exceeds the discounted
future net cash flows of its proved and probable reserves using estimates of future oil and gas
prices and costs plus the cost of unproved properties that have been excluded from the depletion
calculation and which contain no probable reserves. The net cash flows of a cost centers proved
and probable reserves are discounted using a risk-free interest rate adjusted for political and
economic risk on a country-by-country basis. The amount of the impairment loss is recognized as a
charge to the results of operations and a reduction in the net carrying amount of a cost centers
oil and gas properties. Unproved properties and major development projects are assessed on a
quarterly basis for possible impairments or reductions in value. If a reduction in value has
occurred, the impairment is transferred to the carrying value of proved oil and gas properties.
37
Asset Retirement Costs
The Company measures the expected costs required to abandon its producing U.S. oil and gas
properties and HTLTM facilities at a fair value which approximates the cost a third
party would incur in performing the tasks necessary to abandon the field and restore the site.
The fair value is recognized in the financial statements at the present value of expected future
cash outflows to satisfy the obligation as a liability with a corresponding increase in the related
asset. Subsequent to the initial measurement, the effect of the passage of time on the liability
for the asset retirement obligation (accretion expense) is recognized in the results of operations
and included with interest expense. Actual costs incurred upon settlement of the obligation are
charged against the obligation to the extent of the liability recorded. Any difference between the
actual costs incurred upon settlement of the obligation and the recorded liability is recognized as
a gain or loss in the carrying balance of the related capital asset in the period in which the
settlement occurs.
Asset retirement costs associated with the producing U.S. oil and gas properties are being depleted
using the unit of production method based on estimated proved reserves and are included with
depletion and depreciation expense. Asset retirement costs associated with the CDF are depreciated
over the life of the CDF which commenced when the facility was placed into service.
The Company does not make such a provision for its oil and gas operations in China as there is no
obligation on the Companys part to contribute to the future cost to abandon the field and restore
the site.
Development Costs
The Company incurs various costs in the pursuit of HTLTM and GTL projects throughout the
world. Such costs incurred prior to signing a memorandum of understanding (MOU), or similar
agreements, are considered to be business and technology development and are expensed as incurred.
Upon executing a MOU to determine the technical and commercial feasibility of a project, including
studies for the marketability for the projects products, the Company assesses that the feasibility
and related costs incurred have potential future value, are probable of leading to a definitive
agreement for the exploitation of proved reserves and should be capitalized. If no definitive
agreement is reached, then the projects capitalized costs, which are deemed to have no future
value, are written down in the results of operations with a corresponding reduction in the carrying
balance of the HTLTM and GTL development costs.
Additionally, the Company incurs costs to develop, enhance and identify improvements in the
application of the HTLTM and GTL technologies it owns or licenses. The cost of equipment
and facilities acquired, such as the HTLTM commercial demonstration facility (CDF), or
construction costs for such purposes such as with the HTLTM Feedstock Test Facility
(FTF), are capitalized as development costs and amortized over the expected economic life of the
equipment or facilities, commencing with the start up of commercial operations for which the
equipment or facilities are intended. The FTF will be used to develop and identify improvements in
the application of the HTLTM Technology by processing and testing heavy crude feedstock
of prospective partners until such time as the FTF is sold, dismantled or redeployed.
The Company reviews the recoverability of such capitalized development costs annually, or
as changes in circumstances indicate the development costs might be impaired, through an evaluation
of the expected future discounted cash flows from the associated projects. If the carrying value of
such capitalized development costs exceeds the expected future discounted cash flows, the excess
is written down in the results of operations with a corresponding reduction in the
carrying balance of the HTLTM and GTL development costs.
Costs incurred in the operation of equipment and facilities used to develop or enhance
HTLTM and GTL technologies prior to commencing commercial operations are business and
technology development expenses and are charged to the results of operations in the period
incurred.
Furniture and Equipment
Furniture and fixtures are stated at cost. Depreciation is provided on a straight-line basis over
the estimated useful life of the respective assets, at rates ranging from three to five years.
Intangible Assets
Intangible assets are initially recognized and measured at cost. Intangible assets with finite
lives are amortized over their estimated useful lives. Intangible assets are reviewed at least
annually for impairment, or when events or changes in circumstances indicate that the carrying
value of an intangible asset may not be recoverable. If the carrying value of an intangible asset
exceeds its fair value or expected future discounted cash flows, the excess is written down to the
results of operations with a corresponding reduction in the carrying value of the intangible asset.
38
The Company owns intangible assets in the form of an exclusive, irrevocable license to employ the
RTPTM Process for all applications other than biomass and a non-exclusive master license
entitling us to use Syntroleum Corporations (Syntroleum) proprietary technology (GTL
Technology or GTL) to convert natural gas into ultra clean transportation fuels and other
synthetic petroleum products. The Company will assign the carrying value of the HTLTM
Technology to the number of facilities it expects to develop that will use the HTLTM
Technology. The amount of the carrying value of the technologies assigned to each
HTLTM facility will be amortized to earnings on a basis related to the
operations of the HTLTM from the date on which the facility is placed into service. The
carrying value of the HTLTM Technology and the Syntroleum GTL master license are
evaluated for impairment annually, or as changes in circumstances indicate the intangible assets
might be impaired, based on an assessment of their fair market values. The carrying value of the
Syntroleum GTL master license was impaired In 2008, the carrying value for Syntroleum GTL master
license of $10.0 million (see Note 4), was reduced to nil with a corresponding reduction in our
results of operations.
Oil and Gas Revenue
Sales of crude oil and natural gas are recognized in the period in which the product is delivered
to the customer. Oil and gas revenue represents the Companys share and is recorded net of royalty
payments to governments and other mineral interest owners.
In China, the Company conducts operations jointly with the government of China in accordance with a
production-sharing contract. Under this contract, the Company pays both its share and the
governments share of operating and capital costs. The Company recovers the governments share of
these costs from future revenues or production over the life of the production-sharing contract.
The governments share of operating costs is recorded in operating expense when incurred and
capital costs are recorded in oil and gas properties when incurred and expensed to depletion and
depreciation in the year recovered.
Earnings or Loss Per Share
Basic earnings or loss per share is calculated by dividing the net earnings or loss to common
shareholders by the weighted average number of common shares outstanding during the period. Diluted
earnings per share reflects the potential dilution that would occur if stock options, convertible
debentures and purchase warrants were exercised. The if converted method is used in calculating
diluted earnings per share for the convertible debentures. The treasury stock method is used in
calculating diluted earnings per share, which assumes that any proceeds received from the exercise
of in-the-money stock options and purchase warrants would be used to purchase common shares at the
average market price for the period. The Company does not report diluted loss per share amounts, as
the effect would be anti-dilutive to the common shareholders.
Income Taxes
The Company follows the liability method of accounting for future income taxes. Under the liability
method, future income taxes are recognized to reflect the expected future tax consequences arising
from tax loss carry-forwards and temporary differences between the carrying value and the tax basis
of the Companys assets and liabilities. A valuation allowance is recorded against any future
income tax asset if the Company is not more likely than not to be able to utilize the tax
deductions associated with the future income tax asset. The effect of a change in income tax rates
on future tax liabilities and assets is recognized in income in the period in which the change
occurs, provided that the income tax rates are substantively enacted.
Stock Based Compensation
The Company has an Employees and Directors Equity Incentive Plan consisting of a stock option
plan, a bonus plan and an employee share purchase plan. Compensation costs are recognized in the
results of operations over the periods in which the stock options vest for all stock options
granted based on the fair value of the stock options at the date granted. The Company uses the
Black-Scholes option-pricing model for determining the fair value of stock options issued at grant
date. As of the date stock options are granted, the Company estimates a percentage of stock options
issued to employees and directors it expects to be forfeited. Compensation costs are not recognized
for stock option awards forfeited due to a failure to satisfy the service requirement for vesting.
Compensation costs are adjusted for the actual amount of forfeitures in the period in which the
stock options expire.
Upon the exercise of stock options, share capital is credited for the fair value of the stock
options at the date granted with a charge to contributed surplus. Consideration paid upon the
exercise of the stock options is also credited to share capital.
Compensation expenses are recognized when shares are issued from the stock bonus plan. The employee
share purchase portion of the plan has not yet been activated.
Financial Assets and Liabilities
Financial assets
The Companys financial assets are comprised of cash and cash equivalents, accounts receivable,
advances, restricted cash and derivative instruments. These financial assets are classified as
loans and receivables or held for trading financial assets as appropriate. The classification of
financial assets is determined at initial recognition. When financial assets are recognized
initially, they are measured at fair value, normally being the transaction price. Transaction costs
for all financial assets are expensed as incurred.
39
Financial assets are classified as held for trading if they are acquired for sale in the short
term. Cash and cash equivalents, restricted cash and derivatives in a positive fair value position
are also classified as held for trading. Held for trading assets are carried on the balance sheet
at fair value with gains or losses recognized in the consolidated statement of operations. The
estimated fair value of held for trading assets is determined by reference to quoted market prices
and, if not available, on estimates from third-party brokers or dealers.
Loans and receivables are non-derivative financial assets with fixed or determinable payments.
Accounts receivable, note receivable and advances have been classified as loans and receivables.
Such assets are carried at amortized cost, as the time value of money is not significant. Gains and
losses are recognized in income when the loans and receivables are derecognized or impaired.
The Company assesses at each balance sheet date whether a financial asset carried at cost is
impaired. If there is objective evidence that an impairment loss exists, the amount of the loss is
measured as the difference between the carrying amount of the asset and its fair value. The
carrying amount of the asset is reduced with the amount of the loss recognized in earnings.
Financial liabilities
Financial liabilities are classified as held for trading financial liabilities or other financial
liabilities as appropriate. Financial liabilities include accounts payable and accrued liabilities,
derivative financial instruments, credit facilities, long term obligation and long term debt. The
classification of financial liabilities is determined at initial recognition.
Held for trading financial liabilities represent financial contracts that were acquired for sale in
the short term or derivatives that are in a negative fair market value position.
The estimated fair value of held for trading liabilities is determined by reference to quoted
market prices and, if not available, on estimates from third-party brokers or dealers.
Other financial liabilities are non-derivative financial liabilities with fixed or determinable
payments.
Short term other financial liabilities are carried at cost as the time value of money is not
significant. Accounts payable and accrued liabilities and credit facilities have been classified as
short term other financial liabilities. Gains and losses are recognized in income when the short
term other financial liability is derecognized. Transaction costs for short term other financial
liabilities are expensed as incurred.
Long term other financial liabilities are measured at amortized cost. Long-term debt and long term
obligation have been classified as long term other financial liabilities. Transaction costs for
long term other financial liabilities are deducted from the related liability and accounted for
using the effective interest rate method.
Derivative Financial Instruments
The Company may periodically use different types of derivative instruments to manage its exposure
to price volatility, thus mitigating fluctuations in commodity-related cash flows. The Company has
used costless collar derivative instruments to manage this exposure.
Derivative financial instruments are classified as held for trading and recorded on the
consolidated balance sheet at fair value, either as an asset or as a liability under current assets
or current liabilities, respectively. Changes in the fair value of these financial instruments, or
unrealized gains and losses, are recognized in the statement of operations as revenues in the
period in which they occur.
Gains and losses related to the settlement of derivative contracts, or realized gains and losses,
are recognized as revenues in the statement of operations.
Contracts to buy or sell non-financial items that are not in accordance with the Companys expected
purchase, sale or usage requirements are accounted for as derivative financial instruments.
2009 Accounting Changes
In February 2008, the Canadian Institute of Chartered Accountants (CICA) issued Handbook Section
3064, Goodwill and Intangible assets, (S.3064) replacing Handbook Section 3062, Goodwill and
Other Intangible Assets (S.3062) and Handbook Section 3450, Research and Development Costs.
S.3064 is applicable to financial statements relating to fiscal years beginning on or after October
1, 2008. The new section 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 S.3062.
40
Also in February 2008, the CICA amended portions of Handbook Section 1000, Financial Statement
Concepts, which the CICA concluded permitted deferral of costs that did not meet the definition of
an asset. The amendments apply to annual and interim financial statements relating to fiscal years
beginning on or after October 1, 2008. Upon adoption of S.3064 and the amendments to Section 1000
on January 1, 2009, capitalized amounts that no longer meet the definition of an asset are expensed
retrospectively.
The Company adopted the new standards on January 1, 2009 with no transitional adjustment to the
consolidated financial statements as a result of having adopted these standards.
In January 2009, the Emerging Issues Committee of the CICA (EIC) issued Emerging Issues Committee
abstract 173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities which
provides guidance on the implications of credit risk in determining the fair value of an entitys
financial assets and financial liabilities. The guidance clarifies that an entitys own credit risk
and the credit risk of counterparties should be taken into account in determining the fair value of
financial assets and financial liabilities, including derivative instruments, for presentation and
disclosure purposes. The conclusions of the EIC were effective from the date of issuance of the
abstract and did not have any material impact on the Companys consolidated balance sheet or
statement of operations, comprehensive loss and accumulated deficit. However, the Companys fair
value disclosures in Note 12 incorporated this new guidance.
In June 2009, the Accounting Standards Board of the CICA (AcSB) issued Accounting Revisions
Release No. 54, Improving Disclosures About Financial Instruments Background Information and
Basis for Conclusions (Amendments to Financial Instruments Disclosures, Section 3862), which
amended certain disclosure requirements related to financial instrument disclosure in response to
disclosure amendments issued by the International Accounting Standards Board. This is consistent
with the AcSBs strategy to adopt IFRS and to ensure the current existing disclosure requirements
for financial instruments are converged to the extent possible. The new disclosure standards
require disclosure of fair values based on a fair value hierarchy as well as enhanced discussion
and quantitative disclosure related to liquidity risk. The amended disclosure requirements are
effective for annual financial statements relating to fiscal years ending after September 30, 2009
and as such the Company has included the required disclosure in Note 12 of these financial
statements.
Impact of New and Pending Canadian GAAP Accounting Standards
In January 2009, the AcSB issued Handbook Section 1582, Business Combinations (S.1582)
replacing Handbook Section 1581, Business Combinations. The AcSB revised accounting standards in
regards to business combinations with the intent of harmonizing those standards with IFRS. The
revised standards require the acquiring entity in a business combination to recognize all (and
only) the assets acquired and liabilities assumed in the transaction, establish the acquisition
date fair value as the measurement objective for all assets acquired and liabilities assumed; and
require the acquirer to disclose to investors and other users all of the information they need to
evaluate and understand the nature and financial effect of the business combination. These
standards shall be applied prospectively to business combinations with an acquisition date after
the beginning of the first annual reporting period beginning after January 1, 2011. The Company
adopted this standard early on January 1, 2009 with no transitional adjustment to the consolidated
financial statements as a result of adopting this standard. However, the Company did apply the
provisions of this standard to a business combination that occurred in the fourth quarter of 2009
(see Note 18).
Also in January 2009, the AcSB issued Handbook Section 1601, Consolidated Financial Statements
(S.1601) and Handbook Section 1602, Non-Controlling Interests (S.1602), which replace
Handbook Section 1600, Consolidated Financial Statements (S.1600). S.1601 and S.1602 require
all entities to report non-controlling (minority) interests as equity in consolidated financial
statements. The standards eliminate the diversity that currently exists in accounting for
transactions between an entity and non-controlling interests by requiring they be treated as equity
transactions. These standards shall be applied retrospectively effective for interim and annual
financial statements relating to fiscal years beginning on or after January 1, 2011. The Company
adopted these standards early on January 1, 2009 with no transitional adjustment to the
consolidated financial statements as a result of adopting these standards.
41
3. OIL AND GAS PROPERTIES AND DEVELOPMENT COSTS
In July 2009, the Company sold its U.S. operating segment (see Note 19); consequently, the segment
information has been revised to reflect this sale. Capital assets categorized by segment are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2009 |
|
|
|
Oil and Gas |
|
|
|
|
|
|
Business and |
|
|
|
|
|
|
Integrated |
|
|
Conventional |
|
|
|
|
|
|
Technology |
|
|
|
|
|
|
Canada |
|
|
Ecuador |
|
|
Asia |
|
|
Corporate |
|
|
Development |
|
|
Total |
|
Oil and Gas Properties: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
|
|
|
$ |
|
|
|
$ |
148,110 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
148,110 |
|
Unproved |
|
|
94,431 |
|
|
|
6,755 |
|
|
|
14,411 |
|
|
|
|
|
|
|
|
|
|
|
115,597 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94,431 |
|
|
|
6,755 |
|
|
|
162,521 |
|
|
|
|
|
|
|
|
|
|
|
263,707 |
|
Accumulated depletion |
|
|
|
|
|
|
|
|
|
|
(99,744 |
) |
|
|
|
|
|
|
|
|
|
|
(99,744 |
) |
Accumulated provision for impairment |
|
|
|
|
|
|
|
|
|
|
(16,550 |
) |
|
|
|
|
|
|
|
|
|
|
(16,550 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94,431 |
|
|
|
6,755 |
|
|
|
46,227 |
|
|
|
|
|
|
|
|
|
|
|
147,413 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Feasibility studies and other
deferred costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Iraq and Libya HTLTM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
834 |
|
|
|
834 |
|
Egypt GTL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,054 |
|
|
|
5,054 |
|
Accumulated provision for impairment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,888 |
) |
|
|
(5,888 |
) |
Feedstock test facility |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,868 |
|
|
|
10,868 |
|
Accumulated depreciation and
impairment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(393 |
) |
|
|
(393 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,475 |
|
|
|
10,475 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Furniture and equipment |
|
|
24 |
|
|
|
169 |
|
|
|
135 |
|
|
|
968 |
|
|
|
22 |
|
|
|
1,318 |
|
Accumulated depreciation |
|
|
(8 |
) |
|
|
(53 |
) |
|
|
(92 |
) |
|
|
(650 |
) |
|
|
(11 |
) |
|
|
(814 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16 |
|
|
|
116 |
|
|
|
43 |
|
|
|
318 |
|
|
|
11 |
|
|
|
504 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
94,447 |
|
|
$ |
6,871 |
|
|
$ |
46,270 |
|
|
$ |
318 |
|
|
$ |
10,486 |
|
|
$ |
158,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2008 |
|
|
|
Oil and Gas |
|
|
|
|
|
|
Business and |
|
|
|
|
|
|
Integrated |
|
|
Conventional |
|
|
|
|
|
|
Technology |
|
|
|
|
|
|
Canada |
|
|
Ecuador |
|
|
Asia |
|
|
Corporate |
|
|
Development |
|
|
Total |
|
Oil and Gas Properties: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
|
|
|
$ |
|
|
|
$ |
141,089 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
141,089 |
|
Unproved |
|
|
81,090 |
|
|
|
1,454 |
|
|
|
5,233 |
|
|
|
|
|
|
|
|
|
|
|
87,777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81,090 |
|
|
|
1,454 |
|
|
|
146,322 |
|
|
|
|
|
|
|
|
|
|
|
228,866 |
|
Accumulated depletion |
|
|
|
|
|
|
|
|
|
|
(81,717 |
) |
|
|
|
|
|
|
|
|
|
|
(81,717 |
) |
Accumulated provision for impairment |
|
|
|
|
|
|
|
|
|
|
(16,550 |
) |
|
|
|
|
|
|
|
|
|
|
(16,550 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81,090 |
|
|
|
1,454 |
|
|
|
48,055 |
|
|
|
|
|
|
|
|
|
|
|
130,599 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Feasibility studies and other
deferred costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Iraq and Libya HTLTM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
801 |
|
|
|
801 |
|
Egypt GTL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,054 |
|
|
|
5,054 |
|
Accumulated provision for impairment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,054 |
) |
|
|
(5,054 |
) |
Feedstock test facility |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,770 |
|
|
|
8,770 |
|
Commercial demonstration facility |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,036 |
|
|
|
11,036 |
|
Accumulated depreciation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,713 |
) |
|
|
(7,713 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,894 |
|
|
|
12,894 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Furniture and equipment |
|
|
20 |
|
|
|
90 |
|
|
|
120 |
|
|
|
13 |
|
|
|
406 |
|
|
|
649 |
|
Accumulated depreciation |
|
|
(6 |
) |
|
|
|
|
|
|
(79 |
) |
|
|
(6 |
) |
|
|
(77 |
) |
|
|
(168 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14 |
|
|
|
90 |
|
|
|
41 |
|
|
|
7 |
|
|
|
329 |
|
|
|
481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
81,104 |
|
|
$ |
1,544 |
|
|
$ |
48,096 |
|
|
$ |
7 |
|
|
$ |
13,223 |
|
|
$ |
143,974 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
Oil and Gas Properties
Costs as at December 31, 2009 of $115.6 million ($87.8 million at December 31, 2008), related to
unproved oil and gas properties have been excluded from costs subject to depletion and
depreciation. Included in that same depletion calculation were $3.3 million for future development
costs associated with proven undeveloped reserves as at December 31, 2009 ($3.3 million at December
31, 2008). The oil and gas properties in Canada, Ecuador and Mongolia have not had any oil and gas
production and have been excluded from the ceiling test as undeveloped land.
