CALGARY, May 1 /CNW/ - Solana Resources Limited (TSX-V:SOR; AIM:SORL), the Colombia focused independent oil and gas exploration and production company, today announces its results for the year ended December 31, 2006. The complete financial statements and related financial disclosure are included in this release in order to comply with AIM rules.
Solana (www.solanaresources.com) is an international resource company engaged in the acquisition, exploration, development and production of oil and natural gas. The Company's properties are located in Colombia, South America and are primarily held through its wholly owned subsidiary, Solana Petroleum Exploration (Colombia) Limited. The Company is headquartered in Calgary, Alberta, Canada.
Highlights
- Significantly strengthened management team with Scott Price appointed
President and CEO and Glenn van Doorne appointed COO.
- Successfully disposed of 100% of rights and obligations under an
Exploration Participation Agreement (EPA) with Ramshorn International
Limited - removing significant prior financial commitments.
- Yalea-1 well was drilled and is currently producing 109 bopd net to
Solana.
- In March 2007, Solana participated in a potential new field discovery
with the Juanambu-1 well in the Guayuyaco block.
- Solana is a 50% participant in the Costayaco-1 well that is currently
drilling on the Chaza Block.
FINANCIAL REVIEW OF THE YEAR ENDED DECEMBER 31, 2006
The review that follows is a summary of Solana Resources Limited's ("Solana" or "the Company") activities and results ended December 31, 2006, its financial position at December 31, 2006 and its future prospects. Figures are expressed in thousands of United States dollars, unless otherwise indicated.
Additional information on Solana (which does not form part of this announcement) is available on the Company's website at www.solanaresources.com or on Sedar's website at www.sedar.com.
SIGNIFICANT ISSUES
CHANGE IN REPORTING CURRENCY
On October 1, 2006 the Company changed its reporting currency from Canadian dollars (Cdn$) to United States dollars ($) as this currency is more appropriate for the Company's investors and other users of the financial statements. In making this change, the Company has followed recommendations of the Emerging Issues Committee ("EIC") of the Canadian Institute of Chartered Accountants ("CICA"), set out in EIC-130, "Translation Method When The Reporting Currency Differs From The Measurement Currency or There is a Change in The Reporting Currency." (see Note 2 of the financial statements for details).
BREAKAWAY ACQUISITION
As announced in October 2006 and pursuant to a share purchase agreement dated October 4, 2006, the Company acquired all of the issued and outstanding shares of Breakaway Energy Inc. ("Breakaway") in exchange for the issuance of 10 million Solana shares and 10 million performance warrants.
The Breakaway acquisition terms were approved by the Company's Board of Directors as being in the best interest of the Company taking into account, among other issues, the need to attract, retain and reward top quality management (see Note 3 to the Financial Statements below for details).
ASSET CONSOLIDATION, DISPOSITION
Pursuant to a strategic review of the Company's asset portfolio, on February 8, 2007 but having effect from December 1, 2006, the Company signed and announced an agreement disposing 100% of its rights and obligations under an Exploration Participation Agreement (the EPA) with Ramshorn International Limited ("Ramshorn") to Ramshorn. This disposition resulted in changes to entitlements under the EPA but was otherwise for zero consideration. With this agreement, Ramshorn reacquired 100% of five Colombian oil and gas exploration prospects, specifically, Guayabillas, Puma, Guariquies, Alamo and Zeus.
Operations commenced on the EPA prospects in December 2004. As of December 1, 2006, Guayabillas and Alamo had been drilled and abandoned, Puma and Guariquies were being tested and Zeus remained to be drilled. No reserves have ever been allocated to the EPA assets.
IMPAIRMENT ADJUSTMENT
An impairment test calculation was performed at December 31, 2006 to determine if the asset carrying amounts exceeded estimated undiscounted future net cash flows associated with the Company's proved reserves. As a consequence of this calculation an impairment adjustment of $29,822,544 was recognized, principally in respect of the disposition of the EPA properties referenced above in Asset Consolidation, Disposition.
OPERATIONAL UPDATE
LLANOS BASIN
The Llanos basin is located northeast of Bogota, the capital of Colombia, on the east side of the Andes Mountains. This basin covers an area of approximately 200,000 km(2) (77,000 square miles) and holds Colombia's largest number of oil fields and proved oil reserves.
Solana has working interests in five blocks in the Llanos Basin, covering an area of 1,680 km(2) (649 square miles). These blocks are from North to South: Guachiría Norte, Guachiría, Guachiría Sur, Gaviotas and Garibay.
Petroleum Exploration International S.A. (Pexin) had obtained the right to a 30% working interest, upon the completion of certain work obligations, in Solana's Llanos Blocks, with the exception of Garibay. These work obligations involved funding 60% of five wells on Solana's Guachiría Norte, Guachiría, Guachiría Sur and Gaviotas Blocks. As at December 31, 2006 three wells of this five well commitment had been drilled, specifically Gaviotas 1, Bonaire 1 and Yalea 1 (as announced on June 5, 2006) and effective December 21, 2006, Pexin transferred 100% of its rights and obligations on these Blocks to Lewis Energy Colombia. Upon completion of this five well commitment Solana's interest will drop to 70% on these blocks.
GUACHIRÍA NORTE BLOCK
Solana is the Operator of the 412 km(2) (159 square miles) Guachiría Norte Block with a working interest of 100%. The block is located approximately 250 km (155 miles) northeast of Bogota and is subject to an Agencia Nacional de Hidrocarburos (ANH), the Government regulatory body, contract.
Phase 1 (December 21, 2004 to December 21, 2005) commitments were met with the drilling of the Bonaire-1 well. As announced on June 5, 2006, although, the well tested 7 m(3)/day (44 bopd) of waxy crude, a complete technical review, including petrophysical and reservoir parameter analysis, indicated that Bonaire-1 is not commercially viable. Solana now plans to abandon the well.
During Phase 2 (December 21, 2005 to December 21, 2006, extended to March 21, 2007) 56 line-km (35 line-miles) of seismic were acquired and interpreted. Also in Phase 2, a 157 km(2) (61 square miles) 3-D seismic survey, that was acquired in 2001 and reprocessed in 2005, was re-interpreted. This re-interpretation resulted in the identification of a very prospective channel system in the Carbonera depositional package.
In this part of the Llanos Basin, drilling activity is generally restricted to a four month weather window from December to March and as such Solana submitted an application to the ANH to extend the Phase 2 period to March 2007. The ANH approved this extension on the condition that Phases 3 and 4 are combined into one. During Phases 3 and 4 (March 21, 2007 to March 21, 2009) Solana is required to drill two exploration wells.
Subsequent to year end Solana drilled the Calcedonia-1 well. As announced March 26, 2007, this well reached a total depth of 2,480 meters (8,138 feet) and penetrated a thick Carbonera C7 structure that had oil shows and excellent reservoir parameters. Subsequent extensive testing proved the structure was water bearing and the well was temporarily abandoned. In the immediate vicinity there remains a significant Carbonera C5 channel target which the Company intends to test in the future subject to technical review, equipment availability, surface access and capital availability.
GUACHIRÍA BLOCK
Solana is the Operator of the 75 km(2) (29 square miles) Guachiría Block with a working interest of 100%. The block adjoins the Guachiría Norte Block immediately to the South. This block was acquired from Empresa Colombiana de Petroleos SA (Ecopetrol, the State owned oil Company), and is subject to a standard ANH contract plus an additional 13% royalty payable to Ecopetrol.
During Phase 1 (October 9, 2003 to October 9, 2004) the Malabares-1 well was drilled. As announced on June 23, 2004, following an inconclusive test the well was suspended, pending further evaluation.
During Phase 2 (October 9, 2004 to October 9, 2005, extended to June 1, 2006) the Bucaro-1 well was re-entered. As announced September 30, 2005, the well tested 123 m(3)/day (774 bopd) waxy crude but is currently shut in due to a high water cut. In May 2006 the Yalea-1 well was drilled. As announced June 5, 2006, Yalea-1 tested oil and is currently producing approximately 22 m(3)/day (136 bopd, 109 net to Solana).
For Phase 3 (June 1, 2006 to June 1, 2007), Ecopetrol agreed that Solana may substitute its well commitment for a 100 km(2) (39 square mile) 3-D seismic survey, covering the block, and overlapping the southern part of the adjacent Guachiría Norte 3-D seismic survey. This survey started in December 2006, data acquisition is now complete and processing and interpretation is underway. In this part of the Llanos Basin, drilling and seismic activity is generally restricted to a four month weather window from December to March.
