CALGARY and LONDON, Nov. 28 /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 nine month period ended September 30, 2007. These results should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2006 and 2005. All numbers in this report are expressed in US dollars unless otherwise indicated.
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 held through its wholly owned subsidiary, Solana Petroleum Exploration (Colombia) Limited. The company is headquartered in Calgary, Alberta, Canada.
Additional information (which does not form part of this announcement) is available on the Company's website at www.solanaresources.com and the Sedar website at www.sedar.com.
HIGHLIGHTS
- On September 11, 2007 Solana successfully completed drilling the Tres
Curvas-1 well, located in the Catguas Block, Catatumbo Basin, north
eastern Colombia, resulting in a new field discovery. Tres Curvas-1
yielded a combined 180 barrels of oil per day (Bopd) from 61 feet of
perforations in two Catatumbo formation zones. Solana is the operator
of the Catguas Block with a 100% working interest. Trayectoria Oil
and Gas, Sucursal Colombia holds a 15% beneficial interest in the
portion of the block containing the Tres Curvas-1 well.
- In September 2007, long term production testing was initiated at
Costayaco-1. Solana's share of these test volumes helped boost its
total Q3 exit production rate to 1,472 barrels of oil equivalent per
day (Boepd) net of royalties - a 943 Boepd increase over the previous
quarter. Solana averaged 818 Boepd net of royalties over the entire
third quarter of 2007.
- At September 30, 2007 the Company had a cash balance of
$11.8 million.
- Subsequent to the end of the third quarter, on November 13, 2007, a
declaration of commerciality for the Juanambu field was obtained (35%
net working interest to Solana). Juanambu-1 was immediately placed on
production and is currently producing in the range of 450 Bopd net of
royalties to Solana.
- Subsequent to the end of the third quarter, on November 16, 2007,
Solana spudded the Cocodrilo-1 well. Cocodrilo-1 is the second of the
two well program Solana is undertaking on the Catguas Block and is
targeting the Barco and Catatumbo formations that have been
identified on 2D seismic and that are oil bearing in the nearby Tres
Curvas-1 new field discovery. This well is expected to take three
weeks to drill with testing potentially to follow.
- Subsequent to the end of the third quarter, 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$60.1 million. Solana plans to use the proceeds to
fund its Colombian exploration and development activities and general
corporate purposes.
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 six blocks in the Llanos Basin, covering an area of 2,015 km(2) (778 square miles). These blocks are: Guachiria Norte, Guachiria, Guachiria Sur, Colonia, San Pablo and Garibay.
GUACHIRIA NORTE BLOCK
Solana is the Operator of the 412 km(2) (159 square miles) Guachiria Norte Block with a working interest of 70%. The block is located approximately 250 km (155 miles) northeast of Bogota and is subject to an Agencia Nacional de Hidrocarburos (ANH) contract.
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 (December 21, 2005 to December 21, 2006) 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.
Solana is currently incorporating the results of the Calcedonia-1 well, drilled and abandoned in March 2007, with the Onyx 3-D seismic survey, to optimize the location of the next well, a Carbonera C5 channel target. The Company plans to drill this well prior to the March 21, 2009 deadline.
GUACHIRIA BLOCK
Solana is the Operator of the 68 km(2) (26 square miles) Guachiria Block with a working interest of 70%. The block adjoins the Guachiria 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.
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 Guachiria Norte 3-D seismic survey. Data acquisition and processing are now complete. In this part of the Llanos Basin, drilling and seismic activity is generally restricted to a four-month weather window from December to March.
The Company plans to drill the Primavera-1 well in Q1, 2008 targeting a more traditional Llanos structural play.
GUACHIRIA SUR BLOCK
Solana is the Operator of the 366 km(2) (141 square miles) Guachiria Sur Block with a working interest of 70%. 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 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 covers the northern part of the Block, immediately west and south of the Guachiria Block. Data acquisition and processing are now complete. In this part of the Llanos Basin, drilling and seismic activity is generally restricted to a four-month weather window from December to March.
The Company plans to drill the Palmitas-1 well in January, 2008 targeting a structural play. The Company is currently shooting a 50 line km 2D seismic program over this structure.
GAVIOTAS BLOCK
Solana and its partners relinquished the Gaviotas Block effective August 23, 2007, subject to completion of the abandonment (operational and environmental) of Gaviotas-1 and Bevea-1 wells. These activities are planned for first quarter next year.
GARIBAY BLOCK
Solana is the Operator of the 307 km(2) (119 square miles) Garibay Block with a working interest of 100%. The block is located approximately 170 km (105 miles) east of Bogota. This Block is subject to an ANH contract.
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. Acquisition and processing are now complete and interpretation is underway.
The Company is actively looking for a farm-in partner for this Block.
COLONIA BLOCK
On June 25, 2007, Solana acquired the 439 km(2) (169 square mile) Colonia Block, situated immediately to the west of the Guachiria Norte Block. Solana's commitments are to acquire 55 km(2) (21 square miles) of 3-D seismic data and to reprocess the existing 2-D seismic data during the first phase (June 25, 2007 until June 25, 2008), and to drill one exploration well in each of the subsequent five annual phases.
The acquisition of the 3-D seismic data is scheduled to start in December 2007.
The Company is actively seeking to farm down 30% of its interest in this Block to bring its interest in line with the neighbouring three Guachiria blocks.
SAN PABLO BLOCK
On June 25, 2007, Solana acquired the 423 km(2) (163 square mile) San Pablo Block, situated immediately to the west of the Guachiria Sur Block. Solana's commitments are to acquire 50 km(2) (19 square miles) of 3-D seismic data during the first phase (June 25, 2007 until June 25, 2008) and to drill one exploration well in each of the subsequent five annual phases.
The acquisition of the 3-D seismic data is scheduled to start in December 2007.
