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Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
---|---|---|---|---|---|
Petrolatina | LSE:PELE | London | Ordinary Share | GB00B2QMZ536 | ORD USD0.10 |
Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 19.50 | 0.00 | 01:00:00 |
Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
---|---|---|---|---|---|
0 | 0 | N/A | 0 |
TIDMPELE
RNS Number : 1076I
Petrolatina Energy PLC
08 June 2011
8 June 2011
PetroLatina Energy Plc
("PetroLatina", "PELE" or the "Company")
Final Results for the year ended 31 December 2010
PetroLatina (AIM: PELE), the independent oil and gas exploration, development and production company focused on Latin America, announces its audited final results for the year ended 31 December 2010.
Operational Highlights:
-- Continuation of ongoing drilling campaign: 3 new wells drilled (Querubin-1, Chuira-1, Colon-3ST)
-- Completed the Zoe-1 exploration well which is currently producing at a stable rate of 42 bopd of 23 degree API oil
-- Gross production for the year increased by 35 per cent. to 660,137 (2009: 489,159) bbls, at an average daily gross production rate of 1,809 (2009: 1,340) bopd
-- Net production for the year increased by 25.5 per cent. to 292,694 (2009: 233,285) bbls, at an average daily net production rate of 802 (2009: 639) bopd
-- Petrophysical and field performance studies and resulting reservoir simulation exercises commissioned on the Los Angeles and Santa Lucia fields
-- High resolution seismic reinterpretation commissioned from Arcis Seismic Solutions on the Colon field
-- Seismic reprocessing, fault orientation and density analysis and formation fluid study commissioned from Landocean Energy Services Inc. on the Chuira discovery
Financial Highlights:
-- Revenues increased by 46 per cent. to US$20.1m (2009: US$13.8m)
-- Gross underlying profits (before depreciation and impairment charges) increased to US$10.8m (2009: US$10.1m)
-- Underlying EBITDA generation of US$3.1m (2009: US$5.25m)
-- Loss after tax of US$27.6m (2009: US$12.5m)
-- Loss per share of US$0.43 (2009: US$0.28)
-- Cash and cash equivalents (including term deposits) of US$10m (2009: US$4.9m)
-- Successfully raised, in aggregate, US$25m in new equity from management, existing shareholders and senior lenders to the Company in July/August 2010
-- Entered into a Senior Secured Debt Facility of up to US$75m with Macquarie Bank Limited ("Macquarie"), of which an initial tranche of US$25m was made available and drawndown at completion in March 2010
Post Balance Sheet Events:
-- Announced initial production flow rates of 5.5MMscf/d in respect of a 6 month extended test of the Serafin-1 gas well (50 per cent. working interest and operator, which reduces to 25 per cent. if Ecopetrol S.A. back-in, and after PELE has recovered 200 per cent. of its capex incurred to date from revenues.)
-- Announced an updated independent assessment of the Company's reserves, future production and income attributable to its concessions in Colombia as at 31 December 2010
o Based upon the average oil price received in 2010 and as adjusted to actual prices received for each property, Ryder Scott Company, L.P. provided an NPV10 figure for the Company's 3P reserves of US$280.6m (30 November 2009: US$247m)
-- US$4.875m first tranche of the loan notes held by Tribeca Oil and Gas Financing, Inc. ("TOGF"), a subsidiary of existing substantial shareholder Tribeca Oil & Gas Inc. (a portfolio investment company of Tribeca Asset Management Inc ("Tribeca")), a Colombian private equity firm, converted in full into equity
Outlook:
-- Well positioned to resume development drilling in a more effective and lower risk manner
-- Prospect of strong short term cash flow generation and economic returns from the potential further development of the Serafin field:
o High probability of further gas deposits on the licence area
o Studies underway utilising existing 3D seismic coverage to identify further drillable prospects
Luc Gerard, Executive Chairman of PetroLatina, commented:
"I am pleased to report on another year of progress for PetroLatina. During the year we have consolidated our position as a leading operator in Colombia, with one of the largest acreages in the Middle Magdalena Valley, increasing both production and revenue.
Our decision to continue to focus our efforts on the development of our Colombian assets has proved successful - the country is now generally considered to be amongst the fastest growing and most stable in the region."
Enquiries:
PetroLatina Energy Plc Tel: +57 1627 8435 Juan Carlos Rodriguez, Chief Executive Officer Pawan Sharma, Executive Vice President - Corporate Tel: +44 (0)20 7766 Affairs 0081 Strand Hanson Limited Simon Raggett / Matthew Chandler Tel: +44 (0)20 7409 3494 Evolution Securities Limited Chris Sim / Adam James Tel: +44 (0)20 7071 4304 Financial Dynamics Ben Brewerton / Chris Welsh Tel: +44 (0)20 7831 3113
Availability of Annual Report and Financial Statements
Copies of the Company's full Annual Report and Financial Statements are expected to be posted to shareholders today and, once posted, will also be made available to download from the Company's website at www.petrolatinaenergy.com.
The Annual Report and Financial Statements will also be made available for inspection at the Company's registered office during normal business hours on any weekday. PetroLatina Energy Plc is registered in England and Wales with registered number 05173588. The registered office is at 2nd Floor Suite 2.3, Stanmore House, 29-30 St James's Street, London SW1A 1HB.