For the year ended December 31, 2009, $3.9 million ($1.6 million in 2008 and $0.5 million in 2007)
in general and administrative
expenses related directly to oil and gas acquisition, exploration and development activities were
capitalized.
The Company performed a ceiling test calculation at December 31, 2009, 2008 and 2007 to assess the
recoverable value of its Oil and Gas Properties. Based on this calculation, the present value of
future net revenue from the Companys proved plus probable reserves exceeded the carrying value of
the Companys Oil and Gas Properties in 2009 and 2008, resulting in no impairment in each of those
years. However, the Company performed this same calculation at December 31, 2007 which resulted in
an impairment of $6.1 million.
West Texas Intermediate prices used in calculating the expected future cash flows were based on the
following benchmark prices adjusted for gravity, transportation and other factors as required by
sales agreements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(per Bbl) |
|
|
(per Bbl) |
|
|
(per Bbl) |
|
2008 |
|
NA |
|
|
NA |
|
|
$ |
92.00 |
|
2009 |
|
NA |
| |
$ |
57.50 |
|
|
$ |
88.00 |
|
2010 |
|
$ |
80.00 |
|
|
$ |
68.00 |
|
|
$ |
84.00 |
|
2011 |
|
$ |
83.00 |
|
|
$ |
74.00 |
|
|
$ |
82.00 |
|
2012 |
|
$ |
86.00 |
|
|
$ |
85.00 |
|
|
$ |
82.00 |
|
2013 |
|
$ |
89.00 |
|
|
$ |
92.01 |
|
|
$ |
82.00 |
|
2014 |
|
$ |
92.00 |
|
|
$ |
93.85 |
|
|
$ |
82.00 |
|
2015 |
|
$ |
93.84 |
|
|
$ |
95.73 |
|
|
$ |
82.00 |
|
2016 |
|
$ |
95.72 |
|
|
$ |
97.64 |
|
|
$ |
82.02 |
|
2017 |
|
$ |
97.64 |
|
|
$ |
99.59 |
|
|
$ |
83.66 |
|
2018 |
|
$ |
99.59 |
|
|
|
101.59 |
|
|
2% per year |
2019 |
|
$ |
101.58 |
|
|
2% per year |
|
2% per year |
Thereafter |
|
2% per year |
|
2% per year |
|
2% per year |
Development Costs
Feasibility Studies and Other Deferred Costs
The Company is exploring an opportunity in Egypt to monetize stranded gas reserves through the
application of the GTL Technology. Because the Company has been pursuing this project for an
extended period of time and has not been able to obtain a definitive agreement or appropriate
project financing, the Company has impaired the carrying value of the costs associated with GTL as
at December 31, 2008. In 2008, the carrying value for GTL development costs of $5.1 million and
intangible GTL assets of $10.0 million (see Note 4), were reduced to nil with a corresponding
reduction in our results of operations. This impairment does not affect the Companys intention to
continue to pursue this project.
For the year ended December 31, 2009, the Company impaired the carrying value of its deferred costs
associated with its pursuit of HTLTM projects in Iraq and Libya. Impairments (nil in
2008 and 2007) related to its HTLTM Development Costs. These impairments do not affect
the Companys intention to continue to pursue these projects.
HTLTM Facilities
During the third quarter of 2009, the Company determined that the completion and subsequent
improvements to its technology showpiece the FTF in San Antonio diminished the business purpose of
the CDF to nil. Consequently, the abandonment process commenced and the Company has impaired the
net carrying value of the costs associated with the CDF as at September 30, 2009. The carrying
value, net of depreciation, for the CDF, of $0.9 million, was reduced to nil with a corresponding
reduction in our results of operations. Also, see Note 6 below.
As further described above the FTF was entering into the commissioning phase at December 31, 2008
and, as such, was not depreciated, nor impaired for the year ended December 31, 2008. The FTF was
placed into service in the first quarter of 2009.
43
4. INTANGIBLE ASSETS TECHNOLOGY
The Companys intangible assets consist of the following:
HTLTM Technology
In the 2005 merger with the Ensyn Group, Inc. (Ensyn), the Company acquired an exclusive,
irrevocable license to deploy, worldwide, the RTPTM Process for petroleum applications
as well as the exclusive right to deploy the RTPTM Process in all applications other
than biomass. The Companys carrying value of the HTLTM Technology as at December 31,
2009 and 2008 was $92.2 million. Since the company acquired the technology, it has continued to
expand its patent coverage to protect innovations to the HTLTM Technology as they are
developed and to significantly extend the Companys portfolio of HTLTM intellectual
property. The Company is the assignee of three granted patents and currently has five patent
applications pending in the U.S. The Company also has multiple patents pending in numerous other
countries. This intangible asset was not amortized and its carrying value was not impaired for the
years ended December 31, 2009, 2008 and 2007.
Syntroleum GTL Master License
The Company owns a master license from Syntroleum permitting the Company to use Syntroleums
proprietary GTL process in an unlimited number of projects around the world. The Companys master
license expires on the later of April 2015 or five years from the effective date of the last site
license issued to the Company by Syntroleum. Both companies have the right to pursue GTL projects
independently, but the Company would be required to pay the normal license fees and royalties in
such projects. The Companys carrying value of the Syntroleum GTL master license as at December 31,
2009 and 2008 was nil.
Recovery of capitalized costs related to potential HTLTM and GTL projects is dependent
upon finalizing definitive agreements for, and successful completion of, the various projects. As
described in Note 3 to these financial statements, the GTL intangible asset balance of $10 million
was impaired and charged to the results of operations with a corresponding reduction in intangible
GTL in 2008.
5. LONG TERM DEBT
Notes payable consisted of the following as at:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
Variable rate bank note (4.00% at December 31, 2009) paid in
full December 2009 |
|
$ |
|
|
|
$ |
7,000 |
|
Non-interest bearing promissory note, final payment February 2009 |
|
|
|
|
|
|
416 |
|
Convertible note (4.25% at December 31, 2009) due July 2011 |
|
|
38,005 |
|
|
|
32,787 |
|
|
|
|
|
|
|
|
|
|
|
38,005 |
|
|
|
40,203 |
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
|
Unamortized discount |
|
|
(1,071 |
) |
|
|
(4 |
) |
Unamortized deferred financing costs |
|
|
|
|
|
|
(1,932 |
) |
Current maturities |
|
|
|
|
|
|
(412 |
) |
|
|
|
|
|
|
|
|
|
|
(1,071 |
) |
|
|
(2,348 |
) |
|
|
|
|
|
|
|
|
|
$ |
36,934 |
|
|
$ |
37,855 |
|
|
|
|
|
|
|
|
Bank Loan
In September 2007 the Company obtained a $30 million Revolving/Term Credit Facility with an initial
borrowing base of $10 million. The facility is a revolving facility with a three-year term with
interest payable only during the term. In December 2009 the remaining balance in the amount of $7.0
million was repaid in advance of its expiry date and consequently as of December 31, 2009 all
security was in the process of being released back to the Company.
Promissory Note
In connection with the acquisition in July 2008 described in Note 18, the Company issued a
promissory note (the 2008 Note) to Talisman Energy Canada (Talisman) in the principal amount of
Cdn.$12.5 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated
daily and not compounded. The 2008 Note matured and the principal and related interest was paid on
December 31, 2008.
Convertible Note
Also in connection with the acquisition in July 2008 described in Note 18, the Company issued a
convertible promissory note (the Convertible Note) to Talisman in the principal amount of
Cdn.$40.0 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated
daily and not compounded, payable semi-annually and maturing in July 2011. The Convertible Note is
convertible (as to the outstanding principal amount), at Talismans option, into a maximum of
12,779,552 common shares of the Company at Cdn.$3.13 per common share. There were no conversions of
this note as of December 31, 2009.
44
The Convertible Note is assessed based on the substance of the contractual arrangement in
determining whether it exhibits the fundamental characteristics of a financial liability or equity.
Management has concluded that this debt instrument mainly exhibits characteristics that are
liability in nature, however, the embedded conversion feature is equity in nature and is required
to be bifurcated and disclosed separately within shareholders equity. Management has applied a
residual basis method and has valued the liability component first and assigned the residual value
to the equity component. Management has fair valued the liability component by discounting the
expected interest and principal payments using an interest rate of 8.75% being managements
estimate of the expected interest payments for a similar instrument without the conversion feature.
The liability component was valued at Cdn.$37.9 million and the remaining balance of Cdn.$2.1
million was allocated to the equity component. The liability component will be accreted over the
three-year maturity period to bring the liability back to Cdn.$40.0 million using the effective
interest method.
The Companys obligations under the Convertible Note and the Contingent Payment (see Note 18) are
secured by a first fixed charge and security interest in favor of Talisman against the acquired
Talisman leases and the related assets acquired by the Company pursuant to the Talisman lease
acquisition. The Talisman security interest also does not extend to any assets of any subsidiary of
Ivanhoe Energy.
The scheduled maturities of the Companys long term debt, excluding unamortized discount and
unamortized deferred financing costs, as at December 31, 2008 were as follows:
|
|
|
|
|
2010 |
|
$ |
|
|
2011 |
|
|
38,005 |
|
|
|
|
|
|
|
$ |
38,005 |
|
|
|
|
|
Interest expense included in Interest Expense and Financing Costs in the statement of
operations was $0.8 million for the year ended December 31, 2009 ($1.2 million for 2008 and $0.6
million for 2007). For the year ended December 31, 2009, $2.2 million ($1.7 million in 2008 and nil
in 2007) in interest was capitalized to oil and gas properties and development costs in the balance
sheet.
6. ASSET RETIREMENT OBLIGATIONS
The Company provides for the expected costs required to abandon the CDF and FTF. The undiscounted
amount of expected future cash flows required to settle the Companys asset retirement obligations
for these assets as at December 31, 2009 was estimated at $0.9 million. These payments are expected
to be made over the next 20 years; with the majority of the payments to be made within one year. To
calculate the present value of these obligations, the Company used an inflation rate of 1% and 3%
and the expected future cash flows have been discounted using a credit-adjusted risk-free rate of
5.3% and 5.5% for the respective periods shown below. As noted in Note 3 above, the abandonment
process for the CDF commenced in the third quarter of 2009. Management determined that a more cost
effective way to handle this dismantlement would be to redeploy Company staff from its discontinued
operations as opposed to utilizing external service providers. As a result, there was an adjustment
to the estimated future cash flows expected to be needed to abandon this asset. A reconciliation of
the beginning and ending aggregate carrying amount of the obligation associated with the retirement
of the CDF and the FTF for the two-year period ended December 31, 2009 is as follows:
|
|
|
|
|
|
|
|
|
|
|
As at |
|
|
As at |
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
Carrying balance, beginning of year |
|
$ |
1,928 |
|
|
$ |
739 |
|
Liabilities incurred |
|
|
185 |
|
|
|
|
|
Liabilities settled |
|
|
(118 |
) |
|
|
|
|
Accretion expense |
|
|
79 |
|
|
|
76 |
|
Revisions in estimated cash flows |
|
|
(1,126 |
) |
|
|
1,113 |
|
|
|
|
|
|
|
|
Carrying balance, end of period |
|
|
948 |
|
|
|
1,928 |
|
|
|
|
|
|
|
|
|
|
Less: current portion |
|
|
753 |
|
|
|
|
|
|
|
|
|
|
|
|
Carrying balance, end of year |
|
$ |
195 |
|
|
$ |
1,928 |
|
|
|
|
|
|
|
|
45
7. COMMITMENTS AND CONTINGENCIES
Zitong Block Exploration Commitment
At December 31, 2005, the Company held a 100% working interest in a thirty-year production-sharing
contract with China National Petroleum Corporation (CNPC) in a contract area, known as the Zitong
Block located in the northwestern portion of the Sichuan Basin. In January 2006, the Company
farmed-out 10% of its working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc.
of Japan (Mitsubishi) for $4.0 million.
Under this production-sharing contract, the Company was obligated to conduct a minimum exploration
program during the first three years ending December 1, 2005 (Phase I). The Company completed
Phase I with a drilling shortfall of approximately 700 feet. In December 2007, the Company and
Mitsubishi (the Zitong Partners) made a decision to enter into the next three-year exploration
phase (Phase II). The shortfall in Phase I drilling will be carried over into Phase II.
By electing to participate in Phase II the Zitong Partners must relinquish 30%, plus or minus 5%,
of the Zitong block acreage and complete a minimum work program involving the acquisition of
approximately 200 miles of new seismic lines and approximately 23,700 feet of drilling (including
the Phase I shortfall), with total gross remaining estimated minimum expenditures for this program
of $23.1 million. The Zitong Partners have relinquished 25% of the Block to complete the Phase I
relinquishment requirement. The Phase II seismic line acquisition commitment was fulfilled in the
Phase 1 exploration program. Drilling at two locations is planned to commence in the second quarter
of 2010 with expected completed drilling, completion and evaluation of the prospects finalized in
late 2010. The Zitong Partners must complete the minimum work program by the end of the Phase II
period, December 31, 2010, or will be obligated to pay to CNPC the cash equivalent of the
deficiency in the work program for that exploration phase. The cash equivalent of the deficiency in
the drilling program is defined as the actual average unit cost of the last well drilled multiplied
by the footage shortfall. Based on our historical drilling costs, we estimate this deficiency to be
$12.5 million at December 31, 2009. Following the completion of Phase II, the Zitong Partners must
relinquish all of the remaining property except any areas identified for development and future
production.
Nyalga Block Exploration Commitment
The exploration period for the Nyalga Block XVI in Mongolia is for five years in duration and
consists of three phases of two years, one year and two years respectively, with the ability to
nominate a two year extension following the first or second phase. The minimum work obligations
consist of $2.7 million for the first phase with the majority of that commitment in the second year
of the phase, $1.0 million for the second phase and $2.5 million for the third phase with the
majority of that commitment in the second year of that phase. If, in one year, more than the
minimum is expended, the excess can be applied to reduce the minimum expenditure in the next year
of that phase. During the initial seismic program, a portion of the block, representing
approximately 16% of the total, was declared by the Mongolian government to be an historical site
and operations on that portion of the block, the Delgerkhaan area, were suspended. A letter from
the Mineral Resources and Petroleum Authority of Mongolia (the MRPAM) was received in May 2008
which stated that the obligations under year one of first phase would be extended for one year from
the time the Company is allowed access to the suspended area. To date, access has not yet been
allowed and discussions with MRPAM are still ongoing not only as to possibility of entering into
this suspended area but also as to the exact end date of the first phase. Management believes the
end date of the first phase to be April 2010 and as at December 2009 has spent in excess of the
commitments for this first phase. The minimum work obligation as at December 31, 2009 was $3.4
million.
46
Long Term Obligation
As part of its 2005 merger with Ensyn Group, Inc., the Company assumed an obligation to pay $1.9
million in the event, and at such time that, the sale of units incorporating the HTLTM
Technology for petroleum applications reach a total of $100.0 million. This obligation was recorded
in the Companys consolidated balance sheet.
Income Taxes
The Companys income tax filings are subject to audit by taxation authorities, which may result in
the payment of income taxes and/or a decrease its net operating losses available for carry-forward
in the various jurisdictions in which the Company operates. While the Company believes its tax
filings do not include uncertain tax positions, except as noted below, the results of potential
audits or the effect of changes in tax law cannot be ascertained at this time.
The Company has an uncertain tax position in China related to when its entitlement to take tax
deductions associated with development costs commenced. In March 2007, the Company received a
preliminary indication from local Chinese tax authorities as to a potential change in the rule
under which development costs are deducted from taxable income effective for the 2006 tax year. The
Company discussed this matter with Chinese tax authorities and subsequently filed its 2006 tax
return for Sunwings wholly-owned subsidiary Pan-China Resources Ltd. (Pan-China) taking a new
filing position in which development costs are capitalized and amortized on a straight line basis
over six years starting in the year the development costs are incurred rather than deducted in
their entirety in the year incurred. This change resulted in a $50.3 million reduction in tax loss
carry-forwards in 2007 with an equivalent increase in the tax basis of development costs available
for application against future Chinese income. The Company has received no formal notification of
this rule change; however it will continue to file tax returns under this new approach. To the
extent that there is a different interpretation in the timing of the deductibility of development
costs this could potentially result in an increase in the current tax provision of $1.2 million.
The Company has an uncertain tax position related to the calculation of a gain on the consideration
received from two farm-out transactions (In January 2004, the Company signed farm-out and joint
operating agreements with Richfirst Holdings Limited, to acquire a 40% working interest in the
Dagang field for payment of $20.0 million. and the farm-out to Mitsubishi in January 2006 see
under Zitong Block Exploration Commitment in this Note 7) and the designation of whether the
taxable gains may be subject to a withholding tax of 10% pursuant to Chinese tax law for income
derived by a foreign entity. The Company is waiting for the Chinese tax authorities to reply to its
request to validate in writing that its current treatment of such tax position is appropriate. To
the extent that the calculation of a gain is interpreted differently and the amounts are subject to
withholding tax there would be an additional current tax provision of approximately $0.7 million.
No amounts have been recorded in the financial statements related to the above mentioned uncertain
tax positions as management has determined the likelihood of an unfavorable outcome to the Company
to be low.
Other Commitments
From time to time the Company enters into consulting agreements whereby a success fee may be
payable if and when either a definitive agreement is signed or certain other contractual milestones
are met. Under the agreements, the consultant may receive cash, Company shares, stock options or
some combination thereof. These fees are not considered to be material in relation to the overall
capital costs and funding requirements of the individual projects.
See Note 18 for a commitments related to acquisition of properties in Alberta.
The Company may provide indemnities to third parties, in the ordinary course of business, that are
customary in certain commercial transactions such as purchase and sale agreements. The terms of
these indemnities will vary based upon the contract, the nature of which prevents the Company from
making a reasonable estimate of the maximum potential amounts that may be required to be paid. The
Companys management is of the opinion that any resulting settlements relating to potential
litigation matters or indemnities would not materially affect the financial position of the
Company.
Lease Commitments
For the year ended December 31, 2009 the Company expended $1.2 million ($1.2 million in 2008 and
$1.1 million in 2007) on operating leases relating to the rental of office space, which expire
between July 2010 and September 2013. Such leases frequently provide for renewal options and
require the Company to pay for utilities, taxes, insurance and maintenance expenses.
47
As at December 31, 2009, future net minimum payments for operating leases (excluding oil and
gas and other mineral leases) were the following:
|
|
|
|
|
2010 |
|
$ |
1,448 |
|
2011 |
|
|
1,109 |
|
2012 |
|
|
438 |
|
2013 |
|
|
126 |
|
Thereafter |
|
|
|
|
|
|
|
|
|
|
$ |
3,121 |
|
|
|
|
|
8. SHARE CAPITAL AND WARRANTS
The authorized capital of the Company consists of an unlimited number of common shares without par
value and an unlimited number of preferred shares without par value.
Special Warrants Offering
A special warrant is a security sold for cash which may be exercised to acquire, for no additional
consideration, a common share or, in certain circumstances, a common share and a common share
purchase warrant.