GUACHIRÍA SUR BLOCK
Solana is the Operator of the 366 km(2) (141 square miles) Guachiría Sur Block with a working interest of 100%. The block is to the west and the south of the Guachiría Block and to the south of the Guachiría Norte Block. This block is subject to an ANH contract.
During Phase 1 (October 25, 2005 to October 25, 2006) 155 line-km (96 line-miles) of seismic data was acquired and 300 line-km (186 miles) of seismic data was reprocessed.
The commitment to drill a well during Phase 2 (October 25, 2006 to October 25, 2007) was renegotiated with the ANH and was replaced by a 120 km(2) (74 square mile) 3-D seismic survey and a commitment to drill one well during Phase 3 (October 25, 2007 to October 25, 2008). This survey started in December 2006 and covers the northern part of the block, immediately west and south of the Guachiría Block. Acquisition is now complete and processing and interpretation underway.
GAVIOTAS BLOCK
Solana is the Operator of the 377 km(2) (146 square miles) Gaviotas Block with a 100% working interest. In addition to Lewis Energy's 30% earning rights, a Colombian investment fund has a 20% participation right on individual Gaviotas wells. The Fund evaluates and elects its participation on a well by well basis. The block is located approximately 170 km (105 miles) east of Bogota and was acquired from Ecopetrol. It is subject to a standard ANH contract plus an additional 13% royalty payable to Ecopetrol.
During Phase 1 (December 18, 2003 to February 18, 2005) 50 line-km (31 line-miles) of seismic data was acquired.
During Phase 2 (February 18, 2005 to February 18, 2006, extended to May 18, 2006) the Gaviotas-1 well was drilled and 85 line-km (53 line-miles) of seismic was acquired and 650 line-km (404 line-miles) reprocessed. As announced June 5, 2006, although wire line logs of the Gaviotas-1 well indicated hydrocarbon bearing zones, tests were inconclusive. Further petrophysical evaluation of the logs indicated that Gaviotas-1 is not commercially viable. Solana plans to abandon the well.
There is a one well commitment for Phase 3 (May 18, 2006 to May 18, 2007) and Solana is planning to drill the Bevea-1 prospect during the second quarter of 2007.
GARIBAY BLOCK
Solana is the Operator of the 450 km(2) (174 square miles) Garibay Block with a working interest of 100%. The block is located approximately 170 km (105 miles) east of Bogota and 15 km (9 miles) south of the Gaviotas Block. This block is subject to an ANH contract.
During Phase 1 (October 25, 2005 to October 25, 2006) 136 line-km (85 line-miles) of seismic data was acquired and 300 line-km (186 line-miles) reprocessed.
During Phase 2 (October 25, 2006 to October 25, 2007) Solana is required to drill one well. The ANH has approved the replacement of this program with the acquisition of 100 km(2) (39 square miles) of 3-D seismic, subject to relinquishment of 30% of the block area. This survey started in March 2007.
PUTUMAYO BASIN
The Putumayo basin is located in southwest Colombia and extends into Ecuador, where it is called the Oriente (Ecuador)-Maranon (Peru) Basin. It covers an area of approximately 320,000 km(2) (124,000 square miles) and Solana holds interests in the Guayuyaco Block and the Chaza Block totaling 536 km(2) (207 square miles) in this basin.
GUAYUYACO BLOCK
Solana holds a 35% non-operated net working interest in the 212 km(2) (82 square mile) Guayuyaco Block, located approximately 290 km (180 miles) southwest of Bogota. Gran Tierra Energy Inc. is the Operator with a 35% working interest. Ecopetrol has a 30% working interest in the Guayuyaco field which is currently producing 120 m(3)/day (758 bopd, 244 bopd net to Solana). All commitments are fulfilled and the block is being further developed under an Association Contract.
Subsequent to year end, Solana participated in drilling the Juanambu-1 exploration well with a rig mobilized from Venezuela, as announced March 19, 2007. This well reached a total depth of 2,790 meters (9,154 feet) and has been cased as a potential new field discovery. Completion and testing operations are currently underway. Juanambu-1 is proximal to infrastructure allowing for early production. Solana paid for two thirds of this well to earn a 50% interest (35% if Ecopetrol elects to back-in).
CHAZA BLOCK
Solana has a 50% working interest in the 325 km(2) (125 square mile) Chaza Block, immediately west of the Guayuyaco Block. Gran Tierra, the operator, holds the other 50% in the block. The block is held under an ANH contract.
During Phase 1 (June 27, 2005 to June 26, 2006) Solana participated in the acquisition of 27 line-km (17 line-miles) of 2-D seismic and the reprocessing of 250 line-km (155 line-miles) of 2-D seismic data.
During Phase 2 (June 27, 2006 to June 26, 2007) the partners are required to drill one well. The Costayaco-1 well (previously named Naboyaco-1) is currently drilling.
PUMA PROSPECT
As announced February 8, 2007, effective December 1, 2006, Solana disposed 100% of its rights and obligations in the Puma Prospect (see Note 4 to the Financial Statements) with the exception that Solana may recoup its share of Puma-1 completion costs from a portion of any future Puma prospect production.
CATATUMBO BASIN
The Catatumbo Basin is a 7,350 km(2) sub-basin, forming the southwest flank of Venezuela's prolific Maracaibo Basin. Solana has two blocks in the Catatumbo sub-basin, namely Catguas and Carbonera, covering a total area of 1,878 km(2) (726 square miles).
CATGUAS BLOCK
Solana is the operator of the 1,592 km(2) (615 square miles) Catguas Block with an 85% working interest in the southernmost two-thirds of the Block. In the northern third, Solana has a 50% working interest. Solana's partner in this block is Well Logging Ltda, a Colombian company.
The block is held under an ANH contract. First Phase (November 17, 2005 to May 17, 2007) commitments were partially fulfilled by the acquisition of 200 line-km (124 line-miles) of seismic data and 10 line-km (six line- miles) of high resolution seismic.
Seismic interpretation and geochemical mapping have identified several drillable prospects. Two shallower structures, Tres Curvas-1 and Cocodrilo-1, have been selected and will be drilled as soon as a suitable rig has been identified. Drilling these two wells will complete Phase 1 work obligations.
CARBONERA BLOCK
Solana is the Operator with a 50% working interest in the 260 km(2) (100 square mile) Carbonera Block. Its partner is Well Logging Ltda. The block has a commitment to re-enter or drill one well before April 28, 2007.
Although Carbonera contains the Cerro Gordo gas discovery, due to lack of infrastructure, market remoteness and high carbon dioxide levels within the gas, Solana relinquished its Carbonera interest to Well Logging Ltda. on April 20, 2007.
ALAMO PROSPECT
As announced February 8, 2007, effective December 1, 2006, Solana disposed 100% of its rights and obligations in the Alamo Prospect (see Note 4 to the Financial Statements).
LOWER MAGDALENA BASIN
The Lower Magdalena basin is located in northwest Colombia. It covers an area of approximately 87,000 km(2) (33,500 square miles) and contains Solana's Magangue Block.
MAGANGUE BLOCK
The Magangue Block is held pursuant to the Magangue Association Contract. Solana is the operator of the block with a 37.8% working interest and has partners, Ecopetrol with 58%, and Technopetrol, a Colombian company, with 4.2%.
Solana operates the Guepaje gas field on the 169 km(2) (65 square mile) Magangue Block, which is currently producing 98,000 m(3)/day (3.5 mmcfd, 1.2 mmcfd net to Solana) and sold into the local market at $2.42/mmbtu. The well is slowly depleting and Solana is currently re-evaluating the available seismic, geological and petrophysical information to identify possible workover opportunities and other possible targets.
MIDDLE MAGDALENA BASIN
The Middle Magdalena Basin is located in central Colombia and Solana had interests in the Guariquies and Zeus prospects within this basin. Effective December 1, 2006, and as part of the Asset Consolidation, Disposition described above, Solana disposed 100% of its rights and obligations in both the Guariquies and Zeus Prospects (see Note 4 to the Financial Statements).