The Company is actively seeking to farm down 30% of its interest in this Block to bring its interest in line with the neighbouring three Guachiria blocks.
PUTUMAYO BASIN
The Putumayo basin is located in southwest Colombia and extends into Ecuador and Peru, 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 537 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 89 m(3)/day (561 Bopd, 191 Bopd net to Solana). 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. 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 as of September 30, 2007 has produced a total of 7,094 m(3) (44,621 bbls) gross.
On November 13, 2007, a declaration of commerciality was received from Ecopetrol, the state oil company, for the Juanambu field and Juanambu-1 was placed on production at approximately 1,400 Bopd (450 Bopd net of royalty to Solana). Production, currently being transported by truck to existing infrastructure, will flow through a five kilometre, six inch flow-line that is expected to be operational by mid January 2008.
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 2 (June 27, 2006 to June 26, 2007) the partners drilled Costayaco-1 discovery well. This well tested six zones over four formations through cased hole and yielded an exceptional 939 m(3)/day (5,906 Bopd) combined maximum flow rate from 47.2 m (155 ft) of perforations.
The Pride-17 drilling rig, used to drill Costayaco-1, is expected to be available for additional drilling in December. Current plans include drilling two additional wells as soon as Pride-17 is available. To assist with future development drilling location selection, a 70 km(2) 3-D seismic program has been initiated and is expected to be completed by the end of December 2007.
Pursuant to regulatory requirements, the well has been intermittently tested since June 10, 2007 and as of September 30, 2007 has produced a total of 10,645 m(3) (66,957 bbls) gross. The well is currently on a long term test and production is trucked to existing facilities, located on the Guayuyaco Block. Costayaco-1's production rate is currently limited by trucking capacity. A ten kilometer, eight inch pipeline, tying into existing infrastructure, is being designed to replace trucking operations.
The Chaza block is subject to a fiscally attractive Agencia Nacional de Hidrocarburos contract with no additional state participation.
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 one block in the Catatumbo sub-basin, namely Catguas.
CATGUAS BLOCK
Solana is the operator of the 1,591 km(2) (614 square miles) Catguas Block with 100% working interest. In the southernmost two-thirds and in the northern third of the Block, Trayectoria Oil and Gas, Sucursal Colombia, has a 15% and 50% beneficial interest respectively.
The block is held under an ANH contract. Fulfillment of first Phase (November 17, 2005 to May 17, 2007) commitments is underway. The acquisition of 200 line-km (124 miles) of seismic data and 10 line-km (six miles) of high resolution seismic has been completed.
Seismic interpretation and geochemical mapping identified several drillable prospects. Two shallower Barco structures, Tres Curvas and Cocodrilo, were selected. Tres Curvas-1 has been drilled and completed as a new oilfield discovery and Cocodrilo-1 will follow immediately afterwards. An extension to the phase deadline was requested and granted.
In September 2007, Solana successfully drilled, logged and cased a potential new field discovery, the Tres Curvas-1 wildcat exploration well. Tres Curvas-1 reached a total measured depth of 3,550 feet (total vertical depth of 3,518 feet). Initial log interpretations, sidewall cores, and hydrocarbon shows encountered during drilling indicated reservoir quality sandstones with potential oil pay within the Los Cuervos, Barco and Catatumbo formations. Five zones were tested with cased hole drill stem tests in October 2007. The drill stem tests confirmed that the targeted zones were significantly under-pressured and have high porosities and permeabilities.
The preliminary test results for Tres Curvas-1, completed in October 2007, yielded a combined 180 Bopd from 61 feet of perforations in two Catatumbo formation zones.
As a result of a regulatory requirement to reach total depth at Cocodrilo-1 before November 27, 2007, Solana decided to cease testing at Tres Curvas-1 with the DWS drilling rig and move the rig to Cocodrilo-1 immediately. Spud date for Cocodrilo-1 was November 15, 2007.
Given the initial positive Tres Curvas-1 results, further testing to determine optimal flow rates and initial reserves is required. A service rig is being sourced to undertake this evaluation.
The Catguas Block is subject to a fiscally attractive ANH Contract with no additional state participation.
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 84 km(2) (32 square mile) Magangue Block, which is currently producing 97,000 m(3)/day (3.4 mmcfd, 1.0 mmcfd net to Solana) and sold into the local market at a current price of $2.55/mmbtu. Solana is currently re-evaluating the available seismic and geological information to identify possible workover opportunities and other possible targets.
OUTLOOK
Over the next three months, Solana looks to drill the last well in its 2007 six exploration well drilling program that has yielded three discoveries to date. Two wells drilled in the Putamayo basin, Juanambu-1 on the Guayuyaco Block and Costayaco-1 on the Chaza Block, and Tres Curvas-1 drilled on the Catguas Block in the Catatumbo basin, are all new field discoveries. Conversely, the two wells drilled in the Llanos basin, Calcedonia-1 on the Guachiria Norte Block and Bevea-1 on the Gaviotas Block, were abandoned.
By year end, Solana will have drilled the Cocodrilo-1 well on the Catguas Block and one Costayaco step out well. A second Costayaco step out well will immediately follow the first step out. Additionally, the acquisition of the Costayaco 3-D seismic program should be completed by year end, with processing to follow in early 2008.
On November 13, 2007, a declaration of commerciality was received from Ecopetrol, the state oil company, for the Juanambu field and Juanambu-1 was placed on production at approximately 1,400 Bopd (450 Bopd net of royalty to Solana). A six kilometer, six inch flowline tying Juanambu-1 into the Toroyaco facilities should be complete by mid January 2008 and will eliminate Juanambu-1 trucking. Costayaco-1 is expected to produce throughout the fourth quarter with production constrained by trucking limitations.