In July 2008, the Company completed a Cdn.$88.0 million private placement consisting of 29,334,000
special warrants at Cdn.$3.00 per special warrant (the Offering). Each of these special warrants
entitled the holder to one common share of the Company upon exercise of the special warrant. In
August 2008, all of these special warrants were exercised for 29,334,000 common shares. The net
proceeds from the Offering was approximately Cdn.$83.4 million after deducting the agents
commission of Cdn.$4.0 million and the expenses of the Offering of Cdn.$0.6 million. The Company
used Cdn.$22.5 million of the net proceeds of the Offering to complete the cash component of the
Talisman lease acquisition described in Note 18.
Convertible Notes
As described in Note 5, in connection with the acquisition in July 2008, the Company issued the
Convertible Note to Talisman in the principal amount of Cdn.$40.0 million bearing interest at a
rate per year equal to the prime rate plus 2%, calculated daily and not compounded, and payable
semi-annually, maturing in July 2011 and convertible (as to the outstanding principal amount), at
Talismans option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per
common share. Also described in Note 5, management accounted for this convertible note by assigning
a portion of the value, Cdn.$2.1 million, of the instrument to equity.
In April 2008, the Company obtained a loan from a third party finance company in the amount of
Cdn.$5.0 million bearing interest at 8% per annum. The principal and accrued and unpaid interest
matured and was repayable in August 2008. In August 2008, the lender exercised its option to
convert the entire outstanding balance into the Companys common shares at the conversion price of
Cdn.$2.24 per share.
Purchase Warrants
The following reflects the changes in the Companys purchase warrants and common shares issuable
upon the exercise of the purchase warrants for the three-year period ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
Purchase |
|
|
Shares |
|
|
|
Warrants |
|
|
Issuable |
|
|
|
(thousands) |
|
Balance December 31, 2006 |
|
|
29,696 |
|
|
|
29,696 |
|
Purchase warrants exercised |
|
|
(2,000 |
) |
|
|
(2,000 |
) |
Purchase warrants expired |
|
|
(1,200 |
) |
|
|
(1,200 |
) |
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
|
26,496 |
|
|
|
26,496 |
|
Purchase warrants expired |
|
|
(15,096 |
) |
|
|
(15,096 |
) |
Private placements |
|
|
29,334 |
|
|
|
29,334 |
|
Purchase warrants exercised |
|
|
(29,334 |
) |
|
|
(29,334 |
) |
|
|
|
|
|
|
|
Balance December 31, 2008 |
|
|
11,400 |
|
|
|
11,400 |
|
Exchanged as
part of acquisition |
|
|
735 |
|
|
|
735 |
|
|
|
|
|
|
|
|
Balance December 31, 2009 |
|
|
12,135 |
|
|
|
12,135 |
|
|
|
|
|
|
|
|
48
In 2009, 0.7 million purchase warrants were issued in exchange for outstanding warrants of a
company the Company acquired. See Note 18 for further details.
For the year ended December 31, 2009, no purchase warrants were exercised (in 2008, 29.3 million
purchase warrants were exercised for the purchase of common shares please refer to details under
Special Warrants Offering and in 2007 2.0 million warrants were exercised at an average exercise
price of U.S. $2.00 per share for a total of $4.0 million).
For the year ended December 31, 2009, no purchase warrants expired (15.1 million with a carrying
value of $4.3 million in 2008 and 1.2 million with a carrying value of $0.6 million in 2007). The
carrying value is reclassified from Purchase Warrants to Contributed Surplus at the time of
expiration.
As at December 31, 2009, the following purchase warrants were exercisable to purchase common shares
of the Company until the expiry date at the price per share as indicated below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase Warrants |
|
|
|
|
|
|
Price per |
|
|
|
|
|
|
|
|
|
|
Common |
|
|
|
|
|
|
|
|
|
|
Exercise |
|
|
Cash |
|
Year of |
|
Special |
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
|
|
|
|
|
|
|
|
Price per |
|
|
Value on |
|
Issue |
|
Warrant |
|
|
Issued |
|
|
Exercisable |
|
|
Issuable |
|
|
Value |
|
|
Expiry Date |
|
|
Share |
|
|
Exercise |
|
|
|
|
|
|
|
(thousands) |
|
|
($U.S. 000) |
|
|
|
|
|
|
|
|
|
|
($U.S. 000) |
|
2006 |
|
U.S.$ |
2.23 |
|
|
|
11,400 |
|
|
|
11,400 |
|
|
|
11,400 |
|
|
|
18,805 |
|
|
May 2011 |
|
|
Cdn.$ |
2.93 |
(1) |
|
|
31,736 |
|
2009 |
|
|
NA |
|
|
|
735 |
|
|
|
735 |
|
|
|
735 |
|
|
|
622 |
|
|
February 2011 |
|
|
Cdn.$ |
4.05 |
|
|
|
2,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,135 |
|
|
|
12,135 |
|
|
|
12,135 |
|
|
$ |
19,427 |
|
|
|
|
|
|
|
|
|
|
$ |
34,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Each common share purchase warrant originally entitled the holder to purchase one common
share at a price of $2.63 per share until the fifth anniversary date of the closing. In September
2006, these warrants were listed on the Toronto Stock Exchange and the exercise price was changed
to Cdn.$2.93. |
The weighted average exercise price of the exercisable purchase warrants as at December 31,
2009 was U.S. $2.85 per share.
The Company calculated a value of $0.6 million and $18.8 million for the purchase warrants issued
in 2009 and 2006. This value was calculated in accordance with the Black-Scholes pricing model
using a weighted average risk-free interest rate of 0.6% and 4.4%, a dividend yield of 0.0%, a
weighted average volatility factor of 104.9% and 75.3% and an
expected life of 1 and 5 years.
9. STOCK BASED COMPENSATION
The Company has an Employees and Directors Equity Incentive Plan under which it can grant stock
options to directors and eligible employees to purchase common shares, issue common shares to
directors and eligible employees for bonus awards and issue shares under a share purchase plan for
eligible employees. The total number of common shares that may be issued under this plan cannot
exceed 29.3 million.
Stock options are issued at not less than the fair market value on the date of the grant and are
conditional on continuing employment. Expiration and vesting periods are set at the discretion of
the Board of Directors. Stock options granted prior to March 1, 1999 vested over a two-year period
and expire ten years from date of issue. Stock options granted after March 1, 1999 generally vest
over three to four years and expire five to ten years from the date of issue. Additionally, in
2007, the Company granted share option awards whose vesting is contingent upon meeting various
departmental and company-wide goals.
The fair value of each option award is estimated on the date of grant using the Black Scholes
option-pricing formula with service condition options amortized on a straight-line attribution
approach and performance condition options amortized over the service period both with the
following weighted-average assumptions for the years presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Expected term (in years) |
|
|
4.6 |
|
|
|
4.0 |
|
|
|
3.7 |
|
Volatility |
|
|
81.1 |
% |
|
|
63.5 |
% |
|
|
73.5 |
% |
Dividend Yield |
|
|
0.0 |
% |
|
|
0.0 |
% |
|
|
0.0 |
% |
Risk-free rate |
|
|
2.6 |
% |
|
|
3.1 |
% |
|
|
4.1 |
% |
49
The Companys expected term represents the period that the Companys stock-based awards are
expected to be outstanding and was determined based on historical experience of similar awards,
giving consideration to the contractual terms of the stock-based awards, vesting schedules and
expectations of future employee behavior as influenced by changes to the terms of its stock-based
awards. The fair values of stock-based payments were valued using the Black Scholes valuation
method with an expected volatility factor based on
the Companys historical stock prices. The Black Scholes valuation model calls for a single
expected dividend yield as an input. The Company has not paid and does not anticipate paying any
dividends in the near future. The Company bases the risk-free interest rate used in the Black
Scholes valuation method on the implied yield currently available on Canadian zero-coupon issue
bonds with an equivalent remaining term. When estimating forfeitures, the Company considers
historical voluntary termination behavior as well as future expectations of workforce reductions.
The estimated forfeiture rate as at December 31, 2009 is 26.4% (25.9% at December 31, 2008 and
23.1% at December 31, 2007). The Company recognizes compensation costs only for those equity awards
expected to vest.
The weighted average grant-date fair value of stock options granted during 2009 was Cdn.$1.62
(Cdn.$0.90 in 2008 and Cdn$1.09 in 2007).
For the years ended December 31, 2009 the Companys stock based compensation related to option
awards, share bonus awards and shares issued for services were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
Administrative
Expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Option awards |
|
$ |
3,484 |
|
|
$ |
2,241 |
|
|
$ |
1,786 |
|
Share bonus awards |
|
|
|
|
|
|
207 |
|
|
|
340 |
|
Shares issued for services |
|
|
207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,691 |
|
|
|
2,448 |
|
|
|
2,126 |
|
Business and Technology
Development Expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Option awards |
|
|
158 |
|
|
|
432 |
|
|
|
774 |
|
Share bonus awards |
|
|
|
|
|
|
136 |
|
|
|
251 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158 |
|
|
|
568 |
|
|
|
1,025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Option awards |
|
|
17 |
|
|
|
391 |
|
|
|
376 |
|
Share bonus awards |
|
|
|
|
|
|
147 |
|
|
|
202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
538 |
|
|
|
578 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,866 |
|
|
$ |
3,554 |
|
|
$ |
3,729 |
|
|
|
|
|
|
|
|
|
|
|
In addition, nil of the Companys stock based compensation related to option awards was
capitalized to oil and gas properties and development costs in the balance sheet during December
31, 2009 ($0.2 million in 2008 and nil in 2007).
The following table summarizes changes in the Companys outstanding stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
December 31, 2008 |
|
|
December 31, 2007 |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Weighted- |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Stock |
|
|
Exercise |
|
|
of Stock |
|
|
Exercise |
|
|
of Stock |
|
|
Exercise |
|
|
|
Options |
|
|
Price |
|
|
Options |
|
|
Price |
|
|
Options |
|
|
Price |
|
|
|
(thousands) |
|
|
(Cdn.$) |
|
|
(thousands) |
|
|
(Cdn.$) |
|
|
(thousands) |
|
|
(Cdn.$) |
|
Outstanding at beginning of year |
|
|
11,913 |
|
|
$ |
2.32 |
|
|
|
12,945 |
|
|
$ |
2.37 |
|
|
|
12,370 |
|
|
$ |
2.34 |
|
Granted |
|
|
4,188 |
|
|
$ |
2.17 |
|
|
|
3,832 |
|
|
$ |
1.79 |
|
|
|
3,843 |
|
|
$ |
1.05 |
|
Exercised |
|
|
(413 |
) |
|
$ |
2.46 |
|
|
|
(3,067 |
) |
|
$ |
0.90 |
|
|
|
(1,477 |
) |
|
$ |
0.62 |
|
Expired |
|
|
(114 |
) |
|
$ |
2.44 |
|
|
|
(580 |
) |
|
$ |
5.78 |
|
|
|
(1,017 |
) |
|
$ |
3.12 |
|
Forfeited |
|
|
(561 |
) |
|
$ |
2.41 |
|
|
|
(1,217 |
) |
|
$ |
3.05 |
|
|
|
(774 |
) |
|
$ |
2.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year |
|
|
15,013 |
|
|
$ |
2.27 |
|
|
|
11,913 |
|
|
$ |
2.32 |
|
|
|
12,945 |
|
|
$ |
2.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at end of year |
|
|
7,101 |
|
|
$ |
2.48 |
|
|
|
5,062 |
|
|
$ |
2.61 |
|
|
|
6,932 |
|
|
$ |
2.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value of total options outstanding as well as options exercisable as
at December 31, 2009 was $10.8 million and $3.4 million. The total intrinsic value of options
exercised during the year ended December 31, 2009 was $3.0 million ($5.4 million in 2008 and $2.1
million in 2007), and the cash received from exercise of options during the year ended December 31,
2009 was $0.9 million ($1.2 million in 2008 and $0.4 million in 2007).
50
The following table summarizes information respecting stock options outstanding and exercisable as
at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options Outstanding |
|
|
Stock Options Exercisable |
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
Range of |
|
Number |
|
|
Remaining |
|
|
Weighted-Average |
|
|
Number |
|
|
Remaining |
|
|
Weighted-Average |
|
Exercise Prices |
|
Outstanding |
|
|
Contractual Life |
|
|
Exercise Price |
|
|
Exercisable |
|
|
Contractual Life |
|
|
Exercise Price |
|
(Cdn.$) |
|
(thousands) |
|
|
(Years) |
|
|
(Cdn.$) |
|
|
(thousands) |
|
|
(Years) |
|
|
(Cdn.$) |
|
$1.52 to $2.25 |
|
|
9,652 |
|
|
|
3.8 |
|
|
$ |
1.93 |
|
|
|
2,612 |
|
|
|
3.3 |
|
|
$ |
1.85 |
|
$2.29 to $3.44 |
|
|
5,089 |
|
|
|
2.3 |
|
|
$ |
2.85 |
|
|
|
3,906 |
|
|
|
1.1 |
|
|
$ |
2.89 |
|
$3.53 to $3.62 |
|
|
272 |
|
|
|
1.9 |
|
|
$ |
3.56 |
|
|
|
235 |
|
|
|
0.8 |
|
|
$ |
3.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.52 to $3.62 |
|
|
15,013 |
|
|
|
3.1 |
|
|
$ |
2.27 |
|
|
|
6,753 |
|
|
|
2.0 |
|
|
$ |
2.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of the Companys unvested options as at December 31, 2009, and changes during the
year then ended, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
Number |
|
|
Average |
|
|
|
of Stock |
|
|
Grant Date |
|
|
|
Options |
|
|
Fair Value |
|
|
|
(thousands) |
|
|
(Cdn.$) |
|
Outstanding at December 31, 2008 |
|
|
6,851 |
|
|
$ |
0.98 |
|
Granted |
|
|
4,188 |
|
|
$ |
1.62 |
|
Vested |
|
|
(2,814 |
) |
|
$ |
0.46 |
|
Cancelled/forfeited |
|
|
(313 |
) |
|
$ |
0.02 |
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009 |
|
|
7,912 |
|
|
$ |
1.21 |
|
|
|
|
|
|
|
|
|
Unvested options outstanding at December 31, 2009 by type:
|
|
|
|
|
Based on fulfilling service conditions |
|
|
6,926 |
|
Based on fulfilling performance conditions |
|
|
986 |
|
|
|
|
|
|
|
|
7,912 |
|
|
|
|
|
As at December 31, 2009, there was $3.1 million of total unrecognized compensation costs
related to unvested share-based compensation arrangements granted by the Company. That cost is
expected to be recognized over a weighted-average period of 1.6 years. The total fair value of
options vested during the year ended December 31, 2009 was $2.2 million ($3.0 million in 2007 and
$2.9 million in 2007).
10. RETIREMENT PLAN
In 2001, the Company adopted a defined contribution retirement or thrift plan (401(k) Plan) to
assist U.S. employees in providing for retirement or other future financial needs. Employees
contributions (up to the maximum allowed by U.S. tax laws) were matched 100% by the Company in
2009. For the year ended December 31, 2009 the Companys matching contributions to the 401(k) Plan
was $0.4 million ($0.5 million in 2008 and $0.5 million in 2007).
11. SEGMENT INFORMATION
The Company has four reportable business segments: Oil and Gas Integrated, Oil and Gas
Conventional, Business and Technology Development and Corporate. In July 2009, the Company sold its
U.S. operating segment (see Note 19); consequently, the segment information has been revised to
reflect this sale.
Oil and Gas
Integrated
Projects in this segment will have two primary components. The first component consists of
conventional exploration and production activities together with enhanced oil recovery techniques
such as steam assisted gravity drainage. The second component consists of the deployment of the
HTLTM Technology which will be used to upgrade heavy oil at facilities located in the
field to produce lighter, more valuable crude. The Company has two such projects currently reported
in this segment a heavy oil project in Alberta (see Note 18) and a heavy oil project in Ecuador
(see Note 18). The integrated segments were established in 2008 and therefore there is no
comparative information for 2007.
51
Conventional
The Company explores for, develops and produces crude oil and natural gas in China, and recently
acquired an exploration block in Mongolia. In China, the Companys development and production
activities are conducted at the Dagang oil field located in Hebei Province and its exploration
activities are conducted on the Zitong block located in Sichuan Province. In Mongolia, the
exploration activity is being conducted in Block XVI in the Nyalga Basin. Prior to July 2009, (see
Note 18) the Company conducted U.S.
exploration, development and production activities primarily in California and Texas.
Business and Technology Development
The Company incurs various costs in the pursuit of projects throughout the world. Such costs
incurred prior to signing a MOU or similar agreement, are considered to be business and technology
development and are expensed as incurred. Upon executing a MOU to determine the technical and
commercial feasibility of a project, including studies for the marketability for the projects
products, the Company assesses whether the feasibility and related costs incurred have potential
future value, are likely of leading to a definitive agreement for the exploitation of proved
reserves and should be capitalized.
Additionally, the Company incurs costs to develop, enhance and identify improvements in the
application of the technologies it owns or licenses. The cost of equipment and facilities acquired,
or construction costs for such purposes, are capitalized as development costs and amortized over
the expected economic life of the equipment or facilities, commencing with the start up of
commercial operations for which the equipment or facilities are intended.
Corporate
The Companys corporate segment consists of costs associated with the board of directors, executive
officers, corporate debt, financings and other corporate activities.