2006 YEAR-END RESERVES
COMPANY SHARE - CONSTANT PRICE CASE
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December 31, 2006 December 31, 2005
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OIL (MBbls) GAS (MMcf) OIL (MBbls) GAS (MMcf)
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Proved Developed Gross Net Gross Net Gross Net Gross Net
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Producing 263 242 1,972 1,846 340 313 - -
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Non Producing 338 311 - - 340 313 - -
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Proved Undeveloped 119 109 - - 119 109 - -
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Total Proved 720 662 1,972 1,846 799 736 - -
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Probable 222 204 95 89 234 216 - -
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TOTAL 942 866 2,067 1,935 1,034 951 - -
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Solana's independent reserve engineers, DeGolyer and MacNaughton Canada Limited, assign total net proved oil reserves of 662 MBbls and gas reserves of 1,846 MMcf for 2006. Oil reserves were lower than for 2005 due to Guayuyaco production. Reserve additions associated with the Yalea-1 2006 oil discovery slightly offset the Guayuyaco production. 2006 gas reserves result from the previously unrecognized Guepaje gas field.
DeGolyer and MacNaughton Canada Limited evaluated Solana's reserves in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers and the Canadian Institute of Mining, Metallurgy and Petroleum.
SUMMARY ASSET TABLE
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Asset Operator Interest Status Licence Licence Comments
(%) Expiry Area
Date
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Guayu- Gran 35% Production September 0.5km(2) Currently
yaco Tierra 30, producing
Field Energy 2024 244 bopd net
Inc. to Solana.
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Guayu- Gran 50%(1) Exploration March 212 km(2) Drilled
yaco Tierra 30, Juambu-1
Block Energy 2008 exploration
Inc. well in Q1
2007.
Potential
new field
discovery.
Currently
testing.
Contains the
Guayuyaco
field.
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Chaza Gran 50% Exploration June 325 km(2) Currently
Block Tierra 27, drilling the
Energy 2011(5) Costayaco-1
Inc. well.
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Guachi- Solana 100%(3) Exploration June 75 km(2) Contains
ria Colom- 01, Yalea-1
Block bia(1) 2010(6) well
currently
producing
on long term
test.
Interpreting
100 km(2) 3D
seismic
acquired
in Q1 2007.
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Guachi- Solana 100%(3) Exploration March 412 km(2) Calcedonia-1
ria Colom- 21, well
Norte bia(1) 2010(5) recently
Block drilled.
Evaluating
next
exploration
location.
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Guachi- Solana 100%(3) Exploration October 366 km(2) Interpreting
ria Colom- 25, 120 km(2) 3D
Sur bia(1) 2011(5) seismic
Block acquired in
Q1 2007.
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Gavio- Solana 100%(3)(4) Exploration November 377 km(2) Bevea-1 well
tas Colom- 18, expected to
Block bia(1) 2010(6) commence
drilling mid
to late May.
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Garibay Solana 100% Exploration October 450 km(2) Interpreting
Block Colom- 25, 100 km(2)
bia(1) 2011(5) recently
acquired 3D
seismic.
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Catguas Solana 85% Exploration November 461 km(2) Two well
A Block Colom- 17, drilling
bia(1) 2011(5) program,
Tres
Curvas-1 and
Cocodrilo-1,
to commence
in next 30 -
60 days
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Catguas Solana 50% Exploration November 1,131 km(2) Work program
B Block Colom- 17, is integral
bia(1) 2011(5) with Catguas
A only
difference
is working
interest
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Mangan- Solana 37.8% Exploration N/A 169 km(2) Contains the
gue Colom- Guepaje Gas
Block bia(1) field
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Guepaje Solana 37.8% Production January 84 km(2) Currently
Gas Colom- 1, producing
Field bia(1) 2018 1.2 MMscfd
net to
Solana
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Mary Gran 9.17% Production September n/a Currently
field Tierra 30, producing
(Inchi- Energy 2024 18 Bopd net
yaco Inc. to Solana
well)
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(1) Ecopetrol (the state oil and gas company) has the right to back-in
for 30% on any commercial discoveries on these blocks, in which case
Solana's interest would be reduced to 35%.
(2) Solana's Colombian entity is the operator of the indicated assets.
(3) Upon the completion of certain work obligations by a third party on
the indicated assets, the third party will earn a 30% interest in
these assets and Solana's interest will be reduced by 30%.
(4) A third party has the right to 20% of this asset on a well by well
basis. If this party elects to participate on a well, Solana's
interest would be reduced by 20%.
(5) A total of six exploration phases are available. Solana can terminate
its participation at the end of any exploration phase. The expiry
date indicated is the end of the sixth exploration phase. Any
commercial field discovered during an exploration phase will have a
24 year exploitation term.
(6) A total of six exploration phases are available. Solana can resign at
the end of any exploration phase. The expiry date indicated is the
end of the sixth exploration phase. Any commercial field discovered
during an exploration phase will have 22 years exploitation term
following the final exploration phase.
Glenn Van Doorne, Chief Operating Officer of Solana, a Petroleum Geologist, with 30 years of experience and a member of the AAPG and the SPE, is the qualified person that has reviewed the technical reserve, resource and drilling update information contained in these results.
OPERATING RESULTS
Selected Annual Information
The following table summarizes selected financial data for Solana for each of the three most recently completed financial years. Unless otherwise noted, all currency amounts are stated in United States dollars.
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2006 2005 2004
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$ $ $
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Production Revenue, net of
royalties 9,480,911 6,760,501 350,864
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Operating costs 3,123,305 1,454,204 394,327
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----------------------------------------
6,357,606 5,306,297 (43,463)
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Expenses
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General and administrative 4,602,952 2,849,913 964,060
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Depletion, depreciation and
accretion 5,675,320 4,809,927 1,246,080
-------------------------------------------------------------------------
Amortization 1,182,447 - -
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Impairment 29,822,544 - -
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Foreign exchange loss (gain) (2,145,686) (203,808) 428,204
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Stock-based compensation 1,512,938 1,801,780 938,946
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----------------------------------------
40,650,515 9,257,812 3,577,290
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Other income/expenses
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Interest and other 1,531,032 714,397 132,892
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Income taxes (5,153,272) (213,552) (153,238)
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----------------------------------------
Net loss (27,608,605) (3,450,670) (3,641,099)
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Net loss per share (0.34) (0.05) (0.12)
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2006 2005 2004
-------------------------------- ------------ ------------ ------------
$ $ $
Share capital and warrants 130,998,659 87,017,320 85,351,541
Working capital 37,106,929 24,407,788 48,750,038
Petroleum and natural gas
properties 54,313,189 63,142,705 37,638,845
Total assets 106,651,944 95,897,095 89,052,743
Total current liabilities 3,404,607 5,948,079 1,649,360
Shareholders' equity 101,690,514 84,180,499 81,984,051
This consolidated financial information includes the revenue and expenses of Solana Colombia for the years ended December 31, 2006 and 2005. During the year ended December 31, 2006, revenue from operations amounted to $9,480,911, which less the operating costs of $3,123,305, yielded an operating profit of $6,357,606. During the year ended December 31, 2005, the Company generated revenue of $6,760,501, which less operating costs of $1,454,204, yielded an operating profit of $5,306,297. The increase of $1,051,309 is due to a combination of a small increase in production (25,354 bbls) and higher oil prices ($40 on average during 2006 in comparison with $32 in 2005).
General and administrative expenses for the year ended December 31, 2006 amounted to $4,602,952 in comparison to $2,849,913 for the same period ended December 31, 2005. The major components of general and administrative expenses are as follows:
2006 2005
$ $
General office 404,102 486,790
Salaries 1,509,249 946,379
Professional fees 1,743,014 718,628
Public company costs 454,672 194,598
Consulting fees 196,363 353,583
Travel 295,552 149,935
-------------------------
4,602,952 2,849,913
All the categories of general and administrative expenses increased due to the significantly increased operation and exploration activities of the Company.
Depletion, depreciation and accretion amounted to $5,561,409 for the year ended December 31, 2006 in comparison to $4,809,927 for the year ended December 31, 2005. The depletion expense is calculated based on the decline in proved reserves pursuant to the Company's reserve report, and amounts to $5,520,977 in comparison to $4,670,866 for the year ended December 31, 2005. The increase is mainly due to the addition to the proved properties pool as a consequence of dry holes drilled during the year.