Annual General Meeting
The Company's next Annual General Meeting ("AGM") will be held at the offices of Strand Hanson Limited, 26 Mount Row, London W1K 3SQ at 11.00 a.m. on 30 June 2011. The formal Notice of AGM and proxy form have also been posted to shareholders today and can also be downloaded from the Company's website at www.petrolatinaenergy.com.
Chairman's Statement
The Company has undergone significant transformation since Tribeca's initial sizeable investment in July 2008, and I am pleased to report on another progressive year for the Group, which has seen it consolidate its standing as a leading operator in Colombia, holding one of the largest acreages in the Middle Magdalena Valley.
The Group remained focused on its operations in Colombia throughout the year, a strategic decision which has proved successful given the increasing attractiveness of Colombia as a regional oil industry centre and sustained high crude prices. Colombia is generally considered to be one of the fastest growing and most stable countries in Latin America and has regained a coveted investment-grade rating - Standard & Poor's now rate the country's long-term and short-term foreign-currency sovereign credit at BBB- and A3 respectively.
Operational highlights
-- Continuation of an aggressive drilling campaign with 3 new wells being drilled in 2010
-- Gross production for the year increased by 35 per cent. to 660,137 (2009: 489,159) bbls, at an average daily gross production rate of 1,809 (2009: 1,340) bopd; and
-- Net production for the year increased by 25.5 per cent. to 292,694 (2009: 233,285) bbls, at an average daily net production rate of 802 (2009: 639) bopd.
-- Total revenues for the year increased by approximately 46 per cent. to US$20.17 million (2009: US$13.81 million).
-- Announcement of an updated independent assessment of the Group's reserves, future production and income attributable to its concessions in Colombia as at 31 December 2010. Based upon the average oil price received in 2010 and as adjusted to actual prices received for each property, Ryder Scott, the independent petroleum consultants, provided an NPV10 figure for the Group's 3P reserves of US$280.6 million (30 November 2009: US$247 million).
The Company completed its exploratory work commitments during the year within the stipulated contractual time limits.
The disappointing results from the Chuira-1 and Colon-3 wells have provided the Company with an opportunity to re-evaluate its development drilling programme. Having commissioned a number of geological studies from external specialist consultants, the Company is now poised to resume development drilling in a more effective and lower risk manner.
Financial highlights
-- Gross underlying profits* increased to US$10.8 million (2009: US$10.1 million*).
-- Underlying EBITDA generation of US$3.1 million* (2009: US$5.25 million*).
* Excluding the impact of impairment charges for the Chuira-1, Colon-3ST, Santa Lucia Sur-1 and Zoe-1 wells of, in aggregate, US$19.8m (2009: US$6.59m for the Zoe-1 well) and Depreciation & Depletion charges of US$8.36m (2009: US$5.72m).
The loss before tax increased to US$28.72 million (2009: US$12.83 million) principally as a result of: (i) one-off impairment charges of US$19.8 million (2009: US$6.59 million) relating to the Chuira-1 exploration well (US$8.66 million); Colon-3ST (US$8.82 million); Santa Lucia Sur-1 (US$1.68 million) and additional costs incurred in 2010 for the Zoe-1 well (US$0.64 million); (ii) a non-cash financing charge of US$3.21 million (2009: US$3.74 million) and non-cash financing income of US$2.96 million (2009: US$Nil) relating to the accounting treatment and fair value of convertible loan notes subscribed by TOGF in 2009; (iii) the recognition of US$3.66 million (2009: US$Nil) reflecting the fair value of derivative instruments in the form of oil price hedges placed with Macquarie; and (iv) foreign exchange losses of US$1.95 million (2009: US$0.12 million) arising as a result of the revaluation of the Colombian peso against the US dollar experienced during the year. The ongoing cost reduction measures and the expected absence of significant non-cash charges in future years should serve to enhance the Group's reported profitability going forwards alongside an anticipated build-up in the level of production.
Average throughput in PELE's wholly owned RZA pipeline decreased by approximately 13.2 per cent. to 3,041 bopd (2009: 3,504) bopd as a result of maintenance works undertaken on the pipeline.
Subsequent to the reporting period end, we were pleased to announce in March 2011 that commercial gas sales had commenced from our Serafin gas field, offering the prospect of strong short-term cash generation and economic returns.
Outlook and objectives for 2011 and beyond
We continue to firmly believe that Latin America, and in particular Colombia, offers attractive consolidation, corporate and new license acquisition opportunities. The consensus view of analysts is that Colombia's total oil production is set to increase substantially from 690 million bopd in 2009 to 1.3 billion bopd by 2015, rising to approximately 2 billion bopd by 2020. PELE is well placed to contribute to such national production growth as it continues to pursue its development programme in Colombia.
The recently completed updated reserves assessment by Ryder Scott revealed a slight reduction in 2P reserves to 5.9 million boe (30 November 2009: 6.09 million), but importantly attributed an NPV10 figure for these reserves of approximately some US$139 million (approximately GBP86 million) based upon an average oil price received in 2010 of US$79.43 per barrel and as adjusted to actual prices received for each property. The report also highlighted a number of prospective resources amounting to 8.72 million bbls on a net unrisked basis, which are predominantly located in the Santa Lucia field and in various formations of the La Paloma Block (in which PetroLatina has an 85 per cent. working interest (78.2 per cent. net after royalty)).
