CALGARY and LONDON, April 10 /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, 2007.
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
- Participated in three new light oil field discoveries including the
very exciting Costayaco field, and the Juanambu and Tres Curvas
fields.
- 2007 year end exit production rate of 2,625 boepd, a 380% increase
over 2006 year end production of 544 boepd.
- Average 2007 production rate of 869 boepd, a 40% increase over 2006
average production.
- 2007 year end 3P oil reserves (proved, probable and possible) of
20 mmbbls, a 20 fold increase over 2006 year end 3P reserves.
- 2007 net operating revenue of $14.4 million, $8.0 million greater
than 2006 operating revenue.
- On June 25, 2007, Solana acquired 100% in two Llanos basin blocks,
Colonia and San Pablo that immediately offset Solana's three
Guachiria blocks.
- On November 26, 2007, Solana closed a bought deal financing
(including over-allotment shares) of 27.3 million shares at CDN$2.20
per share for gross proceeds of CDN$60.06 million.
- At year end 2007, Solana had a cash balance of $71.5 million.
- On December 20, 2007, the Company, through its wholly owned
subsidiary, Solana Petroleum Exploration (Colombia) Limited, secured
a reserves backed $100 million senior first lien three year revolving
secured credit facility with BNP Paribas Bank. The initial amount
available for drawdown under the facility is $26 million. During the
year ended December 31, 2007, the Company did not draw on this credit
facility
FINANCIAL REVIEW OF THE YEAR ENDED DECEMBER 31, 2007
The review that follows is a summary of Solana Resources Limited's ("Solana" or "the Company") activities and results for the year ended December 31, 2007, its financial position at December 31, 2007 and its future prospects. Figures are expressed in United States dollars, unless otherwise indicated.
Additional information on Solana (which does not form part of this announcement) is available on the Company's website at www.solanaresources.com or on Sedar's website at www.sedar.com.
SIGNIFICANT DEVELOPMENTS
CHANGE IN REPORTING CURRENCY
On October 1, 2006, the Company changed its reporting currency from Canadian dollars (Cdn$) 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
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.
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 for details).
OPERATIONAL UPDATE
LOWER MAGDALENA BASIN
The Lower Magdalena basin is located in northwest Colombia. It covers an area of approximately 87,000 km2 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 a 58% working interest, and Technopetrol, a Colombian company, with a 4.2% working interest.
Solana operates the Guepaje gas field on the 84 km2 Magangue block, which was producing 2.6 mmcfd (gross), 785 mcfd net of royalty to Solana, and sold into the local market for $2.55/mmbtu at the 2007 year end. Solana is currently re-evaluating the available seismic and geological information to identify possible additional drilling targets.
This block borders Pacific Rubiales La Creciente block where there was a significant gas discovery, in the same productive formation as the Guepaje gas field, in 2006.
CATATUMBO BASIN
The Catatumbo Basin is a 7,350 km2 sub-basin, forming the southwest flank of Venezuela's prolific Maracaibo Basin. Solana has one block in the Catatumbo sub-basin.
CATGUAS BLOCK
Solana is the operator of the 1,591 km2 Catguas block with a 100% working interest. In the southern 70% of the block, Trayectoria Oil and Gas, Sucursal Colombia, has a 15% beneficial interest, and a 50% beneficial interest in the remainder. The block is held under an ANH contract.
Phase 1 (November 17, 2005 to May 17, 2007) commitments were fulfilled by drilling the relatively shallow Tres Curvas-1 and Cocodrilo-1 wells.
Tres Curvas-1 tested a combined maximum 180 bopd (gross) from two Catatumbo formation zones and was completed as a new oilfield discovery. The well is currently being tested with a progressive cavity pump.
Cocodrilo-1 was abandoned after failing to identify oil in commercial quantities. An extension to the phase 1 deadline, to accomplish the required activities, was requested and granted.
During phase 2 (May 17, 2007 to November 17, 2008) Solana must drill one exploration well and re-enter one existing well. In the absence of a suitable re-entry candidate the requirement is to drill a second exploration well. Accordingly, two wells, testing deeper targets, are scheduled to be drilled during Q3, 2008. At the end of this phase a certain portion of this block must be relinquished. In view of the prospectivity of the block and to reduce the relinquishment area to 15%, the Company will also acquire 132 line-km of 2-D and 50 km2 of 3-D seismic data in Q2, 2008.
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 km2 and holds Colombia's largest number of oil fields and proved oil reserves.
Solana has working interests in six blocks in the Llanos Basin, covering an area of 2,015 km2. These blocks are from North to South: Guachiria Norte, Colonia, San Pablo, Guachiria, Guachiria Sur and Garibay. These blocks are in the part of the Llanos Basin where drilling and seismic activity is generally restricted to a four-month weather window from December to March.
GUACHIRIA NORTE BLOCK
Solana is the operator of the 412 km2 Guachiria Norte block with a 100% working interest. Lewis Energy Colombia has a 30% beneficial interest in this block. The block is located approximately 250 km northeast of Bogota and is subject to an ANH contract.
During Phases 3 and 4 (March 21, 2007 to March 21, 2009) Solana is required to drill two exploration wells and acquire 25 km2 of 3-D seismic data.
Solana is currently reprocessing the existing 157 km2 Onyx 3-D seismic survey to optimize the location of the next wells. Within this area is a significant Carbonera C5 channel target which the Company intends to test. The Company plans to drill the commitment wells prior to the March 21, 2009 deadline.
COLONIA BLOCK
On June 25, 2007, Solana acquired the 439 km2 Colonia block, situated immediately to the west of the Guachiria Norte block. Solana is the operator and holds a 100% working interest in this block. Solana must acquire 55 km2 of 3-D seismic data and reprocess the existing 2-D seismic data during the first phase (June 25, 2007 until June 25, 2008), and drill one exploration well in each of the subsequent five annual phases. This block is subject to an ANH contract.
The acquisition of the 3-D seismic data started in January 2008 and is scheduled to be finished in April.
SAN PABLO BLOCK
On June 25, 2007, Solana acquired the 423 km2 San Pablo block, situated immediately to the west of the Guachiria Sur block and to the south of the Colonia block. Solana is the operator and holds a 100% working interest in this block. Solana must acquire 50 km2 of 3-D seismic data during the first phase (June 25, 2007 until June 25, 2008) and drill one exploration well in each of the subsequent five annual phases. This block is subject to an ANH contract.
50 km2 of 3-D seismic data was acquired in December 2007.
GUACHIRIA BLOCK
Solana is the operator of the 68 km2 Guachiria block with a 100% working interest. Lewis Energy Colombia has a 30% beneficial interest in this block. The block adjoins the Guachiria Norte block immediately to the South. This block was acquired from Ecopetrol, and is subject to a standard ANH contract plus an additional 13% royalty payable to Ecopetrol.
For Phase 3 (June 1, 2006 to June 1, 2007), Ecopetrol agreed that Solana may substitute its well commitment for a 100 km2 3-D seismic survey, covering the block, and overlapping the southern part of the adjacent Guachiria Norte 3-D seismic survey. Data acquisition and processing are now complete.