Depreciation amounts to $113,912 (2005 - $95,599) on the Company's capital assets, primarily office furniture, office equipment, vehicles and leasehold improvements.
Amortization of intangible assets amounted to $1,182,447 (2005 - Nil) which corresponds to 3/24 of the difference between the purchase price and the net assets acquired as part of the Breakaway acquisition (See Note 3 of the financial statements for details).
Accretion expense amounting to $40,432 (2005 - $48,730) is representative of the Company's future estimated costs to plug and abandon its petroleum and natural gas wells at the end of their useful lives.
For the year ended December 31, 2006, the Company's impairment charge amounted to $29,822,544 (Nil in 2005). This impairment was mainly a consequence of the asset disposition and termination of the EPA with Ramshorn.
The foreign exchange gain amounting to $2,145,686 (2005 - $203,808) reflects substantially the overall appreciation of the Colombian peso against the US dollar, and the appreciation of the CDN dollar against the US dollar by year end.
Stock-based compensation decreased to $1,512,938 (2005 - $1,801,780) primarily due to the amortization of costs associated with the vesting of options granted throughout 2006.
Other income and expenses relate to interest income in 2006 amounting to $1,531,032 compared to $714,397 in 2005 which is representative of the larger cash balances held throughout 2006.
The current income tax expense amounting to $201,233 (2005 - $213,552) istaxes based on presumptive income calculated as a percentage of Colombian equity levels and can be recovered against future income taxes for up to five years. $5,354,505 corresponds to re-assessment of deferred taxation calculation. The Company has approximately Cdn$7,421,000 (US$6,367,770) of Canadian non-capital loss carry forwards, and Colombian tax losses totaling Col$68,546 million (US$30,618,000) which are available to be carried forward. The consolidated financial statements do not reflect the potential tax benefit of these losses, as they do not meet the more likely than not criteria.
The resulting net loss amounting to $27,608,606 for 2006 relative to the net loss amounting to $3,450,670 for 2005 reflects mainly the impact of the impairment adjustment of $29,822,544 as explained above in the significant issues section.
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SUMMARY OF QUARTERLY RESULTS
QUARTERS ENDED
Dec 31, 2006 Sep 30, 2006 Jun 30, 2006 Mar 31, 2006
$ $ $ $
Additions to
Petroleum and
Natural Gas
properties 7,902,112 4,402,811 8,876,927 6,538,659
Total revenues 2,049,754 3,652,608 2,797,670 2,511,910
General and
administrative
expenses 2,042,166 423,640 1,197,315 939,831
Depletion,
depreciation and
accretion 3,958,215 886,985 957,026 1,055,540
Impairment 29,822,544 - - -
Foreign exchange
(income) loss 160,105 (3,424,333) 870,581 247,961
Stock-based
compensation 783,233 209,875 228,640 291,191
Income (loss)
after taxes (31,076,705) 4,989,157 (1,236,674) (284,386)
Income (loss) per
share (0.34) 0.09 (0.02) (0.01)
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Dec 31, 2005 Sep 30, 2005 Jun 30, 2005 Mar 31, 2005
$ $ $ $
Additions to
Petroleum and
Natural gas
properties 10,275,878 5,864,257 5,105,152 6,713,716
Total revenues 3,145,166 2,008,396 1,914,711 406,624
General and
administrative
expenses 960,537 591,813 718,549 579,014
Depletion,
depreciation and
accretion 3,976,602 324,854 399,308 109,163
Impairment - - - -
Foreign exchange
(income) loss (282,610) 196,813 328,394 (446,404)
Stock-based
compensation 653,304 361,237 294,326 492,911
Income (loss)
after taxes (1,951,707) (627,040) (439,104) (432,819)
Income (loss) per
share (0.05) (0.01) (0.02) (0.01)
-------------------------------------------------------------------------
LIQUIDITY
Solana's working capital increased from $24,407,788 in 2005 to $37,106,929 in 2006 substantially due to the placement of 21,000,000 shares in April, 2006.
Cash balances at December 31, 2006 amounting to $29,909,168 and net proceeds from the Company's April 2006 financing, amounting to $34,415,917, are committed to the Company's planned 2007 capital expenditure program in Colombia, which is substantially comprised of six exploration wells and 320 km(2) of 3D seismic. Management believes the Company currently has sufficient working capital to meet these commitments.
Shareholders' equity increased from $84,180,499 in 2005 to $101,690,514 as a result of additional financing net of a significant increase in the cumulative deficit due to the impairment adjustment generated by the asset consolidation (explained above as part of significant issues).
SUMMARY OF CASH INFLOWS AND OUTFLOWS
The Company incurred a cash inflow from operations amounting to $7,114,938 compared to cash inflows in 2005 of $5,453,812 primarily as a result of the oil production from the Guayuyaco field and future tax liability adjustments.
Solana's net cash inflow from financing activities amounted to $34,428,044 for 2006 compared to $1,068,388 in 2005.
The Company incurred cash outflows from its investing activities of $29,112,940 relative to $32,184,351 in 2005. The most significant component of the cash outflows was $25,534,161 ($27,807,764 in 2005) related to expenditures for petroleum and natural gas properties.
RELATED PARTY TRANSACTIONS
The Company paid $52,907 in fees in 2006 (2005 - $79,294) to a company controlled by Ray Antony, a director of the Company. These are included in general and administrative expense.
SUBSEQUENT EVENTS
Juanambu-1 Well
On March 10, 2007 Juanambu-1 reached a total measured depth of 2,790 meters (9,154 feet). As announced on March 19, 2007, the well was successfully drilled and logged, and is a potential new field discovery in the Guayuyaco Block, Putumayo Basin, in southern Colombia. Testing of four hydrocarbon zones is currently underway. Juanambu-1 is proximal to infrastructure allowing for early monetization of any potential commercial production.
Calcedonia-1 Well
On March 26, 2007 the Company announced that the Calcedonia-1 well, located in the Guachíra Norte Block in the Llanos Basin, Colombia, was drilled to a total depth of 8,138 feet. Following testing the well was temporarily abandoned. In the immediate vicinity there remains a significant Carbonera C5 channel target which the Company intends to test in the future subject to technical review, equipment availability, surface access and capital availability.
DISCLOSURE CONTROLS AND PROCEDURES
Management has evaluated the effectiveness of the Company's disclosure controls and procedures as of December 31, 2006. Based on this evaluation some improvements were introduced to existing controls to conclude that the Company's disclosure controls and procedures, as defined in Multilateral Instrument 52-109, are effective to ensure that the information required to be disclosed in reports that are filed or submitted under Canadian securities legislation are recorded, processed, summarized and reported within the time period specified in those rules.
MANAGEMENT'S ASSESSMENT OF INTERNAL CONTROLS
Management completed an assessment of the design of internal controls over financial reporting. During the process of management's assessment, it was determined that certain weaknesses existed in the complex areas of financial reporting and taxation accounting. As is indicative of many small companies, segregation of duties and the existence of full competences in a changing regulatory environment were identified as areas where weaknesses existed. The existence of these weaknesses has been addressed by implementation of alternate cost-effective controls and by the continuation of senior management monitoring and in the case of complex transactions, consulting with external experts to assist management in their analysis.
BUSINESS RISK AND UNCERTAINTIES
The Company's business is subject to risks inherent in oil and gas exploration and development operations. In addition, there are risks associated with the Company's development stage of operations and the foreign jurisdiction in which it operates. The Company has identified certain risks pertinent to its business, including: exploration and reserve risks, drilling and operating risks, costs and availability of materials and services, capital markets and the requirement for additional capital, loss of or changes to production sharing, joint venture or related agreements, economic and sovereign risks, possibly of less developed legal systems, reliance on strategic relationships, market risk, volatility of future oil and gas prices and foreign currency risk.
Solana attempts to monitor, assess and mitigate certain of these risks by retaining an experienced team of professionals and using modern technology. Further, the Company has focused its activities in known hydrocarbon basins in a jurisdiction that has previously established long-term oil and gas ventures with foreign oil and gas companies, existing infrastructure of services and oil and gas transportation facilities, and reasonable proximity to markets. The Company also retains consultants resident in Colombia to monitor economic and political developments and to assist with operating, administrative and legal matters. There are certain risks, however, over which the Company has little or no control.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Petroleum and Natural Gas Operations
Solana follows the full cost method to account for its petroleum and natural gas operations, whereby all costs of exploring for and developing petroleum and natural gas reserves are capitalized and accumulated in country-by-country cost centers. These capitalized costs will be depleted using the unit-of-production method based on estimates of proved reserves. The costs in cost centers from which there has been no commercial production are not subject to depletion until commercial production commences. These capitalized costs are assessed to determine whether it is likely such costs will be recovered in the future. Costs which are not likely to be recovered in the future are written off.