The Group has recently appointed Luis Guillermo as Chief Operating Officer, who brings over 22 years' oil and gas industry experience including 14 years at BP operating divisions in the UK, Colombia, and most recently Houston. His proven technical expertise and international project development experience will be invaluable in helping us to accelerate our ongoing exploration and development programme which aims to fully develop our existing assets.
The Board of directors has for some time believed that the Company's market capitalisation has failed to fully reflect its current and future business prospects. The Board considers that the NPV10 of PetroLatina's 2P Reserves is significantly ahead of the Company's current market capitalisation, and that the current market share price represents a significant discount to the intrinsic, underlying value of the Company.
Despite announcing increased production last year and, more recently, in the first quarter of the current financial year and the acquisition of the VMM-28 block in the Middle Magdalena basin, there has been no corresponding increase in the Company's market capitalisation. Accordingly, we are currently in the process of reviewing and evaluating strategic alternatives for the further development of the Company with the objective of maximising shareholder value.
I would like to thank our shareholders and employees for their continued valuable support and loyalty and look forward to reporting further progress during the remainder of 2011 as PELE continues to realise its potential.
Luc Gerard
Executive Chairman
7 June 2011
Operational & Financial Review
Overview
The Group achieved an average daily gross production rate for 2010 of 1,809 bopd (2009: 1,340 bopd) ending the year with a gross aggregate production volume of 660,137 bbls (2009: 489,159 bbls). Reflecting the improved global oil price environment, the Group generated total revenues of US$20.17 million, exceeding 2009 revenues by approximately US$6.36 million. Regretably, the increasingly competitive market in Colombia also led the Group to experience higher service costs and an unanticipated escalation in the costs of transportation.
Review of Operations
Colombian Assets
The Group completed the last of its exploratory drilling commitments in 2010 with the drilling of two exploration wells and three development wells.
The La Paloma field produced 185,874 gross bbls (2009: 130,734 bbls) at an average daily gross production rate of 509 bopd (2009: 358 bopd). Net oil production to the Group from the La Paloma field was 154,280 bbls (2009: 111,123 bbls) at an average daily net production rate of 423 bopd (2009: 304 bopd).
On the Santa Lucia field, three new wells were drilled during 2010, only one of them (Santa Lucia Sur-1) was dry, leading to an increased field production rate. During 2010, the Santa Lucia, Los Angeles and Querubin fields (Tisquirama Licence) and the Dona Maria field (Lebrija Licence) produced 462,847 gross bbls (2009: 354,310 bbls) at an average daily gross production rate of 1,268 bopd (2009: 971 bopd). Total net oil production to the Group from the Tisquirama Licence and the Lebrija Licence in 2010 was 128,966 bbls (2009: 118,663 bbls) at an average daily net production rate of 353 bopd (2009: 325 bopd). This represented an approximate 8.6 per cent. increase to the net production volumes achieved during 2009. The level of production exceeded our budgeted expectations primarily due to the drilling of the new wells and workovers and the optimisation of resources.
Despite being impaired at the end of 2009, the Midas field produced 11,416 gross bbls (2009: 4,117 bbls) at an average daily gross production rate of 31 bopd (2009: 11 bopd). Net oil production to the Group from the Midas field was 9,447 bbls (2009: 3,499 bbls) at an average daily net production rate of 26 bopd (2009: 10 bopd).
RZA Pipeline
During 2010, 1,109,788 bbls (2009: 1,279,041 bbls) or 3,041 bopd (2009: 3,504 bopd) were transported through the Group's RZA pipeline representing a decrease of approximately 13.2 per cent. compared to throughput achieved in 2009, as a result of maintenance works undertaken on the pipeline.
Serafin Gas Development
The Group commissioned the construction of a connection to the main Colombian gas trunk line in the first quarter of 2010 and initial commercial gas sales commenced at a stable rate of 5.5mmscf/day in March 2011 providing valuable revenues to the Group to support the development of its producing fields. The project offers the prospect of short term cash flow generation and economic returns, with a projected payback period of less than three months post the connection being made and gas sales commencing.
The Board believes that there is a high probability of further gas deposits on the licence area and PELE is currently conducting studies using its existing 3D seismic coverage to identify further drillable prospects. PELE has a 50 per cent. working interest in the project, which will reduce to 25 per cent. if Ecopetrol S.A. exercises its back-in right and once PELE has recovered 200 per cent. of its capex incurred to date from revenues.
Guatemalan Assets
Further to the sale in July 2007 of our assets (Licences A7-2005 and A-6-93) in Guatemala to Quetzal Energy Inc. ("Quetzal"), PELE retained a 20 per cent. carried interest in the first three wells to be worked over, and a 20 per cent. working interest in future wells. We understand that Atzam-2 is currently producing and have approached Quetzal on a number of occasions regarding our carried interest in this well. To date, no satisfactory responses have been received and we intend to continue to pursue Quetzal and to seek recovery of our share of production revenues.
