Petrolifera Petroleum reports 2009 year end results
CALGARY, March 11 /CNW/ - Petrolifera Petroleum Limited (PDP - TSX) today announced its year end 2009 financial and operating results.
HIGHLIGHTS FOR 2009
- La Pinta 1X drilled and suspended as an indicated light gravity
44 degree API crude oil discovery; remediation and testing underway
- Completed 440 km 2D seismic program on Block 106 in Peru;
interpretation continuing
- Farmed out Vaca Mahuida Concession in Argentina, retaining a 25%
working interest and operatorship
- Proposed sale of Argentina assets terminated; retained to fund future
activity with solid cash flow base
- Completed a $58.5 million equity raise with potential for an
additional $40 million from warrants
- Secured the Magdalena License over an excellent prospect at San Angel
in the Lower Magdalena Basin, Colombia
- Farmed out Turpial License in the Middle Magdalena Basin, Colombia on
favorable terms
Despite making the considerable progress embodied in our 2009 highlights, it was a difficult and disappointing year for the company. Our efforts to sell our interests in Argentina failed to attract acceptable bids in line with our internal expectations. Our significant exploratory well at La Pinta in the Upper Magdalena Basin, of Colombia experienced drilling problems and cost overruns. Despite identifying an accumulation of light gravity crude oil, we were unable to adequately test the oil-bearing Cienaga de Oro Formation after two attempts. We are now moving uphole to evaluate a prospective zone in the Upper Porquero Formation in the well. Our production and reserves declined during the year, primarily affected by a disappointing waterflood performance in the northern portion of the Puesto Morales Norte Field ("PMN"). Our overall capital program was disappointing. We experienced our first full year loss since going public in 2005.
On the positive side, we were able to raise new equity capital during the year, albeit at lower prices than we would have preferred. This was dictated by market conditions and the need to enhance liquidity in a very uncertain economic environment. We continued to upgrade our assessment of our high potential acreage in Peru and Colombia and remain optimistic about the prospectivity of our lands. We did reduce our reserve-backed indebtedness during the year and are in the midst of renegotiating this facility, with an anticipated extension of term, to provide more financial flexibility.
While we were successful in negotiating several smaller farmout agreements on certain of our lands, we have not yet secured a suitable arrangement on our higher potential lands in Colombia and Peru. This primarily reflected the fallout from the collapse of commodity prices and financial and credit markets in late 2008 and early 2009, causing prospective farminees to step back from new commitments pending affirmation or a more stable operating environment. This now appears to have occurred, as there is a discernible increase in industry interest in our well-defined exploration opportunities, including in Peru.
These results will be the subject of a conference call at 9:00 AM MT on March 12, 2010. To listen to or participate in the live conference call please dial either 1-647-427-7450 or 1-888-231-8191. A replay of the event will be available from Friday, March 12, 2010 at 12:00 MT until 21:59 MT on Friday, March 19, 2010. To listen to the replay please dial either 1-416-849-0833 or Toll Free at 1-800-642-1687 and enter the pass code 59446960.
Summary Results for the fourth quarter ("Q4 2009") and full year 2009
("FY 2009") are as follows:
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Three months ended Years ended
December 31 December 31
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Years ended % %
December 31 2009 2008 Change 2009 2008 Change
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FINANCIAL ($000, except
per share amounts)
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Total revenue $17,900 $37,411 (52) $83,790 $130,326 (36)
Cash flow from
operations before
non-cash working
capital(1) 5,867 21,689 (73) 32,406 62,802 (48)
Per share, basic 0.05 0.39 (87) 0.41 1.19 (66)
Per share, diluted 0.05 0.39 (87) 0.41 1.17 (65)
Net earnings (loss) (4,081) 2,662 (253) (10,828) 11,554 (194)
Per share, basic (0.03) 0.05 (160) (0.14) 0.22 (164)
Per share, diluted(4) (0.03) 0.05 (160) (0.14) 0.22 (164)
Capital expenditures 12,145 35,539 (66) 71,623 116,751 (39)
Cash 35,732 30,701 16 35,732 30,701 16
Working capital (2,508) 19,956 (113) (2,508) 19,956 (113)
Long-term
investments(2) 19,395 25,428 (24) 19,395 25,428 (24)
Long-term debt 27,464 77,150 (64) 27,464 77,150 (64)
Shareholders' equity 232,126 202,347 15 232,126 202,347 15
Total assets $349,065 $355,658 (2) $349,065 $355,658 (2)
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OPERATING
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Daily sales volumes
Crude oil and
natural gas
liquids - bbl/d 3,833 6,877 (44) 4,340 6,891 (37)
Natural gas - mcf/d 4,056 5,451 (26) 5,251 5,942 (12)
Barrels of oil
equivalent -
boe/d(3) 4,509 7,786 (42) 5,215 7,881 (34)
Average selling prices
Crude oil and
natural gas
liquids - $/bbl $48.08 $56.76 (15) 49.47 49.46 0
Natural gas - $/mcf $2.53 $2.88 (12) 2.81 2.49 13
Barrels of oil
equivalent - $/boe $43.15 $52.15 (17) 44.00 45.12 (2)
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COMMON SHARES
OUTSTANDING (000s)
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Weighted average
Basic 121,759 54,948 122 78,712 52,648 50
Diluted(4) 121,777 55,043 121 73,976 53,573 38
End of period 121,759 54,948 122 121,759 54,948 122
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(1) Cash flow from operations before non-cash working capital changes
("cash flow") and cash flow per share do not have standardized
meanings prescribed by Canadian generally accepted accounting
principles ("GAAP") and therefore may not be comparable to similar
measures used by other companies. Cash flow includes all cash flow
from operating activities and is calculated before changes in non-
cash working capital. The most comparable measure calculated in
accordance with GAAP would be net earnings (loss). Cash flow is
reconciled with net earnings (loss) in the Management's Discussion &
Analysis ("MD&A") attached hereto. Management uses these non-GAAP
measurements for its own performance measures and to provide its
shareholders and investors with a measurement of the company's
efficiency and its ability to fund a portion of its future growth
expenditures.
(2) Includes carrying value of notes received for Asset Back Commercial
Paper ("ABCP") with a face value of $34.6 million and $37.7 million
as at December 31, 2009 and 2008 respectively. Long-term debt in the
amount of $27.5 million as at December 31, 2009 is primarily secured
on a limited recourse basis by the underlying notes formerly known as
ABCP. Bank debt of $16.6 million as at December 31, 2008 was secured
by the ABCP.
(3) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 Mcf :1 bbl. Boe may be misleading particularly if used
in isolation. This conversion is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
(4) As the company has net losses during the three months ended
December 31, 2009, the dilutive effect of stock options and share
purchase warrants became anti-dilutive causing the basic weighted
average common shares outstanding to be used as the denominator in
the dilutive per share net loss calculation.
Review of 2009
Petrolifera experienced a difficult year in 2009. Sales of crude oil declined during each of the first three quarters of 2009, reflecting the absence of any meaningful capital programs in Argentina while we were engaged in an attempted sales process. Unfortunately, the process failed to attract satisfactory bids in line with our expectations. During Q4 2009 we drilled five new infill wells at PMN and stabilized production declines. Expansion of water handling and treatment facilities during the first quarter of 2010 ("Q1 2010") may enable us to realize more of the tested productive potential of these wells, or at a minimum, stabilize and forestall production declines for a period of time. Further infill opportunities to access unswept or attic crude oil volumes have been identified and may be drilled within the Field boundaries during 2010.
The balance of our lands in Argentina have either been farmed out, are being farmed out or will be surrendered if not farmed out. Our drilling program at Gobernador Ayala II was ultimately unsuccessful after early encouragement. All commitments have been fulfilled and if not farmed out, this block in La Pampa Province will be surrendered. A farmout of a portion of our Rinconada Block within the Puesto Morales/Rinconada Concession is being negotiated and another joint venturer has farmed into the Vaca Mahuida Block. We are in the final stages of discussions to farmout the Puesto Guevara Block and we may promote the drilling of numerous Loma Montosa wells within the Puesto Morales Block by third parties during 2010. Petrolifera will continue to operate these concessions.
Sales of crude oil from our PMN Field production continued to be our principal source of revenue during 2009. Natural gas sales accounted for about 17 percent of our sales volumes on a boe basis but a smaller contribution of revenue as natural gas prices remained depressed on a relative basis to prices for crude oil, despite a 13 percent increase on a year over year basis. Argentinean sales declined during 2009 and averaged 4,340 bbl/d of crude oil, 5.3 mmcf/d of natural gas and 5,215 boe/d on an equivalent basis, a 34 percent decline compared to 2008. The principal sources of the decline were underperformance of the waterflood in the northern portion of the PMN Field and the lack of significant capital investment in the Field during the year.
Argentinean crude oil prices continued to be much below world price levels although they did not decline as severely in late 2008 and 2009 as they were already constrained by Argentinean pricing policy. As a consequence, the price received for crude oil sales during 2009 was relatively flat at $49.47 per barrel. On an equivalent basis, netbacks decreased by approximately 14 percent from 2008 levels to $25.66/boe from 2008, as unit operating costs increased due to lower volumes and a significant fixed cost component in operating expenses. Netbacks are calculated by dividing related revenue less costs by total sales volumes. Netback is not a term which has a standardized meaning prescribed by generally accepted accounting principles ("GAAP") and therefore is unlikely to be comparable to similar measures used by other companies. The most comparable measure calculated in accordance with GAAP is net earnings (loss). Netback is reconciled to net earnings (loss) in the attached Management's Discussion and Analysis ("MD&A"). Management uses netbacks as a performance measurement of operating efficiency and the prevailing royalty regime.
Cash flow from operations before non-cash working capital changes ("Cash flow"), also a term which does not have a standardized meaning prescribed by Canadian GAAP, declined during 2009 to $32.4 million ($0.41 per share) compared to $62.8 million ($1.19 per share) in 2008. On a weighted average basis, there were 78.7 million common shares outstanding during 2009 compared to 52.6 million shares in 2008 and there were 121.8 million common shares outstanding at December 31, 2009. Cash flow is reconciled to net earnings (loss) in the attached MD&A.
Our capital budget was more constrained in 2009, with a total investment of $71.6 million compared to $116.8 million in 2008. Over one half of our capital program was in Colombia, primarily related to the drilling of the La Pinta well on the Sierra Nevada License in the onshore Lower Magdalena Basin. The well flowed light gravity 44 degree API crude oil at an instantaneous rate of 776 bbl/d, before the tubing in the wellbore plugged with sand from the oil-bearing formation. Remedial efforts in early 2010 were successfully conducted but on test, the tubing again plugged and we have now decided to set a cement plug and move uphole to test prospective zones in the Upper Porquero Formation. We recently spudded the Brillante SE 1X exploratory well to evaluate a natural gas and natural gas liquids prospect on the same license.
In Argentina, capital outlays for the year were down to $27.1 million from $70.8 million in 2008. The largest single outlay was for the drilling of 15 commitment wells on the Gobernador Ayala II block. These proved to be disappointing after early encouragement and the Block will be farmed out or relinquished. Late in 2009 we drilled five new wells within the boundaries of the PMN Field, for deliverability purposes.
Capital outlays in Peru also declined markedly, as we completed seismic on Block 106 and conducted geological and geophysical studies and worked on preparations to drill on Blocks 107/133 while awaiting drilling environmental impact assessment ("EIA") approvals from the regulatory authorities. As our operations will be conducted in proximity to areas occupied by aboriginal communities, it takes much longer to secure authority to proceed. This has been challenging for us as we have had our drillable prospects identified for some time. We are continuing to dialogue with prospective farmees in this regard due to the high cost associated with drilling in the canopy jungle in Peru and remain enthusiastic about the quality and potential of our holdings in that country.
Our capital programs in 2009 were financed from cash flow, long-term borrowings and cash balances, farmout proceeds (primarily the Turpial Block in Colombia), enhanced by $58.5 million of equity proceeds from the sale of units, comprised of one common share and one-half share purchase warrant. During the year we reduced our overall borrowings by approximately $14 million. Our reserve-backed loan, which is in the process of being renegotiated, was recorded as a current liability at year end 2009 pending completion of the negotiations. Accordingly, a modest year end working capital deficit existed, although we had $35.7 million of cash.
We recorded our first loss since 2005 when we first went public, due to lower revenue and despite lower general and administrative expenses, lower finance charges, lower taxes other than income taxes and lower income taxes than in 2008. Higher provision for depletion, depreciation and accretion and another modest provision for impairment of the carrying value of our long-term investments, deriving from the courts-sanctioned resolution of the asset backed commercial paper ("ABCP") situation in Canada, contributed to the loss. The company's related long-term indebtedness is substantially secured by these holdings on a limited recourse basis.