Petroleum and natural gas reserves form the basis for a number of accounting estimates and support for the carrying amount of petroleum and natural gas properties. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward, based on the results of future drilling, testing, production levels and economics of recovery based on flow forecasts.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS
This discussion and analysis contains forward-looking statements. Forward-looking statements are subject to numerous known and unknown risks and uncertainties, some of which are beyond Solana's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency exchange rate fluctuations, reserve estimates, environmental risks, and competition from other explorers, stock market volatility and ability to access sufficient capital. Solana's actual costs could differ materially from those anticipated in the forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements.
GLOSSARY OF RESERVE TERMS
Proved Reserves - Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable Reserves - Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved + probable reserves.
Possible Reserves - Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is equally unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved + probable + possible reserves.
Developed Reserves - Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and nonproducing.
Developed Producing Reserves - Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
Developed Nonproducing Reserves - Developed nonproducing reserves are those reserves that either have been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
Undeveloped Reserves - Undeveloped reserves are those reserves that are expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.
ABBREVIATIONS
CDN Canadian
U.S. United States
Col. Colombian Pesos
WTI West Texas Intermediate
Bbl barrel
Bopd barrels of oil per day
MBbls thousand barrels
MMBbls million barrels
Mcf thousand cubic feet
Mcfpd thousand cubic feet per day
MMcf million cubic feet
MMcfpd million cubic feet per day
Boe (x)barrel of oil equivalent
Boepd (x)barrel of oil equivalent per day
MBoe (x)thousand barrels of oil equivalent
NGL natural gas liquids
$MM million dollars
TSX-V TSX Venture Exchange
LSE London Stock Exchange
AIM Alternative Investment Market of the London Stock Exchange
MD&A Management's Discussion and Analysis
GAAP Generally Accepted Accounting Principles
G&A General and Administrative Expenses
(x) A Boe conversion ratio of 6 Mcf (equal sign) 1 Bbl has been used.
Boe's may be misleading, particularly if used in isolation. A Boe
conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
Consolidated Statements of Loss and Deficit
(Expressed in US Dollars)
2006 2005
$ $
(Note 2) (Note 2)
REVENUE
Oil and gas revenues, net of royalties 9,480,911 6,760,501
Interest and other 1,531,032 714,397
-------------------------------------------------------------------------
11,011,943 7,474,898
-------------------------------------------------------------------------
EXPENSES
Operating 3,123,305 1,454,204
General and administrative 4,602,952 2,849,913
Depletion, depreciation, accretion
and impairment (Notes 7,8,9) 36,680,312 4,809,927
Foreign exchange gain (2,145,686) (203,808)
Stock-based compensation (Note 12) 1,512,938 1,801,780
-------------------------------------------------------------------------
43,773,821 10,712,016
-------------------------------------------------------------------------
Loss before income taxes (32,761,878) (3,237,118)
Income taxes (Note 14) (5,153,272) 213,552
-------------------------------------------------------------------------
Net loss (27,608,606) (3,450,670)
Deficit, beginning of year (12,526,537) (9,075,867)
Deficit, end of year (40,135,143) (12,526,537)
-------------------------------------------------------------------------
Net loss per share, basic and diluted (Note 15) (0.34) (0.05)
-------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated
financial statements.
Consolidated Balance Sheets
(Expressed in US Dollars)
At the end of December
2006 2005
$ $
(Note 2) (Note 2)
ASSETS
CURRENT
Cash and cash equivalents 29,909,168 20,660,693
Cash in trust (Note 5) 3,274,262 392,696
Accounts receivable 6,297,798 7,005,654
Prepaid expenses 1,030,308 2,296,824
-------------------------------------------------------------------------
40,511,536 30,355,867
Deposits (Note 6) 3,041,509 1,843,389
Petroleum and natural gas properties (Note 7) 54,313,189 63,142,705
Other capital assets (Note 8) 543,080 552,894
Intangible assets (Notes 3,9) 8,036,403 -
Investment (Note 10) 206,227 2,240
-------------------------------------------------------------------------
106,651,944 95,897,095
-------------------------------------------------------------------------
LIABILITIES
CURRENT
Accounts payable and accrued liabilities 3,404,607 5,948,079
-------------------------------------------------------------------------
3,404,607 5,948,079
Asset retirement obligations (Note 11) 1,556,823 536,547
Future income taxes (Note 14) - 5,231,970
-------------------------------------------------------------------------
4,961,430 11,716,596
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital and warrants (Note 12) 130,998,659 87,017,320
Contributed surplus (Note 12) 5,035,075 3,522,137
Cumulative translation adjustment (Note 2) 5,791,923 6,167,579
Deficit (40,135,143) (12,526,537)
-------------------------------------------------------------------------
101,690,514 84,180,499
-------------------------------------------------------------------------
106,651,944 95,897,095
-------------------------------------------------------------------------
Commitments and Contingencies (Notes 3, 4, 7 and 11)
The accompanying notes are an integral part of these consolidated
financial statements.
Consolidated Statements of Cash Flows
(Expressed in US Dollars)
2006 2005
$ $
(Note 2) (Note 2)
SUMMARY OF ACTIVITIES
OPERATING ACTIVITIES
Net loss (27,608,606) (3,450,670)
Items not involving cash:
Unrealized foreign exchange (gain) loss 451,325 654,614
Stock-based compensation 1,512,938 1,801,779
Future tax liability (5,354,505) -
Depletion, depreciation,
accretion and impairment 36,680,312 4,809,927
-------------------------------------------------------------------------
5,681,464 3,815,650
Changes in working capital - operating 1,433,474 1,638,162
-------------------------------------------------------------------------
7,114,938 5,453,812
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Repayment of demand loan - (83,192)
Proceeds from issuance of common shares 34,415,917 -
Proceeds from exercise of warrants - 1,104,816
Proceeds from exercise of options 12,127 47,036
-------------------------------------------------------------------------
34,428,044 1,068,660
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to petroleum and natural
gas properties (25,534,161) (27,807,764)
Additions to other capital assets (104,098) (366,314)
Deposits (1,198,120) (1,774,184)
Investment (203,987) (2,156)
Changes in working capital - Investing 2,072,574 (2,233,933)
-------------------------------------------------------------------------
(29,112,940) (32,184,351)
-------------------------------------------------------------------------
Foreign exchange on cash balances (300,000) 270,000
-------------------------------------------------------------------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 12,130,042 (25,391,879)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 21,053,389 46,445,268
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF YEAR 33,183,431 21,053,389
-------------------------------------------------------------------------
Represented by:
Banks 6,696,625 1,758,212
Short term deposits 23,212,544 18,902,481
Cash in trust 3,274,262 392,696
-------------------------------------------------------------------------
33,183,431 21,053,389
-------------------------------------------------------------------------
The accompanying notes are an integral of these consolidated financial
statements
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2006 and 2005
(Figures are expressed in United States dollars, except otherwise
indicated)
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES
a. Basis of Presentation
The consolidated financial statements include the accounts of Solana
Resources Limited (the "Company") and its wholly-owned subsidiaries,
Solana Petroleum Exploration (Colombia) Limited ("Solana Colombia"),
Breakaway Energy Inc ("Breakaway") and Bayford Investments Limited
("Bayford").
b. Petroleum and Natural Gas Operations
The Company follows the full cost method of accounting for petroleum and
natural gas operations, whereby all costs of exploring for and developing
petroleum and natural gas reserves are capitalized in country-by-country
cost centres. Such costs include land acquisition costs, geological and
geophysical costs, carrying charges on non-producing properties, costs of
drilling both productive and non-productive wells, interest costs on
major development projects and overhead charges directly related to
acquisition, exploration and development activities.
The costs (including exploratory dry holes) in cost centres from which
there has been no commercial production are not subject to depletion
until commercial production commences. The capitalized costs are assessed
to determine whether it is likely such costs will be recovered in the
future. To the extent there are costs which are not likely to be
recovered in the future, they are written-off.