52
The following tables present the Companys segment information for the three years ended December
31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
|
Oil and Gas |
|
|
Business and |
|
|
|
|
|
|
|
|
|
Integrated |
|
|
Conventional |
|
|
Technology |
|
|
|
|
|
|
|
Revenue |
|
Canada |
|
|
Ecuador |
|
|
Asia |
|
|
U.S. |
|
|
Development |
|
|
Corporate |
|
|
Total |
|
Oil revenue |
|
$ |
|
|
|
$ |
|
|
|
$ |
24,968 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
24,968 |
|
Loss on derivative instruments |
|
|
|
|
|
|
|
|
|
|
(1,335 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,335 |
) |
Interest income |
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,639 |
|
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
23,658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
|
|
|
|
|
|
|
|
10,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,191 |
|
General and administrative |
|
|
1,129 |
|
|
|
2,269 |
|
|
|
2,777 |
|
|
|
|
|
|
|
|
|
|
|
15,518 |
|
|
|
21,693 |
|
Business and technology development |
|
|
560 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,941 |
|
|
|
|
|
|
|
9,501 |
|
Depletion and depreciation |
|
|
4 |
|
|
|
53 |
|
|
|
18,033 |
|
|
|
|
|
|
|
1,633 |
|
|
|
145 |
|
|
|
19,868 |
|
Foreign exchange loss |
|
|
(8 |
) |
|
|
|
|
|
|
71 |
|
|
|
|
|
|
|
2 |
|
|
|
5,155 |
|
|
|
5,220 |
|
Interest expense and financing costs |
|
|
|
|
|
|
|
|
|
|
770 |
|
|
|
|
|
|
|
79 |
|
|
|
7 |
|
|
|
856 |
|
Provision for impairment of
development costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,903 |
|
|
|
|
|
|
|
1,903 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,685 |
|
|
|
2,322 |
|
|
|
31,842 |
|
|
|
|
|
|
|
12,558 |
|
|
|
20,825 |
|
|
|
69,232 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
before income taxes |
|
|
(1,685 |
) |
|
|
(2,322 |
) |
|
|
(8,203 |
) |
|
|
|
|
|
|
(12,558 |
) |
|
|
(20,806 |
) |
|
|
(45,574 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Provision for) recovery
of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
|
|
(1,399 |
) |
|
|
|
|
|
|
|
|
|
|
(358 |
) |
|
|
(1,757 |
) |
Future |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,600 |
|
|
|
|
|
|
|
9,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,399 |
) |
|
|
|
|
|
|
9,600 |
|
|
|
(358 |
) |
|
|
7,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from
continuing operations |
|
|
(1,685 |
) |
|
|
(2,322 |
) |
|
|
(9,602 |
) |
|
|
|
|
|
|
(2,958 |
) |
|
|
(21,164 |
) |
|
|
(37,731 |
) |
Net loss from discontinued
operations (net of tax of $29.6 million) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,921 |
) |
|
|
|
|
|
|
|
|
|
|
(23,921 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) and
comprehensive income (loss) |
|
$ |
(1,685 |
) |
|
$ |
(2,322 |
) |
|
$ |
(9,602 |
) |
|
$ |
(23,921 |
) |
|
$ |
(2,958 |
) |
|
$ |
(21,164 |
) |
|
$ |
(61,652 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investments |
|
$ |
12,756 |
|
|
$ |
5,380 |
|
|
$ |
6,049 |
|
|
$ |
|
|
|
$ |
2,093 |
|
|
$ |
95 |
|
|
$ |
26,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2009 |
|
$ |
94,594 |
|
|
$ |
7,597 |
|
|
$ |
57,528 |
|
|
$ |
|
|
|
$ |
102,878 |
|
|
$ |
19,166 |
|
|
$ |
281,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
|
Oil and Gas |
|
|
Business and |
|
|
|
|
|
|
|
|
|
Integrated |
|
|
Conventional |
|
|
Technology |
|
|
|
|
|
|
|
|
|
Canada |
|
|
Ecuador |
|
|
Asia |
|
|
U.S. |
|
|
Development |
|
|
Corporate |
|
|
Total |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
|
|
|
$ |
|
|
|
$ |
48,370 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
48,370 |
|
Gain on derivative instruments |
|
|
|
|
|
|
|
|
|
|
1,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,688 |
|
Interest income |
|
|
|
|
|
|
|
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
562 |
|
|
|
612 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,108 |
|
|
|
|
|
|
|
|
|
|
|
562 |
|
|
|
50,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
|
|
|
|
|
|
|
|
21,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,515 |
|
General and administrative |
|
|
1,627 |
|
|
|
658 |
|
|
|
1,967 |
|
|
|
|
|
|
|
|
|
|
|
10,000 |
|
|
|
14,252 |
|
Business and technology development |
|
|
189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,264 |
|
|
|
|
|
|
|
6,453 |
|
Depletion and depreciation |
|
|
3 |
|
|
|
|
|
|
|
23,135 |
|
|
|
|
|
|
|
2,618 |
|
|
|
5 |
|
|
|
25,761 |
|
Foreign exchange loss |
|
|
26 |
|
|
|
|
|
|
|
278 |
|
|
|
|
|
|
|
|
|
|
|
1,223 |
|
|
|
1,527 |
|
Interest expense and financing costs |
|
|
|
|
|
|
|
|
|
|
821 |
|
|
|
|
|
|
|
76 |
|
|
|
412 |
|
|
|
1,309 |
|
Provion for impairment of GTL
intangible assets and development costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,054 |
|
|
|
|
|
|
|
15,054 |
|
Write off of deferred financing costs |
|
|
|
|
|
|
|
|
|
|
2,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,845 |
|
|
|
658 |
|
|
|
50,337 |
|
|
|
|
|
|
|
24,012 |
|
|
|
11,640 |
|
|
|
88,492 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
before income taxes |
|
|
(1,845 |
) |
|
|
(658 |
) |
|
|
(229 |
) |
|
|
|
|
|
|
(24,012 |
) |
|
|
(11,078 |
) |
|
|
(37,822 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current provision for income taxes |
|
|
|
|
|
|
|
|
|
|
(650 |
) |
|
|
|
|
|
|
(2 |
) |
|
|
(2 |
) |
|
|
(654 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from
continuing operations |
|
|
(1,845 |
) |
|
|
(658 |
) |
|
|
(879 |
) |
|
|
|
|
|
|
(24,014 |
) |
|
|
(11,080 |
) |
|
|
(38,476 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from
discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,283 |
|
|
|
|
|
|
|
|
|
|
|
4,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and
Comprehensive Income (Loss) |
|
$ |
(1,845 |
) |
|
$ |
(658 |
) |
|
$ |
(879 |
) |
|
$ |
4,283 |
|
|
$ |
(24,014 |
) |
|
$ |
(11,080 |
) |
|
$ |
(34,193 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investments |
|
$ |
6,484 |
|
|
$ |
1,369 |
|
|
$ |
8,378 |
|
|
$ |
|
|
|
$ |
4,832 |
|
|
$ |
|
|
|
$ |
21,063 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2008 |
|
$ |
81,126 |
|
|
$ |
1,766 |
|
|
$ |
64,901 |
|
|
$ |
65,371 |
|
|
$ |
105,587 |
|
|
$ |
28,124 |
|
|
$ |
346,875 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
|
|
Oil and Gas |
|
|
Business and |
|
|
|
|
|
|
|
|
|
Conventional |
|
|
Technology |
|
|
|
|
|
|
|
|
|
Asia |
|
|
U.S. |
|
|
Development |
|
|
Corporate |
|
|
Total |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue |
|
$ |
31,365 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
31,365 |
|
Loss on derivative instruments |
|
|
(4,993 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,993 |
) |
Interest income |
|
|
58 |
|
|
|
|
|
|
|
|
|
|
|
259 |
|
|
|
317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,430 |
|
|
|
|
|
|
|
|
|
|
|
259 |
|
|
|
26,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
13,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,000 |
|
General and administrative |
|
|
1,826 |
|
|
|
|
|
|
|
|
|
|
|
7,977 |
|
|
|
9,803 |
|
Business and technology development |
|
|
|
|
|
|
|
|
|
|
9,625 |
|
|
|
|
|
|
|
9,625 |
|
Depletion and depreciation |
|
|
19,222 |
|
|
|
|
|
|
|
1,412 |
|
|
|
6 |
|
|
|
20,640 |
|
Foreign exchange loss |
|
|
216 |
|
|
|
|
|
|
|
|
|
|
|
85 |
|
|
|
301 |
|
Interest expense and financing costs |
|
|
281 |
|
|
|
|
|
|
|
29 |
|
|
|
313 |
|
|
|
623 |
|
Provision for impairment of
oil and gas properties |
|
|
6,130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,675 |
|
|
|
|
|
|
|
11,066 |
|
|
|
8,381 |
|
|
|
60,122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from
continuing operations |
|
|
(14,245 |
) |
|
|
|
|
|
|
(11,066 |
) |
|
|
(8,122 |
) |
|
|
(33,433 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from
discontinued operations |
|
|
|
|
|
|
(5,774 |
) |
|
|
|
|
|
|
|
|
|
|
(5,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss and Comprehensive Loss |
|
$ |
(14,245 |
) |
|
$ |
(5,774 |
) |
|
$ |
(11,066 |
) |
|
$ |
(8,122 |
) |
|
$ |
(39,207 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investments |
|
$ |
23,488 |
|
|
$ |
|
|
|
$ |
5,097 |
|
|
$ |
|
|
|
$ |
28,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55
12. FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS
The accounting classification of each category of financial instruments, and their carrying
amounts, are set out below. Carrying amounts approximate fair value except for long-term debt.
After taking into account its own credit risk, the Company calculated the fair value of its
long-term debt to be $36.0 million as at December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial |
|
|
|
|
|
|
|
|
|
|
Available-for- |
|
|
|
|
|
|
liabilities |
|
|
|
|
|
|
Loans and |
|
|
sale financial |
|
|
Held-for- |
|
|
measured at |
|
|
Total carrying |
|
|
|
receivables |
|
|
assets |
|
|
trading |
|
|
amortized cost |
|
|
amount |
|
Financial Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
|
|
|
$ |
21,512 |
|
|
$ |
|
|
|
$ |
21,512 |
|
Accounts receivable |
|
|
5,021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,021 |
|
Note receivable |
|
|
225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
225 |
|
Restricted cash |
|
|
|
|
|
|
|
|
|
|
2,850 |
|
|
|
|
|
|
|
2,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,779 |
) |
|
|
(10,779 |
) |
Long term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(36,934 |
) |
|
|
(36,934 |
) |
Long term obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,900 |
) |
|
|
(1,900 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5,246 |
|
|
$ |
|
|
|
$ |
24,362 |
|
|
$ |
(49,613 |
) |
|
$ |
(20,005 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial |
|
|
|
|
|
|
|
|
|
|
Available-for- |
|
|
|
|
|
|
liabilities |
|
|
|
|
|
|
Loans and |
|
|
sale financial |
|
|
Held-for- |
|
|
measured at |
|
|
Total carrying |
|
|
|
receivables |
|
|
assets |
|
|
trading |
|
|
amortized cost |
|
|
amount |
|
Financial Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
|
|
|
$ |
38,477 |
|
|
$ |
|
|
|
$ |
38,477 |
|
Accounts receivable |
|
|
3,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,802 |
|
Restricted cash |
|
|
|
|
|
|
|
|
|
|
850 |
|
|
|
|
|
|
|
850 |
|
Derivative instruments |
|
|
|
|
|
|
|
|
|
|
1,459 |
|
|
|
|
|
|
|
1,459 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,219 |
) |
|
|
(9,219 |
) |
Long term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38,267 |
) |
|
|
(38,267 |
) |
Long term obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,900 |
) |
|
|
(1,900 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,802 |
|
|
$ |
|
|
|
$ |
40,786 |
|
|
$ |
(49,386 |
) |
|
$ |
(4,798 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In accordance with CICA Handbook Section 3862, Financial Instruments Disclosures, the
Companys financial assets and liabilities recorded at fair value have been categorized based on
the following fair value hierarchy:
Level 1: unadjusted quoted prices in active markets for identical assets or
liabilities;
Level 2: inputs other than quoted prices included within Level 1 that are
observable for the asset or liability, either directly (i.e. as prices) or indirectly
(i.e. derived from prices); and
Level 3: inputs for the asset or liability that are not based on observable
market date (unobservable inputs).
Cash and cash equivalents are considered Level 1 and restricted cash is considered Level 2. There
were no significant transfers between Levels 1 and 2 and there were no gains or losses relating to
cash and cash equivalents included in the statement of operations.
56
Financial Risk Factors
The Company is exposed to a number of different financial risks arising from typical business
exposures as well as its use of financial instruments including market risk relating to commodity
prices, foreign currency exchange rates and interest rates, credit risk and liquidity risk. There
have been no significant changes to the Companys exposure to risks nor to managements objectives,
policies and processes to manage risks from the previous year except discussed below under
Liquidity Risk. The risks associated with our financial instruments and our policies for
minimizing these risks are detailed below.
Market Risk
Market risk is the risk that the fair value or future cash flows of our financial instruments will
fluctuate because of changes in market prices. Components of market risk to which we are exposed
are discussed below.
Commodity Price Risks
Commodity price risk refers to the risk that the value of a financial instrument or cash flows
associated with the instrument will fluctuate due to the changes in market commodity prices. Crude
oil prices and quality differentials are influenced by worldwide factors such as OPEC actions,
political events and supply and demand fundamentals. The Company may periodically use different
types of derivative instruments to manage its exposure to price volatility as well as being a
requirement of the Companys lenders.
The Company entered into a costless collar derivative to minimize variability in its cash flow from
the sale of up to 18,000 Bbls per month of the Companys production from its Dagang field in China
over a three-year period starting September 2007. This derivative had a ceiling price of $84.50 per
barrel and a floor price of $55.00 per barrel using the WTI as the index traded on the NYMEX. The
contracts related to the derivative above were put in place as part of the Companys bank loan
facility and consequently all remaining contracts were settled when this loan was repaid in
December 2009 (see Note 5).
Results of these derivative transactions for the three years ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Realized gains (losses) on derivative transactions |
|
$ |
124 |
|
|
$ |
(4,430 |
) |
|
$ |
(334 |
) |
Unrealized gains (losses) on derivative transactions |
|
|
(1,459 |
) |
|
|
6,118 |
|
|
|
(4,659 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,335 |
) |
|
$ |
1,688 |
|
|
$ |
(4,993 |
) |
|
|
|
|
|
|
|
|
|
|
Both realized and unrealized gains and losses on derivatives have been recognized in the
results of operations.
As noted above, all remaining contracts were settled in December 2009 and consequently the Company
had no open positions on the derivative assets referred to above at December 31, 2009.
Foreign Currency Exchange Rate Risk
Foreign currency risk refers to the risk that the value of a financial commitment, recognized asset
or liability will fluctuate due to changes in foreign currency rates. The main underlying economic
currency of the Companys cash flows is the U.S. dollar. This is because the Companys major
product, crude oil, is priced internationally in U.S. dollars. Accordingly, the Company does not
expect to face foreign exchange risks associated with its production revenues. However, some of the
Companys cash flow stream relating to certain international operations is based on the U.S. dollar
equivalent of cash flows measured in foreign currencies. The majority of the operating costs
incurred in the Chinese operations are paid in Chinese renminbi. The majority of costs incurred in
the administrative offices in Vancouver and Calgary, as well as some business development costs,
are paid in Canadian dollars. In addition, with the recent property acquisition in Alberta (see
Note 18) the Companys Canadian dollar expenditures increased during the last half of 2008 and 2009
when compared to prior periods, along with an increase in cash and debt balances denominated in
Canadian dollars. Disbursement transactions denominated in Chinese renminbi and Canadian dollars
are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date.
Foreign currency gains and losses also come about when monetary assets and liabilities, mainly
short term payables and receivables, denominated in foreign currencies are translated at the end of
each month. The estimated impact of a 10% strengthening or weakening of the Chinese renminbi, and
Canadian dollar, as of December 31, 2009 on net loss and accumulated deficit for the year ended
December 31, 2009 is a $4.6 million increase, and a $4.4 million decrease, respectively. To help
reduce the Companys exposure to foreign currency risk it seeks to maximize the expenditures and
contracts denominated in U.S. dollars and minimize those denominated in other currencies, except
for its Canadian activities where it attempts to hold cash denominated in Canadian dollars in order
to manage its currency risk related to outstanding debt and current liabilities denominated in
Canadian dollars.
57
Interest Rate Risk
Interest rate risk refers to the risk that the value of a financial instrument or cash flows
associated with the instrument will fluctuate due to the changes in market interest rates. Interest
rate risk arises from interest-bearing borrowings which have a variable interest rate. During 2009,
the Company had a bank loan facility (as noted above, this loan was repaid in full in December
2009) and a convertible note with fluctuating interest rates. The Company estimates that its net
loss and accumulated deficit for the year ended December 31, 2009 would have changed $0.2 million
for every 1% change in interest rates as of December 31, 2009. The Company is not currently
actively attempting to mitigate this interest rate risk given the limited amount and term of its
borrowings and the current
global interest rate environment.
Credit Risk
The Company is exposed to credit risk with respect to its cash held with financial institutions,
accounts receivable, derivative contracts and advance balances. The Company believes its exposure
to credit risk related to cash held with financial institutions is minimal due to the quality of
the institutions where the cash is held and the nature of the deposit instruments. Most of the
Companys accounts receivable balances relate to oil sales to foreign national petroleum companies
and are exposed to typical industry credit risks. In addition, accounts receivable balances consist
of costs billed to joint venture partners where the Company is the operator and advances to
partners for joint operations where the Company is not the operator. The Company manages its credit
risk by entering into sales contracts only with established entities and reviewing its exposure to
individual entities on a regular basis.
All of the Companys revenues come from one customer and 80%-95% of the outstanding receivable
balances as at December 31, 2009 and 2008, respectively, are due from this same customer.
As noted below, included in the Companys trade receivable balance are debtors with a carrying
amount of nil as of the year ended December 31, 2009 which are past due at the reporting date for
which the Company has not provided an allowance, as there has not been a significant change in
credit quality and the amounts are still considered recoverable. The Company defines past due by
the specific contract terms associated with each transaction (e.g. oil sales generally have a one
two month lag, joint venture billings generally are between 15 45 days). During the quarter ended
September 30, 2008 the Company recorded an allowance associated with the advance balance for the
entire outstanding amount of $0.7 million. This advance balance relates to an arrangement whereby
scheduled advances were made to a third party contractor associated with negotiating an
HTLTM and/or GTL project for the Company. In addition, the Company recorded an
allowance for the entire outstanding amount of $0.2 million related to an amount owed to the
Company by a two separate joint interest partners in the fourth quarter of 2009. These provisions
were recorded in General and Administrative expense in the accompanying Statement of Operations and
Comprehensive Loss. There were no other changes to the allowance for credit losses account during
the three-month period ended December 31, 2009 and no other losses associated with credit risk were
recorded during this same period.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Accounts Receivable: |
|
|
|
|
|
|
|
|
Neither impaired nor past due |
|
$ |
5,004 |
|
|
$ |
3,675 |
|
Impaired (net of valuation allowance) |
|
|
|
|
|
|
|
|
Not impaired and past due
in the following periods: |
|
|
|
|
|
|
|
|
within 30 days |
|
|
|
|
|
|
57 |
|
31 to 60 days |
|
|
|
|
|
|
37 |
|
61 to 90 days |
|
|
|
|
|
|
33 |
|
over 90 days |
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5,021 |
|
|
$ |
3,802 |
|
|
|
|
|
|
|
|
Our maximum exposure to credit risk is based on the recorded amounts of the financial assets
above.
Liquidity Risk
Liquidity risk is the risk that suitable sources of funding for the Companys business activities
may not be available, which means it may be forced to sell financial assets or non-financial
assets, refinance existing debt, raise new debt or issue equity. The Companys present plans to
generate sufficient resources to assure continuation of its operations and achieve its capital
investment objectives include alliances or other arrangements with entities with the resources to
support the Companys projects as well as project financing, debt financing or the sale of equity
securities. However, the availability of financing, in particular project funding, is dependent in
part on our ability to fund our projects using the credit and equity markets. Despite the Companys
recent successful financing efforts (see Note 20), the terms and availability of equity and debt
capital, have been materially restricted and financing may not be available when it is required or
on commercially acceptable terms.
58
The contractual maturity of the fixed and floating rate financial liabilities and derivatives are
shown in the table below. The amounts presented represent the future undiscounted principal and
interest cash flows and therefore do not equate to the values presented in the balance sheet.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2009 |
|
|
As at December 31, 2008 |
|
|
|
Contractual Maturity |
|
|
Contractual Maturity |
|
|
|
(Nominal Cash Flows) |
|
|
(Nominal Cash Flows) |
|
|
|
Less than |
|
|
1 to 2 |
|
|
2 to 5 |
|
|
Over 5 |
|
|
Less than |
|
|
1 to 2 |
|
|
2 to 5 |
|
|
Over 5 |
|
|
|
1 year |
|
|
years |
|
|
years |
|
|
years |
|
|
1 year |
|
|
years |
|
|
years |
|
|
years |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non derivative
financial liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts payable |
|
$ |
3,767 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
4,659 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Accruals |
|
$ |
7,012 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
4,560 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Long term debt and interest |
|
$ |
2,305 |
|
|
$ |
38,164 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
3,483 |
|
|
$ |
9,432 |
|
|
$ |
33,495 |
|
|
$ |
|
|
13. CAPITAL MANAGEMENT
The Company manages its capital so that the Company and its subsidiaries will be able to continue
as a going concern and to create shareholder value through exploring, appraising and developing its
assets including the major initiative of implementing multiple, full-scale, commercial HTL heavy
oil projects in Canada, Ecuador and elsewhere internationally as business opportunities
arise. There have been no significant changes in managements objectives, policies and processes to
manage capital or the components of capital from the previous year. However, the availability of
financing, in particular project funding, is dependent in part on our ability to fund our projects
using the credit and equity markets. Despite the Companys recent successful financing efforts (see
Note 20), future financing may not be available when it required or on commercially acceptable
terms.
The Company defines capital as total equity or deficiency plus cash and cash equivalents and long
term debt. Total equity is comprised of share capital, purchase warrants, convertible note,
contributed surplus, shares to be issued and accumulated deficit as disclosed in Note 8. Cash and
cash equivalents are $21.5 million and $38.5 million at December 31, 2009 and December 31, 2008 and
are composed entirely of bank balances in checking accounts with excess cash in money market
accounts which invest primarily in government securities with less than 90 day maturities. Long
term debt is disclosed in Note 5.