Financial Review
During 2010, revenues totalled US$20.17 million (2009: US$13.81 million) an increase of approximately 46 per cent. on the previous year. The main contributory factors were:
-- Increased production from the Los Angeles and Santa Lucia fields primarily resulting from the new wells drilled during the course of 2010;
-- Increased production from the La Paloma field as a result of the installation of electrical submersible pumps ("ESP") on the Colon-1 and Colon-2 wells;
-- Higher crude oil prices. The average WTI price per barrel achieved in the year being US$79.84 (2009: US$61.69). Oil produced and sold during the year amounted to 292,694 net barrels or 802 bopd (2009: 233,285 net barrels or 639 bopd); and
-- A 13.2 per cent. decrease in the average throughput in PELE's wholly owned RZA pipeline.
Impairment charges of US$19.80 million (2009: US$6.59 million) were incurred, which included US$8.66 million for Churia-1, US$8.82 million for Colon-3ST, US$1.68 million for Santa Lucia Sur-1, and an additional US$0.64 million for the Zoe-1 well (2009: US$6.59 million).
Other cost of sales, including hedging, increased to US$9.39 million (2009: US$3.71 milion). Total general and administrative costs and net finance costs were US$11.34 million (2009: US$10.6 million); including a non-cash charge of approximately US$3.21 million (2009: US$3.74 million) ) and non-cash income of US$2.96 million (2009: US$Nil) being applied to recognise the fair value accounting of convertible loan notes subscribed by TOGF in 2009, and US$3.67 million (2009: US$Nil) being applied to recognise the fair value of derivative instruments in the form of oil price hedges placed with Macquarie.
Other cost of sales were higher due to the workovers performed on the Santa Lucia 1, 2 and 3 wells in the Santa Lucia field and workovers on the Los Angeles 10,11,12,14,15 and 16 wells in the Los Angeles field.
Reflecting the exploration write-offs and impairment charges, pre-tax losses for the 2010 financial year were US$28.72 million (2009: US$12.83 million).
Taxation
The total tax credit (current and deferred) for the year was US$1.158 million (2009: US$0.34 million) arising from the increased losses incurred during the year. Since the Group has incurred tax losses during the period, corporation tax charges are not anticipated. The cumulative tax losses in Colombia as of 31 December 2010 were approximately US$26.7 million (2009: US$15.7 million), which based on the Directors' expected utilisation gives rise to a deferred tax asset at the reporting date of US$0.988 million (2009: US$Nil).
Cash flow
Cash generated from operations was US$3.75 million (2009: US$11.09 million).
Net cash used in investing activities was higher at US$39.77 million (2009: US$31.14 million) and included the drilling of the new exploration and development wells.
Net cash from financing activities was higher at US$41.11 million (2009: US$20.80 million) as a result of equity placings which raised a total of US$25 million, a short term bridge loan of US$5 million and the drawdown of a US$25 million tranche of a senior secured loan facility held with Macquarie. The short term bridge loan of US$5 million was repaid, along with a US$6.7 million short term loan held locally with Interbolsa. Interest paid during the period amounted to US$2.1 million (2009: US$1.17 million).
Assets
The Group's total assets at US$90.68 million (2009: US$86.9 million) have increased by approximately 4.3 per cent. principally due to the capitalisation of development and exploration costs for the Los Angeles, La Paloma and Midas blocks. Total Group liabilities of US$60.4 million (2009: US$58.7 million) comprise external borrowings, short and long term loans, derivative liabilities and trade and other payables.
The Group currently has access to sufficient financial resources to meet its working capital requirements for the remainder of 2011, but it is expected that additional funding will be required in due course in order to complete our entire planned work programme. At the year end, the Group had cash and cash equivalents (including term deposits) of US$10.01 million (2009: US$4.91 million). Our plans for 2011 include the drilling of two exploratory and commitment wells which should further transform some of the Group's oil reserves into producing reserves. The Group's current production and near term production potential, as reflected in the Group's recent announcements, will fund part of our planned work programme. We remain confident of being able to raise the necessary finance for the remainder of the programme, and in the event that the Group is unable to raise the necessary equity funding, maintain the flexibility of negotiating a draw down from the long-term debt facility in place with Macquarie to ensure that the Group is able to fully fund its planned development programme.
Financial risk
PetroLatina's activities are subject to a range of financial risks including commodity prices, liquidity within the business and of counterparties, exchange rates and the potential loss of operational equipment or wells. These risks are managed through regular ongoing review taking into account the operational, business and economic circumstances at that time. The Group has a hedging programme in place to hedge oil price movements over the life of the senior secured credit facility provided by Macquarie. To date, the Board has not hedged against exchange rate movements, but intends to regularly review this policy.
Revenues are generated primarily in US Dollars and matched where possible against US Dollar denominated expenditures within the business. However, capital and operating expenditures are Colombian Peso denominated which results in a currency exposure.
Liquidity
Detailed cash forecasts are prepared frequently and reviewed by both management and the Board. The Group's production activities provide a monthly inflow of cash which is currently the main source of working capital and project finance.