The costs in cost centres from which there is production, together with
the cost of production equipment, are depleted and depreciated on the
unit-of-production method, based on the estimated proved reserves after
royalties. Petroleum and natural gas reserves and production are
converted into equivalent units, based upon estimated relative energy
content. Costs of acquiring and evaluating significant unproved
properties are excluded from the depletion calculations. These unproved
properties are assessed to determine whether impairment has occurred.
When proved reserves are assigned or the carrying value of the property
is considered to be impaired, the cost of the property or the amount of
the impairment is added to costs subject to depletion.
Petroleum and natural gas properties are subject to a ceiling test in
each reporting period to determine that the costs are not impaired and do
not exceed the fair value of the properties. The costs are assessed to be
not impaired if the sum of the undiscounted cash flows expected from the
production of proved reserves and the cost of unproved properties, net of
impairment allowances of unproved properties exceed the carrying value of
the petroleum and natural gas properties. If the carrying value of the
petroleum and natural gas properties is determined to be impaired, an
impairment loss is recognized to the extent that the carrying value
exceeds an estimated fair value. The fair value estimate is normally
based on the sum of the discounted cash flows expected from the
production of proved and probable reserves plus the cost of unproved
properties, net of impairment allowances. The cash flows are estimated
using forecast product prices and costs and are discounted using a risk-
free interest rate.
Proceeds from the sale of petroleum and natural gas properties are
applied against capitalized costs, with no gain or loss recognized,
unless such a sale would alter the depletion rate by more than 20%.
c. Asset Retirement Obligations
The fair value of obligations associated with the retirement, removal and
site restoration of tangible long-lived assets are recorded in the period
the asset is put into use, with a corresponding increase to the carrying
amount of the related asset. The obligations recognized are estimates of
statutory, contractual or legal obligations that the Company will
reasonably be expected to incur and then discounted to their present
value using the Company's adjusted risk-free interest rate. The liability
is accreted over time for changes in the fair value of the liability
through charges to accretion which are included in depletion,
depreciation and accretion expense. The costs capitalized to the related
assets are amortized to earnings in a manner consistent with the
depletion and depreciation of the underlying asset. Actual costs incurred
upon settlement of the retirement obligation are charged against the
obligation to the extent of the liability recorded.
d. Joint Ventures
Substantially all of the Company's exploration, development and
production activities are conducted jointly with others and accordingly,
these financial statements reflect only the Company's proportionate
interest in such activities.
e. Revenue Recognition
Revenues associated with the sale of the Company's natural gas, natural
gas liquids and crude oil are recognized when title passes to the
customer.
f. Other Capital Assets
Office furniture, equipment and vehicles are recorded at cost.
Depreciation is calculated using the straight-line method based on the
estimated useful life of the assets. The annual depreciation rates used
for office furniture, equipment and vehicles are 10, 10 and 30%
respectively.
Leasehold improvements are recorded at cost. Amortization is calculated
based on the term of the lease.
g. Foreign Currency
All operations are considered financially and operationally integrated.
Results of operations of foreign subsidiaries are translated using
average exchange rates for revenues and expenses, except depletion,
depreciation and accretion which are translated at the rates of exchange
applicable to the related assets. Monetary items denominated in foreign
currencies are translated at exchange rates in effect at the balance
sheet date and non-monetary items are translated at rates of exchange in
effect when the assets were acquired or obligations incurred. Foreign
exchange gains and losses are recorded in the statements of loss and
deficit.
h. Stock-Based Compensation
The Company adopted the fair value method of accounting for stock
options. Stock-based compensation expense is calculated as the estimated
fair value using the Black-Scholes option-pricing model and is recorded
and reflected as stock-based compensation expense over the vesting period
with a corresponding amount reflected in contributed surplus. When
options are exercised, the associated amounts previously recorded as
contributed surplus are reclassified to common share capital.
i. Income Taxes
The Company follows the liability method of accounting for income taxes.
Under this method, future income tax assets and liabilities are measured
based upon temporary differences between the carrying values of assets
and liabilities and their tax basis. Future income tax assets are only
recognized to the extent it is more likely than not that sufficient
future taxable income will be available to allow the future income tax
asset to be realized.
j. Cash and Cash Equivalents
Cash and cash equivalents includes short-term investments with a maturity
of 90 days or less, when purchased.
k. Measurement Uncertainty
The consolidated financial statements are prepared in accordance with
Canadian generally accepted accounting principles. Management makes
estimates and assumptions that affect the reported amounts of assets,
including petroleum and natural gas properties, and liabilities,
including asset retirement obligations, and disclosure of contingent
assets and liabilities at the date of the consolidated financial
statements, and revenues and expenses, including depletion, depreciation
and accretion, and impairment, during the reporting period. By their
nature, these estimates are subject to measurement uncertainty and actual
results could differ materially from estimated amounts.
l. Loss per Share
The basic loss per share is determined using the weighted average number
of shares outstanding during the year. The company computes diluted loss
per share in the same manner as basic, except that the weighted average
number of diluted common shares is used as the denominator. The company
uses the treasury method in computing the weighted average of diluted
common shares outstanding. This method assumes that the proceeds on
exercise of in-the-money stock options are used to repurchase the
Company's common shares at the average market price during the relevant
period.
NOTE 2 - CHANGE IN ACCOUNTING
Change in reporting Currency
On October 1, 2006, the Company changed its reporting currency from
Canadian dollars (Cdn$) to United States dollars ($) as this currency is
more appropriate for the Company's investors and other users of the
financial statements. In making this change, the Company has followed
recommendations of the Emerging Issues Committee ("EIC") of the Canadian
Institute of Chartered Accountants ("CICA") , set out in EIC-130,
"Translation Method When The Reporting Currency Differs From The
Measurement Currency or There is a Change in The Reporting Currency."
Financial statements for all periods presented have been translated from
Canadian dollars into United States dollars using the current rate
method, based on EIC-130 recommendations. Using this method, all
consolidated assets and liabilities have been translated using the
exchange rate at the balance sheet dates, while shareholders' equity has
been translated using the historical rates of exchange in effect on the
dates of the corresponding transactions. Consolidated Statements of Loss
and Deficit and Consolidated Statements of Cash Flows have been
translated using the prevailing average exchange rate for the period,
except for financing transactions which have been translated using the
historical rates of exchange in effect at the dates of the corresponding
transactions. Any resulting exchange rate differences due to this
translation are included in shareholders' equity as cumulative
translation adjustment. All comparative financial information being
presented has been restated to reflect the Company's financial statements
as if they have been historically reported in United States dollars and
this resulted in a cumulative translation adjustment and corresponding
increase in Petroleum and Natural Gas properties of $5,791,923.
NOTE 3 - ACQUISITION OF BREAKAWAY ENERGY INC.
On October 4, 2006 and pursuant to a share purchase agreement, the
Company acquired all of the issued and outstanding shares of Breakaway
Energy Inc ("Breakaway") in exchange for the issuance of 10 million
Solana shares and 10 million performance warrants. Of the 10 million
Solana shares, two thirds are issued subject to a voluntary escrow
agreement and will be released as to one half on each of October 2, 2007
and 2008, respectively. The performance warrants have a term of
42 months, an exercise price of Cdn$2.00 per share, and are exercisable
only if the Company's share price trades above Cdn$2.75 per share for a
period of more than 45 consecutive days. The 10 million performance
warrants are also subject to a voluntary escrow agreement and will be
released as to one-half on each of October 2, 2007 and 2008,
respectively.
Both the escrowed shares and the performance warrants are subject to
certain vesting provisions over the 24 month period following completion
of the Breakaway acquisition, including immediate vesting in the event of
a change of control or in the event that Company's share price trades
above Cdn$2.75 per share for a period of more than 45 consecutive days.
The Company executed two year employment agreements with two former
Breakaway principals at a salary of Cdn$250,000 per annum per person.
These two employees also were each granted 200,000 stock options pursuant
to the Company's stock option plan exercisable at a price of Cdn$1.15 per
share until October 4, 2011, with one half of the options vesting on
October 4, 2007 and the remaining options vesting on October 4, 2008.