The Companys management reviews the capital structure on a regular basis to maintain the most
optimal debt to equity balance. In order to maintain or adjust its capital structure, the Company
may refinance its existing debt, raise new debt, seek cost sharing arrangements with partners or
issue new shares.
In 2008, the Company expensed $2.6 million of deferred financing costs that were directly
attributable to a proposed offering of securities for its wholly-owned Chinese subsidiary.
The Companys Chinese oil and gas subsidiary was subject to financial covenants, such as interest
coverage ratios, under each of their revolving/term credit facilities which are measured on a
quarterly or semi-annual basis. As noted in Note 5, the Company repaid the outstanding balance of
this loan in December 2009. The Company was in compliance with all financial covenants for the year
ended December 31, 2009.
59
14. INCOME TAXES
The Company and its subsidiaries are required to individually file tax returns in each of the
jurisdictions in which they operate. The provision for income taxes differs from the amount
computed by applying the statutory income tax rate to the net losses before income taxes. The
combined Canadian federal and provincial statutory rates as at December 31, 2009, 2008 and 2007
were 29.0%, 29.5% and 32.12%, respectively. The sources and tax effects for the differences were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Tax benefit computed at the combined Canadian federal and
provincial statutory income tax rates |
|
$ |
(13,217 |
) |
|
$ |
(11,158 |
) |
|
$ |
(10,739 |
) |
Foreign net losses affected at lower income tax rates |
|
|
106 |
|
|
|
4,562 |
|
|
|
1,456 |
|
Effect of change in foreign exchange rates |
|
|
(2,858 |
) |
|
|
3,006 |
|
|
|
(2,878 |
) |
Expiry of tax loss carry-forwards |
|
|
911 |
|
|
|
2,875 |
|
|
|
2,440 |
|
Tax credit carry-forward |
|
|
(350 |
) |
|
|
|
|
|
|
|
|
Compensation not deductible |
|
|
1,456 |
|
|
|
753 |
|
|
|
844 |
|
Financing costs not deductible |
|
|
|
|
|
|
695 |
|
|
|
|
|
Net currency exchange losses not deductible |
|
|
1,501 |
|
|
|
402 |
|
|
|
|
|
Change in prior year estimate of tax loss carry-forwards |
|
|
3,941 |
|
|
|
(59 |
) |
|
|
422 |
|
Realized derivative (gains)/losses not taxable/deductible |
|
|
334 |
|
|
|
(422 |
) |
|
|
|
|
Effect of change in effective income tax rates on future tax assets |
|
|
(4,453 |
) |
|
|
(331 |
) |
|
|
6,109 |
|
Other permanent differences |
|
|
32 |
|
|
|
(127 |
) |
|
|
991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,597 |
) |
|
|
196 |
|
|
|
(1,355 |
) |
Change in valuation allowance |
|
|
4,754 |
|
|
|
458 |
|
|
|
1,355 |
|
|
|
|
|
|
|
|
|
|
|
Provision for (recovery of) income taxes |
|
$ |
(7,843 |
) |
|
$ |
654 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Significant components of the Companys future net income tax assets and liabilities were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
Future Income Tax |
|
|
Future Income Tax |
|
|
|
Assets |
|
|
Liabilities |
|
|
Assets |
|
|
Liabilities |
|
Oil and gas properties and investments |
|
$ |
471 |
|
|
$ |
(1,124 |
) |
|
$ |
4,285 |
|
|
$ |
(1,582 |
) |
Intangibles |
|
|
|
|
|
|
(30,354 |
) |
|
|
|
|
|
|
(37,089 |
) |
Tax loss carry-forwards |
|
|
37,583 |
|
|
|
|
|
|
|
29,602 |
|
|
|
|
|
Tax credit carry-forward |
|
|
350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance |
|
|
(29,570 |
) |
|
|
|
|
|
|
(24,816 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
8,834 |
|
|
$ |
(31,478 |
) |
|
$ |
9,071 |
|
|
$ |
(38,671 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The tax loss carry-forwards in Canada are Cdn.$72.0 million, in China $37.2 million and in the
U.S. $34.3 million. Tax loss carry-forwards in Ecuador are nominal. The tax loss carry-forwards in
Canada expire between 2010 and 2029 and in the U.S. between 2015 and 2029. In China, the tax loss
carry-forwards have no expiration period. A loss of approximately Cdn.$55.3 million from the
disposition of Russian operations in 2000, being the aggregate investment, not including accounting
write-downs, less proceeds received on settlement is a capital loss for Canadian income tax
purposes, available for carry-forward against future Canadian capital gains indefinitely and is not
included in the future income tax assets above.
The amount of current income tax payable at December 31, 2009 associated with income taxes for
China equaled $0.2 million and the amount associated with income taxes for the U.S. equaled $0.3
million.
In April 2009, the Chinese State Tax Administration Bureau issued, Circular [2009] No. 49 (the
Circular) on depletion, depreciation and amortization expense by oil and gas companies. One of
the changes to the existing rules included in the Circular that affects the Company was the
increase of the minimum depreciation and amortization period from six years to eight years. The
implementation of the new rules was retroactive to January 1, 2008. Consequently, upon reviewing
the tax effect of the Circular, the Company revised its 2008 current tax payable in China to $1.6
million from the $0.6 million that was recorded in 2008. The $1.6 million tax payable was
subsequently paid in May 2009.
Prior to the Company selling its U.S. operating segment in July 2009, as further described in Note
19, the Company had future tax assets arising from net operating losses carry-forwards generated by
this business segment. These future income tax assets were partially offset by certain future
income tax liabilities in the U.S. and by a valuation allowance. As at June 30, 2009, as a result
of the sale of the business segment, the Company was no longer able to offset these tax assets and
liabilities but was required to present these future income tax assets as assets from discontinued
operations and a future income tax liability both in the amount of $29.6 million in the
accompanying balance sheet. The future income tax assets classified as Assets from discontinued
operations were ultimately included in the $23.4 million loss on disposition as described in Note
19. Revisions were made to the future income tax liability during the third quarter of 2009 based
on revised projections of taxable income and utilization of net operating loss carryforwards. As at
December 31, 2009, the Companys future income tax liability is $22.6 million in the accompanying
balance sheet, $20.0 million for the U.S. tax jurisdiction and $2.6 million related to the assets
acquired in Mongolia (see Note 18).
60
15. NET LOSS PER SHARE
Had the Company generated net earnings during the years presented, the earnings per share
calculations for the years presented would have included the following weighted average items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(thousands of shares) |
|
Stock options |
|
|
289 |
|
|
|
1,374 |
|
|
|
2,433 |
|
Purchase warrants |
|
|
409 |
|
|
|
|
|
|
|
|
|
Convertible debt |
|
|
13,166 |
|
|
|
6,943 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,864 |
|
|
|
8,317 |
|
|
|
2,433 |
|
|
|
|
|
|
|
|
|
|
|
Additionally, the earnings per share calculations would have included the following weighted
average items had the exercise prices exceeded the average market prices of the common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(thousands of shares) |
|
Stock options |
|
|
10,908 |
|
|
|
9,944 |
|
|
|
8,616 |
|
Purchase warrants |
|
|
16,444 |
|
|
|
16,399 |
|
|
|
28,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27,352 |
|
|
|
26,343 |
|
|
|
37,514 |
|
|
|
|
|
|
|
|
|
|
|
16. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow information for each of the years ended December 31 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Cash paid during the period for |
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
$ |
1,876 |
|
|
$ |
5 |
|
|
$ |
6 |
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
$ |
2,122 |
|
|
$ |
1,120 |
|
|
$ |
238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing and Financing
activities, non-cash |
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of business/assets
(see note 18) |
|
|
|
|
|
|
|
|
|
|
|
|
Shares issued |
|
$ |
6,899 |
|
|
$ |
|
|
|
$ |
|
|
Warrants issued |
|
|
622 |
|
|
|
|
|
|
|
|
|
Debt issued |
|
|
|
|
|
|
52,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,521 |
|
|
$ |
52,052 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of debt to shares |
|
|
|
|
|
|
|
|
|
|
|
|
Extinguishment of debt |
|
$ |
|
|
|
$ |
4,737 |
|
|
$ |
|
|
Extinguishment of interest |
|
|
|
|
|
|
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
4,862 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares issued for bonuses and services |
|
$ |
207 |
|
|
$ |
490 |
|
|
$ |
793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation capitalized |
|
$ |
|
|
|
$ |
175 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Changes in non-cash working capital items |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
$ |
(1,253 |
) |
|
$ |
3,509 |
|
|
$ |
(1,281 |
) |
Note receivable |
|
|
(225 |
) |
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
(175 |
) |
|
|
(48 |
) |
|
|
69 |
|
Accounts payable and accrued liabilities |
|
|
1,314 |
|
|
|
1,905 |
|
|
|
852 |
|
Income tax payable |
|
|
(120 |
) |
|
|
650 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(459 |
) |
|
|
6,016 |
|
|
|
(360 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(140 |
) |
|
|
7 |
|
|
|
(250 |
) |
Prepaid and other current assets |
|
|
41 |
|
|
|
(70 |
) |
|
|
86 |
|
Accounts payable and accrued liabilities |
|
|
163 |
|
|
|
(972 |
) |
|
|
(1,119 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
64 |
|
|
|
(1,035 |
) |
|
|
(1,283 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
(26 |
) |
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(421 |
) |
|
$ |
5,007 |
|
|
$ |
(1,643 |
) |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at December 31, 2009, and 2008, are composed entirely of bank
balances in checking accounts with excess cash in money market accounts which invest primarily in
government securities with less than 90 day maturities.
17. RELATED PARTY TRANSACTIONS
The Company has entered into agreements with a number of entities which are related or controlled
through common directors or shareholders. These entities provide access to an aircraft, the
services of administrative and technical personnel, and office space or facilities in Vancouver,
London and Singapore. The Company is billed on a cost recovery basis in most cases. For the year
ended December 31, 2009 the costs incurred in the normal course of business with respect to the
above arrangements amounted to $3.8 million ($3.0 million for 2008 and $3.3 million for 2007), and
have been measured at their exchange amount and are recorded in general and administrative and
business and technology expense in the statement of operations. As at December 31, 2009 amounts
included in accounts payable and accrued liabilities on the balance sheet under these arrangements
were $0.1 million ($0.1 million at December 31, 2008).
18.
ACQUISITION AND PROJECT RELATED AGREEMENTS
Mongolia
In November 2009, the Company completed the acquisition of PanAsian Petroleum Inc. (PPI) which
provides it with the exclusive right to explore, develop and produce oil or gas within Block XVI in
Mongolias Nyalga Basin. This transaction with PPI resulted in the Company issuing 2,683,291 common
shares in exchange for all of the issued and outstanding common shares of PPI. In addition,
existing purchase warrants in PPI were converted to 735,449 Ivanhoe purchase warrants that entitle
the holders to purchase Ivanhoes common shares at Cdn.$4.05 per share with an expiry in February
2011.
The consideration for this acquisition and net assets acquired are summarized as follows:
|
|
|
|
|
Purchase Consideration: |
|
|
|
|
2,683,291 shares of Ivanhoe at Cdn.$2.70 per share (1) |
|
$ |
6,899 |
|
735,449 warrants to purchase Ivanhoe shares(2) |
|
|
622 |
|
|
|
|
|
|
|
$ |
7,521 |
|
|
|
|
|
|
|
|
|
|
Net Assets Acquired: |
|
|
|
|
Cash |
|
$ |
29 |
|
Non-cash working capital, net |
|
|
(606 |
) |
Oil and gas properties unproved |
|
|
10,742 |
|
Future income tax liability |
|
|
(2,644 |
) |
|
|
|
|
|
|
$ |
7,521 |
|
|
|
|
|
|
|
|
(1) |
|
The Cdn.$2.70 was the closing share price on the TSX on November 26, 2009, the date
of acquisition. |
|
(2) |
|
See Note 8. |
62
Canada
In July 2008, the Company completed the acquisition of Talisman Energy Canadas (Talisman) 100%
working interests in two leases located in the Athabasca oil sands region in the Province of
Alberta, Canada. The total purchase price was Cdn.$90.0 million, of which an initial payment of
Cdn.$22.5 million was made on closing. In addition to this initial payment the Company issued a
promissory note to Talisman in the principal amount of Cdn.$12.5 million bearing interest at a rate
per year equal to the prime rate
plus 2% which matured and was paid on December 31, 2008 and a second promissory note to Talisman in
the principal amount of Cdn.$40.0 million bearing interest at a rate per annum equal to the prime
rate plus 2%, maturing in July 2011 and convertible (as to the outstanding principal amount), at
Talismans option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per
common share.
The Company may also be required to make a cash payment to Talisman of Cdn.$15 million if the
requisite government and other approvals necessary to develop the northern border of one of the
leases (the Contingent Payment) are obtained. No amount is recorded in the financial statements
for this payment as at December 31, 2008 as the chance of occurrence can not be determined at this
time.
Talisman retains a back-in right (the Back-in Right), exercisable once per lease until July 11,
2011, to re-acquire up to a 20% undivided interest in each lease. The purchase price payable by
Talisman were it to exercise the Back-in Right in respect of a particular lease would be an amount
equal to 20% of:
|
(a) |
|
100% of the Companys acquisition cost and certain expenses in respect of the
relevant lease if the Back-in Right is exercised on or before July 11, 2009; |
|
|
(b) |
|
150% of the Companys acquisition cost and certain expenses in respect of the
relevant lease if the Back-in Right is exercised after July 11, 2009 but on or before
July 11, 2010; or |
|
|
(c) |
|
200% of the Companys acquisition cost and certain expenses in respect of the
relevant lease if the Back-in Right is exercised after July 11, 2010 but on or before
July 11, 2011. |
Until July 11, 2011, Talisman has the right of first offer to acquire any interests in heavy oil
projects in the Province of Alberta that the Company or any of its subsidiaries wishes to sell,
excluding the acquired leases.
Ecuador
In October 2008, Ivanhoe Energy Ecuador Inc. (IE Ecuador) entered into a contract with Empresa
Estatal de Petroleos del Ecuador, Petroecuador (Petroecuador), the state oil company of Ecuador,
and its affiliate, Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador,
Petroproduccion (Petroproduccion) to explore and develop an exploration block in Ecuador that
includes the Pungarayacu heavy-oil field, utilizing the Companys HTLTM technology. IE
Ecuador is a wholly-owned subsidiary of Ivanhoe Energy Latin America Inc. (IE Latin America), a
wholly-owned subsidiary of the Company.
IE Ecuador will lead the development of the project. The contract is guaranteed by its parent
company IE Latin America, which will obtain or provide funding and financing for IE Ecuadors
operations under the contract. The contracts 30-year term may be extended by mutual agreement. To
recover its investments, costs and expenses, and to provide for a profit, IE Ecuador will receive
from Petroproduccion a payment of US$37.00 per barrel of oil produced and delivered to
Petroproduccion. The payment will be indexed (adjusted) quarterly for inflation, starting from the
contract date, using the weighted average of a basket of three US Government-published producer
price indices relating to steel products, refinery products and upstream oil and gas equipment.
19. DISCONTINUED OPERATIONS
In June of 2009, management commenced a process to sell all of the Companys United States oil and
gas exploration and production operations. On July 17, 2009, the Company completed the sale of its
wholly owned subsidiary Ivanhoe Energy (USA) Inc. for a purchase price of $39.2 million. The
purchaser acquired all of the Companys oil and gas exploration and production operations in
California and Texas and additional exploration acreage in California. An escrow deposit in the
amount of $2.0 million, which has been set aside from the sales proceeds, will be available to the
purchaser for a period of one year to satisfy any indemnification obligations of the Company. The
Company used approximately $5.2 million of the sales proceeds to repay an outstanding loan to a
third party financial institution holding a security interest in the subsidiary companys assets.
63
The operating results for this discontinued operation for the periods noted were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue |
|
$ |
5,455 |
|
|
$ |
18,120 |
|
|
$ |
12,270 |
|
Gain (loss) on derivative instruments |
|
|
189 |
|
|
|
278 |
|
|
|
(5,594 |
) |
Interest income |
|
|
8 |
|
|
|
98 |
|
|
|
152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,652 |
|
|
|
18,496 |
|
|
|
6,828 |
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
2,132 |
|
|
|
5,137 |
|
|
|
4,319 |
|
General and administrative |
|
|
139 |
|
|
|
2,413 |
|
|
|
1,972 |
|
Depletion and depreciation |
|
|
3,772 |
|
|
|
6,143 |
|
|
|
5,884 |
|
Interest expense and financing costs |
|
|
173 |
|
|
|
520 |
|
|
|
427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,216 |
|
|
|
14,213 |
|
|
|
12,602 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) before disposition |
|
|
(564 |
) |
|
|
4,283 |
|
|
|
(5,774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on disposition (net of tax of $29.6 million
for 2009, nil for 2008 and 2007) |
|
|
(23,357 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) from discontinued operations |
|
$ |
(23,921 |
) |
|
$ |
4,283 |
|
|
$ |
(5,774 |
) |
|
|
|
|
|
|
|
|
|
|
The carrying amounts of the major classes of assets and liabilities for this discontinued
operation were as follows:
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
|
|
|
Assets |
|
|
|
|
Current Assets: |
|
|
|
|
Cash and cash equivalents |
|
$ |
788 |
|
Accounts receivable |
|
|
1,067 |
|
Prepaid and other current assets |
|
|
172 |
|
Derivative instruments |
|
|
700 |
|
|
|
|
|
|
|
|
2,727 |
|
|
|
|
|
|
Oil and gas properties and equipment, net |
|
|
32,577 |
|
Future income tax assets |
|
|
29,600 |
|
Long term assets |
|
|
467 |
|
|
|
|
|
|
|
$ |
65,371 |
|
|
|
|
|
Liabilities |
|
|
|
|
Current Liabilities: |
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
874 |
|
Debt current portion |
|
|
5,200 |
|
Derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
6,074 |
|
|
|
|
|
|
Asset retirement obligations |
|
|
1,810 |
|
|
|
|
|
|
|
$ |
7,884 |
|
|
|
|
|
In conjunction with this asset disposition and the Companys focus on Calgary, Alberta, as a
key management center supporting business units within the Ivanhoe Energy group of companies the
Company decided to close its support office in Bakersfield. Total costs associated with this
closure, including severance and retention payments, are expected to be $0.4 million with nil
accrued as of December 31, 2009 and included in the accompanying operations.
64
20. SUBSEQUENT EVENT
In January 2010, the Company completed a Cdn.$125.0 million private placement (the Private
Placement) consisting of 41,666,667 special warrants (the Special Warrants) at Cdn.$3.00. Each
Special Warrant was converted into one common share of the Company and one-quarter of a share
purchase warrant following the issuance of a receipt for a prospectus by applicable Canadian
securities regulatory authorities, which occurred on February 10, 2010. Each whole share purchase
warrant entitles the holder to acquire one common share of the Company at an exercise price of
Cdn.$3.16 on or before January 26, 2011. The net proceeds from the Private Placement were
approximately Cdn.$120.2 million after deducting fees and commissions of Cdn.$4.3 million and the
expenses of the Private Placement of approximately Cdn.$0.5 million.
Under the terms of the Private Placement, an additional 8,333,333 Special Warrants issuable at
Cdn.$3.00 per Special Warrant were subject to an option, which was exercised in February 2010. The
net proceeds realized by the Company from the issue of the Special Warrants under option totaled
approximately Cdn.$24.3 million after deducting fees and commissions payable of Cdn.$0.63 million
and the expenses of approximately Cdn.$0.1 million. Each Special Warrant under option was converted
into one common share and one-quarter of a share purchase warrant following the issuance of a
receipt for a prospectus by applicable Canadian securities regulatory authorities, which occurred
on March 12, 2010.