Developments in 2010 to date
The test results from the Zoe-1 exploration well on the Midas block in our ongoing 2010 drill programme were not as encouraging as expected. As announced on 8 February 2010, the Zoe-1 well reached a total depth of 10,924ft and testing commenced in the Umir section. This section was found to be somewhat over pressured and a stable flow of approximately 42 bopd of 23 degree API oil was recorded. The well remains on production at this rate, however the carrying value has been fully impaired as discussed below. Based on the test results and using petrophysical parameters, the seismic data and mapping of the subthrust structure, the presence of an oil bearing zone is indicated with original oil in place ("OOIP") of 1.3 MMBO (management estimate). Testing of the Lisama zone was initiated in March 2010, and whilst this was found to be normal pressured it flowed approximately 15 barrels of very heavy oil (tar) and water. A second test flowed water only and accordingly Lisama has been classified as a wet zone, and unlikely to be productive as a reservoir. We deemed the deeper zones to be non-commercial and recorded an impairment charge against this prospect relating to the costs incurred up to and including 31 December 2009 of US$6.59 million in last year's financial statements. We have recorded an additional US$0.64 million relating to costs incurred during 2010 in these financial statements.
With regards to the Chuira-1 well on the Midas block, having completed a fracture of the La Luna formation, the intention is to drill a new well in order to develop the lower areas of La Luna outside the current position of the well. Based on the results of current testing, the well has been unsuccessful, and accordingly the net present value of the well is less than its carrying value. The directors have therefore decided to record an impairment charge of US$8.66 million for this year which represents the difference between the expected value and the carrying value as of 31 December 2010.
The pre-impairment carrying value for the Colon-3ST well on the La Paloma structure of US$9 million (2009: US$Nil) was also tested for impairment during the year. Drilling this well confirmed the presence of hydrocarbons at a depth of 8,817 feet which increased the proved area of the Colon field. However, the production levels of this well were lower than expected due to rock conditions. As a consequence, an impairment test was required and the directors have recorded an impairment charge of US$8.82 million representing the difference between the expected value and the carrying value at the year end.
The test results from the Santa Lucia Sur-1 exploratory commitment well were also not as encouraging as expected. The Santa Lucia Sur-1 well reached its target depth of 8,500 feet and whilst hydrocarbon shows and a well developed sand channel were encountered while drilling through the La Paz formation, subsequent evaluation of wire-line logs indicated the reservoir to be water bearing. Accordingly, in consultation with our partners in the well, PetroSantander Inc., and following this evaluation, the well was plugged and abandoned. As a result we have recorded an impairment charge against this prospect relating to our (50 per cent.) share of costs incurred during 2010 of US$1.68 million in these financial statements.
In the first quarter of the current financial year to 31 March 2011, the Group achieved total gross production of 193,790 bbls (2010 equivalent period: 155,323 bbls) at an average daily gross production rate of 2,154 bopd (2010 equivalent period: 1,726 bopd), with net oil production of 90,536 bbls (2010 equivalent period: 72,465 bbls) at an average daily net production rate of 1,006 bopd (2010 equivalent period: 805 bopd).
Since being placed on an extended test in late March 2011 to 30 April 2011, a gross total of 39,019 boe of gas has been produced from the Serafin-1 gas well and 17,949 boe net to the Company.
Current and Future Work Programme
With the Company now focused on accelerating the development drilling of its much larger Magdalena Valley and Putumayo-4 properties, the number of personnel in our Colombian office has been increased. Activities during 2010 have established a strong foundation from which to reconvene and accelerate our drilling programme.
We continue to pursue our strategy of maximising the potential of our asset portfolio and, subject to securing the requisite full funding, our proposed work programme for the remainder of 2011 and 2012 includes:
-- At Midas
o Exploration activities involving the acquisition of 78km(2) of 3D seismic data and the drilling of one exploratory well.
o Development activities involving the reprocessing of 3D seismic data and the seismic attributes relating to Midas Norte, drilling of the Chuira-2 development well, reprocessing of 3D seismic data and the seismic attributes relating to Midas Sur, and the drilling of the Zoe-2 development well.
-- At La Paloma
o Exploration activities comprising the drilling of one exploratory well.
o Development activitiescomprising drilling of the Colon-4 and Colon-5 development wells.
-- At Putumayo
o Exploration activities involving completing the acquisition of an initial 103km of 2D seismic data followed by an additional 48km of 2D seismic data and the drilling of one exploratory well.
-- At VMM-28
o Acquiring 2D seismic data.
o The drilling of one exploratory well.
-- At Tisquirama Association Contract - Tisquirama B
o Conducting simulation studies on the Los Angeles field and the drilling of one exploratory well (Tronos-1).
-- At Tisquirama Association Contract - Tisquirama A
o Conducting simulation studies on the Santa Lucia field.
We look forward to delivering further progress and significantly improved results to shareholders in 2011 and beyond.