The Breakaway acquisition terms were approved by the Company's Board of
Directors as being in the best interest of the Company taking into
account, among other issues, the need to attract, retain and reward top
quality management. The acquisition was accounted for using the purchase
method where the difference between the purchase price of Cdn$10,782,500
(10 million Solana's shares valued at Cdn$10,782,500) and the fair value
of net assets acquired of Cdn$78,930, equivalent to US dollars
$9,553,295, is treated as an intangible asset and will be amortized over
a 24 month period in line with the terms of the acquisition agreement. No
amount has been allocated to the performance warrants as part of the
purchase price as the likelihood of the performance warrants being
exercise cannot be determined.
NOTE 4 - ASSET DISPOSITION SUBSEQUENT TO DECEMBER 31,2006
Pursuant to a strategic review of the Company's asset portfolio, on
February 8, 2007 but having effect from December 1, 2006, the Company
signed an agreement disposing 100% of its rights and obligations under an
Exploration Participation Agreement (the EPA) with Ramshorn International
Limited ("Ramshorn") to Ramshorn. With this agreement, Ramshorn
reacquired 100% of five Colombian oil & gas exploration prospects,
specifically; Guayabillas, Puma, Guariquies, Alamo and Zeus.
NOTE 5 - CASH IN TRUST
Cash in trust in the amount of $3,274,262 (2005 - $392,696) is mainly
comprised of the escrow account established to satisfy the Company's
share of Guariquies prospect costs. Pursuant to the terms of the
agreement signed with Ramshorn (Note 4) the outstanding balance was
refunded to the Company.
NOTE 6 - DEPOSITS
The Company has funds on deposit at the Agencia Nacional de Hydrocarburos
("ANH") totaling $3,041,509 (2005 - $1,843,389) relating to 10% of work
commitments on acquired ANH acreage. These funds will be returned to the
Company on completion of the work commitments on the Guachiria Norte,
Guachiria Sur, Garibay and Catguas blocks.
NOTE 7 - PETROLEUM AND NATURAL GAS PROPERTIES
December 31, 2006
DD&A,
accretion and Net Book
Cost Impairment Value
$ $ $
Oil and gas properties 94,176,680 41,279,337 52,897,343
Inventory 1,415,846 - 1,415,846
-------------------------------------------------------------------------
95,592,526 41,279,337 54,313,189
-------------------------------------------------------------------------
December 31, 2005
DD&A,
accretion and Net Book
Cost Impairment Value
$ $ $
Oil and gas properties 67,576,853 5,935,816 61,641,037
Inventory 1,501,668 - 1,501,668
-------------------------------------------------------------------------
69,078,521 5,935,816 63,142,705
-------------------------------------------------------------------------
Inventories, including pipe, drilling materials and supplies are
classified as capital assets as they will be used in future oil and gas
activities. These amounts are not depreciated, as they have yet to be
used.
Unevaluated properties, inventory and undeveloped lands amounting to
$25,497,601 are excluded from depletion and depreciation (2005 -
$44,794,709).
A December 31, 2006 impairment test calculation estimated that the
property carrying amounts exceeded the undiscounted future net cash flows
associated with the proved and probable reserves, resulting in
recognition of a $29,822,544 impairment adjustment. The benchmark West
Texas Intermediate Crude Oil prices used in the impairment calculation
are:
Year $/Barrel
---- --------
2007 53.27
2008 53.70
2009 52.68
2010 50.59
2011 52.63
Escalated thereafter 2% /year
Block and Acreage Commitments
The Company has minimum exploration commitments of $26,165,200 to be met
during 2007.
NOTE 8 - OTHER CAPITAL ASSETS
December 31, 2006
Amortization
and Net Book
Cost Depreciation Value
$ $ $
Office furniture and equipment 513,944 157,360 356,584
Leasehold improvements 263,239 76,743 186,496
-------------------------------------------------------------------------
777,183 234,103 543,080
-------------------------------------------------------------------------
December 31, 2005
Amortization
and Net Book
Cost Depreciation Value
$ $ $
Office furniture, equipment
and vehicles 461,885 74,431 387,454
Leasehold improvements 211,200 45,760 165,440
-------------------------------------------------------------------------
673,085 120,191 552,894
-------------------------------------------------------------------------
NOTE 9 - CUMULATIVE DD&A AND IMPAIRMENT
Cumulative DD&A (depletion, depreciation and amortization), accretion and
impairment balance as follows:
December 31, December 31,
2005 Additions 2006
$ $ $
PNG properties-DD&A 5,935,816 5,520,977 11,456,793
Amortization of intangible assets - 1,182,447 1,182,447
Other Assets depreciation 120,191 113,912 234,103
Impairment of PNG properties - 29,822,544 29,822,544
-------------------------------------------------------------------------
6,056,007 36,639,880 42,695,887
-------------------------------------------------------------------------
NOTE 10 - INVESTMENT
The Company has invested $206,227 in the Colombian Hydrocarbon Investment
Fund ("Fund"), and expects to invest a maximum amount of US $500,000. The
Fund is managed by a U.S. based fund manager, who specializes in South
American natural resource sector investments.
The Fund is expected to have an investment period of four years. After
this period, the Fund will be wound up, and any remaining capital and
earned profits will be distributed to the investors over a maximum period
of seven years.
NOTE 11 - ASSET RETIREMENT OBLIGATIONS
The Company has an obligation to plug and abandon its petroleum and
natural gas wells at the end of their useful lives. The present value of
this obligation has been projected using estimates of the future costs
and the timing of abandonment. At December 31, 2006, the Company
estimated the present value of its asset retirement obligations to be
$1,556,823 based on a future liability of $2,007,878 (2005 - $536,547 and
$1,449,513 respectively). These costs are expected to be incurred in the
next five to seven years when wells will be abandoned. A credit-adjusted
risk-free discount rate of 10% and an inflation rate of 2.5% were used to
calculate the present value.
2006 2005
$ $
Balance, December 31 536,547 369,254
Obligations incurred during the year 979,844 118,563
Obligations settled during the year - -
Accretion 40,432 48,730
-------------------------------------------------------------------------
Balance, December 31 1,556,823 536,547
-------------------------------------------------------------------------
NOTE 12 - SHARE CAPITAL
Authorized share capital consists of an unlimited number of common
shares.
Issued Number Amount
$
Common shares:
Balance, December 31, 2004 64,071,792 85,351,541
Exercise of stock options 100,000 49,559
Exercise of broker warrants 565,000 1,102,293
Fair value of warrants exercised - 476,957
Fair value of stock options exercised - 36,970
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Balance December 31, 2005 64,736,792 87,017,320
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Exercise of stock options 140,000 14,000
Private placement of common shares,
net of issuance costs 21,000,000 34,414,044
Purchase price - Breakaway acquisition
(Note 3) 10,000,000 9,553,295
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Balance December 31, 2006 95,876,792 130,998,659
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Contributed surplus:
Balance, December 31, 2004 $1,089,705
Stock-based compensation expense 1,801,780
Transfer from share capital on expiry of warrants 667,622
Transfer to share capital on exercise of stock options (36,970)
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Balance December 31, 2005 3,522,137
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Stock-based compensation expense 1,512,938
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Balance December 31, 2006 5,035,075
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The Company has granted options to purchase common shares to directors,
officers, employees and consultants. Each option permits the holder to
purchase one common share of the Company at the stated exercise price.
Options granted vest over two or three years commencing on the first
anniversary date of the grant and are exercisable on a cumulative basis
over five years. In accordance with the Company's stock option plan,
these options have an exercise price equal to the market price at the
date of grant. At December 31, 2006, 4,350,000 (December 31, 2005 -
4,015,000) options were outstanding under the stock option plan. At
December 31, 2006, 9,587,679 common shares were reserved for issuance
under the stock option plan.