In January 2010, the Companys wholly-owned subsidiaries, Sunwing Holding Corporation (Holdings)
and Sunwing Energy Ltd. (Sunwing), entered into an agreement with a third party (the Optionee)
whereby Sunwing granted to the Optionee a contingent option exercisable until January 2012 (the
Contingent Option) to make an equity investment in Sunwing. Upon exercise of the Contingent
Option, the Optionee would acquire an equity interest in Sunwing of approximately 15% at a price of
Cdn.$25 million. Unless accelerated upon the occurrence of certain events (including a sale or
change of control of Sunwing or an initial public offering of Sunwing securities), the Contingent
Option only becomes exercisable in January 2011. If, prior to the Contingent Option having become
exercisable, the Optionee exercises any share purchase warrants it holds to acquire common shares
of the Company, the Contingent Option will immediately terminate.
65
21. ADDITIONAL DISCLOSURES REQUIRED UNDER U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Companys consolidated financial statements have been prepared in accordance with GAAP as
applied in Canada. In the case of the Company, Canadian GAAP conforms in all material respects with
U.S. GAAP except for certain matters, the details of which are as follows:
Consolidated Balance Sheets
The application of U.S. GAAP has the following effects on consolidated balance sheet items as
reported under Canadian GAAP:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2009 |
|
|
As at December 31, 2008 |
|
|
|
Canadian |
|
|
Increase |
|
|
|
|
U.S. |
|
|
Canadian |
|
|
Increase |
|
|
|
|
U.S. |
|
|
|
GAAP |
|
|
(Decrease) |
|
|
Notes |
|
GAAP |
|
|
GAAP |
|
|
(Decrease) |
|
|
Notes |
|
GAAP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
21,512 |
|
|
$ |
|
|
|
|
|
$ |
21,512 |
|
|
$ |
38,477 |
|
|
$ |
|
|
|
|
|
$ |
38,477 |
|
Accounts receivable |
|
|
5,021 |
|
|
|
|
|
|
|
|
|
5,021 |
|
|
|
3,802 |
|
|
|
|
|
|
|
|
|
3,802 |
|
Note receivable |
|
|
225 |
|
|
|
|
|
|
|
|
|
225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid and other current assets |
|
|
771 |
|
|
|
|
|
|
|
|
|
771 |
|
|
|
637 |
|
|
|
|
|
|
|
|
|
637 |
|
Restricted cash |
|
|
2,850 |
|
|
|
|
|
|
|
|
|
2,850 |
|
|
|
850 |
|
|
|
|
|
|
|
|
|
850 |
|
Derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,459 |
|
|
|
|
|
|
|
|
|
1,459 |
|
Assets of discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,727 |
|
|
|
|
|
|
|
|
|
2,727 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Current Assets |
|
|
30,379 |
|
|
|
|
|
|
|
|
|
30,379 |
|
|
|
47,952 |
|
|
|
|
|
|
|
|
|
47,952 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties
and development costs, net |
|
|
158,392 |
|
|
|
(38,500 |
) |
|
(i) |
|
|
139,346 |
|
|
|
143,974 |
|
|
|
(38,500 |
) |
|
(i) |
|
|
114,385 |
|
|
|
|
|
|
|
|
20,315 |
|
|
(ii) |
|
|
|
|
|
|
|
|
|
|
9,929 |
|
|
(ii) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(iii) |
|
|
|
|
|
|
|
|
|
|
(1,018 |
) |
|
(iii) |
|
|
|
|
|
|
|
|
|
|
|
(861 |
) |
|
(iv) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets technology |
|
|
92,153 |
|
|
|
|
|
|
|
|
|
92,153 |
|
|
|
92,153 |
|
|
|
|
|
|
|
|
|
92,153 |
|
Long term assets |
|
|
839 |
|
|
|
|
|
|
|
|
|
839 |
|
|
|
152 |
|
|
|
451 |
|
|
(v) |
|
|
603 |
|
Assets of discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62,644 |
|
|
|
(24,890 |
) |
|
(xii) |
|
|
37,754 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
281,763 |
|
|
$ |
(19,046 |
) |
|
|
|
$ |
262,717 |
|
|
$ |
346,875 |
|
|
$ |
(54,028 |
) |
|
|
|
$ |
292,847 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
and accrued liabilities |
|
$ |
10,779 |
|
|
$ |
|
|
|
|
|
$ |
10,779 |
|
|
$ |
9,219 |
|
|
$ |
|
|
|
|
|
$ |
9,219 |
|
Income tax payable |
|
|
530 |
|
|
|
|
|
|
|
|
|
530 |
|
|
|
650 |
|
|
|
|
|
|
|
|
|
650 |
|
Debt current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
412 |
|
|
|
|
|
|
|
|
|
412 |
|
Derivative instruments |
|
|
|
|
|
|
8,249 |
|
|
(viii) |
|
|
8,249 |
|
|
|
|
|
|
|
1,121 |
|
|
(viii) |
|
|
1,121 |
|
Asset retirement obligation
- current portion |
|
|
753 |
|
|
|
|
|
|
|
|
|
753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities of discontinued
operations current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,074 |
|
|
|
|
|
|
|
|
|
6,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Current Liabilities |
|
|
12,062 |
|
|
|
8,249 |
|
|
|
|
|
20,311 |
|
|
|
16,355 |
|
|
|
1,121 |
|
|
|
|
|
17,476 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long term debt |
|
|
36,934 |
|
|
|
1,225 |
|
|
(iv) |
|
|
38,005 |
|
|
|
37,855 |
|
|
|
2,086 |
|
|
(iv) |
|
|
40,392 |
|
|
|
|
|
|
|
|
(154 |
) |
|
(iv) |
|
|
|
|
|
|
|
|
|
|
451 |
|
|
(v) |
|
|
|
|
Asset retirement obligations |
|
|
195 |
|
|
|
|
|
|
|
|
|
195 |
|
|
|
1,928 |
|
|
|
|
|
|
|
|
|
1,928 |
|
Long term obligation |
|
|
1,900 |
|
|
|
|
|
|
|
|
|
1,900 |
|
|
|
1,900 |
|
|
|
|
|
|
|
|
|
1,900 |
|
Future income tax liability |
|
|
22,643 |
|
|
|
|
|
|
|
|
|
22,643 |
|
|
|
29,600 |
|
|
|
|
|
|
|
|
|
29,600 |
|
Liabilities of discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,810 |
|
|
|
|
|
|
|
|
|
1,810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities |
|
|
73,734 |
|
|
|
9,320 |
|
|
|
|
|
83,054 |
|
|
|
89,448 |
|
|
|
3,658 |
|
|
|
|
|
93,106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share capital |
|
|
422,322 |
|
|
|
74,455 |
|
|
(vi) |
|
|
510,784 |
|
|
|
413,857 |
|
|
|
74,455 |
|
|
(vi) |
|
|
502,372 |
|
|
|
|
|
|
|
|
(551 |
) |
|
(vii) |
|
|
|
|
|
|
|
|
|
|
(498 |
) |
|
(vii) |
|
|
|
|
|
|
|
|
|
|
|
1,358 |
|
|
(ix) |
|
|
|
|
|
|
|
|
|
|
1,358 |
|
|
(ix) |
|
|
|
|
|
|
|
|
|
|
|
13,200 |
|
|
(viii) |
|
|
|
|
|
|
|
|
|
|
13,200 |
|
|
(viii) |
|
|
|
|
Purchase warrants |
|
|
19,427 |
|
|
|
(19,427 |
) |
|
(viii) |
|
|
|
|
|
|
18,805 |
|
|
|
(18,805 |
) |
|
(viii) |
|
|
|
|
Contributed surplus |
|
|
20,029 |
|
|
|
(3,197 |
) |
|
(vii) |
|
|
13,885 |
|
|
|
16,862 |
|
|
|
(3,250 |
) |
|
(vii) |
|
|
10,665 |
|
|
|
|
|
|
|
|
(2,947 |
) |
|
(viii) |
|
|
|
|
|
|
|
|
|
|
(2,947 |
) |
|
(viii) |
|
|
|
|
Convertible note |
|
|
2,086 |
|
|
|
(2,086 |
) |
|
(iv) |
|
|
|
|
|
|
2,086 |
|
|
|
(2,086 |
) |
|
(iv) |
|
|
|
|
Accumulated deficit |
|
|
(255,835 |
) |
|
|
(89,171 |
) |
|
|
|
|
(345,006 |
) |
|
|
(194,183 |
) |
|
|
(119,113 |
) |
|
|
|
|
(313,296 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Shareholders Equity |
|
|
208,029 |
|
|
|
(28,366 |
) |
|
|
|
|
179,663 |
|
|
|
257,427 |
|
|
|
(57,686 |
) |
|
|
|
|
199,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
and Shareholders Equity |
|
$ |
281,763 |
|
|
$ |
(19,046 |
) |
|
|
|
$ |
262,717 |
|
|
$ |
346,875 |
|
|
$ |
(54,028 |
) |
|
|
|
$ |
292,847 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66
Oil and Gas Properties and Development Costs
(i) There are certain differences between the full cost method of accounting for oil and gas
properties as applied in Canada and as applied in the U.S. The principal difference is in the
method of performing ceiling test evaluations under the full cost method of accounting rules. In
the ceiling test evaluation for U.S. GAAP purposes, the Company limits, on a country-by-country
basis, the capitalized costs of oil and gas properties, net of accumulated depletion, depreciation
and amortization and deferred income taxes, to (a) The present value of estimated future net
revenues computed by applying current prices of oil and gas reserves (with consideration of price
changes only to the extent provided by contractual arrangements) to estimated future production of
proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated
future expenditures (based on current costs) to be incurred in developing and producing the proved
reserves computed using a discount factor of ten percent and assuming continuation of existing
economic conditions; plus (b) the cost of properties not being amortized (e.g. major development
projects) and (c) the lower of cost or fair value of unproven properties included in the costs
being amortized less (d) income tax effects related to the difference between the book and tax
basis of the properties referred to in (b) and (c) above. If unamortized capitalized costs within a
cost center exceed this limit, the excess is charged as a provision for impairment in the statement
of operations. Amounts thus required to be written off shall not be reinstated for any subsequent
increase in the cost center ceiling. Unproved properties and major development projects are
assessed on a quarterly basis for possible impairments or reductions in value. If a reduction in
value has occurred, the impairment is transferred to the carrying value of proved oil and gas
properties. The Company performed the ceiling test in accordance with U.S. GAAP and determined that
for the year ended December 31, 2009 no impairment provision was required and no impairment
provision was required under Canadian GAAP.
(ii) The cumulative differences in the amount of impairment provisions between U.S. and
Canadian GAAP resulted in reductions in accumulated depletion.
(iii) As more fully described under Development Costs in Note 2, under Canadian GAAP, the
Company capitalizes certain development costs incurred for HTLTM and GTL projects
subsequent to executing a MOU to determine the technical and commercial feasibility of a project,
including studies for the marketability for the projects products. If no definitive agreement is
reached, then the projects capitalized costs, which are deemed to have no future value, are
written down and charged to the results of operations with a corresponding reduction in
HTLTM and GTL development costs. Under U.S. GAAP, feasibility, marketing and related
costs incurred prior to executing an HTLTM or GTL definitive agreement are considered to
be research and development and are expensed as incurred.
(iv) As described in Note 5, under Canadian GAAP the Company was required to bifurcate the
value of the Convertible Debt, allocating a portion to long term debt and a portion to equity.
Under U.S. GAAP, the convertible debt securities in their entirety are classified as debt. Under
Canadian GAAP this discount accretion was capitalized. To reconcile to U.S. GAAP the entire $2.1
million recorded in equity is reversed as well as the unamortized discount of $1.2 million and the
accreted discount that was capitalized in the amount of $0.9 million. In addition, because the
convertible note is not denominated in U.S. currency the remeasurement of the different carrying
value for U.S. GAAP results in an increase to net income. The foreign exchange gain of $0.2 million
is shown as a separate amount in the U.S. GAAP reconciliation of the Companys balance sheet shown
above and is adjusted to the Foreign Exchange Loss line item in the U.S. GAAP reconciliation of the
statement of operations below.
Deferred Financing Costs
(v) As more fully described under Financial Assets and Liabilities in Note 2, for Canadian
GAAP the Company accounts for deferred financing costs, or transaction costs, as a reduction from
the related liability and accounted for using the effective interest method. For U.S. GAAP
purposes, these costs are classified as other assets and amortized over the expected term of the
financial liability.
Shareholders Equity
(vi) In June 1999, the shareholders approved a reduction of stated capital in respect of the
common shares by an amount of $74.5 million being equal to the accumulated deficit as at December
31, 1998. Under U.S. GAAP, a reduction of the accumulated deficit such as this is not recognized
except in the case of a quasi reorganization.
67
(vii) Under Canadian GAAP, the Company accounts for all stock options granted to employees and
directors since January 1, 2002 using the fair value based method of accounting. Under this method,
compensation costs are recognized in the financial statements over the stock options vesting
period using an option-pricing model for determining the fair value of the stock options at the
grant date. Under U.S. GAAP, prior to January 1, 2006 the Company applied Accounting Principles
Board (APB) Opinion No. 25, as interpreted by Financial Accounting Standards Board (FASB)
Interpretation No. 44, in accounting for its stock option plan and did not recognize compensation
costs in its financial statements for stock options issued to employees and directors. Beginning
January 1, 2006 the Company applied the revision to FASBs Accounting Standards Codification
Manual (ASC) Topic 718 Stock Compensation (formerly Statement of Financial Accounting Standards
(SFAS) No. 123R) which supersedes APB No. 25, Accounting for Stock Issued to Employees. The
Company elected to implement this statement on a modified prospective basis whereby the Company
began recognizing stock based compensation in its U.S. GAAP results of operations for the unvested
portion of awards outstanding as at January 1, 2006 and for all awards granted after January 1,
2006. There are no significant differences between the accounting for stock options under Canadian
GAAP and U.S. GAAP subsequent to January 1, 2006.
(viii) The Company accounts for purchase warrants as equity under Canadian GAAP. The
accounting treatment of warrants under U.S. GAAP reflects the application of ASC Topic 815
Derivatives and Hedging (formerly SFAS No. 133). Under ASC Topic 815,, share purchase warrants
with an exercise price denominated in a currency other than a companys functional currency are
accounted for as derivative liabilities. Changes in the fair value of the warrants are required to
be recognized in the statement of operations each reporting period for U.S. GAAP purposes. At the
time that the Companys share purchase warrants are exercised, the value of the warrants will be
reclassified to shareholders equity for U.S. GAAP purposes. Under Canadian GAAP, the fair value of
the warrants on the issue date is recorded as a reduction to the proceeds from the issuance of
common shares, with the offset to the warrant component of equity. The warrants are not revalued to
fair value under Canadian GAAP.
(ix) Under U.S. GAAP, the aggregate value attributed to the acquisition of royalty rights
during 1999 and 2000 was $1.4 million higher, due to the difference between Canadian and U.S. GAAP
in the value ascribed to the shares issued, primarily resulting from differences in the recognition
of effective dates of the transactions.
68
Consolidated Statements of Operations
The application of U.S. GAAP had the following effects on net loss and net loss per share as
reported under Canadian GAAP:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
|
Canadian |
|
|
Increase |
|
|
|
|
U.S. |
|
|
|
GAAP |
|
|
(Decrease) |
|
|
Notes |
|
GAAP |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
24,968 |
|
|
$ |
|
|
|
|
|
$ |
24,968 |
|
Loss on derivative instruments |
|
|
(1,335 |
) |
|
|
(6,506 |
) |
|
(viii) |
|
|
(7,841 |
) |
Interest income |
|
|
25 |
|
|
|
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue |
|
|
23,658 |
|
|
|
(6,506 |
) |
|
|
|
|
17,152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
10,191 |
|
|
|
|
|
|
|
|
|
10,191 |
|
General and administrative |
|
|
21,693 |
|
|
|
|
|
|
|
|
|
21,693 |
|
Business and technology development |
|
|
9,501 |
|
|
|
150 |
|
|
(x) |
|
|
9,651 |
|
Depletion and depreciation |
|
|
19,868 |
|
|
|
(10,574 |
) |
|
(xi) |
|
|
9,294 |
|
Foreign exchange loss |
|
|
5,220 |
|
|
|
(154 |
) |
|
(iv) |
|
|
5,066 |
|
Interest expense and financing costs |
|
|
856 |
|
|
|
|
|
|
|
|
|
856 |
|
Provision for impairment of intangible asset and development costs |
|
|
1,903 |
|
|
|
(980 |
) |
|
(x) |
|
|
923 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Expenses |
|
|
69,232 |
|
|
|
(11,558 |
) |
|
|
|
|
57,674 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes |
|
|
(45,574 |
) |
|
|
5,052 |
|
|
|
|
|
(40,522 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Provision for) recovery of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(1,757 |
) |
|
|
|
|
|
|
|
|
(1,757 |
) |
Future |
|
|
9,600 |
|
|
|
|
|
|
|
|
|
9,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,843 |
|
|
|
|
|
|
|
|
|
7,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations |
|
|
(37,731 |
) |
|
|
5,052 |
|
|
|
|
|
(32,679 |
) |
Net income (loss) from discontinued operations (net of tax of $29.6 million) |
|
|
(23,921 |
) |
|
|
24,890 |
|
|
(xii) |
|
|
969 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss and Comprehensive Loss |
|
|
(61,652 |
) |
|
|
29,942 |
|
|
|
|
|
(31,710 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss from continuing operations, basic and diluted |
|
$ |
(0.13 |
) |
|
$ |
0.01 |
|
|
|
|
$ |
(0.12 |
) |
Net Income (loss) from discontinued operations, basic and diluted |
|
|
(0.09 |
) |
|
|
0.10 |
|
|
|
|
|
0.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss per share, basic and diluted |
|
$ |
(0.22 |
) |
|
$ |
0.11 |
|
|
|
|
$ |
(0.11 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of shares (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted |
|
|
279,722 |
|
|
|
|
|
|
|
|
|
279,722 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
|
Canadian |
|
|
Increase |
|
|
|
|
U.S. |
|
|
|
GAAP |
|
|
(Decrease) |
|
|
Notes |
|
GAAP |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
48,370 |
|
|
$ |
|
|
|
|
|
$ |
48,370 |
|
Gain on derivative instruments |
|
|
1,688 |
|
|
|
4,665 |
|
|
(viii) |
|
|
6,353 |
|
Interest income |
|
|
612 |
|
|
|
|
|
|
|
|
|
612 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue |
|
|
50,669 |
|
|
|
4,665 |
|
|
|
|
|
55,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
21,515 |
|
|
|
|
|
|
|
|
|
21,515 |
|
General and administrative |
|
|
14,252 |
|
|
|
|
|
|
|
|
|
14,252 |
|
Business and technology development |
|
|
6,453 |
|
|
|
|
|
|
|
|
|
6,453 |
|
Depletion and depreciation |
|
|
25,761 |
|
|
|
(2,820 |
) |
|
(xi) |
|
|
22,941 |
|
Foreign exchange loss |
|
|
1,527 |
|
|
|
|
|
|
|
|
|
1,527 |
|
Interest expense and financing costs |
|
|
1,309 |
|
|
|
|
|
|
|
|
|
1,309 |
|
Provision for impairment of intangible asset and development costs |
|
|
15,054 |
|
|
|
(4,640 |
) |
|
(x) |
|
|
10,414 |
|
Write off of deferred financing costs |
|
|
2,621 |
|
|
|
|
|
|
|
|
|
2,621 |
|
Provision for impairment of oil and gas properties |
|
|
|
|
|
|
21,560 |
|
|
(ix) |
|
|
21,560 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Expenses |
|
|
88,492 |
|
|
|
14,100 |
|
|
|
|
|
102,592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes |
|
|
(37,822 |
) |
|
|
(9,435 |
) |
|
|
|
|
(47,257 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current recovery of income taxes |
|
|
(654 |
) |
|
|
|
|
|
|
|
|
(654 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations |
|
|
(38,476 |
) |
|
|
(9,435 |
) |
|
|
|
|
(47,911 |
) |
Net income (loss) from discontinued operations |
|
|
4,283 |
|
|
|
(19,423 |
) |
|
(xii) |
|
|
(15,140 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss and Comprehensive Loss |
|
|
(34,193 |
) |
|
|
(28,858 |
) |
|
|
|
|
(63,051 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss from continuing operations, basic and diluted |
|
$ |
(0.15 |
) |
|
$ |
(0.04 |
) |
|
|
|
$ |
(0.19 |
) |
Net Income (loss) from discontinued operations, basic and diluted |
|
|
0.02 |
|
|
|
(0.07 |
) |
|
|
|
|
(0.05 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss per share, basic and diluted |
|
$ |
(0.13 |
) |
|
$ |
(0.11 |
) |
|
|
|
$ |
(0.24 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of shares (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted |
|
|
258,815 |
|
|
|
|
|
|
|
|
|
258,815 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007 |
|
|
|
Canadian |
|
|
Increase |
|
|
|
|
U.S. |
|
|
|
GAAP |
|
|
(Decrease) |
|
|
Notes |
|
GAAP |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
31,365 |
|
|
$ |
|
|
|
|
|
$ |
31,365 |
|
Loss on derivative instruments |
|
|
(4,993 |
) |
|
|
592 |
|
|
(iii) |
|
|
(4,401 |
) |
Interest income |
|
|
317 |
|
|
|
|
|
|
|
|
|
317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue |
|
|
26,689 |
|
|
|
592 |
|
|
|
|
|
27,281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs |
|
|
13,000 |
|
|
|
|
|
|
|
|
|
13,000 |
|
General and administrative |
|
|
9,803 |
|
|
|
|
|
|
|
|
|
9,803 |
|
Business and technology development |
|
|
9,625 |
|
|
|
|
|
|
|
|
|
9,625 |
|
Depletion and depreciation |
|
|
20,640 |
|
|
|
(3,470 |
) |
|
(ix) |
|
|
17,170 |
|
Foreign exchange loss |
|
|
301 |
|
|
|
|
|
|
|
|
|
301 |
|
Interest expense and financing costs |
|
|
623 |
|
|
|
|
|
|
|
|
|
623 |
|
Provision for impairment of intangible asset and development costs |
|
|
|
|
|
|
(6,011 |
) |
|
(x) |
|
|
(6,011 |
) |
Provision for impairment of oil and gas properties |
|
|
6,130 |
|
|
|
(280 |
) |
|
(ix) |
|
|
5,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Expenses |
|
|
60,122 |
|
|
|
(9,761 |
) |
|
|
|
|
50,361 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations |
|
|
(33,433 |
) |
|
|
10,353 |
|
|
|
|
|
(23,080 |
) |
Net income (loss) from discontinued operations |
|
|
(5,774 |
) |
|
|
1,462 |
|
|
|
|
|
(4,312 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss and Comprehensive Loss |
|
|
(39,207 |
) |
|
|
11,815 |
|
|
|
|
|
(27,392 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss from continuing operations, basic and diluted |
|
$ |
(0.14 |
) |
|
$ |
0.04 |
|
|
|
|
$ |
(0.10 |
) |
Net Income (loss) from discontinued operations, basic and diluted |
|
|
(0.02 |
) |
|
|
0.01 |
|
|
|
|
|
(0.01 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss per share, basic and diluted |
|
$ |
(0.16 |
) |
|
$ |
0.05 |
|
|
|
|
$ |
(0.11 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of shares (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted |
|
|
242,362 |
|
|
|
|
|
|
|
|
|
242,362 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Costs
(x) As more fully described under Oil and Gas Properties and Development Costs in this note,
for Canadian GAAP, feasibility, marketing and related costs incurred prior to executing a
HTLTM or GTL definitive agreement are capitalized and are subsequently written down upon
determination that a projects future value has been impaired. For U.S. GAAP, such costs are
considered to be research and development and are expensed as incurred.