Based on the 320 km(2) of 3D seismic acquired during the first quarter of 2007 in the Guachiria and Guachiria Sur Blocks and other seismic, drilling locations for the next Llanos dry season drilling campaign have been selected. Rigs are being sourced.
In addition to development activity on Costayaco, Juanambu, Tres Curvas and possibly Cocodrilo (in the event of a discovery), Solana looks forward to drilling five to six exploration wells in 2008. Significantly more management time and capital will be applied to the highly prospective Catguas Block.
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 Quarterly Information
The following table summarizes selected financial data for Solana for each of the two most recently completed financial three month and nine month periods ended September 30, 2007 and 2006.
September 2007 September 2006
-------------------------------------------------------------------------
Three Nine Three Nine
Months Months Months Months
Ended Ended Ended Ended
-------------------------------------------------------------------------
$ $ $ $
-------------------------------------------------------------------------
Revenue
Production Revenue,
net of
Royalties 3,152,267 5,953,735 3,308,657 7,887,763
Operating costs 969,405 2,443,658 567,023 1,563,566
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2,182,862 3,510,077 2,741,634 6,324,197
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Expenses
General and
administrative 1,165,775 3,545,106 423,640 2,560,787
Depletion,
depreciation 2,018,435 4,224,763 886,985 2,899,552
Foreign exchange
loss (gain) 237,775 463,999 (3,424,332) (2,305,790)
Stock-based
compensation 1,302,779 4,134,068 209,875 729,705
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4,724,764 12,367,936 (1,903,832) 3,884,254
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September 2007 September 2006
-------------------------------------------------------------------------
Three Nine Three Nine
Months Months Months Months
Ended Ended Ended Ended
-------------------------------------------------------------------------
$ $ $ $
-------------------------------------------------------------------------
Other income/(expenses)
Interest and other 193,397 663,796 343,951 1,074,426
Income taxes - (89,258) (260) (46,271)
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193,397 574,538 343,691 1,028,155
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Net income (loss) (2,348,505) (8,283,321) 4,989,157 3,468,098
Net income (loss)
per share (0.02) (0.08) 0.05 0.04
September 30, December 31,
2007 2006
-------------------------------------------------------------------------
$ $
Share capital 126,347,717 122,962,256
Working capital 12,045,307 37,106,929
Petroleum and natural gas properties 75,135,164 54,313,189
Total assets 96,771,186 98,615,541
Total current liabilities 5,629,716 3,404,607
Shareholders' equity 89,494,518 93,654,111
Cash dividends per share NIL NIL
Results of operations for the three and nine month periods ending
September 30, 2007
This consolidated financial information includes the revenue and expenses of the Company for the nine month periods ended September 30, 2007 and 2006. During the nine month period ended September 30, 2007, revenue from operations amounted to $5,953,735. In this same period, operating costs were $2,443,658 resulting in an operating profit of $3,510,077. During the nine month period ended September 30, 2006, the Company generated revenue of $7,887,763. In this same period operating costs were $1,563,566 resulting in an operating profit of $6,324,197. This lower operating profit is mainly due to lower production volumes from the Guayuyaco field (46,139 bbls as of September 30, 2007 versus 105,323 bbls as of September 30, 2006). Higher crude prices somewhat mitigated the effect these lower production volumes had on revenue. Operating costs as a percentage of the net revenue are significantly higher in the nine month period ending September 30, 2007 in comparison with the period ending September 30, 2006 (41% versus 19%) and in the three month period ending September 30, 2007 in comparison with the three month period ending September 30, 2006 (30% versus 17%) due to the impact of additional costs incurred during testing of new discoveries.
The Company produced on average 588 Boepd for the nine months ended September 30, 2007 and 663 Boepd for the nine months ended September 30, 2006. Production from Costayaco-1 testing offset the lower Guayuyaco production volumes. Additionally, the average is affected by the income from Juanambu test volumes (15,000 bbls equivalent to about $858,000) accounted as cost recovery rather than crude sales revenue.
The Company's revenue (net of royalties), operating costs and net backs for the three month periods ended September 30, 2007 and 2006 are:
September 30, 2007 September 30, 2006
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Three Nine Three Nine
Months Months Months Months
Ended Ended Ended Ended
Oil
Bopd - Average 659 421 585 483
Revenue, net of
royalties per
barrel 62.42 53.77 57.31 54.35
Net operating costs
per barrel 14.59 15.46 9.44 8.96
Gas
Mcf per day - Average 952 1,006 1,031 1,082
Revenue, net of
royalties per Mcf 2.42 2.29 2.28 2.26
Net operating costs
per Mcf 0.91 0.90 0.85 0.67
General and administrative expenses for the three and nine month periods ended September 30, 2007 amounted to $1,165,775 and $3,545,106 respectively, in comparison to the three and nine month period ended September 30, 2006, which were to $423,640 and $2,560,787 respectively.
The substantial components of general and administrative expenses are as follows:
September 30, 2007 September 30, 2006
-------------------------------------------------------------------------
Three Nine Three Nine
Months Months Months Months
Ended Ended Ended Ended
$ $ $ $
General office 252,076 790,271 (149,784) 938,987
Salaries & Benefits 877,168 2,086,667 351,370 735,895
Professional fees 45,348 240,639 52,570 372,092
Public company costs 137,155 323,092 152,222 404,520
Consulting fees (145,972) 104,437 17,262 109,293
---------------------------------------------------
1,165,775 3,545,106 423,640 2,560,787
---------------------------------------------------
---------------------------------------------------
General and administrative expenses increased in the 2007 three month and nine month periods in comparison with same periods of the previous year mainly due to costs related with labor contract terminations, higher salaries and benefits, and a 20% increase in staff. The General offices credit in the three month period ended September 30, 2006 resulted from a cumulative adjustment of overhead billed to partners. The credit in consulting fees during the three month period ended September 30, 2007 is due to reclassification of consulting fees initially expensed and subsequently allocated to investments in oil and gas properties.