Fourth Quarter 2009
Sales in Q4 2009, while much below those recorded in Q4 2008, were slightly ahead of Q3 2009, reflecting the modest impact of the drilling of five new wells at PMN Field. Crude oil sales averaged 3,833 bbl/d, natural gas sales were 4.1 mmcf/d and on an equivalent basis, sales were 4,509 boe/d, three percent ahead of the prior quarter.
Crude oil prices were modestly higher at $48.08/bbl while natural gas prices were modestly lower at $2.53/mcf compared to $2.74/mcf in Q3 2009. On a boe basis, Q4 2009 prices were $43.15/boe, above Q3 2009 levels but 17 percent below Q4 2008 pricing.
Cash flow was $5.9 million, seven percent above Q3 2009 levels but well below Q4 2008 levels due to lower production and prices. A loss of $4.1 million was recorded.
Capital spending was reduced to $12 million in Q4 2009, with renewed drilling activity in Argentina for deliverability purposes and an increasing emphasis on retaining corporate liquidity at higher levels.
Outlook
We attempted to retest the Cienaga de Oro Formation in our La Pinta 1X well in early 2010 without success, despite the timely and efficient remediation of the well, as sanding problems again plugged the tubing. We have decided to plug off this challenging lower zone and attempt to test and then complete a prospective zone in the Upper Porquero Formation, which looks promising based on log shows of crude oil and natural gas while drilling. We are also presently drilling the Brillante SE 1X exploratory well on the Sierra Nevada License in Colombia. This is a commitment well under the terms of the License and will be drilled to approximately 9,500 feet. We also anticipate that the San Angel prospect on the offsetting Magdalena License will be evaluated by drilling in late 2010 into 2011. Due to high relative costs, we will continue to attempt to lower risk and financial exposure in Colombia, through farmout on favorable terms, thereby retaining optimum exposure to significant potential enhancement of value upon successful drilling with limited or lower cash outlays.
Outside of farmout activity financed by third parties and the possible drilling of some additional wells within the PMN Field in 2010, our cash outlays in Argentina will be minimized. Also, it remains our objective to complete a farmout of our Peruvian acreage. We have had extensive discussions with various oil industry operators and remain confident of our ability to complete a transaction on terms to our benefit in due course. The overall commitment in Peru by a farmee would be considerable, so it takes time to secure the right joint venture arrangement, with appropriate terms for the potential and risks of our landholdings in that country.
We intend to husband our cash, emphasize liquidity and to focus on enhancing value by capitalizing on our extensive high working interest land holdings, which render us the capacity to farmout, while retaining, if possible, significant representation in our plays at low imbedded cost. We intend to keep our alternatives available as we restore momentum and capitalize on the large potential of our extensive holdings in South America, in 2010 and beyond. We intend to enhance our capital spending efficiency in this manner and thus improve on our performance. We anticipate our corporate outlays for 2010 will be minimized, as we adjust to more constrained spending limits, continue to reduce debt and participate, to the extent possible, in much of our anticipated activity through spending by third parties to earn an interest in our properties.
Petrolifera Petroleum Limited is a public Canadian crude oil, natural gas and natural gas liquids production, exploration and development company. We hold approximately six million acres of exploration rights, all in South America in eleven license or concessions in Argentina, Peru and Colombia. Our shares and warrants are listed for trading on the Toronto Stock Exchange under the symbol PDP and PDP.WT.
Forward Looking Information
This press release contains forward-looking information including, but not limited to the anticipated remediation and further testing of the La Pinta 1X well in Colombia, the company's plans to renegotiate its existing reserve-backed credit facility, the evaluation and implementation of remedial measures for the waterflood program in Argentina, planned assessment of infill drilling opportunities on the PMN Field in Argentina, strategies for reducing the company's financial exposure to high cost exploration and drilling activities in Colombia and Peru and eliminate residual commitments in Argentina including, planned farm-out and/or joint ventures arrangements, drilling of the exploratory well, Brillante SE 1X on the Sierra Nevada License onshore Colombia and the exploratory well, San Angel on the Magdalena License onshore Colombia, and planned capital expenditures (including sources of funding and timing thereof). Forward looking information is not based on historical facts but rather on Management's expectations regarding the company's future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of finding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities and expectations with respect to general economic conditions. Such forward looking information reflects Management's current beliefs and assumptions and is based on information currently available to Management. Forward looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward looking information, including but not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production, delays or changes to plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of geological interpretations; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environment risks), the risk of commodity price and foreign exchange rate fluctuations, the uncertainty associated with negotiating with foreign governments and third parties located in foreign jurisdictions and the risk associated with international activity. There can be no assurance that remediation efforts and subsequent testing of the La Pinta 1X well drilled on the Sierra Nevada License will yield commercial results. Readers are cautioned that instantaneous flow rates are not reflective of sustainable production rates and if the La Pinta 1X well is remediated, such that commercial production is established, the resultant production rates may differ materially from the recorded instantaneous flow rate reflected herein. The company's ability to complete its capital program and repay outstanding indebtedness is dependent upon completion of planned farm-out arrangements and recovery of sunk costs, restoration of production in Argentina and stabilized or improved commodity prices. Petrolifera may have to bring participants into its acreage holdings and planned evaluation activities on less attractive terms than might otherwise have been the case due to the combination of tighter economic conditions and the influence of contractual commitments and deadlines on the terms of trade. There can be no assurance that the company will be successful in its efforts to secure planned farm-outs and/or joint venture arrangements. Additionally, the company's discussions regarding the renegotiation of its reserve-backed credit facility are at a preliminary stage and there can be no assurance that these discussions will result in terms acceptable to Petrolifera or at all. Additional risks and uncertainties associated with Petrolifera's future plans are described in Petrolifera's Annual Information Form, available on SEDAR at www.sedar.com. Although the forward looking information contained herein is based upon assumptions which Management believes to be reasonable, the company cannot assure investors that actual results will be consistent with this forward looking information. This forward looking information is made as of the date hereof and the company assumes no obligation to update or revise this information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward looking information, prospective investors in the company's securities should not place undue reliance on this forward looking information. Additionally readers are reminded that cash flow and netbacks do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow and netbacks are reconciled to net earnings (loss) in the attached MD&A.
Management's Discussion and Analysis ("MD&A")
The following is dated as of March 11, 2010 and should be read in conjunction with the consolidated financial statements of Petrolifera Petroleum Limited ("Petrolifera" or the "company") for the years ended December 31, 2009 and 2008 as contained in this annual report. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and are presented in Canadian dollars. This MD&A provides management's view of the financial condition of the company and the results of its operations for the reporting periods indicated.
Information in this report, including the letter to shareholders, contains forward-looking information including but not limited to the company's plan to renegotiate its existing reserve-backed credit facility, anticipated remediation and further testing of the La Pinta 1X well in Colombia, evaluation and implementation of remedial measures for the waterflood program in Argentina, future exploration and development opportunities in Argentina, Colombia and Peru, future drilling plans in Argentina, Colombia and Peru and the anticipated timing associated therewith, planned capital expenditures (including sources of funding and timing thereof), strategies for reducing the company's financial exposure to high cost exploration and drilling activities and eliminate residual work commitments in Argentina, including planned farm-out and/or joint ventures arrangements, anticipated improvements in natural gas prices in Argentina, the anticipated impact of the proposed conversion to International Financial Reporting Standards ("IFRS") on the company's consolidated financial statements, planned debt repayments and the timing thereof and the company's ability to continue to comply with financial covenants imposed pursuant to its reserve-backed credit facility. See "Forward-Looking Information" for a discussion of the forward-looking information contained in this report and the risks and uncertainties associated therewith. Additional risks and uncertainties relating to Petrolifera and its business and affairs are also described in detail in its Annual Information Form for the year ended December 31, 2009. Throughout this MD&A, per barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil (6:1). The conversion is based on an energy equivalency conversion method primarily applicable to the burner tip and does not represent a value equivalency at the wellhead. Boe may be misleading, particularly if used in isolation.
Petrolifera Background Information
Petrolifera is a Canadian based crude oil, natural gas and natural gas liquids exploration, development and production company with operations in Argentina, Colombia and Peru, South America. Growth to date has been organic, derived from successful exploration and development drilling programs. The company's main production field is Puesto Morales Norte ("PMN"), Argentina. Extensive undeveloped lands are held in all three countries, including three licenses in Peru, three licenses in Colombia and various blocks or portions thereof in Argentina.
Selected Financial Information
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As at and for the Years
Ended December 31(1) 2009 2008 2007 2006 2005
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($000, except per
share amounts)
Total revenue $83,791 130,326 134,223 $105,583 $2,864
Net earnings (loss) (10,825) 11,554 29,301 37,312 (415)
Per share, basic (0.14) 0.22 0.61 0.95 (0.02)
Per share, diluted (0.14) 0.22 0.57 0.75 (0.02)
Total assets 349,065 355,658 204,227 118,517 31,581
Long-term liabilities $47,817 $99,306 $10,259 $2,347 $467
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(1) No cash dividends have been declared by the company since
incorporation.
With high-potential exploration activities in Colombia and Peru being identified as having greater growth potential for added shareholder value, Petrolifera announced on March 2, 2009 that it had initiated a process to dispose of its Argentinean interests. During July 2009, a number of bids for the company's Argentinean interests were received from third parties. After careful consideration, on July 15, 2009 the company announced that the process to dispose of its interests did not result in any acceptable bids and, accordingly, management decided to retain the company's Argentinean interests. Following the market test of sale alternatives, the company reactivated its technical assessment and has recently completed a five-well infill drilling program at PMN to enhance overall production levels. The company's production had declined from 2008 levels due to the absence of sustained capital investment prior to and during the sales process, complications with the efficiency of its PMN waterflood program in the northern portion of the field and natural declines resulting in lower revenue and a net loss during 2009.
In light of the decision to retain its Argentinean assets and given the capital requirements for its extensive capital expenditure programs in Peru and Colombia, Petrolifera's focus in the third quarter of 2009 was on balance sheet reconstruction. With the adverse commodity and capital market conditions which emerged in late 2008 and continued through much of the first half of 2009, the company's ability to complete farm-outs on some of its properties was limited, as prospective partners recalibrated their own financial condition and commitment levels at a time when preserving liquidity was paramount in the oil and gas industry. The company restored liquidity to its balance sheet through a marketed, underwritten public offering which raised $57.5 million of gross proceeds and a private placement with management and directors, on the same terms as the public offering, which raised an additional $1.0 million and reaffirmed the commitment of management and directors to the future of the company. As capital market conditions improved, the company successfully negotiated farm-out arrangements on its Turpial License, in the Middle Magdalena Basin, onshore Colombia and on its Vaca Mahuida Concession, located in the Neuquen Basin, Rio Negro Province, onshore Argentina. The proceeds from the equity issuances and farm-out arrangements are being used to reduce bank indebtedness or to replenish liquidity, which can then be drawn to assess the full potential of the La Pinta 1X exploratory well, to explore a significant potential accumulation of natural gas and natural gas liquids at Brillante and at a later date to evaluate several shallower formations of interest on the company's Sierra Nevada License in the Lower Magdalena Basin, onshore Colombia.
FINANCIAL AND OPERATING REVIEW
SALES VOLUMES, PRICING AND REVENUE
Years Ended December 31 2009 2008 % change
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Daily sales volumes:
Crude oil and natural gas liquids - bbl/d 4,340 6,891 (37)
Natural gas - mcf/d 5,251 5,942 (12)
Equivalent - boe/d 5,215 7,881 (34)
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Average selling prices:
Crude oil and natural gas liquids - $/bbl $ 49.47 $ 49.46 -
Natural gas - $/mcf 2.81 2.49 13
Weighted average selling price - $/boe $ 44.00 $ 45.12 (2)
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Petroleum and natural gas sales ($000) $83,752 130,148 (36)
Interest income ($000) 39 178 (78)
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Total revenue ($000) $83,791 130,326 (36)
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Petroleum and natural gas revenues in 2009 were $83.8 million on average sales volumes of 5,215 boe per day, compared to $130.1 million on sales of 7,881 boe per day during 2008, a decrease of 36 percent for revenue and 34 percent for sales volumes. Sales of crude oil and natural gas liquids represented 83 percent of the company's sales volumes in 2009, which was lower than 87 percent in 2008. This was mainly the result of operational challenges as detailed herein. All of Petrolifera's sales during 2009 were from its Puesto Morales/Rinconada, Puesto Morales Este and, to a minor extent, Gobernador Ayala II Concessions in Argentina and all of its crude oil sales were made to the Argentinean operation of a large multinational company.