The commitment for Phase 4 (June 1, 2007 to June 1, 2008) is to drill an exploration well. The Company drilled the Primavera-1 well in February, 2008, resulting in a potential oil discovery. Testing operations are scheduled to commence in mid-April 2008.
Solana's Yalea-1 well was producing 30 bopd (gross), 17 bopd net of royalty, at the 2007 year end.
GUACHIRIA SUR BLOCK
Solana is the operator of the 366 km2 Guachiria Sur block with a 100% working interest. Lewis Energy Colombia has a 30% beneficial interest in this block. The block is to the west and the south of the Guachiria block and to the south of the Guachiria Norte block. This block is subject to an ANH contract.
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 km2 3-D seismic survey and a commitment to drill one well during Phase 3 (October 25, 2007 to October 25, 2008). This survey covers the northern part of the block, immediately west and south of the Guachiria block. Data acquisition and processing are now complete.
The Company commenced drilling the Palmitas-2 well on March, 21, 2008 targeting a Carbonera structural play. During Q4 2007, the Company acquired 55 line-km of 2D seismic data over this structure.
GARIBAY BLOCK
Solana is the operator of the 307 km2 Garibay block with a working interest of 100%. The block is located approximately 170 km east of Bogota. This block is subject to an ANH contract.
During Phase 2 (October 25, 2006 to October 25, 2007) Solana was required to drill one well. The ANH approved the replacement of this program with the acquisition of 100 km2 (39 square miles) of 3-D seismic, subject to relinquishment of 30% of the block area. This survey was completed in April 2007. Acquisition and processing are now complete.
During Phase 3 (October 25, 2007 to October 25, 2008), the Company is required to drill one exploration well. On November 17, 2007, a farm-in agreement was signed with Cepsa Colombia SA whereby they will finance the drilling of the Topocho-1 exploration well in return for a 50% working interest in the block and become the operator.
GAVIOTAS BLOCK
During Q2 2007, Solana drilled the Bevea-1 well. After failing to test commercial quantities of oil, the well was abandoned. Bevea-1 was Solana's second non-commercial well on this block, and the Gaviotas block was relinquished effective July 17, 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 km2 and Solana holds interests in the Guayuyaco block and the Chaza block totalling 536 km2 in this basin.
GUAYUYACO BLOCK
Solana holds a 35% non-operated net working interest in the 212 km2 Guayuyaco block, located approximately 290 km southwest of Bogota. Gran Tierra Energy Inc. is the Operator with a 35% working interest and Ecopetrol holds the remaining 30% working interest. The Guayuyaco field which was producing 566 bopd (gross), 182 bopd net of royalty to Solana, on December 31, 2007. All commitments have been fulfilled and the block is being further developed under an Association Contract.
During the first quarter of 2007 Solana participated in drilling the Juanambu-1 discovery well which was productive in the Caballos, Villeta T and Rumiyaco Kg formations. The well has been completed with a jet pump and the tubing string configured to allow for production from selected zones. Pursuant to regulatory requirements, the well has been intermittently tested since April 26, 2007 and was producing 1,933 bopd (gross), 622 bopd net of royalty to Solana, on December 31, 2007.
Ecopetrol granted "commerciality" to the Juanambu field on November 7, 2007, and the well is currently averaging approximately 1,400 bopd (gross), 451 bopd net of royalty to Solana. Trucking operations have been replaced with a six kilometre six inch flowline that went into operation on February 29, 2008. The line connects Juanambu-1 into the nearby Toroyaco facility and from there into existing infrastructure.
CHAZA BLOCK
Solana has a 50% working interest in the 325 km2 Chaza block, immediately west of the Guayuyaco block. Gran Tierra Energy Inc., the operator, holds the other 50% in the block. The block is held under an ANH contract.
During Phase 2 (June 27, 2006 to June 26, 2007) the partners drilled the Costayaco-1 discovery well which tested at a combined maximum rate of 5,906 bopd from four separate formations; the Caballos, Villeta T, Villeta U and the Rumiyaco Kg. This well produced a total of 66,957 bbls (gross) during 2007 and is currently on a long term test. Costayaco-1 was producing 3,272 bopd (gross), 1,505 bopd net of royalty to Solana, at the 2007 year end. Production is trucked to facilities at Uchupayaco that were constructed in the second half of 2007. Costayaco-1 is currently averaging 3,500 bopd (gross), 1,610 bopd net of royalty to Solana, and is limited by trucking capacity. A ten kilometre, eight inch pipeline, tying into existing infrastructure at Uchupayaco, is being built to replace trucking operations. This line is scheduled to be in operation by mid 2008.
To assist with future development drilling location selection, a 70 km2 3-D seismic program was acquired in December 2007.
By January 2008, Costayaco-2 was drilled and completed as an oil well. The well tested over 6,600 bopd (gross) from the Caballos and Villeta T sands. The U sand was not tested as it showed very similar characteristics to Costayaco-1. A long term test is planned in the next four months.
In February 2008, Costayaco-3 was drilled and encountered the same reservoir sequences with similar good oil and gas shows as the other Costayaco wells. Initial log interpretations indicate hydrocarbon pay across the Rumiyaco Kg, the Villeta U, the Villeta T and the Caballos formations. Log quality precludes the ability to conclusively identify oil water contacts. Testing operations commenced March 19, 2008 and are anticipated to take one month.
Four additional wells, Costayaco-4 through -7, are planned in the field during 2008.
Work is under way to reduce existing infrastructure production constraints beyond Uchupayaco. It is currently anticipated that 6,000 to 9,000 bopd gross could be accommodated during the second half of 2008. A second stage of infrastructure expansion, to accommodate the anticipated increase in production from the continuing Costayaco drilling program, is currently being evaluated.
2007 YEAR-END REMAINING RECOVERABLE RESERVES
Company Share - Forecast Price Case
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December 31, 2007 December 31, 2006
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OIL (mbbls) GAS (mmcf) OIL (mbbls) GAS (mmcf)
-------------------------------------------------------------------------
Proved Developed Gross Net Gross Net Gross Net Gross Net
-------------------------------------------------------------------------
Producing 2,766 2,544 2,428 1,943 263 242 1,889 1,768
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Non Producing 4,580 3,447 333 307
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Proved Undeveloped 117 107
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Total Proved 7,346 5,991 2,428 1,943 713 656 1,889 1,768
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Probable 6,420 4,639 407 325 213 196 178 167
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Proved +
Probable 13,766 10,630 2,835 2,268 926 852 2,067 1,935
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Possible 6,241 4,514
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Proved +
Probable +
Possible 20,007 15,144 2,835 2,268 926 852 2,067 1,935
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Net Present Value - Before Tax ($ Millions)
Forecast Price Case
Company Share - As at December 31, 2007
-------------------------------------------------------------------------
Discount rate 0% 5% 10% 15%
-------------------------------------------------------------------------
Total proved 452.7 369.7 313.8 273.4
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Proved + probable 805.7 663.0 562.6 487.7
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Proved + probable
+ possible 1,156.1 908.6 743.4 625.8
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Net Asset Value ($ Millions, except per share amounts)
Company Share - As at December 31, 2007
-------------------------------------------------------------------------
Proved + probable reserves - NPV 10% before tax 562.6
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Working capital 71.0
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Undeveloped land - 758,000 net acres ($50/acre)(1)(2) 37.9
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Seismic (at cost) 21.6
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Net Asset Value $693.1
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Common shares outstanding 123.2
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Fully diluted shares 137.8
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Net asset value per basic common share $5.63
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Net asset value per diluted common share(3) $5.23
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(1) Undeveloped land value used instead of expected monetary value
calculation of prospect inventory as it is more conservative
(2) Solana's most recent farmout equated to $105/acre
(3) Assumes 10.0 million warrants are exercised for proceeds of
$20.0 million and 4.6 million options are exercised for proceeds of
$8.1 million
Solana's independent reserve engineers, DeGolyer and MacNaughton Canada
Limited, assign Colombia total net proved oil reserves of 5,991 MBbls and gas
reserves of 1,943 MMcf for 2007. Oil reserves are higher than for 2006
primarily due to the Costayaco and Juanambu discoveries.