Depletion, depreciation and accretion amounted to $2,018,435 and $4,224,763 for the three and nine month periods ended September 30, 2007, compared to the same periods in 2006, which were $886,985 and $2,899,552 respectively. The variance is due mainly to a substantial increase in the depletable base partially compensated by the impact of the booking additional reserves.
The foreign exchange loss amounted to $237,775 and $463,999 for the three and nine month periods ended September 30, 2007, reflecting variations of the Canadian dollar and the Colombian peso against the U.S. dollar during these periods. A gain of $3,424,333 and $2,305,791 was recognized for the same periods ended September 30, 2006. This variance is also affected by the adoption of the US dollar as the reporting currency effective October 1, 2006.
Stock-based compensation amounted to $1,302,779 and $4,134,068 for the three and nine month period ended September 30, 2007, respectively, as compared to $209,875 and $729,705 for same periods ended September 30, 2006. This significant increase is due to the amortization of stock based compensation associated with the Breakaway acquisition that was concluded in October 2006.
Other income and expenses relate to interest income amounting to $193,397 and $663,796 for the three and nine month periods ended September 30, 2007, respectively, compared to $343,951 and $1,074,426 for the same periods ended September 30, 2006. This decrease in interest income is due to the lower cash balances held throughout the current period.
The net losses are $2,348,505 and $8,283,321 for the three and nine month periods ended September 30, 2007, respectively, compared with net income of $4,989,157 and $3,468,098 for the same periods ended September 30, 2006. These differences are representative of the higher oil and gas revenues and significant foreign exchange gains booked during the three month period ended September 30, 2006.
Selected Quarterly Financial Information
The following table sets out selected Solana unaudited quarterly financial information derived from unaudited quarterly financial statements prepared by management.
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Sept 30, June 30, Mar 31, Dec 31,
2007 2007 2007 2006
Additions to Petroleum
and Natural Gas
properties 7,191,743 10,486,480 7,274,457 7,902,112
Total revenues 3,345,664 1,726,827 1,545,040 2,049,754
General and
administrative
expenses 1,165,775 1,319,363 1,061,304 2,042,166
Depletion,
depreciation and
accretion 2,018,435 945,635 1,266,908 2,441,325
Impairment - - - 29,822,544
Foreign exchange
(gain) loss 237,775 199,233 25,655 160,105
Stock-based
compensation 1,302,779 1,207,881 1,617,193 2,300,703
Loss after income tax (2,348,505) (2,802,217) (3,132,598) (31,076,705)
Loss per share
(basic and diluted) (0.02) (0.05) (0.04) (0.34)
Sep 30, Jun 30, Mar 31, Dec 31,
2006 2006 2006 2005
Additions to Petroleum
and Natural Gas
properties 4,402,811 8,876,927 6,538,659 10,275,878
Total revenues 3,652,608 2,797,670 2,511,910 3,145,166
General and
administrative
expenses 423,640 1,197,315 939,831 960,537
Depletion,
depreciation and
accretion 886,985 957,026 1,055,540 3,976,602
Foreign exchange
(gain) loss (3,424,333) 870,581 247,961 (282,610)
Stock-based
compensation 209,875 228,640 291,191 653,304
Income (Loss) after
income tax 4,989,157 (1,236,674) (284,386) (1,951,707)
Income (Loss) per share
(basic and diluted) 0.05 (0.01) (0.01) (0.05)
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LIQUIDITY
Solana's working capital decreased from $18,039,839 at June 30, 2007, to $12,045,307 at September 30, 2007, largely due to the Company's petroleum and natural gas property expenditures.
The Company has $11,762,900 cash balance at September 30, 2007. Management is actively seeking additional equity and is concurrently structuring a debt facility to fund its ongoing exploration, appraisal and development programs.
The Company currently does not have any long term debt.
SUMMARY OF CASH INFLOWS AND OUTFLOWS
The company generated cash inflows from operations of $1,072,621 and outflows of $843,947 for the three and nine month periods ended September 30, 2007, compared to the same periods in 2006 which generated a cash inflow of $1,071,136 and an outflow of $2,278,717. This difference is substantially due to a reduction in non-cash working capital resulting from the payment of outstanding pending cash calls.
Solana's net cash inflow from financing activities amounted to $23,711 for the nine month period ended September 30, 2007, compared to $34,440,170 for the nine month period ended September 30, 2006, due to the private placement completed in April 2006.
The Company incurred cash outflows from its investing activities of $8,499,697 and $20,620,631 for the three and nine month periods ended September 30, 2007 as compared to $3,673,192 and $19,142,885 for the three and nine month periods ended September 30, 2006. The most significant cash outflow component for the nine month period ended September 30, 2007 was the investment of $24,941,360 in petroleum and natural gas properties.
RELATED PARTY TRANSACTIONS
The Company paid $41,598 in management fees in the current nine month period ended September 30, 2007 to a company controlled by a director of the Company. These fees are included in general and administrative expense.
CAPITALIZATION
Authorized share capital consists of an unlimited number of common shares.
Continuity of common shares Shares Amount
No. $
-------------------------------------------------------------------------
Balance, December 31, 2006 95,876,792 122,962,256
Shares in escrow earned in the period 3,385,461
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Balance, September 30, 2007 95,876,792 126,347,717
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Continuity of stock options Number
-------------------------------------------------------------------------
Balance, December 31, 2006 4,350,000
Issued 225,000
Exercised -
Expired 1,421,668
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Balance, September 30, 2007 3,153,332
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Continuity of warrants Number
-------------------------------------------------------------------------
Balance, December 31, 2006 10,000,000
Issued -
Exercised -
Expired -
-------------------------------------------------------------------------
Balance, September 30, 2007 10,000,000
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SUBSEQUENT EVENTS
Subsequent to the end of the third quarter, on November 13, 2007, a declaration of commerciality for the Juanambu field was obtained (Solana net 35% working interest). Juanambu-1 was immediately placed on production and is currently producing in the range of 450 Bopd net of royalties to Solana.