As more fully described under Note 3, the Company and INPEX have signed an agreement to
jointly pursue the opportunity to develop a heavy oil field in Iraq that Ivanhoe believes is a
suitable candidate for its patented HTLTM heavy oil upgrading technology. In the second
quarter of 2007, the Company received a $9.0 million payment related to this agreement which was
credited to the carrying value of its Iraq and CDF HTLTM Investments related to this
project for Canadian GAAP purposes. The prior costs for Iraq projects had previously been expensed
for U.S. GAAP purposes therefore that portion of the proceeds, $6.3 million, was credited to the
statement of operations for U.S. GAAP purposes. For the year ended December 31, 2009 the Company
recorded nil (nil in 2008 and $6.3 million in 2007) as a reduction to net loss for U.S. GAAP when
compared to Canadian GAAP due to the recovery of prior costs expensed for U.S. GAAP and capitalized
for Canadian GAAP.
As more fully described under Note 3, the Company wrote off $5.1 million in GTL development
costs under Canadian GAAP. These costs had already been expensed under U.S. GAAP in previous
periods and therefore this transaction reduced the net loss for U.S. GAAP purposes in 2008.
Depletion and Depreciation
(xi) As discussed under Oil and Gas Properties and Development Costs in this note, there is
a difference between U.S. and Canadian GAAP in performing the ceiling test evaluation under the
full cost method of accounting rules. Application of the ceiling test evaluation under U.S. GAAP
has resulted in an accumulated net increase in impairment provisions on the Companys U.S. and
China oil and gas properties. This net increase in U.S. GAAP impairment provisions has resulted in
lower depletion rates for U.S. GAAP purposes and a reduction in the net losses for the years ended
December 31, 2009, 2008 and 2007.
71
Discontinued Operations
(xii) As at December 31, 2008, the $24.9 million adjustment related to discontinued operations
included a $1.4 million increase that is attributed to the acquisition of royalty rights during
2000 and 1999 due to the difference between Canadian and U.S. GAAP in the value ascribed to the
shares issued, primarily resulting from differences in the recognition of effective dates of the
transactions, Additionally, there was a $3.1 million increase due to depletion differences as more
fully described in note (ii). These increases were offset by $29.4 million decrease due to
impairment differences as more fully described in note (i).
These accumulated balance sheet adjustments were charged off as part of the gain/loss
calculation at the time of sale and flow through the statement of operations for the year ended
December 31, 2009 in the Net Loss from Discontinued Operations line item.
Consolidated Statements of Cash Flows
As a result of the expensing of HTLTM and GTL development costs as required under U.S.
GAAP and the recovery of such costs, the statement of cash flows as reported would result in cash
(deficit) surplus from operating activities of $(12.4 million), $16.6 million and $11.5 million for
the years ended December 31, 2009, 2008 and 2007. Additionally, capital investments reported under
investing activities would be $26.2 million, $20.7 million and $28.3 million for the years ended
December 31, 2009, 2008 and 2007, respectively.
Additional U.S. GAAP Disclosures
Oil and Gas Properties and Development Costs
The categories of costs included in Oil and Gas Properties and Development Costs, including the
U.S. GAAP adjustments discussed in this note were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Technology |
|
|
|
|
|
|
Canada |
|
|
Ecuador |
|
|
Asia |
|
|
Corporate |
|
|
Development |
|
|
Total |
|
Property acquisition costs |
|
$ |
77,093 |
|
|
$ |
852 |
|
|
$ |
42,298 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
120,243 |
|
Capitalized Interest |
|
|
3,049 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,049 |
|
Exploration costs |
|
|
6,437 |
|
|
|
2,988 |
|
|
|
32,831 |
|
|
|
|
|
|
|
|
|
|
|
42,256 |
|
Development costs |
|
|
|
|
|
|
|
|
|
|
87,100 |
|
|
|
|
|
|
|
|
|
|
|
87,100 |
|
Production facilities |
|
|
|
|
|
|
2,483 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,483 |
|
HTLTM facilities |
|
|
6,991 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,868 |
|
|
|
17,859 |
|
Support equipment and general property |
|
|
24 |
|
|
|
601 |
|
|
|
427 |
|
|
|
968 |
|
|
|
22 |
|
|
|
2,042 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93,594 |
|
|
|
6,924 |
|
|
|
162,656 |
|
|
|
968 |
|
|
|
10,890 |
|
|
|
275,032 |
|
Accumulated depletion and depreciation |
|
|
(8 |
) |
|
|
(53 |
) |
|
|
(79,521 |
) |
|
|
(650 |
) |
|
|
(404 |
) |
|
|
(80,636 |
) |
Provision for impairment |
|
|
|
|
|
|
|
|
|
|
(55,050 |
) |
|
|
|
|
|
|
|
|
|
|
(55,050 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
93,586 |
|
|
$ |
6,871 |
|
|
$ |
28,085 |
|
|
$ |
318 |
|
|
$ |
10,486 |
|
|
$ |
139,346 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Technology |
|
|
|
|
|
|
Canada |
|
|
Ecuador |
|
|
China |
|
|
Corporate |
|
|
Development |
|
|
Total |
|
Property acquisition costs |
|
$ |
75,732 |
|
|
$ |
863 |
|
|
$ |
31,137 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
107,732 |
|
Capitalized Interest |
|
|
1,672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,672 |
|
Exploration costs |
|
|
3,686 |
|
|
|
591 |
|
|
|
31,575 |
|
|
|
|
|
|
|
|
|
|
|
35,852 |
|
Development costs |
|
|
|
|
|
|
|
|
|
|
83,315 |
|
|
|
|
|
|
|
|
|
|
|
83,315 |
|
HTLTM facilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,590 |
|
|
|
19,590 |
|
Support equipment and general property |
|
|
20 |
|
|
|
90 |
|
|
|
412 |
|
|
|
13 |
|
|
|
406 |
|
|
|
941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
81,110 |
|
|
|
1,544 |
|
|
|
146,439 |
|
|
|
13 |
|
|
|
19,996 |
|
|
|
249,102 |
|
Accumulated depletion and depreciation |
|
|
(6 |
) |
|
|
|
|
|
|
(72,030 |
) |
|
|
(6 |
) |
|
|
(7,628 |
) |
|
|
(79,670 |
) |
Provision for impairment |
|
|
|
|
|
|
|
|
|
|
(55,050 |
) |
|
|
|
|
|
|
|
|
|
|
(55,050 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
81,104 |
|
|
$ |
1,544 |
|
|
$ |
19,359 |
|
|
$ |
7 |
|
|
$ |
12,368 |
|
|
$ |
114,382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72
As at December 31, 2009, the costs of unproved properties included in oil and gas properties, which
have been excluded from the depletion and ceiling test calculations, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred in |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior to |
|
|
|
Total |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property Acquisition |
|
$ |
89,206 |
|
|
$ |
11,920 |
|
|
$ |
77,187 |
|
|
$ |
|
|
|
$ |
99 |
|
Exploration |
|
|
25,530 |
|
|
|
17,655 |
|
|
|
6,325 |
|
|
|
129 |
|
|
|
1,421 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
114,736 |
|
|
$ |
29,575 |
|
|
$ |
83,512 |
|
|
$ |
129 |
|
|
$ |
1,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of unproved oil and gas properties by prospect as at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred in |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior to |
|
|
|
Total |
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2007 |
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tamarack |
|
$ |
93,570 |
|
|
$ |
12,480 |
|
|
$ |
81,090 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ecuador |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Block 20 |
|
|
6,755 |
|
|
|
5,301 |
|
|
|
1,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Zitong Block |
|
|
3,249 |
|
|
|
632 |
|
|
|
968 |
|
|
|
129 |
|
|
|
1,520 |
|
Nyalga Block |
|
|
11,162 |
|
|
|
11,162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,411 |
|
|
|
11,794 |
|
|
|
968 |
|
|
|
129 |
|
|
|
1,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
114,736 |
|
|
$ |
29,575 |
|
|
$ |
83,512 |
|
|
$ |
129 |
|
|
$ |
1,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
With regard to the Tamarack Project in Canada, the Company plans to continue on the path for
submitting a regulatory application, for the first phase of development, in the 3rd quarter of
2010.
With regard to Block 20 in Ecuador, the Company began drilling the first well in the appraisal
phase at the end of 2009 and will be evaluating the results through the end of the first quarter of
2010. Additional wells are planned for the first and second quarter of 2010.
With regard to the Zitong Block prospect, drilling at two locations is planned to commence in
the second quarter of 2010 with expected completed drilling, completion and evaluation of the
prospects finalized in late 2010, which would satisfy the Phase II exploration.
With regard to the Nyalga Block prospect, the Company plans to initiate a seismic program in
the first quarter of 2010 and complete a drilling and testing program by the end of 2012, which
would satisfy the exploration phase.
73
Accounts Payable and Accrued Liabilities
The following was the breakdown of accounts payable and accrued liabilities:
|
|
|
|
|
|
|
|
|
|
|
As at December 31, |
|
|
|
2009 |
|
|
2008 |
|
Trade payables |
|
$ |
3,767 |
|
|
$ |
4,659 |
|
Accrued general and administrative expenses |
|
|
784 |
|
|
|
1,112 |
|
Accrued operating expenses |
|
|
515 |
|
|
|
394 |
|
Accrued capital expenditures |
|
|
2,820 |
|
|
|
1,896 |
|
Accrued salaries and related expenses |
|
|
2,123 |
|
|
|
148 |
|
Accrued interest |
|
|
770 |
|
|
|
1,010 |
|
|
|
|
|
|
|
|
|
|
$ |
10,779 |
|
|
$ |
9,219 |
|
|
|
|
|
|
|
|
Accounting Standards Codification 820 Fair Value Measurements and Disclosures (ASC 820) establishes
a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair
value. The three levels of the fair value hierarchy are described below:
Level 1: Input values based on unadjusted quoted prices in active markets for
identical assets or liabilities that the reporting entity has the ability to access at
the measurement date.
Level 2: Input values based on other than quoted prices included within Level 1 that
are observable for the asset or liability, either directly or indirectly.
Level 3: Input values are unobservable inputs for the asset or liability.
As required by ASC 820-10-35-37, when the inputs used to measure fair value fall within different
levels of the hierarchy, the level within which the fair value measurement is categorized, is based
on the lowest level input that is significant to the fair value measure in its entirety.
The following table presents the companys fair value hierarchy for those assets and liabilities
measured at fair value on a recurring basis as of December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2009 |
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments liabilities |
|
$ |
7,582 |
|
|
$ |
|
|
|
$ |
667 |
|
|
$ |
8,249 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value measurement of derivative instruments liabilities related to its purchase warrants
denominated in Cdn.$ that are traded on the TSX are considered Level 1, while the fair value
measurement of derivative instruments liabilities related to its purchase warrants denominated in
Cdn.$ that are not traded on the TSX are considered Level 3.
Impact of New and Pending U.S. GAAP Accounting Standards
In June 2009, the FASB issued guidance now codified as ASC Topic 105, Generally Accepted
Accounting Principles, as the single source of authoritative nongovernmental U.S. GAAP. ASC Topic
105 does not change current U.S. GAAP, but is intended to simplify user access to all authoritative
U.S. GAAP by providing all authoritative literature related to a particular topic in one place. All
existing accounting standard documents will be superseded and all other accounting literature not
included in the FASB Codification will be considered non-authoritative. These provisions of ASC
Topic 105 are effective for interim and annual periods ending after September 15, 2009 and,
accordingly, are effective for our current fiscal reporting period. The adoption of this
pronouncement did not have an impact on the Companys financial position or results of operations,
but did impact our financial reporting process by eliminating all references to pre-codification
standards. On the effective date of this Statement, the Codification superseded all then-existing
non-SEC accounting and reporting standards, and all other non-grandfathered non-SEC accounting
literature not included in the Codification became non-authoritative.
As a result of the Companys implementation of this codification during 2009, previous references
to new accounting standards and literature are no longer applicable. In these annual financial
statements, the Company has provided reference to both new and old
guidance to assist in understanding the impacts of recently adopted accounting literature,
particularly for guidance adopted since the beginning of the current fiscal year but prior to the
ASC.
74
Also in June 2009, the FASB issued guidance for Amendments to FAS 46R in ASC Topic 810 (formerly
SFAS No. 167) of the Codification, which improves financial reporting by enterprises involved with
variable interest entities. The amendments replace the quantitative-based risks and rewards
calculation for determining which enterprise, if any, has a controlling financial interest in a
variable interest entity with an approach focused on identifying which entity has the power to
direct the activities of a variable interest entity that most significantly impact the entitys
economic performance and: (1) the obligation to absorb losses of the entity; or, (2) the right to
receive benefits from the entity. The amendments are effective as of the beginning of the first
annual reporting period that begins after November 15, 2009, and shall be applied prospectively.
The Company is currently reviewing the potential impact, if any, this guidance will have on the
consolidated financial statements upon adoption.
Also in June 2009, the FASB issued guidance for Accounting for Transfers of Financial Assets, an
Amendment to FAS 140 in ASC Topic 860 (formerly SFAS No. 140, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities-a replacement of FASB Statement
No. 125, as amended by SFAS No. 166, Accounting for Transfers of Financial Assets An Amendment of
FASB Statement No. 140) of the Codification, which is effective for fiscal years beginning after
November 15, 2009, which amends prior principles to require more disclosure about transfers of
financial assets and the continuing exposure, retained by the transferor, to the risks related to
transferred financial assets, including securitization transactions. It eliminates the concept of a
qualifying special-purpose entity, changes the requirements for derecognizing financial assets,
and requires additional disclosures. It also enhances information reported to users of financial
statements by providing greater transparency about transfers of financial assets and an entitys
continuing involvement in transferred financial assets. The Company is currently reviewing the
potential impact, if any, this guidance will have on the Companys consolidated financial
statements upon adoption.
In May 2009, the FASB issued guidance in the ASC Topic 855 Subsequent Events (formerly SFAS No.
165) of the Codification, which establishes the accounting for and disclosure of events that occur
after the balance sheet date but before financial statements are issued or are available to be
issued. It requires the disclosure of the date through which an entity has evaluated subsequent
events and the basis for that date, that is, whether that date represents the date the financial
statements were issued or were available to be issued. The guidance was effective for interim or
annual periods ending after June 15, 2009. The adoption of this guidance did not have a material
impact on the Companys consolidated financial statements. In February 2010, the issued Accounting
Standards Update No. 2010-09 Subsequent Events (Topic 855) Amendments to Certain Recognition and
Disclosure Requirements which provides amendments to Subtopic 855-10 to alleviate potential
conflicts between Subtopic 855-10 and the SECs requirements with regard to subsequent event
disclosures. An entity that is an SEC filer is required to evaluate subsequent events through the
date that the financial statements are issued and is not required to disclose the date through
which subsequent events have evaluated.
In April 2009, the FASB issued guidance in the ASC Topic 820 Fair Value Measurements and
Disclosures (formerly FASB Staff Position (FSP) FAS 157-4) of the Codification on determining
fair value when the volume and level of activity for an asset or liability have significantly
decreased and identifying transactions that are not orderly. The guidance emphasizes that even if
there has been a significant decrease in the volume and level of activity, the objective of a fair
value measurement remains the same. Fair value is the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation
or distressed sale) between market participants. The guidance provides a number of factors to
consider when evaluating whether there has been a significant decrease in the volume and level of
activity for an asset or liability in relation to normal market activity. In addition, when
transactions or quoted prices are not considered orderly, adjustments to those prices based on the
weight of available information may be needed to determine the appropriate fair value. The
guidance was effective for interim or annual reporting periods ending after June 15, 2009, and
shall be applied prospectively. The implementation of this guidance did not have a material impact
on the Companys consolidated financial statements.
In April 2009, FASB issued guidance in the ASC Topic 825 Financial Instruments (formerly FSP FAS
107-1 and APB 28-1) of the Codification on interim disclosures about fair value of financial
instruments. The guidance requires disclosures about the fair value of financial instruments for
both interim reporting periods, as well as annual reporting periods. The guidance was effective
for all interim and annual reporting periods ending after June 15, 2009 and shall be applied
prospectively. The implementation of this guidance did not have a material impact on the Companys
consolidated financial statements as at December 31, 2009, other than the additional disclosure in
Note 12.