SUMMARY ASSET TABLE
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Asset Operator Interest Status Licence Licence Comments
(%) Expiry Area
Date
-------------------------------------------------------------------------
Guayuyaco Gran Tierra 35% Production March 30, 0.5 km2 Currently
Field Energy Inc. 2030 producing
182 bopd
net to
Solana.
-------------------------------------------------------------------------
Inchiyaco Gran Tierra 7.2% Production March 30, Currently
Field Energy Inc. 2030 producing
11 bopd net
to Solana.
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Juanambu Gran Tierra 35% Production March 30, Currently
Field Energy Inc. 2030 producing
622 bopd
net to
Solana.
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Guayuyaco Gran 50%(1) Exploration March 30, 212 km2 Contains
Block Tierra 2030 the
Energy Inc. Guayuyaco,
Inchiyaco
and
Juanambu
fields.
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Costayaco Gran Tierra 50% Production June 27, Currently
Field Energy Inc. 2035 producing
1,631 bopd
net to
Solana
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Chaza Gran Tierra 50% Exploration June 27, 325 km2 Contains
Block Energy Inc. 2035 the
Costayaco
field.
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Guachiria Solana 70% Exploration October 1, 75 km2 Contains
Block Colombia(2) 2031 the
Primavera-1
discovery
and the
Yalea-1
well,
currently
producing
on long
term test.
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Guachiria Solana 70% Exploration December 412 km2 Evaluating
Norte Colombia(2) 21, 2034 next
Block exploration
location.
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Guachiria Solana 70% Exploration October 366 km2 Palmitas-2
Sur Colombia(2) 25, 2035 well
Block drilling.
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Colonia Solana 100% Exploration June 25, 439 km2 Acquired
Block Colombia(2) 2038 50 km2 3D
seismic.
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San Pablo Solana 100% Exploration June 25, 423 km2 Acquired
Block Colombia(2) 2038 50 km2 3D
seismic.
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Garibay Solana 50% Exploration October 450 km2 Farmed out
Block Colombia(2) 25, 2035 50% to
Cepcolsa.
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Catguas A Solana 50% Exploration November 461 km2
Block Colombia(2) 17, 2035
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Catguas B Solana 85% Exploration November 1131 km2 Drilled
Block Colombia(2) 17, 2035 Tres
Curvas-1
which
tested
180 bopd
and
Cocodrilo-1,
dry
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Mangangue Solana 37.8% January 169 km2 Contains
Block Colombia(2) 1, 2018 the Guepaje
Gas field
-------------------------------------------------------------------------
Guepaje Solana 37.8% Production January 84 km2 Currently
Gas Colombia(2) 1, 2018 producing
Field 980 mscfd
net to
Solana
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(1) Ecopetrol the Colombian oil and gas company has the right to back-in
for 30% on any commercial discoveries, in which case Solana's
interest would be reduced to 35%.
(2) Solana's Colombian entity is the operator of the indicated assets.
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.
2007 2006 2005
-------------------------------------------------------------------------
$ $ $
Production Revenue, net of
royalties 18,294,389 9,480,911 6,760,501
Operating costs 3,944,131 3,123,305 1,454,204
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14,350,258 6,357,606 5,306,297
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Expenses
General and administrative 5,129,153 4,602,952 2,849,913
Depletion, depreciation and
accretion 5,789,093 5,340,876 4,809,927
Impairment - 29,822,544 -
Foreign exchange loss (gain) 77,290 (2,145,686) (203,808)
Stock-based compensation 13,640,012 3,029,830 1,801,780
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24,635,548 40,650,516 9,257,812
-------------------------------------------------------------------------
Other income/expenses
Interest and other 1,091,321 1,531,032 714,397
Income tax expense (recovery) 89,257 (5,153,272) 213,552
-------------------------------------------------------------------------
Net loss and comprehensive loss (9,283,226) (27,608,606) (3,450,670)
Net loss per share, basic
and diluted (0.09) (0.34) (0.05)
-------------------------------------------------------------------------
2007 2006 2005
-------------------------------------------------------------------------
$ $ $
Share capital and warrants 187,223,652 122,962,256 87,017,320
Working capital 70,974,442 37,106,929 24,407,788
Petroleum and natural gas
properties 81,963,075 54,313,189 63,142,705
Total assets 166,641,302 98,615,541 95,897,095
Total current liabilities 9,307,557 3,404,607 5,948,079
Shareholders' equity 155,359,807 93,654,111 84,180,499
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This consolidated financial information includes the revenue and expenses of Solana Colombia for the years ended December 31, 2007 and 2006. During the year ended December 31, 2007, the Company generated revenue of $18,294,389, which after deducting operating costs of $3,944,131, yielded an operating profit of $14,350,258. During the year ended December 31, 2006, revenue from operations amounted to $9,480,911, which after deducting operating costs of $3,123,305, yielded an operating profit of $6,357,606. The increase of $7,992,652 is due to a combination of an increase in production (58,271 bbls more in 2007 than in 2006) and higher oil prices ($50/bbl average during 2007 compared to $40/bbl in 2006).
General and administrative expenses for the year ended December 31, 2007 amounted to $5,129,153 in comparison to $4,602,952 for the same period ended December 31, 2006. The major components of general and administrative expenses are as follows:
2007 2006
$ $
General office 237,649 404,102
Salaries 3,180,637 1,509,249
Professional fees 794,218 1,743,014
Public company costs 388,619 454,672
Consulting fees 150,079 196,363
Travel 377,951 295,552
--------------------------
--------------------------
5,129,153 4,602,952
Most of the general and administrative expenses decreased in comparison with 2006, except for salaries and travel expenses which increased due to the significantly higher level of operation and exploration activities during 2007.
Depletion, depreciation and accretion amounted to $5,789,093 for the year ended December 31, 2007, in comparison to $5,340,876 for the year ended December 31, 2006. The depletion expense is calculated based on the depletable asset base, annual production and the proved reserves pursuant to the Company's annual reserve report, and amounts to $5,504,640 for the year ended December 31, 2007, in comparison to $5,186,532 for the year ended December 31, 2006. The increase is mainly due to a combination of a higher depletable asset base and increased production but is somewhat offset by the additions to the proved reserves as a consequence of the Juanambu and Costayaco discoveries during 2007.