The reduction in sales revenues during 2009 compared to 2008 reflects minimal investment undertaken during the period leading up to and during the sale process related to the company's Argentinean interests, operational challenges, which included labour strikes and downtime at several wells and natural declines. Operational challenges during 2009 included unscheduled workovers of key producing wells and shut-ins caused by equipment failures. Also, the company experienced certain challenges with the PMN waterflood program initiated during 2007, including rising water cuts especially in the northern part of the field. Remedial measures for the waterflood program are being evaluated following a tracer sampling program and improvements in the water treatment and injection capacity of the company's facilities is underway.
The company's realized crude oil and natural gas liquids price averaged $49.47 per barrel in 2009, which is comparable to $49.46 per barrel realized in 2008. Lower realized US dollar crude oil pricing of US$44.13 per barrel during 2009 relative to the US$46.73 per barrel during 2008 was offset by an average seven percent strengthening of the US dollar, as compared to the Canadian dollar. This resulted in a higher 2009 reported price relative to 2008, as expressed in Canadian dollars. During 2009, Petrolifera negotiated a new crude oil sales agreement with a well-established multinational purchaser and secured a crude oil price with some exposure to world crude oil price ("WTI") improvements. During 2009, the crude oil price realized by Petrolifera averaged approximately 72 percent of the WTI average of US$61.46 per barrel, compared to the 2008 average of approximately 47 percent of the WTI average of US$99.59 per barrel.
During 2009, natural gas prices increased 13 percent over the level realized during 2008 to average $2.81 per mcf. This reflected some relaxation of regulated Argentinean natural gas prices in industrial markets and a seven percent strengthening of the US dollar, as compared to the Canadian dollar. This resulted in a higher reported price as expressed in Canadian dollars. The company successfully negotiated a price increase for 2009 Argentinean winter sales volumes to US$2.40 per mcf. This was a 10 percent improvement relative to the US$2.19 per mcf realized during the winter sales volumes of 2008. Natural gas prices are believed to have the potential of further improvement in the longer term, due to market conditions and new Argentinean policy initiatives aimed at eventual market deregulation for industrial sales, including for power generation.
Despite modest improvements in the average selling prices for crude oil and natural gas during 2009, relative to 2008, the increase in the company's ratio of natural gas volumes, which are priced considerably lower than the energy equivalent of crude oil, to total production volumes resulted in a reduction in the weighted average selling price per boe.
Interest income was minimal in 2009 compared to $0.2 million during 2008, when interest was earned on short-term cash deposits and the company's short-term investment. Interest on the investment in notes, formerly known as Asset Backed Commercial Paper ("ABCP"), with a face value of $34.6 million, has not been recognized since August 2007, due to the lack of market liquidity for these notes. See "Long-Term Investments" for additional details including estimates of valuation. During 2009, the company received interest payments on its investment, formerly known as ABCP, of $1.8 million that had already been incorporated in the determination of fair value as at December 31, 2008.
ROYALTIES, OPERATING EXPENSES AND CORPORATE NETBACKS
CORPORATE NETBACKS(1)
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Years Ended December 31 2009 2008
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($000, except per unit amounts) Total Per boe Total Per boe
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Average daily sales (boe/d) 5,215 7,881
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Petroleum and natural gas sales $83,752 $ 44.00 130,148 $ 45.12
Interest income 39 0.02 178 0.06
Royalties (12,017) (6.31) (18,381) (6.37)
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Net revenue 71,774 37.71 111,945 38.81
Operating costs (22,930) (12.05) (26,040) (9.03)
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Corporate netback $48,844 $ 25.66 $85,905 $ 29.78
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(1) Calculated by dividing related revenue and costs by total boe sold,
resulting in a corporate netback. Netback does not have a
standardized meaning prescribed by GAAP and therefore is unlikely to
be comparable to similar measures used by other companies. The most
comparable measure calculated in accordance with GAAP would be net
earnings (loss). Nevertheless, Petrolifera's management uses netbacks
as a performance measurement of operating efficiency and the
prevailing royalty regime. A high ratio of netback to selling price
is a positive indicator. A reconciliation of corporate netback to net
income (loss) can be found in the Net Earnings (Loss) table.
Compared to amounts recorded in 2008, Petrolifera's corporate netback of $25.66 per boe decreased 14 percent during 2009. Modestly higher realized commodities pricing during 2009 was more than offset by higher operating costs per boe and an increase in the company's ratio of natural gas volumes, which are priced considerably lower than the equivalent heating value of crude oil, to total production volumes. This resulted in a reduction in the weighted average selling price per boe. Petrolifera's calculated unit netback of $25.66 per boe remained a respectable 58 percent of the 2009 selling price per boe, a reduction from the 66 percent achieved during 2008.
OPERATING COSTS
Total operating costs during 2009 decreased by approximately 12 percent compared to 2008 to $23.0 million (2008 - $26.0 million), largely due to lower total production volumes. On a per boe basis, operating costs increased 33 percent for 2009 to $12.05 per boe, compared to $9.03 per boe for 2008. Lower crude oil and natural gas liquids production volumes, combined with increased well servicing costs, transportation costs and one-time labour costs during 2009 resulted in the increase. Also contributing to higher operating costs per boe during 2009, compared to 2008, were the additional number of wells being operated for the entire year resulting from the active 2008 drilling program, the number of wells on pump or that required servicing on a more frequent basis and inflationary pressures. The challenges related to the company's waterflood program, mitigated to a lesser extent by the PMN infill well drilling program near the end of 2009, resulted in an increase in total fluid throughput, with a lower crude oil cut. Accordingly, the additional fluid handling costs resulted in a further increase in the operating costs per boe for 2009 relative to 2008.
ROYALTIES
Royalties represent charges levied by governments and landowners against production or revenue. Included in royalties are revenue taxes imposed by provincial jurisdictions. Royalties during 2009 were $12.0 million ($6.31 per boe), compared to $18.4 million ($6.37 per boe) during 2008 and the ratio of royalties to petroleum and natural gas revenue was 14 percent for both years. The decrease on a boe basis is primarily attributable to the lower realized weighted average selling price during 2009 compared to 2008.
NET EARNINGS AND SHARES OUTSTANDING
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000, except per unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Corporate netback $48,844 $ 25.66 $85,905 $ 29.78
General and administrative (8,285) (4.35) (8,425) (2.92)
Stock-based compensation (4,674) (2.46) (5,847) (2.03)
Finance charges (5,097) (2.68) (5,417) (1.88)
Foreign exchange loss (115) (0.06) (180) (0.06)
Fair value impairment (2,104) (1.11) (8,882) (3.07)
Depletion, depreciation
and accretion (33,546) (17.62) (28,984) (10.05)
Income tax provision (3,974) (2.09) (14,431) (5.00)
Taxes other than income taxes (1,874) (0.98) (2,185) (0.76)
-------------------------------------------------------------------------
Net earnings (loss) (10,825) $(5.69) $11,554 $ 4.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In 2009, the company reported a net loss of $10.8 million ($0.14 per weighted average basic and diluted share) compared to 2008 net earnings of $11.6 million ($0.22 per weighted average basic and diluted share). The net loss for 2009 was mainly due to lower commodities sales volumes, a lower weighted average selling price, and higher non-cash depletion, depreciation and accretion expense.
As the company's Argentinean operation is considered self-sustaining, changes in this operation's reported net assets, as expressed in Canadian dollars, resulting from foreign exchange differences between the US dollar and Canadian dollar is recognized as comprehensive income (loss). In 2009, the company's comprehensive loss was $30.7 million, compared to the comprehensive income for 2008 of $38.3 million. The comprehensive loss for 2009 was due to the aforementioned net loss for 2009 and a 15 percent strengthening of the Canadian dollar, relative to the US dollar. This reduced the net assets of the company's Argentinean operations which are denominated in US dollars and reported in Canadian dollars. The comprehensive income during 2008 was due to the recognized net earnings combined with a 19 percent strengthening of the US dollar, relative to the Canadian dollar. This increased the Canadian dollar reported net assets of the company's Argentinean operations.
In 2009, the weighted average number of common shares outstanding was 78.7 million, compared to 52.6 million in 2008. The increase in the weighted average number of common shares for 2009 reflected the August 2009 issuance of 65.3 million common shares from treasury for gross proceeds of $57.5 million; the September 2009 private placement issuance of 1.1 million common shares from treasury for proceeds of $1.0 million; in 2008, 4.4 million common shares were issued from treasury at $9.00 per common share for gross process of $40.0 million; and 0.2 million warrants were exercised during the third quarter of 2008 and 0.2 million and 0.3 million options which were respectively exercised during the first quarter of 2008 and third quarter of 2009, resulted in the issuance of a like number of common shares during the respective year. As the company had a net loss for 2009, the effect of "in-the-money" stock options and share purchase warrants became anti-dilutive, resulting in the exclusion of the effect of these equity instruments on the diluted net loss per common share calculation, whereas for 2008, 0.9 million additional common shares were included in the calculation of diluted net earnings per share.
As at the close of business on March 10, 2010, the company had the following securities issued and outstanding:
- 121,798,510 common shares; and
- 7,898,067 stock options; and
- 33,240,250 warrants.
GENERAL & ADMINISTRATIVE AND STOCK-BASED COMPENSATION
General and administrative ("G&A") expenses were $8.3 million and $8.4 million for 2009 and 2008, respectively. These costs primarily consist of management and administrative salaries, legal and professional fees, insurance, travel and other administrative expenses. G&A expenses of $4.7 million and $5.1 million were also capitalized during 2009 and 2008, respectively, primarily related to further exploration and evaluation of the prospects in Colombia, Peru and Argentina.
On a per boe basis, G&A was $4.35 per boe of sales in 2009 compared to $2.92 per boe in 2008. The increase in G&A per boe in 2009, relative to 2008, was primarily due to lower sales volumes.
For 2009, a non-cash expense of $3.6 million ($5.1 million in 2008) was recorded as stock-based compensation, reflecting the amortization of the fair value of stock options over the vesting period. The decrease in stock-based compensation was mainly attributable to a lower fair value of options granted during 2009, compared to the fair value of options granted during 2008.
During 2009 certain employees, officers and non-managerial directors of the company voluntarily surrendered 1.8 million options with a weighted average exercise price of $13.79 per option. In accordance with Canadian GAAP, any unvested options that were voluntarily surrendered were deemed to have become vested, resulting in the recognition of an additional non-cash stock-based compensation expense of $1.1 million.
During 2008, the company paid $0.2 million to certain non-officer employees, resulting in the cancellation of 0.4 million "out of the money" options. As a result of these optionees surrendering certain of their options, per Canadian GAAP any unvested options were deemed to have become vested, resulting in the recognition of an additional non-cash stock-based compensation expense of $0.7 million.
FINANCE CHARGES
Included in the finance charges of $5.1 million and $5.4 million for 2009 and 2008, respectively, was interest paid and accrued on the company's outstanding current and long-term bank debt and deferred financing charges that are allocated over the life of the reserve-backed credit facility. Despite higher average company borrowings, the decrease in finance charges during 2009, compared to 2008, reflected a lower effective interest rate of 4.2 percent for 2009, compared to 8.8 percent for 2008.
FOREIGN EXCHANGE
During 2009, the weakening of the US dollar relative to the Canadian dollar, resulted in a foreign exchange gain on less reported US dollar denominated debt, as expressed in Canadian dollars. This foreign exchange gain was offset by foreign exchange losses on Argentinean and corporate working capital, as partially denominated in Argentinean pesos and US dollars, respectively, because as the Canadian dollar strengthened relative to both aforementioned foreign currencies, the company reported a corresponding reduction in working capital, as expressed in Canadian dollars. Combined, this resulted in a net foreign exchange loss of $0.1 million for 2009.
The company's main exposure to foreign currency risk in Argentina relates to the pricing of crude oil sales, operating costs and capital expenditures, which are mainly denominated in US dollars and Argentinean pesos, partially mitigated by draws on a portion of the reserve-backed credit facility, which is denominated in US dollars. The company's main exposure to foreign currency risk in its Peru, Colombia and corporate segments relates to working capital in support of the company's local capital expenditure programs, which may be funded in US dollars, Peruvian New Soles or Colombian Pesos, partially mitigated by draws on the reserve-backed credit facility, which is denominated in US dollars.
FAIR VALUE IMPAIRMENT
During 2009, a court-approved plan for restructuring the ABCP was implemented and the company has received longer-term notes in exchange for its ABCP holdings. The maturities of the new notes generally match those of the assets previously contained in the underlying conduits. In recognition of the loss of liquidity in the company's investment in notes formerly known as ABCP, a provision was made in the financial statements for a non-cash fair value impairment charge of $2.1 million for 2009 (2008 - $8.9 million). Since August 2007 when the loss of liquidity in the Canadian commercial paper market first occurred, the cumulative effect of impairments represents approximately 46 percent of the face value of the investment. The basis for the impairment provision is explained under "Long-Term Investments."