75
In March 2008, FASB issued guidance in the ASC Topic 815 Derivatives and Hedging (formerly SFAS
No. 161) of the Codification on improved financial reporting about derivative instruments and
hedging activities by requiring enhanced disclosures to enable investors to better understand the
effects on an entitys financial position, financial performance and cash flows. The guidance was
effective beginning January 1, 2009. Management has complied with the disclosure requirements of
this recent statement see additional disclosures under Commodity Price Risks under Note 12 to
these financial statements.
In February 2008, FASB issued guidance in the Effective Date of FASB Statement No. 157 ASC Topic
820 (formerly FSP FAS 157-2) of the Codification, which amended SFAS No. 157 to delay the effective
date of SFAS No. 157 for non-financial assets and non-
financial liabilities until fiscal years beginning after November 15, 2008, and interim periods
within those fiscal years, except for items that are recognized or disclosed at fair value in the
financial statements on a recurring basis. The implementation of this Topic, which was effective
January 1, 2009, did not have a material impact on the Companys consolidated financial statements.
In December 2007, the FASB issued guidance in ASC Topic 805 Business Combinations (formerly SFAS
No. 141(R), Business Combinations). The standard requires the acquiring entity in a business
combination to recognize all (and only) the assets acquired and liabilities assumed in the
transaction; establishes the acquisition date fair value as the measurement objective for all
assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and
other users all of the information they need to evaluate and understand the nature and financial
effect of the business combination. In April 2009, the FASB issued FSP FAS 141(R)-1 which amends
and clarifies SFAS No. 141(R) to address application issues raised by preparers, auditors and
members of the legal profession on initial recognition and measurement, subsequent measurement and
accounting, and disclosure of assets and liabilities arising from contingencies in a business
combination. This statement shall be applied prospectively. The implementation of SFAS No. 141(R)
and FSP FAS 141(R)-1, effective January 1, 2009, did not have a material impact on the companys
consolidated financial statements.
In December 2007, the FASB issued guidance in the ASC Topic 810 Consolidation (formerly SFAS No.
160) of the Codification on the accounting for non-controlling (minority) interests in consolidated
financial statements. This guidance clarifies the classification of non-controlling interests in
consolidated statements of financial position and the accounting for and reporting of transactions
between the reporting entity and holders of such non-controlling interests. This guidance was
effective as of the beginning of an entitys first fiscal year that began on or after December 15,
2008 and was required to be adopted prospectively, except for the reclassification of
non-controlling interests to equity and the recasting of net income (loss) attributable to both the
controlling and non-controlling interests, which were required to be adopted retrospectively. The
Company adopted this guidance effective January 1, 2009, and did not have a material impact on the
consolidated financial statements.
In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the
existing Regulation S-K and Regulation S-X reporting requirements to align with current industry
practices and technological advances. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the
new disclosure requirements require a company to (a) disclose its internal control over reserves
estimation and report the independence and qualification of its reserves preparer or auditor, (b)
file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve
audit and (c) report oil and gas reserves using an average price based upon the prior 12-month
period rather than period-end prices. The provisions of this final ruling became effective for
disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009. The
implementation of this Rule, did not have a material impact on the Companys consolidated financial
statements.
In August 2009, the FASB issued Accounting Standards Update (ASU) 2009 05 Fair Value
Measurements and Disclosures (Topic 820) Measuring Liabilities at Fair Value (ASU 09-05), which
became effective the first reporting period (including interim periods) beginning after issuance.
ASU 09-05 requires entities to measure the fair value of liabilities using one or more of several
prescribed valuation techniques within the ASU when quoted prices in an active market for the
identical liability are not available. The ASU also clarifies that: entities are not required to
include separate inputs or adjustments to other inputs relating to the existence of restrictions
that prevent the transfer of liabilities when estimating their fair value; and quoted prices in
active markets for identical liabilities at the measurement date and the quoted prices for
identical liabilities traded as assets in active markets when adjustments to the quoted prices of
assets are required are Level 1 fair value measurements. The adoption of this standard did not have
a material impact on the Companys financial statements.
76
QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND U.S. GAAP (UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
4th Qtr |
|
|
3rd Qtr |
|
|
2nd Qtr |
|
|
1st Qtr |
|
|
4th Qtr |
|
|
3rd Qtr |
|
|
2nd Qtr |
|
|
1st Qtr |
|
Total revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian GAAP |
|
$ |
4,999 |
|
|
$ |
7,991 |
|
|
$ |
4,844 |
|
|
$ |
5,824 |
|
|
$ |
19,525 |
|
|
$ |
26,159 |
|
|
$ |
(3,249 |
) |
|
$ |
8,235 |
|
U.S. GAAP |
|
$ |
2,263 |
|
|
$ |
6,826 |
|
|
$ |
4,280 |
|
|
$ |
3,783 |
|
|
$ |
24,920 |
|
|
$ |
40,800 |
|
|
$ |
(15,453 |
) |
|
$ |
5,068 |
|
Net income (loss) from
continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian GAAP |
|
$ |
(11,915 |
) |
|
$ |
(2,795 |
) |
|
$ |
(11,444 |
) |
|
$ |
(11,577 |
) |
|
$ |
(16,321 |
) |
|
$ |
4,822 |
|
|
$ |
(18,547 |
) |
|
$ |
(8,430 |
) |
U.S. GAAP |
|
$ |
(12,385 |
) |
|
$ |
(1,151 |
) |
|
$ |
(8,985 |
) |
|
$ |
(10,158 |
) |
|
$ |
(27,188 |
) |
|
$ |
20,206 |
|
|
$ |
(30,201 |
) |
|
$ |
(10,728 |
) |
Net income (loss) from
discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(net of tax): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian GAAP |
|
$ |
|
|
|
$ |
(23,290 |
) |
|
$ |
66 |
|
|
$ |
(697 |
) |
|
$ |
2,341 |
|
|
$ |
5,240 |
|
|
$ |
(3,184 |
) |
|
$ |
(114 |
) |
U.S. GAAP |
|
$ |
41 |
|
|
$ |
(689 |
) |
|
$ |
1,151 |
|
|
$ |
466 |
|
|
$ |
(18,212 |
) |
|
$ |
5,618 |
|
|
$ |
(2,780 |
) |
|
$ |
234 |
|
Net income (loss) per share
continuing operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian GAAP |
|
$ |
(0.04 |
) |
|
$ |
(0.01 |
) |
|
$ |
(0.04 |
) |
|
$ |
(0.04 |
) |
|
$ |
(0.06 |
) |
|
$ |
0.02 |
|
|
$ |
(0.08 |
) |
|
$ |
(0.03 |
) |
U.S. GAAP |
|
$ |
(0.04 |
) |
|
$ |
(0.00 |
) |
|
$ |
(0.03 |
) |
|
$ |
(0.04 |
) |
|
$ |
(0.11 |
) |
|
$ |
0.08 |
|
|
$ |
(0.12 |
) |
|
$ |
(0.04 |
) |
Net income (loss) per share
discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian GAAP |
|
$ |
0.00 |
|
|
$ |
(0.09 |
) |
|
$ |
0.00 |
|
|
$ |
(0.00 |
) |
|
|
0.01 |
|
|
|
0.02 |
|
|
$ |
(0.01 |
) |
|
$ |
(0.00 |
) |
U.S. GAAP |
|
$ |
0.00 |
|
|
$ |
(0.00 |
) |
|
$ |
0.00 |
|
|
$ |
0.01 |
|
|
|
(0.06 |
) |
|
|
0.02 |
|
|
$ |
(0.01 |
) |
|
$ |
0.00 |
|
The differences in the net loss and net loss per share for the second quarter of 2008 were mainly
due to an additional negative $12.2 million fair value adjustment of derivative instruments for
U.S. GAAP. The differences in the net income and net income per share for the third quarter of 2008
were mainly due to an additional $14.6 million positive fair value adjustment of derivative
instruments for U.S. GAAP. The differences in the net loss and net loss per share for the fourth
quarter of 2008 were mainly due to the additional ceiling test write downs for U.S. GAAP.
SUPPLEMENTARY DISCLOSURES ABOUT OIL AND GAS PRODUCTION ACTIVITIES (UNAUDITED)
(all tabular amounts are expressed in thousands of U.S. Dollars, except reserves and depletion rate
amounts)
The following information about the Companys oil and gas producing activities is presented in
accordance with Accounting Standards Codification 932 Extractive Activities Oil and Gas (section
235-55) formerly U.S. SFAS No. 69, Disclosures About Oil and Gas Producing Activities.
On December 31, 2008, the SEC issued final rules relating to reserve definitions and related
disclosure requirements. The rules are effective for estimates and disclosures made in annual
reports on Form 10-K for fiscal years ended on or after December 31, 2009, including those in this
report. The impact of the new rules on our reserves estimates also require us to modify our
reserves disclosures this year to transition our reserves estimates from the old rules to the new
rules. We have chosen to report our transition to the new rules in a manner that we believe best
illustrates the impact of the changes on our reserves estimates and allows us to clearly present
how our reserves estimates changed during 2009 as a result of our operational activities separate
from the adoption of the new rules. The unaudited supplemental information on oil and gas
exploration and production activities for 2009 has been presented in accordance with the new
reserve estimation and disclosure rules, which may not be applied retrospectively. The 2007 and
2006 data are presented in accordance with FASB oil and gas disclosure requirements effective
during those periods.
Oil and Gas Reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible from
a given date forward, from known reservoirs, and under existing economic conditions, operating
methods, and government regulations.
Proved developed oil and gas reserves are proved reserves that can be expected to be recovered: (i)
through existing wells with existing equipment and operating methods or in which the cost of the
required equipment is relatively minor compared to the cost of a new well; and (ii) through
installed extraction equipment and infrastructure operational at the time of the reserves estimate
if the extraction is by means not involving a well.
77
Estimates of oil and gas reserves are subject to uncertainty and will change as additional
information regarding the producing fields and technology becomes available and as future economic
conditions change.
Reserves presented in this section represent the Companys share of reserves, excluding royalty
interests of others. The reserves were based on the estimates by the independent petroleum
engineering firm of GLJ Petroleum Consultants Ltd.
The changes in the Companys net proved oil reserves for the three-year period ended December 31,
2009 were as follows:
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
|
China |
|
Net proved reserves, December 31, 2006 |
|
|
1,785 |
|
Revisions of previous estimates |
|
|
(22 |
) |
Production |
|
|
(483 |
) |
|
|
|
|
Net proved reserves, December 31, 2007 |
|
|
1,280 |
|
Revisions of previous estimates |
|
|
242 |
(1) |
Production |
|
|
(490 |
) |
|
|
|
|
Net proved reserves, December 31, 2008 |
|
|
1,032 |
|
Revisions of previous estimates |
|
|
535 |
(2) |
Production |
|
|
(466 |
) |
|
|
|
|
Net proved reserves, December 31, 2009 |
|
|
1,101 |
|
|
|
|
|
|
|
|
(1) |
|
The oil reserve revision is due to better performance of the Dagang property in
relation to the 2007 Reserve Report. |
|
(2) |
|
The oil reserve revision is due to improved production and fracture performance of the
Dagang property in relation to what was estimated in the 2008 Reserve Report. |
|
|
|
|
|
Net proved developed reserves as at: |
|
|
|
|
December 31, 2007 |
|
|
1,071 |
|
December 31, 2008 |
|
|
862 |
|
December 31, 2009 |
|
|
885 |
|
During 2009 the Company performed 6 fracture stimulations for approximately $3.7 million including
capitalized overhead. This resulted in re-classing a portion of our proved undeveloped reserves
into proved developed reserves.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil
and Gas Reserves
For the year ended December 31, 2009, future net cash flows were computed using prices used in
estimating the Companys proved oil reserves (12-month historical average), and current costs, and
statutory tax rates (adjusted for tax deductions) that relate to existing proved oil reserves. For
the years ended December 31, 2008 and 2007, future net cash flows were computed using year end
prices, year-end costs, and statutory tax rates. The following standardized measure of discounted
future net cash flows from proved oil reserves was computed using prices of $58.00, $41.57 and
$92.90 per barrel of oil in 2009, 2008 and 2007, respectively. A discount rate of 10% was applied
in determining the standardized measure of discounted future net cash flows.
The Company does not believe that this information reflects the fair market value of its oil and
gas properties. Actual future net cash flows will differ from the presented estimated future net
cash flows in that:
|
|
|
future production from proved reserves will differ from estimated production; |
|
|
|
|
future production may also include production from probable and possible reserves; |
|
|
|
|
future, rather than average annual, prices and costs will apply; and |
|
|
|
|
existing economic, operating and regulatory conditions are subject to change. |
78
The standardized measure of discounted future net cash flows as at December 31 in each of the three
most recently completed financial years were as follows:
|
|
|
|
|
|
|
2009 |
|
|
|
China |
|
Future cash inflows |
|
$ |
63,862 |
|
Future development and restoration costs |
|
|
3,307 |
|
Future production costs |
|
|
36,825 |
|
Future income taxes |
|
|
593 |
|
|
|
|
|
Future net cash flows |
|
|
23,137 |
|
10% annual discount |
|
|
4,589 |
|
|
|
|
|
Standardized measure |
|
$ |
18,548 |
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
China |
|
Future cash inflows |
|
$ |
42,906 |
|
Future development and restoration costs |
|
|
3,310 |
|
Future production costs |
|
|
22,934 |
|
|
|
|
|
Future net cash flows |
|
|
16,662 |
|
10% annual discount |
|
|
2,576 |
|
|
|
|
|
Standardized measure |
|
$ |
14,086 |
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
China |
|
Future cash inflows |
|
$ |
118,911 |
|
Future development and restoration costs |
|
|
5,190 |
|
Future production costs |
|
|
52,446 |
|
Future income taxes |
|
|
1,010 |
|
|
|
|
|
Future net cash flows |
|
|
60,265 |
|
10% annual discount |
|
|
10,674 |
|
|
|
|
|
Standardized measure |
|
$ |
49,591 |
|
|
|
|
|
Note: |
|
|
The Company is using current costs in the preparation of the information shown in the tables
above and to determine proved reserves. However, future production costs may not be easily
comparable to historical production costs. The two main causes for this difficulty in analyzing of
future production costs when compared to historical spending are summarized as follows:
|
|
1. |
|
In March 2006, the Ministry of Finance of the Peoples Republic of China (PRC) issued
the Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation
Business (the Windfall Levy Measures). According to the Windfall Levy Measures,
effective as of March 26, 2006, enterprises exploiting and selling crude oil in the PRC are
subject to a windfall gain levy (the Windfall Levy) if the monthly weighted average price
of crude oil is above $40 per barrel. The Windfall Levy is imposed at progressive rates
from 20% to 40% on the portion of the weighted average sales price exceeding $40 per
barrel. As a result, the cost associated with the Windfall Levy is not related to
production volumes but instead is related to the commodity price. As an example, as oil
prices increased during 2008, the amount of the Windfall Levy also increased significantly,
resulting in $13.46 per barrel (bbl) increase in 2008 when compared to 2007. The Windfall
Levy accounted for $21.14 per bbl cost of the total $43.92 per bbl operating costs in our
China operations, or in absolute terms $10.4 million of the total $21.5 million. This
compared to only $4.00 per bbl or $1.9 million in absolute terms incurred during 2009. |
|
2. |
|
Effective January 1, 2009 the Dagang field reached Commercial Production status as
defined by the Production Sharing Contract with our partner CNPC. The effect of this change
is that the Company no longer pays 100% of operating costs but now pays 82%, representing
the pre-cost recovery proportionate share. Effective September 1, 2009 the project
reached cost recovery and the working interests changed to 51% CNPC and 49% for the
Company. In our 2008 independent reserve report that was used to prepare the standardized
measure disclosures above, the 49/51% reversion was estimated based on total costs yet to
recover. |
79
Changes in standardized measure of discounted future net cash flows as at December 31 in each of
the three most recently completed financial years were as follows:
|
|
|
|
|
|
|
2009 |
|
|
|
China |
|
Sale of oil and gas, net of production costs |
|
$ |
(14,777 |
) |
Net changes in prices and production costs |
|
|
6,396 |
|
Net change in future development costs |
|
|
(3,536 |
) |
Development costs incurred during the period
that reduced future development costs |
|
|
3,712 |
|
Revisions of previous quantity estimates |
|
|
11,106 |
|
Accretion of discount |
|
|
1,409 |
|
Net change in income taxes |
|
|
(593 |
) |
Changes in production rates (timing) and other |
|
|
745 |
|
|
|
|
|
Increase |
|
|
4,462 |
|
Standardized measure, beginning of year |
|
|
14,086 |
|
|
|
|
|
Standardized measure, end of year |
|
$ |
18,548 |
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
China |
|
Sale of oil and gas, net of production costs |
|
$ |
(26,855 |
) |
Net changes in prices and production costs |
|
|
(21,620 |
) |
Net change in future development costs |
|
|
(2,708 |
) |
Development costs incurred during the period
that reduced future development costs |
|
|
4,720 |
|
Revisions of previous quantity estimates |
|
|
3,739 |
|
Accretion of discount |
|
|
4,959 |
|
Net change in income taxes |
|
|
925 |
|
Changes in production rates (timing) and other |
|
|
1,335 |
|
|
|
|
|
Decrease |
|
|
(35,505 |
) |
Standardized measure, beginning of year |
|
|
49,591 |
|
|
|
|
|
Standardized measure, end of year |
|
$ |
14,086 |
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
China |
|
Sale of oil and gas, net of production costs |
|
$ |
(18,365 |
) |
Net changes in prices and production costs |
|
|
16,322 |
|
Net change in future development costs |
|
|
(3,545 |
) |
Development costs incurred during the period
that reduced future development costs |
|
|
10,188 |
|
Revisions of previous quantity estimates |
|
|
(898 |
) |
Accretion of discount |
|
|
4,279 |
|
Net change in income taxes |
|
|
(925 |
) |
Changes in production rates (timing) and other |
|
|
(257 |
) |
|
|
|
|
Increase |
|
|
6,799 |
|
Standardized measure, beginning of year |
|
|
42,792 |
|
|
|
|
|
Standardized measure, end of year |
|
$ |
49,591 |
|
|
|
|
|
80
Costs incurred in oil and gas property acquisition, exploration, and development activities for the
Companys Oil and Gas Properties were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
$ |
1,361 |
|
|
$ |
75,732 |
|
|
$ |
|
|
Exploration |
|
|
11,119 |
|
|
|
5,357 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,480 |
|
|
|
81,089 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ecuador |
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
|
|
|
|
|
863 |
|
|
|
|
|
Exploration |
|
|
5,301 |
|
|
|
591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,301 |
|
|
|
1,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia |
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
|
11,161 |
|
|
|
|
|
|
|
|
|
Exploration |
|
|
1,253 |
|
|
|
1,956 |
|
|
|
11,611 |
|
Development |
|
|
3,785 |
|
|
|
6,420 |
|
|
|
11,881 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,199 |
|
|
|
8,376 |
|
|
|
23,492 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
33,980 |
|
|
$ |
90,919 |
|
|
$ |
23,492 |
|
|
|
|
|
|
|
|
|
|
|
The U.S. GAAP depletion rates, calculated on a per Boe of net production basis, were as follows:
|
|
|
|
|
China |
|
|
|
|
Year ended December 31, 2009 |
|
$ |
16.06 |
|
Year ended December 31, 2008 |
|
$ |
41.61 |
|
Year ended December 31, 2007 |
|
$ |
32.73 |
|
The results of operations from producing activities for the years ended December 31 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Oil and gas revenue |
|
$ |
24,968 |
|
|
$ |
48,370 |
|
|
$ |
31,365 |
|
Operating costs |
|
|
10,191 |
|
|
|
21,515 |
|
|
|
13,000 |
|
Depletion |
|
|
7,479 |
|
|
|
20,385 |
|
|
|
15,832 |
|
Provision for impairment |
|
|
|
|
|
|
21,560 |
|
|
|
5,850 |
|
|
|
|
|
|
|
|
|
|
|
Results of operations from
producing activities |
|
$ |
7,298 |
|
|
$ |
(15,090 |
) |
|
$ |
(3,317 |
) |
|
|
|
|
|
|
|
|
|
|
81