Depreciation amounted to $149,904 (2006 - $113,912) on the Company's capital assets, primarily office furniture, office equipment, vehicles and leasehold improvements.
Accretion expense amounting to $134,549 (2006 - $40,432) 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.
While there is no impairment charge for the year ended December 31, 2007, for the year ended December 31, 2006, the Company's impairment charge amounted to $29,822,544, This impairment was mainly a consequence of the asset disposition and termination of the Exploration Participation Agreement with Ramshorn (see note 4 to the Financial Statements).
The foreign exchange loss is $77,290 (2006 - $2,145,686 gain) and is substantially due to the appreciation of the Colombian peso and the Canadian dollar against the US dollar during 2007.
Stock-based compensation associated with options was $1,003,462 (2006 - $1,512,938). This decrease was due to a reduction in the amortization of costs associated with the vesting of options granted throughout 2007. Additional stock compensation expense of $6,912,486 and $5,724,064 was recognized for shares and performance warrants respectively in 2007 relating to the Breakaway acquisition (2006 - Nil).
Other income and expenses relates to interest income in 2007 amounting to $1,091,321 compared to $1,531,032 in 2006. This decrease is due to the lower cash balances held throughout most of 2007.
The current income tax expense amounting to $89,257 (2006 - $201,233) corresponds to the provision for income taxes based on presumptive income calculated on equity levels in Colombia and can be recovered against income taxes in future periods during a five year carry forward period in Colombia. A future tax recovery of $5,354,505 in 2006 (2007 - Nil) corresponds to a re-assessment of the deferred taxation calculation.
The Company has approximately Cdn$10,265,000 ($10,355,500) of Canadian non-capital tax loss carry forwards, and Colombian tax losses totaling Col$77,961 million ($38,695,000) 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 net loss of $9,283,226 for 2007 relative to the 2006 net loss of $27,608,606 is mainly due to the impact of the impairment adjustment of $29,822,544 in 2006 resulting from the asset disposition and termination of the Exploration Participation Agreement with Ramshorn (see note 4 to the Financial Statements), and the significant increase in 2007 operating profit as a consequence of increased production and higher product prices.
SUMMARY OF QUARTERLY RESULTS
QUARTERS ENDED
Dec 31, 2007 Sep 30, 2007 Jun 30, 2007 Mar 31, 2007
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$ $ $ $
Additions to
Petroleum and
Natural Gas
properties 8,336,394 7,191,743 9,319,502 7,274,457
Total revenues 12,768,179 3,345,664 1,726,827 1,545,040
General and
administrative
expenses 1,582,711 1,165,775 1,319,363 1,061,304
Depletion,
depreciation
and accretion 1,558,115 2,018,435 945,635 1,266,908
Foreign exchange
(gain) loss (385,373) 237,775 199,233 25,655
Stock-based
compensation 9,512,159 1,302,779 1,207,881 1,617,193
Income (loss) after
taxes (999,906) (2,348,505) (2,802,217) (3,132,598)
Income (loss) per
share (0.01) (0.02) (0.05) (0.04)
-------------------------------------------------------------------------
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 7,756,245 6,538,659
Total revenues 2,049,755 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 2,441,325 886,985 957,026 1,055,540
Impairment 29,822,544 - - -
Foreign exchange
(gain) loss 160,105 (3,424,333) 870,581 247,961
Stock-based
compensation 2,300,124 209,875 228,640 291,191
Income (loss)
after taxes (31,076,703) 4,989,157 (1,236,674) (284,386)
Income (loss) per
share (0.34) 0.05 (0.01) (0.01)
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LIQUIDITY
Solana's working capital increased from $37,106,929 in 2006 to $70,974,442 in 2007 substantially due to the placement of 27,300,000 shares in November, 2007.
Cash balances at December 31, 2007, amounted to $71,537,827 and include the $57,348,910 net proceeds from the Company's November 2007 financing. These funds are committed to the Company's planned 2008 firm and contingent capital expenditure program in Colombia, which is substantially comprised of fourteen wells, 2 and 3D seismic data acquisition and infrastructure acquisition. The Company currently has sufficient working capital to meet these commitments. Additionally, on December 20, 2007, the Company secured a $100 million reserves based credit facility with BNP Paribas Bank. As at year end the Company had not accessed this facility and has no immediate plans to do so.
Shareholders' equity increased from $93,654,111 in 2006 to $155,359,807 as a result of additional financing net of a significant increase in the cumulative deficit due to the impairment adjustment recognized in 2006.
SUMMARY OF CASH INFLOWS AND OUTFLOWS
The Company's cash inflow from operations amounted to $12,893,927 compared to a cash inflow in 2006 of $7,114,937. This increase was due to additional oil production from the Juanambu and Costayaco fields discovered in 2007 and higher oil prices.
Solana's net cash inflow from financing activities amounted to $57,348,910 for 2007 compared to $34,428,044 in 2006.
The Company incurred cash outflows from its investing activities of $31,955,538 in 2007 relative to $29,112,940 in 2006. The majority of the cash outflows related to expenditures on petroleum and natural gas properties.
RELATED PARTY TRANSACTIONS
The Company paid $56,076 in fees in 2007 (2006 - $52,907) to DCR Investments Inc., a company controlled by Ray Antony, a director of the Company. These are included in general and administrative expenses.
SUBSEQUENT EVENTS
The Company's shares traded at a weighted average price that exceeded Cdn$2.75 per share for a 45 consecutive day period subsequent to the 2007 year-end. Thus, on February 5, 2008, all the remaining securities that were held in escrow (See Note 3 to the Financial Statements), were released in accordance with the terms of the voluntary share escrow agreement.
MANAGEMENT'S ASSESSMENT OF DISCLOSURE CONTROLS
Management has evaluated the effectiveness of the Company's disclosure controls and procedures as of December 31, 2007. Based on this evaluation some improvements were introduced to existing controls to conclude that the Company's disclosure controls and procedures 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.
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, possibility 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 Colombia, 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
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 (i.e. based on six thousand cubic feet of natural gas to one barrel of crude oil). 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.
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%.
Effective January 1, 2007, the Company adopted the new Canadian Institute of Chartered Accountants ("CICA") standards related to Section 1530, "Comprehensive Income," Section 3855, "Financial Instruments - Recognition and Measurement," Section 3861, "Financial Instruments - Disclosure and Presentation" and Section 3865, "Hedges." As required by the standards, the Company has adopted these standards retrospectively without restatement. (See Note 2 to the Financial Statements)
All prior periods have been recast to reflect the Company's financial statements as if they had been historically reported in United States dollars and this resulted in an accumulated other comprehensive income of $5,791,923.