Juan Carlos Rodriguez
Chief Executive Officer
7 June 2011
Consolidated statement of comprehensive income
For the year ended 31 December 2010
2010 2009 US$'000 US$'000 Revenue 20,171 13,812 -------------------------------------------------------- --------- --------- Impairment of Oil & Gas assets 19,804 6,590 Depreciation of property, plant and equipment 8,355 5,720 Other cost of sales including hedging 9,392 3,709 -------------------------------------------------------- --------- --------- Total cost of sales 37,551 16,019 Gross loss (17,380) (2,207) Administrative expenses (7,646) (4,857) Loss from operations (25,026) (7,064) Finance income 3,332 160 Finance expense (7,030) (5,930) Loss before tax (28,724) (12,834) Taxation 1,158 338 Total loss and comprehensive loss for the year attributable to equity shareholders of the parent (27,566) (12,496) 2010 2009 US$ US$ Loss per share attributable to the equity shareholders of the parent during the year (basic and diluted) 0.43 0.28
Consolidated statement of financial position
As at 31 December 2010
2010 2009 US$'000 US$'000 ASSETS Non-current assets Property, plant and equipment 67,257 64,566 Intangible Exploration and Evaluation Assets 8,495 14,376 Deferred tax asset 988 - 76,740 78,942 Current assets Inventories 367 149 Trade and other receivables 2,130 2,250 Withholding taxes 1,435 623 Cash and cash equivalents 8,042 3,232 Term deposits 1,970 1,675 13,944 7,929 --------- --------- Total Assets 90,684 86,871 LIABILITIES Non-current liabilities Provisions 3,125 2,225 Loans and borrowings 24,937 12,407 Deferred tax liability 5,506 5,960 --------- --------- 33,568 20,592 Current liabilities Trade and other payables 8,385 24,388 Taxation 285 50 Derivative liability 6,812 6,120 Loans and borrowings 11,364 7,501 --------- --------- 26,846 38,059 Total Liabilities 60,414 58,651 --------- --------- Total Net Assets 30,270 28,220 EQUITY Share capital 26,550 22,212 Share premium 98,372 76,800 Warrant and option reserve 4,576 2,400 Retained deficit (99,228) (73,192) --------- --------- Total equity 30,270 28,220
Consolidated statement of cashflows
For the year ended 31 December 2010
2010 2009 US$'000 US$'000 Loss for the year (27,566) (12,496) Share-based payments 497 470 Depreciation of property, plant and equipment 8,355 5,720 Impairment of intangible asset 19,804 6,590 Finance income (3,332) (160) Finance expense 7,030 5,930 Income tax credit (1,158) (338) Cash flows from operating activities before changes in working capital and provisions 3,630 5,716 Increase in inventories (218) (113) (Increase)/decrease in trade and other receivables (407) 1,395 Increase in trade and other payables 743 4,095 Cash generated from operations 3,748 11,093 Income taxes paid (285) (50) Net cash from operating activities 3,463 11,043 Investing activities Finance income 252 160 Purchase of property, plant and equipment (8,420) (2,492) Payments for oil & gas exploration and development (31,304) (27,310) Investment fixed term deposits (295) (1,498) Net cash flows from operating and investing activities (36,304) (20,097) 2010 2009 US$'000 US$'000 Financing activities Issue of ordinary share capital 25,000 - Loan notes subscribed during the period - 11,165 Short and long term loans subscribed during the period 30,275 12,090 Repayment of loans during the period (12,052) (1,287) Interest paid (2,109) (1,168) Net cash flows from financing activities 41,114 20,800 Increase in cash and cash equivalents including restricted cash 4,810 703 Cash and cash equivalents at the start of the period 3,232 2,529 Cash and cash equivalents at the end of the period 8,042 3,232
Notes forming part of the financial information for the year ended 31 December 2010
1 Basis of preparation
The financial statements of the Group for the twelve months ended 31 December 2010 have been prepared in accordance with International Financial Reporting Standards, International Accounting Standards and Interpretations (collectively "IFRS") issued by the International Accounting Standards Board ("IASB") as adopted by European Union.
The audited financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2010 or 2009 but is derived from those accounts. Statutory accounts for 2009 have been delivered to the registrar of companies, and those for 2010 will be delivered in due course. The auditors have reported on those accounts; their reports were: (i) unqualified but did include a reference to matters to which the auditors drew attention by way of emphasis without qualifying their report and (ii) did not contain a statement under section 498 (2) or (3) of the Companies Act.
This announcement does not constitute the Group's annual report and statutory accounts.
Going concern
The Group plans to continue an ongoing drilling programme in the next twelve months, which should further transform more of its oil reserves into producing assets. With future anticipated additional revenues from the ongoing work programme, the Group is well placed to be able to fund part of its ongoing work programme without the need to raise additional capital. The Group has development commitments and repayment obligations in respect of the credit facility with Macquarie which are due to commence in the fourth quarter of 2011. The repayment obligations will be satisfied from future cashflows, however the development commitments will require additional funds to be raised prior to the first quarter of 2012, or earlier if these works are accelerated and commenced prior to the first quarter. The Directors remain confident that the Group's current and future exploration and near term production potential, which includes future anticipated revenues from the Colon, Querubin-1 and Serafin-1 wells, together with the Group's historic proven ability to raise additional funds, will enable the Group to fully finance its future working capital requirements beyond the period of 12 months of the date of this report. However, there can be no guarantee that the required funds will be raised within the necessary timeframe. Consequently a material uncertainty exists that may cast significant doubt on the Group's ability to fund this cash shortfall and therefore be able to meet its commitments and discharge its liabilities in the normal course of business for a period not less than 12 months from the date of the annual report and financial statements.
The financial statements do not include the adjustments that would result if the Group was unable to continue in operation.
2 Loss per share
Basic loss per share amounts are calculated by dividing loss for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year. The weighted average number of equity shares in issue for the period 64,362,830 (2009: 44,589,672).
Losses for the Group attributable to the equity holders of the Company for the year are US$27,566,000 (2009: US$12,496,000). The effect of the options and warrants in issue is anti-dilutive; therefore a diluted loss per share is not presented.
The Group would still report a diluted loss per share after adjustment for the effect of the convertible loan note, hence no reconciliation is provided.