DEPLETION, DEPRECIATION & ACCRETION ("DD&A")
DD&A is calculated using the unit-of-production method relative to total estimated proved reserves. DD&A for 2009 was $33.5 million or $17.62 per boe, compared to $29.0 million or $10.05 per boe for 2008. The increase in DD&A for 2009, relative to 2008, was mainly due to the cost of infrastructure related to the Argentinean production, a 2008 year end downward reserve adjustment applied to 2009 production, a December 31, 2009 downward reserve adjustment, a seven percent weakening of the average 2009 Canadian dollar to US dollar ratio relative to 2008 levels resulting in a higher reported depletion expense on the self-sustaining Argentinean operations (expressed in Canadian dollars) and the impact of the inclusion of Gobernador Ayala II exploration costs. Capital costs of $14.0 million (Dec. 31, 2008 - $14.5 million) incurred for unevaluated properties and other assets in Argentina and $56.1 million (2008 - $48.6 million) and $47.5 million (2008 - $13.8 million) for major development projects and other assets in the pre-production stage located in Peru and Colombia, respectively, have been excluded from the cost pool subject to depletion and depreciation.
Accretion expense, which is included in DD&A expense, was $0.6 million for 2009, compared to $0.4 million for 2008. Accretion expense will continue at appropriate levels in the future to accrete the discounted liability of $9.6 million (Dec. 31, 2008 - $10.1 million) over the estimated timing of reclamation expenditures on the company's oil and gas properties.
CEILING TEST
Oil and gas companies are required to compare the recoverable value of their oil and gas assets to their recorded carrying value at the end of each reporting period. Excess carrying values over fair value are to be written off against earnings. No write-down was required in 2009 or for 2008. The following benchmark prices were applied in determining the recoverable value of the company's oil and gas assets:
-------------------------------------------------------------------------
Crude Oil Price Natural Gas Price
($US/bbl) ($US/mcf)
-------------------------------------------------------------------------
2010 $49.88 $2.66
2011 51.00 2.72
2012 52.02 2.77
2013 53.06 2.83
2014 $54.12 $2.88
-------------------------------------------------------------------------
+ approximately 2% + approximately 2%
thereafter thereafter
-------------------------------------------------------------------------
TAXES
The current income tax provision of $3.4 million and $7.9 million in 2009 and 2008, respectively, related primarily to income taxes payable in Argentina. Additionally, a future income tax expense of $0.6 million and $6.5 million for 2009 and 2008, respectively, was recorded at the statutory rate to recognize the differences between the remaining tax pools and accounting carrying values. The implied effective tax rate of the income tax provision is not indicative of the company's jurisdictional tax rates for 2009. Taxes other than income taxes of $1.9 million and $2.2 million for 2009 and 2008, respectively, represent taxes charged on all banking transactions in Argentina.
CAPITAL RESOURCES, CAPITAL EXPENDITURES AND LIQUIDITY
In the aftermath of the 2008-2009 commodity price, credit market and capital market collapses, the company improved its liquidity and balance sheet during 2009 with successful equity raises of $58.5 million from treasury, comprised of a $57.5 million publicly-marketed, underwritten transaction and a $1.0 million private placement with management and directors, on identical terms to the public offering. Equity was raised primarily to fund future Colombian capital programs, with a priority to remediate and then test the company's La Pinta 1X exploratory well and to fund additional drilling at Brillante on the company's Sierra Nevada acreage in addition to paying down a portion of the company's reserve-backed facility. The company anticipates renegotiating its reserve-backed credit facility in 2010 with a view to securing an extended term beyond the current expiry of September 5, 2010. In the interim, the company has classified its reserve-backed credit facility as current.
The company is continuing to negotiate farmout arrangements on exploratory lands in Argentina, Peru and Colombia to maximize the benefit to its shareholders from the strong ownership positions in these prospective lands and the significant value-added impact of its early stage geological and geophysical activity. To some extent, the aforementioned commodity price and capital market collapses forestalled this process, as prospective partners recalibrated their own financial conditions and commitment levels at a time when preserving liquidity was paramount in all businesses. However, recent strong crude oil prices have stimulated renewed interest by third parties to secure participation in the company's undeveloped lands in Peru and Colombia. The company recently entered into farmout agreements on its Vaca Mahuida Concession, Rio Negro Province, Argentina and on its Turpial License, in the Middle Magdalena Basin, onshore Colombia. The farmee under each agreement directly or indirectly reimbursed Petrolifera for back-costs or agreed to incur the majority, if not all, of the remaining planned capital spending on the current work programs.
The company's 2010 budget includes reducing its reserve-backed credit facility by up to $20.0 million. The company's 2010 budget estimated net cash outlays on capital expenditures (net of cost recoveries or carried expenditures resulting from farmout arrangements) of approximately $20.0 million is anticipated to be financed through the company's cash reserves. Completion of farmouts or joint venture arrangements is required to fund the remaining portion of the company's 2010 exploration activities in Colombia and Peru. Should the farmout arrangements not proceed as planned, the company may have the ability to defer capital expenditures on certain licenses in addition to adjusting its debt repayments. See "Commitments, Contractual Obligations, Guarantees & Off-Balance Sheet Financing".
CASH FLOW
Cash flow and cash flow per share do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital. The most comparable measure calculated in accordance with GAAP would be net earnings (loss). Cash flow is reconciled with net earnings (loss) below. Cash flow per share is calculated by dividing cash flow by the weighted average shares outstanding. Management uses these non-GAAP measurements for its own performance measures and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund a portion of its future growth expenditures.
Reconciliation of net earnings (loss) to cash flow:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net earnings (loss) $(10,825) $11,554
Add non-cash charges:
Depletion, depreciation and accretion 33,546 28,984
Stock-based compensation 4,674 5,847
Fair value impairment 2,104 8,882
Unrealized foreign exchange loss 1,428 180
Amortization of deferred finance charges 868 829
Future income tax provision 612 6,526
-------------------------------------------------------------------------
Cash flow $32,407 $62,802
-------------------------------------------------------------------------
Per share, basic 0.41 1.19
Per share, diluted 0.41 1.17
-------------------------------------------------------------------------
Cash flow in 2009 was $32.4 million or $0.41 per weighted average basic and diluted share, compared to $62.8 million or $1.19 per weighted average basic share and $1.17 per weighted average diluted share in 2008. The 48 percent decrease in total cash flow during 2009, relative to 2008, primarily resulted from reductions in sales volumes and average realized selling prices, partially offset by a decrease in the current tax provision and an increase in realized foreign exchange gains. Cash flow during 2009 was affected by the attempted process to sell the company's Argentinean interests, as the company made minimal maintenance capital investments prior to and during the period of the sales process, resulting in lower production and sales volumes. During the fourth quarter of 2009, the company embarked on an infill development well program and invested capital to increase the water treatment capacity of its facilities, in an attempt to enhance production and cash flow. The infill wells indicate a total tested or onstream initial productivity of approximately 1,100 bbl/d of crude oil, which the company anticipates to bring "on stream" upon accommodating the additional fluid volumes at its water treatment handling facilities which is expected to occur during the first half of 2010. Cash flow per share for 2009 decreased relative to 2008 for the aforementioned reasons and from the impact of an increase in the number of shares outstanding.
EQUITY FINANCING & PRIVATE PLACEMENT FROM TREASURY
During August 2009, the company announced that it entered into an underwriting agreement with a syndicate of underwriters to issue 56,820,000 units (each, a "Unit") at a price of $0.88 per Unit, with each Unit consisting of one common share in the capital of the company (each, a "Common Share") and one-half of one Common Share purchase warrant of the company (each whole Common Share purchase warrant, a "Warrant"), for gross proceeds of approximately $50.0 million (the "Public Offering"). The underwriters were granted an over-allotment option (the "Over-Allotment Option"), which included the right to purchase up to an additional 15 percent of the Units, exercisable in whole or in part up to 30 days following closing on August 28, 2009. The Over-Allotment Option was exercised in whole by the underwriters, closed on September 4, 2009 and resulted in a total issuance of 65,343,000 Units, raising gross proceeds to approximately $57.5 million.
In September 2009, the company announced that it had closed a non-brokered private placement with certain directors and officers of the company to issue 1,137,500 Units at a price of $0.88 per Unit, with each Unit consisting of a Common Share and one-half of one Warrant, for gross proceeds of approximately $1.0 million (the "Private Placement"). The Units offered pursuant to the Private Placement were issued on the same terms as those offered pursuant to the company's Public Offering, without commission payable.
There were 33.2 million Warrants issued pursuant to the Public Offering, Over-Allotment Option and Private Placement. Each Warrant entitles the holder thereof to purchase one Common Share (each a "Warrant Share") at an exercise price of $1.20 per Warrant Share until August 28, 2011. In the event that the 20-day volume weighted average price of Petrolifera's common shares on the Toronto Stock Exchange exceeds $2.50, the company may, within five business days after such an event, provide notice to the holders of the Warrants ("Warrantholders") of early expiry and thereafter, the holders of the Warrants are obligated to exercise the Warrants or they will expire on the date which is 30 days after the date of the notice to the Warrantholders. The net proceeds of the Public Offering and Private Placement were added to working capital to augment cash balances, to be used to fund a portion of the company's exploration capital expenditure program primarily in Colombia and to reduce indebtedness relating to the company's reserve-backed credit facility. As at December 31, 2009, the net proceeds of the Public Offering, Over-Allotment Option and Private Placement were used to repay US$15.0 million of the company's reserve-backed credit facility, to fund approximately $10.2 million of capital expenditures in Colombia and to fund a US$4.1 million trust account for the company's Colombia work commitments, with the remainder of the funds held as cash, pending further expenditures, primarily anticipated to be in Colombia.
Proceeds of the Private Placement, Public Offering and Over-Allotment Option are summarized as follows:
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Gross Proceeds of Public Offering and Over-Allotment Option $57,502
Gross Proceeds of Private Placement 1,001
-------------------------------------------------------------------------
Total 2009 equity financing 58,503
Underwriters' commissions and issue costs (3,060)
-------------------------------------------------------------------------
Net funds available to reduce indebtedness,
capital expenditures and working capital $55,443
-------------------------------------------------------------------------
The proposed use of net proceeds per the Private Placement, Public Offering and Over-Allotment Option relative to actual use of net proceeds as at December 31, 2009, are as follows:
-------------------------------------------------------------------------
Use of Net Proceeds Per Use of Net Proceeds
Public Offering, as at Dec. 31, 2009
Over-Allotment Option
($000) and Private Placement
-------------------------------------------------------------------------
Capital expenditure program,
primarily in Colombia $32,743 $10,227
Reduction of reserve-backed
credit facility Up to 16,000 15,953
Working capital 6,700 4,359
Cash to be deployed in 2010
to capital expenditure program - 24,904
-------------------------------------------------------------------------
$55,443 $55,443
-------------------------------------------------------------------------
On June 11, 2008 the company announced that it entered into an underwriting agreement with a syndicate of underwriters to issue, on a "bought deal" basis, 4,445,000 common shares from treasury at a price of $9.00 per common share for gross proceeds of approximately $40.0 million. The underwriters were granted an over-allotment option to purchase up to an additional 666,750 common shares on the same terms and conditions, exercisable in whole or in part up to 30 days following closing. This financing was closed on June 27, 2008 and the over-allotment option was not exercised.
CAPITAL EXPENDITURES
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Colombia $37,036 $12,610
Argentina 27,082 70,792
Peru 7,462 33,306
Corporate 43 43
-------------------------------------------------------------------------
Capital expenditures 71,623 116,751
Proceeds from farmout arrangement (2,767) -
-------------------------------------------------------------------------
Net capital expenditures $68,856 $116,751
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital expenditures in 2009 were $71.6 million, compared to $116.8 million for 2008. Capital spending throughout 2009 was financed from available cash, cash flow, proceeds from a farmout arrangement and proceeds from the Public Offering and the Private Placement.
Peru
Expenditures were incurred on Block 107 in Peru for preparation of the drilling base camp. On April 16, 2009 Petrolifera was awarded a license over Block 133, which is comprised of approximately one million acres and is contiguous with Block 107. This license represented important protection acreage relative to the company's anticipated activities on Block 107. The company has completed its first round of farmout discussions with respect to Blocks 107 and 133 in the Ucayali Basin, Peru in an attempt to secure recovery of a portion of its sunk costs incurred on these blocks and to secure work commitments for new activity. Several large international companies have examined the company's technical analysis and management continues the process of discussing the terms of proposed agreements with a view to farming out interests in these licenses.