The Company also adopted Section 3251, "Equity", and Section 1506, "Accounting Changes". Section 3251 replaces Section 3250, "Surplus," and describes standards for the presentation of equity and changes on equity for the reporting period as a result of the application of Section 1530, "Comprehensive Income." The only impact of Section 1506, "Accounting Changes," is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862, "Financial Instruments - Disclosures" and 3863 "Financial Instruments - Presentation" which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company will adopt these standards on January 1, 2008 and it is expected that the only effect on the Company will be additional disclosures regarding the significance of financial instruments for the entity's financial position and performance; and the nature, extent and management of risk arising from financial instruments to which the entity is exposed. (See Note 2 to the Financial Statements)
Section 1535, "Capital Disclosures" is effective for annual periods beginning on or after October 1, 2007 and establishes standards for disclosing information about the Company's capital and how it is managed. It requires disclosures of the Company's objectives, policies and processes for managing capital, the quantitative data about what the Company regards as capital, whether the Company has complied with any capital requirements and if it has not complied, the consequences of such non-compliance. The Company is currently evaluating the impact of the adoption of this section on the consolidated financial statements.
The adoption of the above new standards had no impact on the Company's retained earnings as at January 1, 2007.
In addition, on October 1, 2006, the Company changed its reporting currency from Canadian dollars (Cdn$) to United States dollars ($). Financial statements for the year ended December 31, 2006 have been translated from Canadian dollars into United States dollars using the current rate method. 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. The Consolidated Statements of Loss and Deficit have been translated using the prevailing average exchange rate for the period, except for equity transactions which have been translated using the historical rates of exchange in effect at the dates of the corresponding transactions. All prior periods have been recast to reflect the Company's financial statements as if they had been historically reported in United States dollars and this resulted in an accumulated other comprehensive income of $5,791,923.
See Notes 1 and 2 to the Financial Statements for a full description of the Company accounting policies.
FUTURE CHANGE IN ACCOUNTING POLICIES
As of January 1, 2009, the Company will be required to adopt new CICA Handbook Section 3064 "Goodwill and Intangible Assets" which replaces Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs." Various changes have been made to other standards to be consistent with the new Section 3064, which establishes standards for the recognition, measurement, presentation and disclosure of goodwill and of intangible assets. Standards concerning goodwill are unchanged from the standards in the previous Section 3062. The Company is assessing the impact of this new standard on its consolidated financial statements, however, the adoption is not expected to have a material impact on its consolidated financial statements.
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.
SOLANA RESOURCES LIMITED
CONSOLIDATED STATEMENTS OF LOSS, COMPREHENSIVE LOSS AND DEFICIT
Expressed in US Dollars
For the Years Ended December 31,
2007 2006
$ $
(Note 2) (Note 2)
Revenue
Oil and gas revenues, net of royalties 18,294,389 9,480,911
Interest 1,091,321 1,531,032
------------ ------------
19,385,710 11,011,943
------------ ------------
Expenses
Operating 3,944,131 3,123,305
General and administrative 5,129,153 4,602,952
DD&A, and impairment (Notes 7,8,9) 5,789,093 35,163,420
Foreign exchange loss (gain) 77,290 (2,145,686)
Stock-based compensation (Note 12) 13,640,012 3,029,830
------------ ------------
28,579,679 43,773,821
------------ ------------
Loss before income taxes (9,193,969) (32,761,878)
Income tax expense (recovery) ( Note 14) 89,257 (5,153,272)
------------ ------------
Net loss and comprehensive loss (9,283,226) (27,608,606)
Deficit, beginning of year (40,135,143) (12,526,537)
------------ ------------
Deficit, end of year (49,418,369) (40,135,143)
------------ ------------
Net loss per share, basic and diluted (Note 15) (0.09) (0.34)
------------ ------------
The accompanying notes are an integral part of these consolidated
financial statements.
SOLANA RESOURCES LIMITED
CONSOLIDATED BALANCE SHEETS
Expressed in US Dollars
December 31,
2007 2006
$ $
(Note 2) (Note 2)
ASSETS
Current:
Cash and cash equivalents 71,537,827 29,909,168
Cash in trust (Note 5) - 3,274,262
Accounts receivable 7,954,162 6,297,798
Prepaid expenses 790,010 1,030,308
------------ ------------
80,281,999 40,511,536
Deposits (Note 6) 3,156,750 3,041,509
Petroleum and natural gas properties
(Notes 4,7) 81,963,075 54,313,189
Other capital assets (Note 8) 877,051 543,080
Investment (Note 10) 362,427 206,227
------------ ------------
166,641,302 98,615,541
------------ ------------
LIABILITIES
Current:
Accounts payable and accrued liabilities 9,307,557 3,404,607
------------ ------------
Asset retirement obligations (Note 11) 1,973,938 1,556,823
------------ ------------
11,281,495 4,961,430
------------ ------------
SHAREHOLDERS' EQUITY
Share capital and warrants (Note 12) 187,223,652 122,962,256
Contributed surplus (Note 12) 11,762,601 5,035,075
Accumulated other comprehensive income
(Note 2) 5,791,923 5,791,923
Deficit (49,418,369) (40,135,143)
------------ ------------
(43,626,446) (34,343,220)
------------ ------------
155,359,807 93,654,111
------------ ------------
166,641,302 98,615,541
------------ ------------
Commitments and Contingencies (Notes 3, 7 and 11)
APPROVED BY THE BOARD
(signed) "Ray Antony" (signed) "Grant Howard"
-------------------------- ----------------------------
Ray Antony, Director Grant Howard, Director
The accompanying notes are an integral part of these consolidated
financial statements.
SOLANA RESOURCES LIMITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Expressed in US Dollars For the years ended December 31
2007 2006
$ $
(Note 2) (Note 2)
Cash provided by (used in):
Operating activities
Net loss (9,283,226) (27,608,606)
Items not involving cash:
Unrealized foreign exchange (gain)
loss (19,677) 451,324
Stock-based compensation 13,640,012 3,029,830
Future income tax (recovery) - (5,354,505)
Depletion, depreciation, accretion
and impairment 5,789,093 35,163,420
------------ ------------
10,126,202 5,681,463
Changes in working capital - operating 2,767,725 1,433,474
------------ ------------
12,893,927 7,114,937
------------ ------------
Financing activities
Proceeds from issuance of common shares 57,348,910 34,415,917
Proceeds from exercise of options - 12,127
------------ ------------
57,348,910 34,428,044
------------ ------------
Investing activities
Sales of capital assets 23,711 -
Additions to petroleum and natural
gas properties (33,289,074) (25,534,161)
Additions to other capital assets (507,586) (104,098)
Deposits (115,241) (1,198,120)
Investment (156,200) (203,987)
Changes in working capital - investing 2,136,274 (2,072,574)
------------ ------------
(31,908,116) (29,112,940)
------------ ------------
Foreign exchange gain (loss) on cash held
in foreign currency 19,676 (300,000)
------------ ------------
Net increase in cash and cash equivalents 38,354,397 12,130,041
Cash and cash equivalents, beginning of year 33,183,430 21,053,389
------------ ------------
Cash and cash equivalents, end of year 71,537,827 33,183,430
------------ ------------
Represented by:
Cash 2,680,319 6,696,624
Short term deposits 68,857,508 23,212,544
------------ ------------
71,537,827 29,909,168
Cash in trust - 3,274,262
------------ ------------
71,537,827 33,183,430
------------ ------------
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2007 and 2006
(Figures are expressed in US dollars, except otherwise indicated)
NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES
a. Basis of Presentation
The consolidated financial statements include the accounts of Solana
Resources Limited ("Solana" or 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 (i.e. based on six thousand cubit feet of natural gas to one
barrel of crude oil). 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 plus the cost of unproved properties, net
of impairment, exceed the net total 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 consolidated 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 lesser of the term of the lease or their useful lives.