Subsequent to the end of the third quarter, on November 16, 2007, Solana spudded the Cocodrilo-1 well. Cocodrilo-1 is the second of the two well program Solana is undertaking on the Catguas Block and is targeting the Barco and Catatumbo formations that have been identified on 2D seismic and that are oil bearing in the nearby Tres Curvas-1 new field discovery. This well is expected to take three weeks to drill with testing potentially to follow.
Subsequent to the end of the third quarter, 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. Solana plans to use the proceeds to fund its Colombian exploration and development activities and general corporate purposes.
MANAGEMENT'S ASSESSMENT OF INTERNAL CONTROLS AND
DISCLOSURE CONTROLS AND PROCEDURES
Management has evaluated the effectiveness of the Company's disclosure controls and procedures as of September 30, 2007. Based on this evaluation, management has concluded that the Company's disclosure controls and procedures, as defined in Multilateral Instrument 52-109, are sufficient 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 periods 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 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 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 a known hydrocarbon basin, in a jurisdiction that has previously established long-term oil and gas ventures with foreign oil and gas companies, existing infrastructure 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 operation, 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 Operation
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 facilities, 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 impaired 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 products 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%.
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
INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the Three and Nine Month Periods Ended
September 30, 2007 and 2006
(Unaudited)
Notice to Reader:
The accompanying unaudited interim consolidated financial statements of
Solana Resources Limited (the "Company") for the three and nine month periods
ended September 30, 2007 and 2006 have been prepared by management and
approved by the Audit Committee and the Board of Directors of the Company.
These statements have not been reviewed by the Company's external auditors.
DATED the 28th day of November, 2007
(signed) "Scott Price"
J. Scott Price,
President and Chief Executive Officer
SOLANA RESOURCES LIMITED
INTERIM CONSOLIDATED BALANCE SHEET
(Unaudited)
Expressed in US Dollars
September 30, December 31,
2007 2006
$ $
------------- -------------
ASSETS
Current:
Cash and cash equivalents 11,762,900 29,909,168
Cash in trust - 3,274,262
Accounts receivable - trade 4,378,713 1,472,209
- cash calls 1,296,634 4,825,589
Prepaid expenses 236,776 1,030,308
------------- -------------
17,675,023 40,511,536
Deposits (Note 3) 2,796,750 3,041,509
Petroleum and natural gas properties 75,135,164 54,313,189
Other capital assets 840,065 543,080
Investment (Note 4) 324,184 206,227
------------- -------------
79,096,163 58,104,005
------------- -------------
96,771,186 98,615,541
------------- -------------
------------- -------------
LIABILITIES
Current:
Accounts payable and accrued liabilities
- trade 5,130,028 3,404,607
- cash calls 499,688 -
------------- -------------
5,629,716 3,404,607
Asset retirement obligations (Note 5) 1,646,952 1,556,823
------------- -------------
7,276,668 4,961,430
SHAREHOLDERS EQUITY
Share capital (Note 6) 126,347,717 122,962,256
Contributed surplus (Note 6) 5,773,342 5,035,075
Accumulated other comprehensive income
(Note 2) 5,791,923 5,791,923
Deficit (48,418,464) (40,135,143)
------------- -------------
89,494,518 93,654,111
------------- -------------
96,771,186 98,615,541
------------- -------------
------------- -------------
SOLANA RESOURCES LIMITED
INTERIM CONSOLIDATED STATEMENT OF LOSS AND DEFICIT
(Unaudited)
Expressed in US Dollars
September 30, 2007 September 30, 2006
Three Nine Three Nine
months months months months
ended ended ended ended
$ $ $ $
------------ ------------ ------------ ------------
Revenue
Oil and gas
revenues, net
of royalties 3,152,267 5,953,735 3,308,657 7,887,763
Interest 193,397 663,796 343,951 1,074,426
------------ ------------ ------------ ------------
3,345,664 6,617,531 3,652,608 8,962,189
------------ ------------ ------------ ------------
Expenses
Operating 969,405 2,443,658 567,023 1,563,566
General and
administrative 1,165,775 3,545,106 423,640 2,560,787
Depletion,
depreciation and
accretion 2,018,435 4,224,763 886,985 2,899,552
Foreign exchange
loss (gain) 237,775 463,999 (3,424,332) (2,305,790)
Stock-based
compensation
(Note 6) 1,302,779 4,134,068 209,875 729,705
------------ ------------ ------------ ------------
5,694,169 14,811,594 (1,336,809) 5,447,820
------------ ------------ ------------ ------------
Income (loss) before
income taxes (2,348,505) (8,194,063) 4,989,417 3,514,369
Income Taxes - 89,258 260 46,271
------------ ------------ ------------ ------------
Net Income (loss) (2,348,505) (8,283,321) 4,989,157 3,468,098
Deficit, beginning
of period (46,069,959) (40,135,143) (14,047,596) (12,526,537)
------------ ------------ ------------ ------------
Deficit, end
of period (48,418,464) (48,418,464) (9,058,439) (9,058,439)
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Income (loss) per
share (Note 7) (0.02) (0.08) 0.05 0.04
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
SOLANA RESOURCES LIMITED
INTERIM CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
Expressed in US Dollars
September 30, 2007 September 30, 2006
Three Nine Three Nine
months months months months
ended ended ended ended
$ $ $ $
------------ ------------ ------------ ------------
Summary of activities
Operating activities
Net Income (loss) (2,348,505) (8,283,321) 4,989,157 3,468,098
Items not
involving cash:
Unrealized
foreign exchange
loss (gain) 151,983 (186,829) - 594,847
Depletion,
depreciation
and accretion 2,018,435 4,224,763 886,985 2,899,554
Stock-based
compensation 1,302,779 4,134,068 209,875 729,705
------------ ------------ ------------ ------------
1,124,692 (111,319) 6,086,017 7,692,204
Changes in non-cash
working capital (52,071) (732,628) (5,014,882) (9,970,922)
------------ ------------ ------------ ------------
1,072,621 (843,947) 1,071,135 (2,278,718)
------------ ------------ ------------ ------------