On Block 106, in the Maranon Basin, Peru, a 440 km 2D seismic acquisition program was completed and the data was reprocessed and reinterpreted. With a view to farming out an interest in this License, further discussions are anticipated with a number of qualified, interested third parties.
Colombia
In Colombia, significant outlays were incurred in 2009, primarily for the 100 percent-owned La Pinta 1X exploration well, which spudded on January 23, 2009 on the company's Sierra Nevada License, situated onshore the Lower Magdalena Basin. The well was drilled to a final depth of approximately 11,250 feet. Petrolifera was encouraged by results encountered during the drilling of the La Pinta 1X well, based on hydrocarbon shows and logs. The well costs were significantly over original budget, as the company experienced problems running intermediate casing in the upper section of the wellbore and then subsequently encountered challenges arising from instability in the lower section of the well, due to overpressured subsurface conditions. Both problems were eventually resolved. Log analysis and shows provided the basis for initiating an extensive testing program, which commenced in May, 2009. The testing program also encountered certain challenges, including multiple hydraulic packer failures. The company has now suspended the La Pinta 1X well, after testing light gravity 45 degrees API crude oil at instantaneous measured rates of up to 776 bbl per day with limited associated natural gas and no water, from the upper portion of the Cienaga de Oro Formation ("CDO"). The well was suspended following evidence of sand plugging in the production tubing, which precluded further testing. Readers are cautioned that instantaneous rates are not reflective of sustainable production rates and if the La Pinta 1X well is remediated such that commercial production is established, these production rates may differ materially from the recorded instantaneous flow rate reflected above.
The company evaluated various options in respect of reentering and further testing the La Pinta 1X well. In January 2010 a snubbing unit was mobilized to the wellsite from the United States. The snubbing unit arrived in the Lower Magdalena Basin location on February 1, 2010 and it took approximately one week to rig up. The work program for the snubbing unit was designed to reenter the La Pinta 1X well bore, clean out the tubing string blockage and then attempt to test the well. Unfortunately, the test again resulted in plugged tubing and a decision was made to move uphole to attempt to test a zone in the Upper Porquero Formation.
Petrolifera has also completed 2D and 3D seismic programs over its Turpial License in the Middle Magdalena Basin, onshore Colombia and has completed the interpretation of the seismic data. In December, 2009 the company reached a farmout agreement with Apco Properties limited, a subsidiary of Apco Oil and Gas International Inc. ("Apco"), whereby the company recovered approximately US$2.6 million, representing a portion of seismic costs previously incurred on the Turpial License and will, as operator, be carried through the next US$1.9 million of work on this license. After completion of this work program, Apco will earn a 50 percent working interest in the Turpial License from the company, which will retain an equal working interest.
On October 7, 2009 the company announced that it had executed the contract for the conversion of the Sierra Nevada II technical evaluation agreement ("TEA") into the Magdalena License, covering lands adjacent to the company's Sierra Nevada License in the Lower Magdalena Valley, onshore Colombia. The Magdalena License comprises approximately 595,000 acres and is considered to be mainly prospective for natural gas and natural gas liquids.
Argentina
In Argentina, during 2009 the company conducted a multi-well drilling program to meet its contractual obligations on its 100 percent-owned Gobernador Ayala II Block in the Province of La Pampa, Argentina. The company had identified two heavy oil accumulations at shallow depths with this program, and continues to assess the potential of these accumulations. We anticipate that the license may be relinquished if a farmout cannot be completed. On the Vaca Mahuida Concession, situated southeast of Puesto Morales, the company and its joint venture partner drilled, logged and cased for testing the VM X-2014 exploratory well. The well encountered a number of zones of interest, including some oil shows in the side wall cores resulting in the company anticipating further testing. During January, 2010, the company announced that it had entered into an additional farmout agreement on the Vaca Mahuida Concession. After completion of the committed work program and related expenditures, ownership of the Concession would be reduced to a 25 percent working interest with Petrolifera continuing as the operator. Under the terms of the farmout agreement, Petrolifera will be reimbursed for a 2010 drilling program of four exploratory wells ranging in depths from 1,000 to 1,500 meters, reimbursed for the back-costs of the VM X-2014 exploratory well, and if required, payments in cash to the Rio Negro Provincial Government for the value of any outstanding amount for work units that have not been incurred by the end of the first period of the exploration license, which expires on May 31, 2010.
Lower Argentinean crude oil production reflected the reduced investment activity undertaken in the period leading up to and during the Argentinean sales process, which did not ultimately result in any acceptable bids. In late 2009, the company completed the drilling and testing of five infill wells within the PMN Field in the Neuquen Basin, Argentina. The five infill wells tested initial productivity of approximately 1,100 bbl/d of crude oil. Overall field productivity may have to be constrained for a period of time until the total incremental fluid volumes, comprised of crude oil and water, that have been added by the new infill wells, can be accommodated by the water treatment and handling facilities. At that time, the full impact and sustainable productivity of the infill wells can be determined.
CREDIT FACILITIES
During April 2009, the company negotiated with a Canadian chartered bank an expansion of a line-of-credit ("ABCP line-of-credit"), primarily secured by the longer term notes exchanged for the ABCP, to a maximum of $28.2 million. Any borrowings from the expanded ABCP line-of-credit are categorized as long-term, as the facility's initial maturity is April, 2011 and the company can make up to five extension requests, with each extension for an additional one-year period. At December 31, 2008, the prevailing terms of the ABCP line-of-credit had a maximum draw of $18.0 million and was due on demand, resulting in the company categorizing its borrowings under the line-of-credit as a current liability. The line-of-credit bears interest at a floating rate.
As at December 31, 2009, the company had a US$100.0 million reserve-backed revolving credit facility with an established availability of US$50.0 million. During 2009 the availability of the reserve-backed facility was reduced from US$70.0 million to US$50.0 million, based on crude oil and natural gas reserves as at December 31, 2008. Borrowings from the reserve-backed credit facility are categorized as current, as the facility is scheduled to expire on September 5, 2010. The company has the ability to adjust its $20.0 million in reserve-backed debt repayments budgeted in 2010 should certain farmout arrangements not proceed as planned. Management anticipates it will renew and extend the term of this facility prior to expiry.
The reserve-backed revolving credit facility bears interest at LIBOR plus a margin, is secured by the pledge of the shares of Petrolifera's subsidiaries and parent company guarantees and has a provision for a borrowing base adjustment every six months, with the next adjustment to be calculated based on information as at June 30, 2009, which is in progress. From time-to-time changes in the availability of the reserve-backed credit facility are anticipated to occur through significant reserve additions, disposals or revisions. Reductions in current availability under the reserve-backed credit facility would require additional repayments based on amounts currently drawn.
As at December 31, 2009, the reserve-backed facility had $52.3 million (US$50.0 million) outstanding (2008 - US$63.0 million) and the long-term ABCP line-of-credit facility had $27.5 million outstanding (2008 - $16.6 million).
The company is subject to external restrictions on its reserve-backed revolving credit facility. Under this facility's agreement, the outstanding draws cannot exceed two times the 12 month trailing EBITDA. EBITDA is a non-GAAP measure and is defined by the credit facility agreement as net earnings (loss) prior to deduction of finance charges, income taxes, depletion, depreciation and accretion expense, stock-based compensation and unrealized foreign exchange losses. As at December 31, 2009, outstanding draws on the reserve-backed credit facility and a portion of long-term debt were $60.9 million and the maximum amount allowed as calculated by the credit facility (two times EBITDA) was $80.0 million, so Petrolifera was in compliance with this covenant. With existing realized commodity pricing, the company's cost structure and a planned debt reduction program for the ensuring year, Petrolifera anticipates that it will continue to be in compliance with the financial debt to EBITDA ratio covenant.
Reconciliation of net loss to EBITDA is as follows:
-------------------------------------------------------------------------
Year Ended December 31 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net loss $(10,825)
Add Interest, income taxes, depletion, depreciation and
accretion expense and other non-cash expenses:
Depletion, depreciation, and accretion 33,546
Finance charges 5,097
Fair value impairment 2,104
Stock-based compensation 4,674
Income tax provision 3,974
Unrealized foreign exchange loss 1,428
-------------------------------------------------------------------------
EBITDA $39,998
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RESTRICTED CASH AND LONG-TERM INVESTMENTS
As at December 31, 2009, long-term investments included notes received in exchange for ABCP with a face value of $34.6 million and a carrying value of $18.7 million and collateral to support issued letters of credit of $0.7 million. Restricted cash, as at December 31, 2009, included collateral to support issued letters of credit of $3.2 million, with terms to maturity of less than one year. As at December 31, 2008, ABCP with a face value of $37.7 million and a carrying value of $22.5 million and collateral to support issued letters of credit of $2.9 million were included in long-term investments. The decrease in the face and carrying values of the investments formerly known as ABCP is explained herein. These investments were classified as held for trading and were carried at fair value, which is assessed each reporting date.
In January, 2009, the Pan-Canadian Investors Committee for Third-Party Structured Asset-Backed Commercial Paper announced that the Superior Court of Ontario granted the Plan Implementation Order and that, accordingly, the plan for restructuring ABCP had been fully implemented. In exchange for the shorter-term ABCP, the company received longer term notes with maturities that generally approximate those of the assets previously contained in the underlying conduits. Assuming these replacement notes become liquid and could be sold for cash, the company would be able to substantially reduce its net indebtedness incurred from lack of access to these amounts.
During 2009, the company was advised that the ineligible asset tracking note Class 2 ("IA - Class 2") had total pledged market collateral of $400.0 million. Several credit events have occurred in the IA - Class 2 portfolio resulting in losses greater than the pledged market collateral, thereby reducing the outstanding principal amount of this investment to nil (the company had an investment in IA - Class 2 notes with an original face value of $2.9 million and a carrying value as at December 31, 2008 of $0.8 million). Further, the ineligible asset tracking note Class 1 ("IA - Class 1") has total pledged market collateral of $500.0 million and a third party portfolio investment manager expects no principal returns given the likelihood of multiple credit events (the company has an investment in the IA - Class 1 notes with an original face value of $3.7 million and a carrying value as at December 31, 2008 of $1.0 million). On August 11, 2009 a third party credit rating agency downgraded the Class A-2 notes to "BBB" from "A" and maintained the rating under review with negative implications due to a series of credit events.
For 2009, the company received $1.7 million in payments, representing interest that had accrued on the previous holdings of ABCP during the period from mid-August 2007 until January 21, 2009, net of its pro-rata portion of expenses, including legal costs associated with the resolution agreed and approved under the Canada Business Corporations Act and the Companies Creditors' Arrangement Act. It is expected that substantially all of the restructuring costs and reserves were deducted from these payments and are not expected to have any further impact on future payments to the company, although there may be other deductions related to alternative banking, legal or administrative fees. For 2009, the company received $0.1 million of interest and return of capital payments that had accrued on the investments formerly known as ABCP during the period from January 21, 2009 until December 31, 2009. For 2009, the company has recognized a $2.1 million impairment in the carrying value of its longer-term notes received in exchange for ABCP primarily due to the loss in its IA - Class 1 and IA - Class 2 notes resulting from a series of third party credit defaults or expected defaults, respectively, and a lowered rating from a third party credit rating agency on the company's A-2 class of investment notes. During the year ended December 31, 2008, the company recognized an impairment in fair value of $8.9 million on its investment in ABCP.
As no active market for the longer term notes has developed, management has estimated the fair value of the company's investment in the longer term notes at December 31, 2009, based on a probabilistic recovery of principal and interest, after taking into account all available information. Under this valuation method, several different outcomes of the recovery of the principal and interest are estimated, considering the information available as at December 31, 2009. A weighted average recovery is then calculated. This weighted average recovery is used to determine the discounted cash flows that are expected from these investments. The discount rate used to discount the expected cash flows from the longer term notes was an approximation of the risk-free rate for the expected life of the longer term notes to be received. As the rate used for discounting was an approximation of the risk-free rate, all other risks have been incorporated in the estimated probability-adjusted expected outcomes. This methodology applied all risking information into the various scenarios and discounted the fully-risked cash flow stream only for the time value of money. The recovery factors used were as follows:
-------------------------------------------------------------------------
Face Risk- Risk-
Value adjusted adjusted Capital Interest
Class of Capital Interest Weighted Weighted Risk-free
of Notes Recovery Recovery Average Average Term Discount
Note ($000s) Range Range Recovery Recovery (years) Rate
-------------------------------------------------------------------------
A-1 13,978 0 - 80% 0 - 60% 75% 54% 3 - 7 3%
A-2 13,543 0 - 70% 0 - 30% 64% 27% 7 3%
B 2,459 0 - 30% 0% 27% 0% 7 3%
C 928 0% 0% 0% 0% 7 3%
IA-1 3,674 0% 0% 0% 0% 7 3%
-------------------------------------------------------------------------
Total 34,582
-------------------------------------------------------------------------
Based on the above approach the fair value of the investment in the longer term notes was $18.7 million as at December 31, 2009 compared to $22.5 million as at December 31, 2008 as reconciled in the following table:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
ABCP, beginning of year $22,582 $31,464
Fair value impairment (2,104) (8,882)
Interest received previously included in fair value
of investment (1,789) -
-------------------------------------------------------------------------
Notes formerly known as ABCP, end of 2009 or
ABCP, end of 2008 $18,689 $22,582
-------------------------------------------------------------------------
Since 2007, the total impairment is approximately 46 percent of the original cost of the investment recognized on the longer term notes, including impairments recognized on the ABCP, which is an increase compared to the 40 percent of impairment relative to the original cost of the ABCP recognized at December 31, 2008.