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 follows the fair value method of accounting for stock options
and performance warrants. 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 and performance warrants are exercised, the
associated amounts previously recorded as contributed surplus are
reclassified to 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 in money market
instruments with an initial maturity from date of acquisition of 90 days
or less.
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, in
particular the amounts recorded based on estimates of reserves and future
costs and actual results could differ materially from estimated amounts.
l. Earnings per Share
The basic earnings per share is determined using the weighted average
number of shares outstanding during the year. The Company computes
diluted earnings 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 and
warrants are used to repurchase the Company's common shares at the
average market price during the relevant period.
NOTE 2 - CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2007, the Company adopted the new Canadian Institute
of Chartered Accountants ("CICA") standards related to Section 1530,
"Comprehensive Income," Section 3855, "Financial Instruments -
Recognition and Measurement," Section 3861, "Financial Instruments -
Disclosure and Presentation" and Section 3865, "Hedges." As required by
the standards the Company has adopted these standards retrospectively
without restatement.
Section 1530 of the CICA Handbook describes how to report and disclose
comprehensive income and its components. Comprehensive income is the
change in a company's net assets during a period from transactions and
other events and circumstances from non-owner sources. Other than net
earnings, it includes items that would not normally be included in net
earnings. Upon adoption of Section 1530, amounts previously recognized on
the balance sheet as cumulative translation adjustment have been
reclassified as accumulated other comprehensive income.
Upon adoption of Section 3855, all financial instruments were classified
into one of the following five categories: held-for-trading, loans and
receivables, held-to-maturity investments, available-for-sale financial
assets or other based on their initial classification. Held-for-trading
financial assets are measured at fair value with changes in fair value
recorded in other comprehensive income until the instrument is
derecognized or impaired. All derivative instruments are recorded in the
balance sheet at fair value unless they qualify for the normal sale and
normal purchase exemption. All changes in their fair value are recorded
in net income unless the Company applies cash flow hedge accounting in
which case the changes in fair value is mostly recorded in other
comprehensive income. The other categories of financial instruments are
recognized at amortized cost using the effective interest method.
Upon adoption of these standards, the Company classified its cash and
cash equivalents, and cash in trust as held-for-trading, items measured
at fair value which equals the carrying value. Accounts receivable and
deposits are classified as loans and receivables, which are measured at
amortized cost. Investment has been classified as available-for-sale,
which is measured at cost as the fair value is not readily available.
Accounts payable are classified as other financial liabilities, which are
measured at amortized cost.
Transaction costs related to financial assets and financial liabilities
that are not classified as held-for-trading, are expensed using the
effective interest rate method and are recorded within interest expense
whereas transaction costs related to items designated as held for trading
are charged to net earnings.
Section 3865 of the CICA Handbook describes when and how hedge accounting
can be used. Hedging is an activity that may be used by a company to
change an exposure to one or more risks by creating an offset between
changes in the cash flows attributable to a hedge item or changes
resulting from a risk exposure relating to a hedge item and a hedging
item. Hedge accounting allows gains, losses, revenues and expenses from
the derivative and the item it hedges to be recorded in the statement of
loss in the same period. The Company monitors and when appropriate, may
use derivative financial instruments to manage exposure to fluctuations
in oil and natural gas prices. The Company currently does not utilize
hedges or other derivative financial instruments in its operations; as a
result the adoption of Section 3865 currently has no material impact on
the consolidated financial statements of the Company.
All prior periods have been recast to reflect the Company's financial
statements as if they had been historically reported in United States
dollars and this resulted in an accumulated other comprehensive income of
$ 5,791,923.
The Company also adopted Section 3251, "Equity", and Section 1506,
"Accounting Changes". Section 3251 replaces Section 3250, "Surplus," and
describes standards for the presentation of equity and changes on equity
for that reporting period as a result of the application of Section 1530,
"Comprehensive Income." The only impact of Section 1506, "Accounting
Changes," is to provide disclosure of when an entity has not applied a
new source of GAAP that has been issued but is not yet effective. This is
the case with Section 3862, "Financial Instruments - Disclosures" and
3863 "Financial Instruments - Presentation" which are required to be
adopted for fiscal years beginning on or after October 1, 2007. The
Company will adopt these standards on January 1, 2008 and it is expected
that the only effect on the Company will be additional disclosures
regarding the significance of financial instruments for the entity's
financial position and performance; and the nature, extent and management
of risk arising from financial instruments to which the entity is
exposed.
Section 1535, "Capital Disclosures" is effective for annual periods
beginning on or after October 1, 2007 and establishes standards for
disclosing information about the Company's capital and how it is managed.
It requires disclosures of the Company's objectives, policies and
processes for managing capital, the quantitative data about what the
Company regards as capital, whether the Company has complied with any
capital requirements and if it has not complied, the consequences of such
non-compliance. The Company is currently evaluating the impact of the
adoption of this section on the consolidated financial statements.
The adoption of the above new standards had no impact on the Company's
retained earnings as at January 1, 2007.
In addition, on October 1, 2006, the Company changed its reporting
currency from Canadian dollars (Cdn$) to United States dollars ($).
Financial statements for the year ended December 31, 2006 have been
translated from Canadian dollars into United States dollars using the
current rate method. 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. The Consolidated Statements of Loss and Deficit have been
translated using the prevailing average exchange rate for the period,
except for equity transactions which have been translated using the
historical rates of exchange in effect at the dates of the corresponding
transactions.
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 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, or earlier if the
weighted average share price exceeds Cdn$2.75 per share for a
45 consecutive day period. 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 weighted average share price exceeds Cdn$2.75
per share for a 45 consecutive day period.
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 the Company's weighted average
share price exceeds Cdn$2.75 per share for a 45 consecutive day period.
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 purchase price of Cdn$10,782,500 (10 million
Solana shares valued at Cdn$10,782,500, equivalent to US dollars
$9,553,295) was allocated to the fair value of net working capital
acquired of Cdn$78,930. No value was initially ascribed to the
performance warrants as the likelihood of achieving the performance was
considered remote at that time.
The shares held in escrow are presented as having been issued but there
is a reduction to the value of such share capital to the extent that the
related compensation expense has not been earned by the employees. The
Company recognizes stock-based compensation expense and increases share
capital by the same amount each period until the shares fully vest.
Subsequent to year end, the weighted average share price for a 45 day
period exceeded $2.75 and thus the shares and performance warrants were
released from escrow and considered fully vested at that time. As a
result, the 2007 financial statements reflect the vesting of the shares
and performance warrants by way of recognition of increased stock
compensation expense over the accelerated vesting period of 17 months.
The remaining fair value of the shares and performance warrants will be
expensed in 2008 until the date that the shares and performance warrants
vested. The Company recognized $5,724,064 (2006 - $Nil) of stock
compensation expense relating to the performance warrants in 2007 and
$6,912,486 (2006 - $1,516,892) related to the escrowed shares in 2007.