Financing activities
Proceeds from the
exercise of options - - - 12,127
Proceeds from the
issuance of shares - - - 36,725,684
Cost of issuance - - - (2,297,641)
Sale of capital
assets - 23,711 - -
------------ ------------ ------------ ------------
- 23,711 - 34,440,170
Investing activities
Additions to
petroleum & NG
properties (7,191,743) (24,941,360) (4,402,811) (19,818,397)
Additions to
Investments (26,163) (117,957) - (316,593)
Changes in non-cash
working capital (1,375,709) 4,373,720 (3,578) 1,189,564
Additions to capital
assets (156,082) (179,793) (10,624) (105,641)
Deposits 250,000 244,759 743,821 (91,818)
------------ ------------ ------------ ------------
(8,499,697) (20,620,631) (3,673,192) (19,142,885)
------------ ------------ ------------ ------------
Foreign exchange 4,765 20,337 (58,384) 5,578,843
------------ ------------ ------------ ------------
Net increase
(decrease) in cash (7,422,311) (21,420,530) (2,660,441) 18,597,410
Cash and cash
equivalents,
beginning of period
(Note 9) 19,185,211 33,183,430 37,534,634 16,276,783
------------ ------------ ------------ ------------
Cash and cash
equivalents, end of
period (Note 9) 11,762,900 11,762,900 34,874,193 34,874,193
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
SOLANA RESOURCES LIMITED
INTERIM CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Unaudited)
Expressed in US Dollars
September 30, 2007 September 30, 2006
Three Nine Three Nine
months months months months
ended ended ended ended
$ $ $ $
------------ ------------ ------------ ------------
Net Income (loss) (2,348,505) (8,283,321) 4,989,158 3,468,099
Other Comprehensive
Income (loss) - - - -
------------ ------------ ------------ ------------
Comprehensive
Income (loss) (2,348,505) (8,283,321) 4,989,158 3,468,099
------------ ------------ ------------ ------------
SOLANA RESOURCES LIMITED
Notes to the Interim Consolidated Financial Statements
For the Three Month Periods Ended September 30, 2007 and 2006
(Unaudited)
Note 1. Basis of Presentation
The interim consolidated financial statements of Solana Resources
Limited ("Solana" or the "Company") for the three and nine-month
periods ended September 30, 2007 and 2006 have been prepared by
management in accordance with accounting principles generally
accepted in Canada on the same basis as the audited consolidated
financial statements as at and for the year ended December 31, 2006
except for new standards adopted as described in Note 2. These
interim consolidated financial statements should be read in
conjunction with the consolidated financial statements and the notes
thereto in Solana's annual report for the year ended December 31,
2006, as the interim consolidated financial statements do not conform
in all respects to the note disclosure requirements of Generally
Accepted Accounting Principles for annual financial statements.
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 prospectively. Therefore, the comparative interim
consolidated financial statements have not been restated, except for
the amount relating to the cumulative translation adjustment as
described below.
The 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. 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 are
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 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. 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 as held-for-trading, which are measured at fair
value which equals the carrying value. Accounts receivable and
deposits are classified as loan and receivables, which are measured
at amortized costs. Investments have been classified as held-to-
maturity investments. Accounts payable are classified as other
financial liabilities, which are measured at amortized cost.
For financial assets and financial liabilities that are not
classified as held-for-trading, the transaction costs that are
directly attributable to the acquisition or issue of a financial
asset or financial liability are adjusted to the fair value initially
recognized for that instrument. These costs are expensed using the
effective interest rate method and are recorded within interest
expense.
The Section 3855 of the CICA Handbook describes the standards for
recognizing and measuring financial assets, financial liabilities and
non-financial derivatives. Upon adoption of Section 3855 all
financial instruments should be classified into one of the following
categories: held-for-trading (assets and liabilities), assets
available-for-sale, loans and receivables, assets held-to-maturity
and other financial liabilities. All financial instruments are
measured at fair value on initial recognition. Transaction costs are
included in the initial carrying amount of financial instruments
except for held-for-trading items in which case they are expensed as
incurred. Measurement in subsequent periods depends on the
classification of the financial instruments. Management does not
believe that the adoption of this section will have a material impact
on the financial statements.
The 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 risks 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 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.
Comparative Financial Information.
On October 1, 2006, the Company changed its reporting currency from
Canadian dollars (CDN$) to United States dollars ($). Financial
statements for prior periods presented 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. 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 comparative financial information being presented has been
restated 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 adoption of these new standards had no impact on the Company's
retained earnings as at January 1, 2007.
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 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 3863, "Financial Instruments
Presentations" 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 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.
Note 3. Deposits
At the end of September 30, 2007, the Company had $2,796,750 on
deposit with the Colombian Agency of National Hydrocarbons ("ANH")
reflecting a percentage of the cost of work commitments on certain
ANH exploration blocks. These funds will be returned to the Company
by ANH on completion of the work commitments on the Guachiria Norte,
Catguas, Guachiria Sur, Garibay, Colonia and San Pablo Blocks.