The theoretical fair value of the company's longer-term notes could range from $14.0 million to $25.0 million using the valuation methodology described above with reasonably possible alternative assumptions. The outcome of the actual timing and amount ultimately recoverable from these notes may differ materially from this estimate, which would impact the company's earnings. To date, no active market for the longer term notes has developed to permit liquidation of the company's investment for proceeds equal to or greater than the collateral value pursuant to the ABCP line-of credit agreement.
RELATED PARTY TRANSACTIONS
Connacher Oil and Gas Limited ("Connacher") purchased 13,556,000 Units for gross proceeds to Petrolifera of $11.9 million pursuant to the Public Offering, which closed on August 28, 2009, that resulted in the issuance of a total of 65,343,000 Units for gross proceeds of approximately $57.5 million.
Pursuant to the Private Placement, certain directors and officers of the company purchased 1,137,500 Units for gross proceeds of $1.0 million, on the same terms as the Public Offering.
Under the terms of an Administrative Agreement with Connacher, which has been in effect since January 1, 2008, Connacher provided certain administrative services at the direction of the company. The fee for this services was $0.2 million for 2009 (2008 - $0.2 million). From time to time, Connacher also paid bills on behalf of the company, for which it is reimbursed. Connacher also provided certain support and services to the company in its pursuit of exploration opportunities in Colombia, for which it was indemnified and reimbursed, without further economic interest in the secured opportunities. Connacher is a significant shareholder of the company with a 22 percent equity interest as at December 31, 2009 and the Executive Chairman of the company is the President and Chief Executive Officer of Connacher.
During 2009 the company paid professional legal fees and common share issue costs of $0.5 million (2008 - $0.9 million), to a law firm in which an officer of the company is a partner. Transactions with the related party occurred within the normal course of business and have been measured at the exchange amount on normal business terms. The exchange amount is the amount of consideration established and agreed with the related party.
SIGNIFICANT ACCOUNTING POLICIES AND APPLICATION OF CRITICAL ACCOUNTING ESTIMATES
Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Changes in these judgments and estimates may have a material impact on the company's financial results and condition. The following accounts, although not exhaustive, that are most likely to be impacted by critical accounting estimates include long-term investments and impairments, property and equipment and depletion expense, asset retirement obligations and accretion expense, future income tax liabilities and future tax expense and contributed surplus and stock-based compensation expense. The following discusses such accounting policies and is included in the MD&A to aid the reader in assessing the significant accounting policies and practices of the company and the likelihood of materially different results being reported. Management reviews its estimates regularly. The emergence of new information and changed circumstances may result in changes to estimates which could be material and the company might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies. The following assessment of significant accounting policies is not meant to be exhaustive:
Oil and Gas Reserves
Under Canadian Securities Regulators' "National Instrument 51-101-Standards of Disclosure for Oil and Gas Activities" ("NI 51-101") proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. In accordance with this definition, the level of certainty should result in at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves. In the case of probable reserves, which are less certain to be recovered than proved reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those reserves less certain to be recovered than probable reserves. There is at least a 10 percent probability that the quantities actually recovered will exceed the sum of proved plus probable plus possible reserves.
The company's oil and gas reserve estimates are made by independent reservoir engineers using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the company's plans. The reserve estimates are also used in determining the company's borrowing base for its credit facilities and may impact the same upon revision or changes to the reserve estimates. The effect of changes in proved oil and gas reserves on the financial results and position of the company is described under the heading "Full Cost Accounting for Oil and Gas Activities".
Full Cost Accounting for Oil and Gas Activities
The company uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development are capitalized whether successful or not. The aggregate of net capitalized costs and estimated future development costs is amortized using the unit-of-production method based on estimated proved oil and natural gas reserves.
Major Development Projects and Unproved Properties
Certain costs related to major development projects and unproved properties are excluded from net capitalized costs subject to depletion until proved reserves have been determined, the project becomes commercial, or their value is impaired. These costs are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.
Full Cost Accounting Ceiling Test
The company is required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. Impairment is indicated if the carrying value of the long-lived asset or oil and gas cost centre is not recoverable from the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings.
The ceiling test is based on estimates of reserves, production rate, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature these estimates are subject to measurement uncertainty and the impact on the consolidated financial statements could be material.
Asset Retirement Obligations
The company is required to provide for future removal and site restoration costs by estimating these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to earnings and the appropriate liability account over the expected service life of the asset. When the future removal and site restoration costs cannot be reasonably determined, a contingent liability may exist. Contingent liabilities are accrued and eventually charged to earnings only when management is able to determine the amount and the likelihood of the future obligation. The company estimates future retirement costs based on current estimates adjusted for inflation and credit risk. These estimates are subject to measurement uncertainty.
Income Taxes
The company follows the liability method of accounting for income taxes. Under this method tax assets are recognized when it is more than likely realization will occur. Tax liabilities are recognized for temporary differences between recorded book values and underlying tax values. Rates used to determine income tax asset and liability amounts are enacted rates expected to be used in future periods when the timing differences change. The period in which a timing difference reverses are impacted by future income and capital expenditures. Rates are also affected by legislation changes.
Stock-Based Compensation
The company uses the fair value method to account for stock options. The determination of the amounts for stock-based compensation is based on assumptions of stock volatility, interest rates and the term of the option. These assumptions by their nature are subject to measurement uncertainty.
Legal, Environment Remediation and Other Contingent Matters
In respect of these matters, the company is required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine if such a loss can be estimated. When any such loss is determined, it is charged to earnings. Management continually monitors known and potential contingent matters and makes appropriate provisions by charges to earnings when warranted by circumstance.
Foreign Currency Translation
Colombia, Peru, Barbados and the US subsidiaries are considered to be "integrated foreign operations" for accounting purposes and, therefore, these foreign operations' financial statements are translated into Canadian dollars using the temporal method. Under the temporal method, the company translates foreign denominated monetary assets and liabilities at the exchange rate prevailing at year end; non-monetary assets, liabilities and related depletion and depreciation are translated at historic rates; revenues and expenses are translated at the average rate of exchange for the period; and any resulting foreign exchange gains or losses are included in net earnings (loss).
As a self-sustaining foreign operation, the Argentinean financial statements are translated into Canadian dollars using the current rate method, whereby assets and liabilities are translated at the rate of exchange in effect at the balance sheet date; revenues and expenses are translated at the average monthly rates of exchange during the period and gains or losses on translation are included as a foreign currency translation adjustment in the consolidated statements of comprehensive income and accumulated other comprehensive income (loss).
IMPACT OF NEW AND PROPOSED ACCOUNTING PRONOUNCEMENTS
During August, 2009, the CICA issued amendments to Section 3855, Financial Instruments - Recognition and Measurement. The amendments included the definitions of a financial asset or financial liability held for trading and loans and receivables, provided guidance concerning the assessment of embedded derivatives upon reclassification of a financial asset out of the held-for-trading category and requires that Section 3025, Impaired Loans, be applied to assess whether held-to-maturity investments are impaired and to account for any such impairment. The amendment concerning the embedded derivates was adopted for any reclassification made on or after July 1, 2009 and did not have any impact on the company's financial statements. The remaining amendments to Section 3855 apply to the company's annual financial statements for the year ended December 31, 2009. The adoption of the amendments to Section 3855 did not have an impact on the company's financial statements.
During June, 2009, the CICA issued amendments to Section 3855, Financial Instruments - Recognition and Measurement, and Section 3862, Financial Instruments - Disclosures. The amendment to Section 3855 clarifies when an embedded prepayment option is separated from its host debt instrument for accounting purposes. The company prospectively adopted the CICA amendment to Section 3855 which did not have an impact on the company's consolidated financial statements. The amendments to Section 3862 enhance financial instrument disclosure requirements about liquidity risk and provide new disclosure requirements for fair value measurements. The amendments to Section 3862 apply to the company's annual consolidated financial statements for the year ended December 31, 2009. Upon adoption of the Section 3862 amendments, the company did not provide comparative information for the disclosures required by the amendments.
Effective January 1, 2009 the company adopted CICA Handbook section 3064, Goodwill and Intangible Assets, which replaced section 3062, Goodwill and Other Intangible Assets and section 3450, Research and Development Costs. Various changes have been made to other sections of the CICA Handbook for consistency purposes. Section 3064 establishes new standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous section 3062. As the company does not carry goodwill or intangible assets, as defined by section 3064, this new standard had no impact on the presentation and disclosures of the company.
In January 2009, the CICA issued EIC-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. The abstract provides guidance on how to take into account credit risk of an entity and counterparty when determining the fair value of financial assets and financial liabilities, including derivative instruments. This abstract is effective for the company's interim and annual Consolidated Financial Statements for periods ending on or after March 31, 2009 with retrospective application without reinstatement of prior periods. The application of this did not have a material effect on the company's Consolidated Financial Statements.
In December 2008, the CICA issued Section 1582, Business Combinations, which will replace CICA Section 1581 of the same name. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The company is currently evaluating the impact of this changeover on its Consolidated Financial Statements.
In December 2008, the CICA issued Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests, which replaces existing Section 1600. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. These standards currently do not impact the company as it has full controlling interest of all of its subsidiaries.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In October 2009, the Canadian Accounting Standards Board issued a third and final International Financial Reporting Standards ("IFRS") Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to adopt IFRS in place of Canadian GAAP for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011. The company's IFRS adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by the company for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.
Management has commenced its IFRS conversion project which consists of the following three phases:
1. Preliminary phase - this phase commenced with a review of the
company's significant accounting policies relative to current and
proposed IFRS. The results of this analysis were priority ranked
according to the complexity and the extent of the impact in adoption
of IFRS accounting policies.
2. Impact and evaluation phase - the company is now in the process of
preparing draft analysis for the impact and evaluation phase, where
items identified in the preliminary phase are addressed according to
the priority levels assigned to them. This phase involves analysis of
policy choices allowed under IFRS and impact on the financial
statements.
3. Implementation phase - this final phase involves implementing all
changes approved in the impact and evaluation phase.
Upon completion of the preliminary phase, management determined that the differences most likely to have the greatest degree of complexity and impact on the company's consolidated financial statements were as follows:
- First-time adoptions exemption - the International Accounting
Standards Board has approved additional exemptions from the
retrospective application of IFRS for first time adopters. Of most
relevance to the company, is an exemption that allows full cost oil
and gas companies to elect, at the date of transition to IFRS, to
measure exploration and evaluation assets at the amount determined
under Canadian GAAP and to measure oil and gas assets in the
development or production phases by allocating the amount determined
under Canadian GAAP to the underlying assets pro-rata using reserve
volumes or reserve values as of that date. Management will consider
if this exemption should be applied as it continues to monitor the
IFRS adoption efforts of the company's peers.
- Re-classification of exploration and evaluation ("E&E") expenditures
from property, plant and equipment ("PP&E") on the consolidated
balance sheet - this will consist of the book value of the company's
undeveloped land that relates primarily to its Colombian and Peruvian
properties. E&E assets will not be depleted and must be assessed for
impairment when indicators suggest the possibility of impairment.
- Calculation of depletion expense for PP&E - upon transitioning to
IFRS, the company has the option to calculate depletion using a
reserve base of proved reserves or both proved and probable reserves,
as compared to the Canadian GAAP method of calculating depletion
using only proved reserves.
- Impairment of PP&E - under IFRS, impairment of PP&E must be
calculated at a more detailed level than what is currently required
under Canadian GAAP. Impairment calculations will be performed at the
cash generating unit level using either total proved or proved plus
probable reserves.
- Foreign currency translation methods and the functional currencies of
each of the company's foreign operations - under IFRS, the functional
currency emphasizes the currency that determines the pricing of the
transactions that are undertaken, rather than focusing on the
currency in which those transactions are denominated.