NOTE 4 - ASSET 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 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 and 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 as of December 31, 2006 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 in 2007.
NOTE 6 - DEPOSITS
The Company has funds on deposit at the totaling of $3,156,750 as of
December 31, 2007 and $3,041,509 as of December 31, 2006, relating to 10%
of work commitments on acquired Agencia Nacional de Hydrocarburos ("ANH")
acreage. These funds will be returned to the Company on completion of the
work commitments (Note 7) on the Guachiria Norte, Guachiria Sur, Garibay,
Catguas blocks, Colonia and San Pablo blocks.
NOTE 7 - PETROLEUM AND NATURAL GAS PROPERTIES
December 31, 2007
Cumulative
DD&A and Net Book
Cost Impairment Value
$ $ $
Oil and gas properties 126,298,776 46,918,526 79,380,250
Inventory 2,582,825 - 2,582,825
-------------------------------------------------------------------------
128,881,601 46,918,526 81,963,075
-------------------------------------------------------------------------
December 31, 2006
Cumulative
DD&A 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
-------------------------------------------------------------------------
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
$26,712,319 are excluded from depletion and depreciation (2006 -
$25,497,601).
At December 31, 2006, an impairment test calculation indicated that the
property carrying amounts exceeded the discounted future net cash flows
associated with the proved and probable reserves, resulting in
recognition of a $29,822,544 impairment adjustment. This impairment was
mainly a consequence of the asset disposition and termination of the
Exploration Participation Agreement with Ramshorn (Note 4). The Company
performed a ceiling test at December 31, 2007 resulting in no requirement
for impairment adjustments. The benchmark West Texas Intermediate Crude
Oil prices used in the 2007 impairment calculation are:
Year $/Barrel
---- --------
2008 90.00
2009 86.52
2010 84.87
2011 83.32
2012 82.78
2013 82.19
2014 81.53
2015 81.99
2016 83.63
2017 85.30
Escalated thereafter 2%/year
Block and Acreage Commitments
The Company has minimum exploration commitments of $47,239,700 to be met
during 2008.
NOTE 8 - OTHER CAPITAL ASSETS
December 31, 2007
Cumulative
Amortization
and Net Book
Cost Depreciation Value
$ $ $
Office furniture, equipment and
vehicles 916,380 299,121 617,259
Leasehold improvements 344,678 84,886 259,792
-------------------------------------------------------------------------
1,261,058 384,007 877,051
-------------------------------------------------------------------------
December 31, 2006
Cumulative
Amortization
and Net Book
Cost Depreciation Value
$ $ $
Office furniture, equipment and
vehicles 513,944 157,360 356,584
Leasehold improvements 263,239 76,743 186,496
-------------------------------------------------------------------------
777,183 234,103 543,080
-------------------------------------------------------------------------
NOTE 9 - CUMULATIVE DD&A, AND IMPAIRMENT
Cumulative DD&A (depletion, depreciation and accretion), and impairment
balance as follows:
December 31, December 31,
2006 Additions 2007
$ $ $
PNG properties - DD&A 11,456,793 5,639,189 17,095,982
Other Assets - Amortization and
depreciation 234,103 149,904 384,007
Impairment of PNG properties 29,822,544 - 29,822,544
-------------------------------------------------------------------------
41,513,440 5,789,093 47,302,533
-------------------------------------------------------------------------
NOTE 10 - INVESTMENT
The Company has invested $362,427 (2006 - $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, it is expected that the Fund will be wound up, and any
remaining capital and any 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, 2007, the Company
estimated the present value of its asset retirement obligations to be
$1,973,938 based on a future liability of $2,204,081 (2006 - $1,556,823
and $2,007,878 respectively). These costs are expected to be incurred in
the next 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.
2007 2006
$ $
Balance, January 1 1,556,823 536,547
Obligations incurred during the year 282,566 979,844
Accretion 134,549 40,432
-------------------------------------------------------------------------
Balance, December 31 1,973,938 1,556,823
-------------------------------------------------------------------------
NOTE 12 - SHARE CAPITAL
Authorized share capital consists of an unlimited number of common
shares.
Number Amount
$
Common shares:
Balance, December 31, 2005 64,736,792 87,017,320
-------------------------------------------------------------------------
Exercise of stock options 140,000 12,127
Private placement of common shares, net
of issuance costs 21,000,000 34,415,917
Shares issued in escrow - Breakaway (Note 3) 10,000,000 9,553,295
Shares in escrow to be earned (Note 3) (8,036,403)
-------------------------------------------------------------------------
Balance, December 31, 2006 95,876,792 122,962,256
Private placement of common shares,
net of issuance costs 27,300,000 57,348,910
Shares issued in escrow - earned in period
(Note 3) 6,912,486
-------------------------------------------------------------------------
Balance, December 31, 2007 123,176,792 187,223,652
-------------------------------------------------------------------------
Contributed surplus:
Balance, December 31, 2005 3,522,137
Stock-based compensation expense - stock options 1,512,938
-------------------------------------------------------------------------
Balance, December 31, 2006 5,035,075
Stock-based compensation expense - stock options 1,003,462
Warrants issued in escrow - earned in period (Note 3) 5,724,064
-------------------------------------------------------------------------
Balance, December 31, 2007 11,762,601
-------------------------------------------------------------------------
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, 2007, 4,625,000 options were outstanding
under the stock option plan (December 31, 2006 - 4,350,000). At
December 31, 2007, 7,692,679 common shares were reserved for issuance
under the stock option plan.
December 31, 2007 December 31, 2006
Weighted Weighted
Number Average Number Average
of Shares Price of Shares Price
(Cdn$ (Cdn$
Per Per
Share) Share)
Outstanding, beginning year 4,350,000 1.64 4,015,000 2.01
Granted, during the year 1,965,000 2.14 1,655,000 1.25
Exercised during the year - - (140,000) 0.10
Expired or cancelled during
the year (1,690,000) 1.92 (1,180,000) -
----------- -----------
Outstanding, end of year 4,625,000 1.75 4,350,000 1.64
----------- -----------
Exercisable, end of year 1,873,333 1.55 1,923,333 1.90
----------- -----------
December 31, 2007
Weighted
Average
Number of Remaining Number of
Exercise Options Contractual Options Exercise
Price Outstanding Life (years) Exercisable Price
2.75 350,000 1.92 350,000 2.75
2.72 200,000 2.90 200,000 2.72
2.50 75,000 4.82 - -
2.25 1,665,000 4.96 - -
2.11 30,000 3.28 10,000 2.11
1.70 25,000 4.63 - -
1.67 400,000 2.67 266,667 1.67
1.19 200,000 4.22 - -
1.15 1,200,000 3.92 566,666 1.15
0.60 480,000 0.93 480,000 0.60
-------------------------------------------------------------------------
1.75 4,625,000 3.67 1,873,333 1.55
-------------------------------------------------------------------------
Stock-based compensation expense of $1,003,462 (December 31, 2006 -
$1,512,938) related to options has been recognized in accordance with the
fair value method with a corresponding credit to contributed surplus.
Additional stock based compensation expense of $6,912,486 ( 2006 -
$1,516,892) related with Breakaway acquisition shares and $5,724,064
(2006 - Nil) related to Breakaway performance warrants was recognized
(Note 19).