Note 4. Investment
The Company has invested $324,184 in the Colombian Hydrocarbon
Investment Fund ("Fund"), and expects to invest a maximum of
$500,000. The Fund is managed by a U.S. based fund manager, who
specializes in South American natural resources 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 capital and
earned profits will be returned and distributed to the investors over
a maximum period of seven years.
Note 5. Asset Retirement Obligations
The following table represents the reconciliation of the beginning
and ending obligations associated with the retirement of oil and gas
properties:
---------------------------------------------------------------------
Asset retirement obligations December 31, 2006 $1,556,823
Liabilities incurred during period -
Liabilities settled during period -
Accretion 90,129
---------------------------------------------------------------------
Asset retirement obligations, September 30, 2007 $1,646,952
---------------------------------------------------------------------
At September 30, 2007, the estimated total undiscounted amount
required to settle the asset retirement obligations was $1,840,000
(2006 - $2,100,000). These obligations will be settled at the end of
the useful lives of the underlying assets, which currently extend up
to seven years into the future. This amount has been discounted using
a credit-adjusted risk-free discount rate of 10% and an inflation
rate of 2.5%.
Note 6. Share Capital
Authorized share capital consists of an unlimited number of common
shares.
Continuity of common shares Shares Amount
No. $
---------------------------------------------------------------------
Balance, December 31, 2006 95,876,792 122,962,256
Shares in escrow earned in period 3,385,461
---------------------------------------------------------------------
Balance, September 30, 2007 126,347,717
---------------------------------------------------------------------
Continuity of contributed surplus Amount
$
---------------------------------------------------------------------
Balance, December 31, 2006 5,035,075
Stock based compensation expense 738,267
---------------------------------------------------------------------
Balance, September 30, 2007 5,773,342
---------------------------------------------------------------------
Continuity of stock options Number
---------------------------------------------------------------------
Balance, December 31, 2006 4,350,000
Issued 225,000
Exercised -
Expired 1,421,668
---------------------------------------------------------------------
Balance, September 30, 2007 3,153,332
---------------------------------------------------------------------
Continuity of warrants Number
---------------------------------------------------------------------
Balance, December 31, 2006 10,000,000
Issued -
Exercised -
Expired -
---------------------------------------------------------------------
Balance, September 30, 2007 10,000,000
---------------------------------------------------------------------
Warrant terms
---------------------------------------------------------------------
Strike price CDN$2.00/share
Activation price Share price must exceed CDN$2.75 for 45 days
Expiry April 4, 2010
Stock-based compensation
For the nine months of 2007, stock based compensation expense of
$738,267 has been recorded in the Consolidated Statement of Loss and
Deficit (2006 - $729,705). The fair values of all common share
options granted are estimated on the date of grant using the Black-
Scholes option-pricing model. The weighted average fair market value
of options granted and the assumptions used in their determination
are as noted below:
Nine months ended
September 30, 2007
---------------------
Risk-free interest rate (percent) 4.28
Expected life (years) 3.5
Volatility (percent) 70
Expected annual dividend per share -
Note 7. Per-Share amounts
The weighted average number of common shares, basic and diluted,
outstanding during the nine months ended September 30, 2007 was
96,252,392 (September 30, 2006 - 85,876,792).
Note 8. Segmented information
Three month period ended September 30, 2007
Canada Colombia Total
$ $ $
--------------------------------------
Revenue - 3,152,267 3,152,267
Operating costs - 969,405 969,405
--------------------------------------
- 2,182,862 2,182,862
--------------------------------------
General and administrative
expenses 750,505 415,270 1,165,775
Depletion, depreciation,
and accretion 10,118 2,008,317 2,018,435
Foreign exchange loss 19,830 217,945 237,775
Stock-based compensation 1,302,779 0 1,302,779
Interest income (160,891) (32,506) (193,397)
--------------------------------------
1,922,341 2,609,026 4,531,367
--------------------------------------
Income (loss) before taxes (1,922,341) (426,164) (2,348,505)
Income taxes - - -
--------------------------------------
Net income (loss) (1,922,341) (426,164) (2,348,505)
--------------------------------------
--------------------------------------
Identifiable assets 31,157,773 65,613,413 96,771,186
--------------------------------------
--------------------------------------
Expenditures on petroleum and
natural gas properties - 7,191,743 7,191,743
--------------------------------------
--------------------------------------
Nine month period ended September 30, 2007
Canada Colombia Total
$ $ $
--------------------------------------
Revenue - 5,953,735 5,953,735
Operating costs - 2,443,658 2,443,658
--------------------------------------
- 3,510,077 3,510,077
--------------------------------------
General and administrative
expenses 1,798,506 1,746,600 3,545,106
Depletion, depreciation,
and accretion 14,404 4,210,359 4,224,763
Foreign exchange (gain) loss 31,256 432,743 463,999
Stock-based compensation 4,134,068 - 4,134,068
Interest income (587,231) (76,565) (663,796)
--------------------------------------
5,391,003 6,313,137 11,704,140
--------------------------------------
Income (Loss) before taxes (5,391,003) (2,803,060) (8,194,063)
Income taxes - 89,258 89,258
--------------------------------------
Net Income (loss) (5,391,003) (2,892,318) (8,283,321)
--------------------------------------
--------------------------------------
Identifiable assets 31,157,773 65,613,413 96,771,186
--------------------------------------
--------------------------------------
Expenditures on petroleum and
natural gas properties - 24,941,360 24,941,360
--------------------------------------
--------------------------------------
Three month period ended September 30, 2006
Canada Colombia Total
$ $ $
--------------------------------------
Revenue - 3,308,657 3,308,657
Operating costs - 567,023 567,023
--------------------------------------
- 2,741,634 2,741,634
--------------------------------------