- With the recent withdrawal of the IAS 12 Income Taxes exposure draft
and the issuance of IAS 37 Provisions, Contingent Liabilities and
Contingent Assets, management is still determining the impact of
these revised standards mainly on its IFRS transition of income taxes
and asset retirement obligations.
During the impact and evaluation phase, certain potential policy differences between IFRS and Canadian GAAP are currently being investigated to assess whether there may be a broader impact on the company's:
- Disclosure controls - throughout the transition process, the company
will be assessing stakeholders' information requirements and will
ensure that adequate and timely information is provided so that all
stakeholders are kept apprised.
- Internal controls over financial reporting ("ICFR") - as the adoption
of IFRS policies is completed, an assessment will be made to
determine changes required for ICFR. The company anticipates changes
to its IT systems and the training of impacted staff and implementing
appropriate additional controls related to the grouping of
development assets into cash generating units and separately
identifying E&E assets.
- Contracts and lending agreements - management has been cognizant of
the upcoming transition to IFRS and will ensure that agreements that
reference Canadian GAAP statements or financial covenants are
modified to allow for IFRS statements and calcuations made in
accordance with IFRS statements, respectively. Based on the expected
changes to the company's accounting policies at this time, there are
no foreseen issues with the existing wording of debt covenants and
other agreements as a result of the conversion to IFRS.
The conclusion of the impact and evaluation phase will require the audit committee of the Board of Directors to review and approve all accounting policy choices as proposed and recommended by management. The final implementation phase involves implementing all changes approved in the impact and evaluation phase.
Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on the financial statements. In addition, due to anticipated changes to IFRS and International Accounting Standards prior to the company's adoption of IFRS, management's plan is subject to change based on new facts and circumstances that arise after the date of this MD&A. The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect the company. Management's timeframe to complete the third and final implementation phase of its IFRS adoption efforts is scheduled during the second half of 2010 which will allow the company to adopt IFRS in place of Canadian GAAP effective January 1, 2011.
COMMITMENTS, CONTRACTUAL OBLIGATIONS, GUARANTEES & OFF-BALANCE SHEET ARRANGEMENTS
WORK COMMITMENTS
In 2005, Petrolifera acquired two significant oil and gas exploration licenses onshore Peru for Blocks 106 and 107, respectively, located in the Maranon and Ucayali Basins. During April 2009, Petrolifera was awarded a license over Block 133, offsetting and contiguous with Block 107 and relinquished approximately one half of Block 107 during May 2009. Based on its interpretation of the 950 km 2D seismic program acquired over the acreage by the company in 2007 and 2008, Petrolifera believes it has retained the most prospective acreage under Block 107.
The Peruvian licenses have negotiated work programs through 2016, unless extended. Each work program has a specified minimum financial commitment that must be met for the company to maintain its rights to these licenses. Specifically, the immediate minimum work commitments of US$0.3 million for Block 133 are primarily comprised of geological field studies and as such are not capital intensive. The company has met, or surpassed, all of its current work commitments for Blocks 106 and 107 in a timely manner. The company has the right to withdraw from the licenses at the end of each period associated with the term of the licenses. The first well is required to be completed by mid-2014 on Block 107, which positions the company to maintain these properties in good standing at a low cost.
In 2007, the company was granted three Colombian concessions comprised of one license, Sierra Nevada, and two TEAs. Petrolifera has converted the Turpial and Sierra Nevada II TEAs into exploration licenses with the latter renamed Magdalena. Petrolifera drilled the La Pinta 1X well on the Sierra Nevada License, which fulfilled this license's first phase of work commitments. The company is now in the second phase of the work program, which requires the drilling of one exploratory well and acquiring additional seismic by June, 2010. The company spudded the Sierra Nevada License's second phase exploratory well, Brillante SE-1X, on February 16, 2010, to evaluate a seismically-defined structure that is considered prospective for natural gas and possibly associated natural gas liquids. The company anticipates it will take approximately 90 days to drill, complete and test the Brillante well, which is targeting the CDO at a depth of approximately 9,500 feet, although overpressured conditions, such as were encountered in the La Pinta 1X well, are not anticipated. During the first half of 2010, the company anticipates commencing a 3D seismic program over the La Pinta structure. On the company's Turpial License, the company has completed its first year's program comprised of 3D seismic acquisition, processing and interpretation. Anticipated expenditures during the second phase of the Turpial exploration contract will be disproportionally financed by the company's joint venturer, with the work program consisting of a minimum acquisition and interpretation of 114 km(2) of 2D seismic prior to September, 2010. The company is in the first phase of its Magdalena License, which requires an exploration well to be completed prior to December, 2010. The company anticipates commencement of drilling a test well on its San Angel prospect during the fourth quarter of 2010.
The company's Colombian and Peruvian 2010 exploration budget addresses the aforementioned work commitments. Financing of the company's 2010 exploration activities is anticipated through existing cash reserves and completion of farmouts or joint ventures arrangements. Should these farmout arrangements not proceed as planned, the company may have the ability to defer capital expenditures on certain licenses.
In Argentina, the company has net work commitments of US$0.6 million related to the Puesto Guevara Concession that are anticipated to be completed during 2010. During 2009, the company completed its work commitments related to the Gobernador Ayala II Concession and after disappointing drilling results is attempting to farmout this license. The company's 25 percent working interest in Vaca Mahuida Concession's first period work commitments have been eliminated by a farmout to third parties, completed in early 2010.
CONTRACTUAL OBLIGATIONS
The company's contractual obligations for drilling, leases for office premises and other equipment and an administrative services agreement for 2010 and annually thereafter are as follows:
-------------------------------------------------------------------------
Subsequent
2010 2011 to 2011 Total
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Drilling service contracts
and other leases $16,609 $507 $ - $17,116
-------------------------------------------------------------------------
GUARANTEES
The company has issued letters of credit in the total amount of US$1.7 million to secure the capital expenditure requirements associated with three exploration licenses in Peru and US$2.1 million in support of the Colombian work commitments. A deposit of US$4.1 million was placed in a trust account in Colombia to meet certain work obligations on the Magdalena License as they occur.
OFF-BALANCE SHEET ARRANGEMENTS
The company does not have any off-balance sheet arrangements.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the company is accumulated, recorded, processed, summarized and reported to the company's management as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation as of the end of the year covered by this MD&A, the company's Executive Chairman, President and Chief Operating Officer and Chief Financial Officer have concluded that the company's disclosure controls and procedures as of the end of the year are effective to provide reasonable assurance that material information related to the company, including its consolidated subsidiaries, is communicated to them as appropriate to allow timely decisions regarding required disclosure.
Management of the company is also responsible for designing and testing the effectiveness of internal controls over the company's financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The design of the company's internal controls over financial reporting was based on the Committee of Sponsoring Organizations of the Treadway Commission's "Internal Control - Integrated Framework". The testing of the effectiveness of the internal controls over financial reporting did not reveal any material weaknesses relating to their design. It should be noted that while the company's Executive Chairman, President and Chief Operating Officer and Chief Financial Officer believe that the company's disclosure controls and procedures provide a reasonable level of assurance that they are effective and that the internal controls over financial reporting are adequately designed and are effective, they do not expect that the financial disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. In reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. There have been no changes in the company's systems of internal controls over financial reporting during the three and twelve months ended December 31, 2009 that would materially affect, or are reasonably likely to materially affect, the company's internal controls over financial reporting.
BUSINESS RISKS
Petrolifera is exposed to certain risks and uncertainties inherent in the oil and gas business. Furthermore, being a smaller independent company, it is exposed to financing and other risks which may impair its ability to realize on its assets or to capitalize on opportunities which might become available to it. Additionally, Petrolifera operates in various foreign jurisdictions and is exposed to other risks including currency fluctuations, political and economic risk, price controls and varying forms of fiscal regimes and government policies or changes thereto which may impair Petrolifera's ability to conduct profitable operations.
The risks arising in the oil and gas industry include price fluctuations for both crude oil and natural gas over which the company has limited control; risks arising from exploration and development activities; production risks associated with the depletion of reservoirs and the ability to market production. Additional risks include environmental and health and safety concerns.
Virtually all of the company's total revenue in its fiscal year ending December 31, 2009 was derived from crude oil, natural gas and natural gas liquids production from the Puesto Morales/Rinconada Concession in Argentina. The occurrence of any event that would prevent the production of crude oil and natural gas by the company from the Puesto Morales/Rinconada Concession, including physical problems or infrastructure facilities (howsoever arising) supporting the producing region or negative actions on the part of any government or regulatory authority in Argentina, would have a significant adverse effect on the company's cash flows and revenue until such time as such problem is remedied. Additionally, there is a risk of premature decline of the reservoirs that may impact recoverability of the reserves associated with significant wells.
Farmout (and joint venture) efforts continue with respect to much of the company's prospect inventory. Current capital market conditions may make this process more challenging and time consuming than under more buoyant economic conditions, resulting in the company having to bring participants into its acreage holdings and planned activities on less attractive terms than might otherwise have been negotiated. There can be no assurances as to the timing or completion of possible farmout (and/or joint venture) arrangements.
Farmout or joint venture arrangements can expose Petrolifera to additional risks and uncertainties where the concurrence of co-venturers is required to pursue various actions or the co-venturer is required to fund expenditures on behalf of Petrolifera to meet contractual work commitments. Other parties influencing the timing of events may have priorities that differ from Petrolifera's, even if they generally share Petrolifera's objectives. Additionally, Petrolifera is exposed to the credit risk of its co-venturers and possible default if its co-venturer fails to meet contractual work commitments initially undertaken by Petrolifera under its Licenses.
The success of the company's capital programs as embodied in its productivity and reserve base, could also impact its prospective liquidity and pace of future activities. Control of finding, development, operating and overhead costs per boe is an important long-term criterion in determining company growth, success and access to new capital sources.
To date, the company has utilized debt and equity financing and has had a bias towards conservatively financing its operations under normal industry conditions to offset the inherent risks of international oil and gas exploration, development and production activities. The company may be required to raise additional capital to fund its activities in light of overall industry conditions, the high cost of the La Pinta well, the termination of the Argentina sale process, the remaining work commitments associated with the company's exploratory lands and the slow pace at which farmout negotiations are preceding. Capital markets may not be receptive to offerings of new equity from treasury, whether by way of private placement or public offerings. Additionally, there can be no assurance that the outstanding Warrants will be exercised to provide the company with additional liquidity.
Access to financing has been impacted by sub-prime mortgage defaults, the liquidity crisis affecting the ABCP and collateralized debt obligation markets and deterioration in the global economy. Banks have been adversely affected by the worldwide economic crisis and have severely curtailed existing liquidity lines, increased pricing and introduced new and tighter borrowing restrictions to corporate borrowers, with extremely limited access to new facilities or for new borrowers. These factors may impact Petrolifera's ability to obtain equity, debt or bank financing on terms that are commercially reasonable, or at all, and could negatively impact its ability to access liquidity needed for its operations in the longer term. This may be further complicated by the limited market liquidity for shares of smaller companies, restricting access to some institutional investors.
Periodic fluctuations in energy prices may also affect lending policies of the company's banker for new borrowings in addition to the semi-annual review of reserves which may reduce the existing availability of indebtedness. This in turn could limit growth prospects over the short run or may even require the company to dedicate cash flow, dispose of properties or raise new equity to reduce bank borrowings under circumstances of declining energy prices or disappointing drilling results.
While hedging activities may have opportunity costs when realized prices exceed hedged pricing, such transactions are not meant to be speculative and are considered within the broader framework of financial stability and flexibility. Management continuously reviews the need to utilize such financing techniques.
The company attempts to mitigate its business and operational risk exposures by maintaining comprehensive insurance coverage on its assets and operations, by employing or contracting competent technicians and professionals, by instituting and maintaining operational health, safety and environmental standards and procedures and by maintaining a prudent approach to exploration and development activities. The company also addresses and regularly reports on the impact of risks to its shareholders, writing down the carrying values of assets that may not be recoverable.