3 Tangible fixed assets
Fixtures, fittings Field, Proven and plant and oil and equipment machinery Pipelines gas assets Total US$'000 US$'000 US$'000 US$'000 US$'000 Cost At 1 January 2009 217 2,141 13,361 24,913 40,632 Additions 102 1,944 525 18,467 21,038 Transfers (11) (170) (218) 16,618 16,219 At 31 December 2009 308 3,915 13,668 59,998 77,889 Additions 70 510 - 10,605 11,185 Disposals - - (139) - (139) At 31 December 2010 378 4,425 13,529 70,603 88,935 Depreciation, depletion and impairment At 1 January 2009 45 198 1,677 5,683 7,603 Charge for period 43 89 699 4,889 5,720 At 31 December 2009 88 287 2,376 10,572 13,323 Charge for period 49 302 665 7,339 8,355 At 31 December 2010 137 589 3,041 17,911 21,678 Net book value At 31 December 2010 241 3,836 10,488 52,692 67,257 At 31 December 2009 220 3,628 11,292 49,426 64,566
The directors considered the carrying value of the Oil & Gas assets and concluded, based on the carrying value versus the value in use, that there has been no indication of impairment.
Reserves estimates
There are numerous uncertainties inherent in estimating reserves and assumptions that, whilst valid at the time of estimation, may change significantly when new information becomes available. Changes in the forecast prices of commodities, exchange rates, production costs or recovery rates may change the economic status of reserves and may, ultimately, result in the reserves being restated. Such changes in reserves could impact on depreciation rates, asset carrying values, and provisions for close down, restoration and environmental cleanup costs. The Group utilises the expertise of third party consultants to report on the reserves estimates to increase the reliability of their estimations.
4 Intangible fixed assets
2010 2009 US$'000 US$'000 Cost and Net book value At 1 January 14,376 13,336 Additions 13,923 23,849 Transfer to oil and gas assets - (16,219) Impairment (19,804) (6,590) Cost and Net book value at 31 December 8,495 14,376
The amounts for intangible E & E assets represent costs incurred on active oil and gas exploration projects.
In accordance with the Group's oil and gas asset accounting policy, E & E assets are evaluated when circumstances exist that suggest the possibility of impairment as well as when E & E assets are reclassified to the development and producing phase. The outcome of ongoing exploration, and therefore whether the carrying value of assets will be recovered, is inherently uncertain.
As at 31 December 2010, the Group's unevaluated Oil & Gas assets split into deferred exploration costs on the Putumayo and Tisquirama licences totalled US$2.5 million (2009: US$2.1 million). In addition, there were costs totalling US$1.8 million relating to the Chuira-1 and Colon-3 and Colon-3 Side Track wells (together "Colon-3") and US$4.1 million relating to seismic costs at Midas. In performing an assessment of the carrying value of the unevaluated Oil & Gas properties at the reporting date, the directors concluded that no further impairment existed for the Group's unevaluated Oil & Gas assets at 31 December 2010.
The directors have reviewed the impairments required on each of the intangible asset licence areas and the details of those considerations are set out below.
Midas - Zoe-1
The carrying value for the Zoe-1 well on the Midas structure tested for impairment at 31 December 2009 was US$6.59 million. The results of testing evidenced that the deeper zones of Zoe-1 were proven to be non-commercial therefore, the Directors recorded an impairment charge of US$6.59 million as of 31 December 2009. Additional costs of US$0.63 million were incurred during 2010 and as a consequence they have been impaired during the year. The total additional impairment charge for Zoe-1 in 2010 was US$0.63 million and represents the difference between the expected value in use and the carrying value of the Zoe-1 well.
Midas - Chuira-1
The carrying value for the Chuira-1 well on the Midas structure tested for impairment during the year ended 31 December 2010 was US$10 million (2009: US$9.4 million). Having completed a fracture of the La Luna formation, the intention is to drill a new well in order to develop the lower areas of La Luna outside the current position of the Chuira-1 well. Based on the results of current testing and the net present value of the well being less than the carrying value, the well has proved to be unsuccessful. The directors have recorded an impairment charge of US$8.66 million in the year (2009: Nil) which represents the difference between the expected value and the carrying value as of 31 December 2010. The resultant carrying value of the Chuira-1 well was US$1.34 million.
La Paloma - Colon-3 sidetrack
The carrying value for the Colon-3ST well on the La Paloma structure tested for impairment during the year ended 31 December 2010 was US$9 million (2009: US$ Nil). Drilling this well confirmed the presence of hydrocarbons at a depth of 8,817 feet which increased the proved area of the Colon field. However, the production levels of this well were lower than expected due to rock conditions. As a consequence, an impairment test was required and the directors have recorded an impairment charge of US$8.82 million (2009: US$Nil) representing the difference between the expected value and the carrying value as of 31 December 2010. The resultant carrying value of the Colon-3ST well was US$0.18 million.
Santa Lucia - Santa Lucia Sur-1
The Santa Lucia Sur-1 exploration well was a commitment well and was drilled to a total depth of 8,500 feet, at a total cost to PetroLatina of US$1.68 million (2009: US$Nil). The Company has a 50 per cent. interest in the well with PetroSantander Inc. holding the remaining 50 per cent. share. Hydrocarbon shows and a well developed sand channel were encountered while drilling through the La Paz formation, but evaluation of wire-line logs indicated the reservoir to be water bearing. Following this evaluation, the well was plugged and abandoned. The remaining prospectivity in the block is being evaluated for future exploration. The entire value of the asset was written off and the impairment charge was recognised for US$1.68 million.