December 31, 2006 December 31, 2005
Weighted Weighted
Average Average
Exercise Exercise
Number Price Number Price
of (Cdn$ of (Cdn$
Shares Per Share) Shares Per Share)
Outstanding, beginning
of year 4,015,000 2.01 1,725,000 1.92
Granted, during
the year 1,655,000 1.25 2,390,000 2.02
Exercised during
the year (140,000) 0.10 (100,000) 0.60
Expired or cancelled
during the year (1,180,000) - - -
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Outstanding,
end of year 4,350,000 1.64 4,015,000 2.01
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Exercisable,
end of year 1,923,333 1.90 1,791,667 1.99
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December 31, 2006
Weighted Weighted Weighted
Exercise Average Average Average
Price Number Remaining Exercise Number Exercise
Range of Contractual Price of Price
(Cdn$ Options Life (Cdn$ Options (Cdn$
Per Share) Outstanding (years) Per Share) Exercisable Per Share)
2.72 200,000 3.90 2.72 133,336 2.72
1.67 1,320,000 3.67 1.67 439,996 1.67
3.50 40,000 3.01 3.50 40,000 3.50
2.75 730,000 2.92 2.75 730,000 2.75
0.60 480,000 1.93 0.60 480,000 0.60
1.91 50,000 2.01 1.91 - -
2.75 50,000 2.90 2.75 - -
1.15 1,475,000 4.82 1.15 100,001 1.15
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4,350,000 3.73 1.64 1,923,333 1.90
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December 31, 2005
Weighted Weighted Weighted
Exercise Average Average Average
Price Number Remaining Exercise Number Exercise
Range of Contractual Price of Price
(Cdn$ Options Life (Cdn$ Options (Cdn$
Per Share) Outstanding (years) Per Share) Exercisable Per Share)
2.72 200,000 4.90 2.72 66,667 2.72
3.50 70,000 4.01 3.50 - 3.50
1.67 1,920,000 4.67 1.67 - 1.67
4.10 200,000 4.17 4.10 100,000 4.10
2.75 905,000 3.92 2.75 905,000 2.75
0.10 140,000 0.45 0.10 140,000 0.10
1.91 100,000 3.01 1.91 100,000 1.91
0.60 480,000 2.93 0.60 480,000 0.60
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4,015,000 4.08 2.01 1,791,667 1.99
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Stock-based compensation expense of $1,512,938 (December 31, 2005 -
$1,801,779) related to options granted has been recognized in accordance
with the fair value method with a corresponding credit to contributed
surplus. Upon exercise of these options, the credit to contributed
surplus is reversed to share capital. Upon the exercise of options in
2006, $12,127 (2005 - $36,970) was reclassified from contributed surplus
to share capital.
The Company estimates the fair value of stock options granted using the
Black-Scholes option pricing model with the following assumptions:
December 31
2006 2005
Risk-free interest rate (%) 4.25 3.81
Expected life (years) 5 5
Volatility in the price of common shares (%) 96.5 104
Dividends per common share (Cdn$ per share) - -
The resultant weighted average fair value per option amounts to Cdn$1.25
(2005 - Cdn$1.65).
NOTE 13 - RELATED PARTY TRANSACTIONS
For the year ended December 31, 2006 management fees of $52,907
(December 31, 2005 - $79,294) were paid to a company controlled by Ray
Antony, a director of the Company and are included in general and
administrative expenses.
These fees are for services rendered in the normal course of operations
and are measured at the exchange amount, which is the amount of
consideration established and agreed to by the related parties.
NOTE 14 - INCOME TAXES
The provision for income taxes differs from the amounts that would be
computed by applying the combined income tax rates to the pre tax loss
due to the following:
2006 2005
$ $
Statutory tax rate 38% 38%
Loss before tax (32,761,878) (3,237,118)
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(12,449,514) (1,230,105)
Non-deductible stock-based compensation 575,000 690,000
Increase in valuation allowance 6,520, 009 540,105
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5,354,505 -
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The approximate tax effect of each type of temporary difference that
gives rise to the Company's future tax assets and liabilities are as
follows:
2006 2005
$ $
Property plant and equipment 4,300,000 (5,110,000)
Asset retirement obligation 510,000 110,000
Non-capital losses carried forward 3,300,000 990,000
Share issue costs 1,000,000 1,160,000
Less valuation allowance (9,110,000) (2,381,970)
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Future income tax liability - (5,231,970)
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Subject to confirmation from taxation authorities, the Company has
approximately Cdn$9.9 million of Canadian non-capital loss carry forwards
which expire between 2007 and 2026. The consolidated financial statements
do not reflect the potential tax benefit of these losses, as they do not
meet the more likely than not criteria.
Current income taxes are based on presumptive income calculated as a
percentage of Colombian equity levels and can be recovered against future
income taxes for up to five years.
2006 2005
$ $
Current Income taxes 201,233 213,552
Future Tax Recovery (5,354,505) -
----------- -----------
(5,153,272) 213,552
NOTE 15 - NET LOSS PER SHARE
Net loss per share is calculated using the weighted average number of
shares outstanding during the year ended December 31, 2006 is 82,067,532
(December 31, 2005 - 64,602,423)
NOTE 16 - SEGMENTED INFORMATION
The Company's oil and gas activities are conducted exclusively in
Colombia. Accordingly, all petroleum and natural gas exploration and
development activities relate Colombia.
2006 Canada Colombia Total
$ $ $
Oil and gas revenues, net of royalties - 9,480,911 9,480,911
Interest 1,313,081 217,951 1,531,032
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1,313,081 9,698,862 11,011,943
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Operating expenses - 3,123,305 3,123,305
General and administrative expenses 1,381,348 3,221,604 4,602,952
Depletion, depreciation
and accretion 48,232 5,627,089 5,675,321
Amortization of intangible assets 1,182,447 - 1,182,447
Impairment of PNG properties - 29,822,544 29,822,544
Foreign exchange loss (gain) (715,622) (1,430,064) (2,145,686)
Stock-based compensation 1,512,938 - 1,512,938
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3,409,343 40,364,478 43,773,821
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Loss before taxes (2,096,262) (30,665,616) (32,761,878)
Income tax recovery - 5,153,272 5,153,272
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Net loss (2,096,262) (25,512,344) (27,608,606)
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Total assets 29,272,806 77,379,138 106,651,944
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Capital expenditures 24,224 25,614,035 25,638,259
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2005 Canada Colombia Total
$ $ $
Oil and gas revenues, net of royalties - 6,760,501 6,760,501
Interest 607,880 106,517 714,397
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607,880 6,867,018 7,474,898
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Operating expenses - 1,454,204 1,454,204
General and administrative expenses 1,423,532 1,426,381 2,849,913
Depletion, depreciation
and accretion 6,734 4,803,193 4,809,927
Foreign exchange loss (gain) 1,012,940 (1,216,747) (203,807)
Stock-based compensation 1,801,779 - 1,801,779
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4,244,985 6,467,031 10,712,016
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(Loss) income before taxes (3,637,105) 399,987 (3,237,118)
Income tax expense - (213,552) (213,552)
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Net loss (3,637,105) 186,435 (3,450,670)
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Total assets 25,172,416 70,724,679 95,897,095
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Capital expenditures 24,432 28,149,646 28,174,078
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NOTE 17 - FINANCIAL INSTRUMENTS
a. Foreign Currency Exchange Risk
The Company is exposed to foreign currency fluctuations as it holds
Canadian Dollars, United States Dollars and Colombian Pesos in cash and
short-term investments. There are no exchange rate contracts in place.
b. Fair Values of Financial Instruments
The fair value of the Company's financial instruments, including cash and
cash equivalents, cash in trust, accounts receivable and accounts payable
approximate their carrying values due to their short maturity terms. The
fair value of the deposits is not significantly different than its
carrying value.
c. Credit Risk
The majority of the accounts receivable are in respect of oil and gas
operations. The Company generally extends unsecured credit to these
customers and therefore the collection of accounts receivable may be
affected by changes in economic or other conditions. Management believes
the risk is mitigated by the size and reputation of the companies to
which they extend credit. The Company has not experienced any material
credit loss in the collection of accounts receivable to date.
d. Commodity Price Risk
Due to the volatility of commodity prices the Company is potentially
exposed to adverse consequences of declining prices. The Company may
enter into oil and natural gas contracts in order to protect its cash
flow on future sales from the potential adverse impact of declining
prices. These contracts would reduce the fluctuation in sales revenue by
locking in prices with respect to future deliveries of oil and natural
gas. As at December 31, 2006 and 2005, the Company had not entered into
any of these contracts.
NOTE 18 - SUBSEQUENT EVENT
In accordance with the provisions of the agreement with Ramshorn
International Limited ("Ramshorn"), (Note 5), on February 8, 2007, the
Company received a refund of the December 1, 2006 outstanding balance of
an escrow account that the Company had established to guarantee its share
of Guariquies ongoing costs. Pursuant to this agreement the Company
expects to receive 100% of its share of Puma-1 completion costs from 50%
of Ramshorn's operating profits deriving from any future Puma prospect
production.