General and administrative
expenses 294,869 128,771 423,640
Depletion, depreciation,
and accretion 1,914 885,071 886,985
Foreign exchange (gain) loss 1,260,717 (4,685,050) (3,424,333)
Stock-based compensation 209,875 - 209,875
Interest income (316,488) (27,463) (343,951)
--------------------------------------
1,450,887 (3,698,671) (2,247,784)
--------------------------------------
Income (loss) before taxes (1,450,887) 6,440,305 4,989,418
Capital taxes - 260 260
--------------------------------------
Net Income (loss) (1,450,887) 6,440,045 4,989,158
--------------------------------------
--------------------------------------
Identifiable assets 56,809,735 82,414,507 139,224,242
--------------------------------------
--------------------------------------
Expenditures on petroleum and
natural gas properties - 4,402,811 4,402,811
--------------------------------------
--------------------------------------
Nine month period ended September 30, 2006
Canada Colombia Total
$ $ $
--------------------------------------
Revenue - 7,887,763 7,887,763
Operating costs - 1,563,566 1,563,566
--------------------------------------
- 6,324,197 6,324,197
--------------------------------------
General and administrative
expenses 1,118,526 1,442,261 2,560,787
Depletion, depreciation,
and accretion 5,809 2,893,743 2,899,552
Foreign exchange (gain) loss (77,071) (2,228,720) (2,305,791)
Stock-based compensation 729,705 - 729,705
Interest income (1,041,839) (32,587) (1,074,426)
--------------------------------------
735,130 2,074,697 2,809,827
--------------------------------------
Income (loss) before taxes (735,130) 4,249,500 3,514,370
Capital taxes - 46,271 46,271
--------------------------------------
Net (loss) income (735,130) 4,203,229 3,468,099
--------------------------------------
--------------------------------------
Identifiable assets 56,809,735 82,414,507 139,224,242
--------------------------------------
--------------------------------------
Expenditures on petroleum and
natural gas properties - 19,818,397 19,818,397
--------------------------------------
--------------------------------------
Note 9. Supplemental cash flow information
September 30, September 30,
2007 2006
$ $
------------- -------------
Cash represented by:
Cash and cash equivalents 11,762,900 34,874,194
- -
Restricted cash - 4,776,605
------------- -------------
11,762,900 39,650,799
------------- -------------
------------- -------------
Cash interest paid - -
------------- -------------
Cash taxes paid - -
------------- -------------
Note 10. Related party transactions
Management fees in the amount of $41,598 (2006 - $ 40,261) 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.
Note 11. Income Taxes
Subject to confirmation from taxation authorities, the Company has
approximately CDN$9.9 million ($10 million) of Canadian non-capital
loss carry forwards which expire between 2007 and 2026. Additionally,
the Company has Colombian tax losses totaling Col 65 billion
($30 million) which are available to be carried forward and used to
offset future Colombian taxable income up to a maximum of 25% per
year.
The consolidated financial statements do not reflect the potential
tax benefit of these losses, as currently they do not meet the more
likely than not criteria, to be recognized.
Provision for 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.
Note 12. Commitments
The Company has remaining commitments to be met during 2007 of
$10.3 million. These commitments are 68% related to exploration
activities, 28% to development costs and 4% to comply with
environmental regulatory obligations.
Note 13. Financial instruments
The nature of crude oil and natural gas operations in Colombia expose
the Company to fluctuations in commodity prices and foreign currency
exchange rates. The Company does not manage these risks through the
use of financial instruments.
Credit risk
A substantial portion of the Company's accounts receivable are with
customers in the oil industry and are subject to normal industry
credit risks. The carrying amount of accounts receivable reflects
management's assessment of the credit risk associated with these
customers. Solana's crude oil is sold to the Colombian state oil
company, Ecopetrol, based on world prices adjusted for quality and
transportation. Revenues are denominated in United States dollars.
Typically, the Company's maximum credit exposure to customers is
revenue from two months' sales.
Foreign currency exchange risk
The Company is exposed to foreign currency fluctuations as certain
expenditures and expenses are denominated in Colombian pesos and
Canadian dollars.
Fair value of financial instruments
The Company's financial instruments are classified as cash and cash
equivalents, cash in trust, accounts receivable and deposits and
accounts payable on the balance sheet. The carrying values and fair
values of these financial instruments at September 30, 2007 are not
significantly different due to the short maturity term of these
financial instruments.
Note 14. Subsequent Events
Subsequent to the end of the third quarter, on November 13, 2007, a
declaration of commerciality for the Juanambu field was obtained
(Solana net 35% working interest). Juanambu-1 was immediately placed
on production and is currently producing in the range of 450 Bopd net
of royalties to Solana.
Subsequent to the end of the third quarter, on November 16, 2007,
Solana spudded the Cocodrilo-1 well. Cocodrilo-1 is the second of the
two well program Solana is undertaking on the Catguas Block and is
targeting the Barco and Catatumbo formations that have been
identified on 2D seismic and that are oil bearing in the nearby Tres
Curvas-1 new field discovery. This well is expected to take three
weeks to drill with testing potentially to follow.
Subsequent to the end of the third quarter, 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. Solana plans to use the proceeds to
fund its Colombian exploration and development activities and general
corporate purposes.
Corporate Information
Directors Nominated Adviser
Raymond P. Antony, Chair(1)(3)(4) Nabarro Wells & Co. Limited
Stan Grad, Director(2)(4)
Grant Howard, Director(1)(4) UK Broker
Roy H. Hudson, Director(3)(4) Tristone Capital Limited
Keith J. Jackson, Director(1)(4)
Joaquin Moreno Uribe, Director(2)(3)(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
Canada Regatta Office Park, West Bay Road,
Tel.: 403-770-1822 P.O. Box 31106 SMB
Fax.: 403-770-1826 Gran Cayman, KYl-1205,
Cayman Islands
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: +571 629 1636
Fax: +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
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.