5 Loans and Borrowings - Senior Secured Debt Facility
On 8 March 2010, the Company entered into a four year Senior First Lien Secured Credit Facility (the "Senior Facility") of up to, in aggregate, US$75 million with Macquarie to finance part of the Company's planned ongoing drilling programme.
During negotiations of the credit facility, an initial US$5,000,000 promissory note short term facility was agreed and drawndown on 26 February 2010 carrying an interest rate of 18 per cent. per annum and was secured over the assets and undertakings of the Group on 26 February 2010.
The Company drew down US$25m under Tranche A and allotted the associated warrants to Macquarie. The funds were used to repay the aforementioned US$5m bridging loan extended to the Company from Macquarie and to repay trade payables, with the remainder used to part fund existing exploration and development operations.
The Senior Facility consists of the following drawn and undrawn facilities and terms:
-- Tranche A: US$25 million. Under the terms of the agreement, Macquarie were allotted 8 million warrants exercisable at a price of GBP0.757 per share at any time over the 5 year period from drawdown of Tranche A. These warrants were valued at US$2.7 million and will be amortised over the 5 year exercise period together with the loan facility fee.
-- Tranche B/C: consist in aggregate of US$50m, to fund pre agreed development work, potential future acquisitions and for general working capital purposes. The tranches can be drawn down, at Macquarie's sole discretion, at any time during the three year period ended 8 March 2013. Under Tranche B (to be used for development activities), Macquarie would be allotted up to 12 million new warrants exercisable at a 20 per cent. premium to the prevailing previous 20 day VWAP. If any funds are drawn down under Tranche C (to fund new projects or commitments) in addition to the 12 million warrants detailed above, Macquarie will be eligible for additional warrants.
-- An interest rate payable ranging between 3 month US LIBOR + 7.5 per cent. and 3 month US LIBOR + 9 per cent. dependent upon the NPV of the Company's proved oil and gas reserves.
-- The debt facility has a four year term expiring on 7 March 2014. Repayment is on a quarterly linear amortisation basis starting 30 months prior to the final maturity date.
-- The Group must accomplish certain covenants related to: production levels; cumulative net revenue; current ratio (not lower than 1:1); EBITDA covenant ratio (not lower than 2.5:1); Group Debt EBITDA ratio (not higher than 3.5:1); Adjusted Present Value ratio (not lower than 2:1) and an agreed G&A cap not higher than US$375,000.
The exercise price of the 8 million warrants previously issued was amended on 4 August 2010 and reduced to GBP0.50 (US$0.85) per share in consideration of Macquarie investing US$5 million and subscribing for new ordinary shares in the capital of the Company as set out in note 21 of the Group's Financial Statements. The incremental charge of US$0.5 million has been charged to share premium as part of financing costs.
The warrants are exercisable in whole or in part at any time within 4 years of their date of issue. These warrants remain outstanding at the year end.
The amortisation of the costs of the loan issue taken to the P&L during the period was US$261,000 (2009: US$Nil).
6 Post Reporting Date Events
On 21 January 2011, the Company issued and allotted (credited as fully paid) (i) 571,083 new ordinary shares of US$0.10 par value each ("Ordinary Shares") to TOGF in satisfaction of the third six monthly interest instalment to 17 December 2010 due in respect of the second tranche of US$6.29 million convertible loan notes subscribed by TOGF on 17 June 2009, (ii) a further 423,022 new Ordinary Shares to TOGF in satisfaction of the fourth and final six monthly interest instalment to 21 January 2011 due in respect of the first tranche of US$4.875 million convertible loan notes subscribed by TOGF on 21 January 2009 (together the "Interest Shares"), and (iii) 14,695,521 new Ordinary Shares in satisfaction of the conversion in full of the first tranche of US$4.875 million convertible loan notes subscribed by TOGF on 21 January 2009. The Interest Shares rank pari passu in all respects with the Company's existing Ordinary Shares.
On 8 March 2011, the Company issued and allotted (credited as fully paid) 246,154 Ordinary Shares as a result of the exercise of warrants, and a further 204,491 Ordinary Shares on 15 March 2011 as a result of additional warrant exercises.
7 Related party transactions
Details of key management personnel's remuneration are given in note 3 of the full Group's Financial Statements.
Latinamerican Drilling Company ("Latco"), a company controlled for part of 2010 by Tribeca, and in which Juan Carlos Rodriguez had a material interest, has entered into an agreement to provide rig services to the Group. During the year US$6,542,970 (2009: US$12,665,724) was incurred for services provided by Latco. At the year end, a total of US$357,533 (2009: US$6,034,776) was due and outstanding to Latco. Details of the convertible loan note provided by TOGF, a company controlled by TOGI, are set out in note 18 of the full Group's Financial Statements.
TDN, a company controlled by Juan Carlos Rodriguez, a director and substantial shareholder in PELE, provides transportation services to the Company. During the year US$1,782,468 (2009: US$2,122,807) was incurred for services provided by TDN. At the year end, a total of US$100,817 (2009: US$1,162,943) was due and outstanding to TDN.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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