The Company estimates the fair value of stock options and warrants
granted using the Black-Scholes option pricing model with the following
assumptions:
December 31
2007 2006
Risk-free interest rate (%) 3.87 4.25
Expected life (years) 5 5
Volatility in the price of common shares (%) 103.1 96.5
Dividends per common share (Cdn$ per share) - -
The resultant weighted average fair value per option amounts to Cdn$1.55
(2006 - Cdn$0.88 ) and warrants fair value was Cdn$0.73 (2006 - Nil).
NOTE 13 - RELATED PARTY TRANSACTIONS
For the year ended December 31, 2007 management fees of $56,076
(December 31, 2006 - $52,907) were paid to a company controlled by 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. There are
no receivable or payable balances with related parties at December 31,
2006 or 2007.
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:
2007 2006
$ $
Statutory tax rate 36.3% 38%
Loss before tax (9,193,969) (32,761,878)
-------------------------------------------------------------------------
(3,337,411) (12,449,514)
Non-deductible stock-based compensation 4,951,324 1,150,000
Unrecognized tax (expense) benefit (1,613,913) 5,945,009
-------------------------------------------------------------------------
Recovery of future income taxes - 5,354,505
-------------------------------------------------------------------------
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:
2007 2006
$ $
Property plant and equipment 4,700,000 4,300,000
Asset retirement obligation 630,000 510,000
Non-capital losses carried forward 3,200,000 3,300,000
Share issue costs 1,000,000 1,000,000
Less valuation allowance (9,530,000) (9,110,000)
------------ ------------
Future income tax liability - -
------------ ------------
Subject to confirmation from taxation authorities, the Company has
approximately Cdn$10.2 million of Canadian non-capital loss carry
forwards which expire between 2008 and 2027, and Colombian tax losses
totaling Col$78 billion ($38.6 million) 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.
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.
2007 2006
$ $
Current Income taxes 89,257 201,233
Future Tax Recovery - (5,354,505)
------------ ------------
89,257 (5,153,272)
------------ ------------
------------ ------------
NOTE 15 - NET LOSS PER SHARE
Basic net loss per share is calculated using the weighted average number
of shares outstanding during the year ended December 31, 2007 which is
98,569,395 (December 31, 2006 - 82,067,532). The impact of options and
performance warrants was not included in the calculation of the net loss
per share as this would be anti-dilutive.
NOTE 16 - SEGMENTED INFORMATION
The Company's oil and gas activities are conducted exclusively in
Colombia.
2007 Canada Colombia Total
$ $ $
Oil and gas revenues, net of
royalties - 18,294,389 18,294,389
Interest 906,747 184,574 1,091,321
-------------------------------------------------------------------------
906,747 18,478,963 19,385,710
Operating expenses - 3,944,131 3,944,131
General and administrative
expenses 2,418,500 2,710,653 5,129,153
Depletion, depreciation and
accretion 12,989 5,776,104 5,789,093
Foreign exchange loss(gain) 9,257 68,033 77,290
Stock-based compensation 13,640,012 - 13,640,012
-------------------------------------------------------------------------
16,080,758 12,498,921 28,579,679
-------------------------------------------------------------------------
Loss before income taxes (15,174,011) 5,980,042 (9,193,969)
Income tax expense - (89,257) (89,257)
-------------------------------------------------------------------------
Net loss (15,174,011) 5,890,785 (9,283,226)
-------------------------------------------------------------------------
Total assets 83,157,756 83,483,546 166,641,302
-------------------------------------------------------------------------
Capital expenditures - 33,289,074 33,289,074
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
1,313,081 9,698,862 11,011,943
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 5,292,644 5,340,876
Impairment - 29,822,544 29,822,544
Foreign exchange gain (715,622) (1,430,064) (2,145,686)
Stock-based compensation 3,029,830 - 3,029,830
-------------------------------------------------------------------------
3,743,788 40,030,033 43,773,821
---------------------------------------
-------------------------------------------------------------------------
Loss before income taxes (2,430,707) (30,331,171) (32,761,878)
Income tax recovery - 5,153,272 5,153,272
-------------------------------------------------------------------------
Net loss (2,430,707) (25,177,899) (27,608,606)
-------------------------------------------------------------------------
Total assets 29,236,403 77,379,138 98,615,541
-------------------------------------------------------------------------
Capital expenditures 24,224 25,509,937 25,534,161
-------------------------------------------------------------------------
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 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 its
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, 2007 and 2006, the Company had not entered into
any such contracts.
NOTE 18 - CREDIT FACILITY
On December 20, 2007, the Company, through its wholly owned subsidiary,
Solana Colombia, secured a $100 million senior first lien three year
revolving secured credit facility with BNP Paribas Bank. The initial
amount available for drawdown under the facility is $26 million and
amounts drawn down bear an interest rate that varies with the Company's
net production ranging from 2.375% to 3.125% over LIBOR. The facility is
secured by the Company's Colombian oil and gas reserves and the amount
available for drawdown will be adjusted pursuant to the lender's review
of semi-annual reserve reports. During the year ended December 31, 2007,
the Company did not draw on this credit facility.
NOTE 19 - SUBSEQUENT EVENT
The Company's shares traded at a weighted average price that exceeded
Cdn$2.75 per share for a 45 consecutive day period subsequent to the 2007
year-end. Thus, on February 5, 2008, all the remaining securities that
were held in escrow (Note 3), were released in accordance with the
voluntary share escrow agreement.
Corporate Information
Directors Nominated Adviser
Raymond P. Antony, Chair (1,2,3,4) Nabarro Wells & Co. Limited
Stan Grad, Director (2,4)
Grant Howard, Director (1,3,4) UK Broker
Roy H. Hudson, Director (3,4) Tristone Capital Limited
Keith J. Jackson, Director (1,4)
J. Scott Price, Director,
President & CEO (2,4)
(1) Audit Committee
(2) Reserves Committee
(3) Corporate Governance and Compensation Committee
(4) Health, Environment and Safety Committee
Management
J. Scott Price, President & CEO
Glenn Van Doorne, COO
Ricardo Montes, CFO
Trading Symbols
TSX-V: SOR
LSE (AIM): SORL
Transfer Agents
Valiant Trust Company
Auditor
Deloitte & Touche LLP
Legal Counsel
Davis LLP
Banker
Royal Bank of Canada
Offices
Head Office: Subsidiary:
Suite 640, 340 - 12th Avenue S.W. Solana Petroleum Exploration
Calgary, Alberta, T2R 1L5 (Colombia) Limited
Regatta Office Park, West Bay Road,
P.O.Box 31106
SMB
Canada Gran Cayman, KYl-1205,
Tel.: 403-770-1822 Cayman Islands
Fax.: 403-770-1826 Tel.: 345-949-3977
Fax.: 345-945-7566
Branch:
Solana Petroleum Exploration
Colombia Limited
Calle 113 No. 7-21, Of 706
Torre A, Edificio Teleport
Bogota, D.C. Colombia
Tel: 011 571 629 1636
Fax: 011 571 629 1704
www.solanaresources.com
-----------------------
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
mmbtu million British thermal units
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.