FOURTH QUARTER 2009 SUMMARY RESULTS
-------------------------------------------------------------------------
For the Three Months Ended December 31 2009 2008 % Change
-------------------------------------------------------------------------
FINANCIAL ($000, except per share amounts)
-------------------------------------------------------------------------
Total revenue $17,900 $37,411 (52)
Cash flow from operations before non-cash
working capital(1) 5,867 21,689 (73)
Per share, basic 0.05 0.39 (87)
Per share, diluted 0.05 0.39 (87)
Net earnings (loss) (4,081) 2,662 (253)
Per share, basic (0.03) 0.05 (160)
Per share, diluted(4) (0.03) 0.05 (160)
Capital expenditures 12,145 35,539 (66)
Cash 35,732 30,701 16
Working capital (2,508) 19,956 (113)
Long-term investment(2) 19,395 25,428 (24)
Long-term debt 27,464 77,150 (64)
Shareholders' equity 232,126 202,347 15
Total assets $349,065 $355,658 (2)
-------------------------------------------------------------------------
OPERATING
-------------------------------------------------------------------------
Daily sales volumes
Crude oil and natural gas liquids - bbl/d 3,833 6,877 (44)
Natural gas - mcf/d 4,056 5,451 (26)
Barrels of oil equivalent - boe/d(3) 4,509 7,786 (42)
Average selling prices
Crude oil and natural gas liquids - $/bbl $48.08 $56.76 (15)
Natural gas - $/mcf $ 2.53 $ 2.88 (12)
Barrels of oil equivalent - $/boe $43.15 $52.15 (17)
-------------------------------------------------------------------------
COMMON SHARES OUTSTANDING (000s)
-------------------------------------------------------------------------
Weighted average
Basic 121,759 54,948 122
Diluted(4) 121,777 55,043 121
End of period 121,759 54,948 122
-------------------------------------------------------------------------
(1) Cash flow from operations before non-cash working capital changes
("cash flow") and cash flow per share do not have standardized
meanings prescribed by Canadian generally accepted accounting
principles ("GAAP") and therefore may not be comparable to similar
measures used by other companies. Cash flow includes all cash flow
from operating activities and is calculated before changes in non-
cash working capital. The most comparable measure calculated in
accordance with GAAP would be net earnings (loss). Cash flow is
reconciled with net earnings (loss) in this Management's Discussion &
Analysis ("MD&A"). Management uses these non-GAAP measurements for
its own performance measures and to provide its shareholders and
investors with a measurement of the company's efficiency and its
ability to fund a portion of its future growth expenditures.
(2) Includes carrying value of notes received for Asset Backed
Commercial Paper ("ABCP") with a face value of $34.6 million and
$37.7 million as at December 31, 2009 and 2008 respectively. Long-
term debt in the amount of $27.5 million as at December 31, 2009 is
primarily secured on a limited recourse basis by the underlying notes
formerly known as ABCP. Bank debt of $16.6 million as at December 31,
2008 was secured by the ABCP.
(3) All references to barrels of oil equivalent (boe) are calculated
on the basis of 6 Mcf : 1 bbl. Boe may be misleading particularly if
used in isolation. This conversion is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
(4) As the company has net losses during the three months ended December
31, 2009, the dilutive effect of stock options and share purchase
warrants became anti-dilutive causing the basic weighted average
common shares outstanding to be used as the denominator in the
dilutive per share net loss calculation.
FOURTH QUARTER 2009 FINANCIAL AND OPERATING REVIEW
SALES VOLUMES, PRICING AND REVENUE
-------------------------------------------------------------------------
For the Three Months Ended December 31 2009 2008 % Change
-------------------------------------------------------------------------
Daily sales volumes:
Crude oil and natural gas liquids - bbl/d 3,833 6,877 (44)
Natural gas - mcf/d 4,056 5,451 (26)
Equivalent - boe/d 4,509 7,786 (42)
-------------------------------------------------------------------------
Average selling prices:
Crude oil and natural gas liquids - $/bbl $ 48.08 $ 56.76 (15)
Natural gas - $/mcf 2.53 2.88 (12)
Weighted average selling price - $/boe $ 43.15 $ 52.15 (17)
-------------------------------------------------------------------------
Petroleum and natural gas sales ($000) $17,898 $37,355 (52)
Interest income ($000) 2 56 (96)
-------------------------------------------------------------------------
Total revenue ($000) $17,900 $37,411 (52)
-------------------------------------------------------------------------
Petroleum and natural gas revenues in the fourth quarter of 2009 were $17.9 million on sales volumes of 4,509 boe per day, compared to $37.4 million on sales of 7,786 boe per day during the fourth quarter of 2008, a decrease of 52 percent for revenue and 42 percent for sales volumes. For the three months ended December 31, 2009, sales of crude oil and natural gas liquids represented 85 of the company's sales volumes, which was lower than the 88 percent for the comparable period in 2008. The reduction in sales revenues during the three months ended December 31, 2009, compared to the same period in 2008, reflects the minimal investment during 2009 in the company's Argentinean interests, as it takes time to reactivate drilling programs which were suspended or cancelled. Production was also affected by natural production declines and operational challenges, which included downtime at several wells.
Relative to the third quarter of 2009, when petroleum and natural gas revenues were $17.2 million on sales volumes of 4,362 boe per day, higher revenues and sales volumes of four percent and three percent, respectively, were experienced during the fourth quarter of 2009. At the end of 2009, the company completed drilling and testing five infill wells within the PMN Field in the Neuquen Basin, Argentina. The five infill wells indicate a total tested initial productivity of approximately 1,100 bbl/d of crude oil. The company anticipates the full impact and sustainability of the infill wells can be determined during the first quarter of 2010, upon completion of the expansion to its water treatment handling facilities to handle the incremental fluid volumes, comprised of crude oil and water.
Operational challenges during the three months ended December 31, 2009, included a scheduled workover of a key producing well and shut-ins caused by equipment failures.
The company's realized crude oil price fell 15 percent to average $48.08 per barrel for the fourth quarter of 2009, compared to $56.76 per barrel realized in the fourth quarter of 2008. In the three months ended December 31, 2009, the average natural gas price declined by 12 percent from the level realized during the comparable period in 2008 to average $2.53 per mcf, despite averaging US$2.40 per mcf in both the fourth quarter of 2009 and 2008. The reduction in both commodities average realized selling prices during the fourth quarter of 2009, as expressed in Canadian dollars, is attributable to an average 13 percent strengthening of the Canadian dollar, as compared to the US dollar, compared to the fourth quarter of 2008. During the three months ended December 31, 2009 and 2008, the respective crude oil price realized by Petrolifera averaged approximately 61 percent and 80 percent of the WTI average of US$76.06 and US$58.60 per barrel.
FOURTH QUARTER 2009 ROYALTIES, OPERATING EXPENSES
CORPORATE NETBACKS(1)
-------------------------------------------------------------------------
For the Three Months Ended
December 31 2009 2008
-------------------------------------------------------------------------
($000, except per unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Average daily sales (boe/d) 4,509 7,786
-------------------------------------------------------------------------
Petroleum and natural gas sales $17,898 $ 43.15 $37,355 $ 52.15
Interest income 2 - 56 0.08
Royalties (2,655) (6.40) (5,489) (7.66)
-------------------------------------------------------------------------
Net revenue 15,245 36.75 31,922 44.57
Operating costs (5,568) (13.42) (7,365) (10.28)
-------------------------------------------------------------------------
Corporate netback $ 9,677 $ 23.33 $24,557 $ 34.29
-------------------------------------------------------------------------
(1) Calculated by dividing related revenue and costs by total boe
sold, resulting in a corporate netback. Netback does not have a
standardized meaning prescribed by GAAP and therefore is unlikely to
be comparable to similar measures used by other companies. The most
comparable measure calculated in accordance with GAAP would be net
earnings (loss). Nevertheless, Petrolifera's management uses netbacks
as a performance measurement of operating efficiency and the
prevailing royalty regime. A high ratio of netback to selling price
is a positive indicator. A reconciliation of corporate netback to net
income (loss) can be found in the Net Earnings (Loss) table.
The corporate netback per boe decreased 32 percent during the fourth quarter of 2009 relative to same period in 2008. Lower realized commodity pricing and higher operating costs per boe contributed to the reduction. Petrolifera's calculated unit netback of $23.33 per boe remained a respectable 54 percent of the selling price per boe during the three months ended December 31, 2009, although this was a reduction from the 66 percent corporate netback relative to the selling price per boe during the same period in 2008.
The corporate netback in the fourth quarter of 2009 was four percent higher than in the prior quarter in 2009. Improved average realized selling prices and lower operating costs per boe during the three months ended December 31, 2009, compared to the prior quarter in 2009 contributed to the improvement.
FOURTH QUARTER 2009 OPERATING COSTS
Total operating costs during the three months ended December 31, 2009, decreased by approximately 24 percent compared to the same period in 2008, largely due to lower production volumes. On a per boe basis, operating costs increased 31 percent for the three months ended December 31, 2009, compared to the same period for 2008. Lower sales volumes and higher well servicing costs during the three months ended December 31, 2009 resulted in the increase per boe. Also contributing to higher operating costs per boe during the three months ended December 31, 2009, compared to the same period in 2008, were the number of wells on pump or that required servicing on a more frequent basis. The challenges related to the company's waterflood program caused an increase in total fluid throughput, with a lower percentage of crude oil, resulting in an increase in the operating costs per boe for the three months ended December 31, 2009 relative to the same period in 2008.
Total operating costs were comparable during the fourth and third quarters of 2009. On a per boe basis, operating costs were six percent lower for the three months ended December 31, 2009, compared to the third quarter of 2009. During the fourth quarter of 2009, higher crude oil and natural gas liquids production volumes and reduced well servicing costs combined with a one-time labour charge in the third quarter of 2009 resulted in the decrease.
FOURTH QUARTER 2009 ROYALTIES
Royalties in the fourth quarter of 2009 were $2.7 million ($6.40 per boe) compared to $5.5 million ($7.66 per boe) or 15 percent of petroleum and natural gas revenue in both periods of 2009 and 2008, compared to $2.5 million ($6.09 per boe) or 14 percent of petroleum and natural gas revenue in the third quarter of 2009.
FOURTH QUARTER 2009 NET EARNINGS AND SHARES OUTSTANDING
-------------------------------------------------------------------------
For the Three Months Ended
December 31 2009 2008
-------------------------------------------------------------------------
($000, except per unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Corporate netback $ 9,677 $ 23.33 $24,557 $ 34.29
General and administrative (1,915) (4.62) (2,099) (2.93)
Stock-based compensation (675) (1.63) (1,595) (2.23)
Finance charges (1,040) (2.51) (1,833) (2.56)
Foreign exchange gain (loss) (225) (0.54) 789 1.10
Fair value impairment - - (3,505) (4.89)
Depletion, depreciation and
accretion (8,936) (21.55) (11,328) (15.81)
Income tax provision (724) (1.75) (1,947) (2.72)
Taxes other than income taxes (243) (0.59) (377) (0.53)
-------------------------------------------------------------------------
Net earnings (loss) $(4,081) $(9.85) $ 2,662 $ 3.72
-------------------------------------------------------------------------
For the fourth quarter of 2009, the company reported a net loss of $4.1 million, which equated to a net loss of $0.03 per weighted average basic and diluted share, compared to net earnings of $2.7 million, which equated to $0.05 per weighted average basic and diluted share for the same period in 2008. A net loss was recognized during the fourth quarter of 2009, compared to the net earnings in the same quarter in 2008, due to lower sales volumes, lower selling prices and foreign exchange losses.
For the three months ended December 31, 2009, the company's comprehensive loss was $7.1 million as compared to the comprehensive income in the same 2008 period of $22.8 million. The comprehensive loss during the three months ended December 31, 2009, was due to the aforementioned net loss combined with a two percent strengthening of the Canadian dollar, relative to the US dollar, which reduced the reported net assets of the company's Argentinean operations, as denominated in US dollars. The comprehensive income during the three months ended December 31, 2008, was due to the aforementioned net earnings, combined with a 13 percent strengthening of the US dollar, relative to the Canadian dollar, which increased the reported net assets of the company's Argentinean operations.
During the three months ended December 31, 2009 the weighted average number of common shares outstanding was 121.8 million, compared to 54.9 million during the same period in 2008. The increase in the weighted average number of common shares for the three months ended December 31, 2009, relative to the same period in 2008, reflected the August 2009 issuance of 65.3 million common shares from treasury for gross proceeds of $57.5 million; the September 2009 private placement issuance of 1.1 million common shares from treasury for proceeds of $1.0 million and the exercise of 0.3 million options which were exercised during the third quarter of 2009, resulting in the issuance of a like number of common shares. As the company had net losses during the three months ended December 31, 2009, the effect of "in-the-money" stock options and share purchase warrants became anti-dilutive, resulting in the exclusion of the effect of these equity instruments on the diluted net loss per common share calculation, whereas in the same period in 2008, 0.1 million additional common shares were included in the calculation of diluted net earnings per share.
G&A AND STOCK-BASED COMPENSATION
G&A expenses were comparable at $1.9 million and $2.1 million for the three months ended December 31, 2009 and 2008, respectively. On a per boe basis, G&A was $4.62 per boe of sales for the last three months of 2009 compared to $2.93 per boe for the last three months of 2008. The increase in G&A per boe for the fourth quarter of 2009, relative to the same period in 2008, was primarily due to lower sales volumes. G&A expenses of $1.1 million and $1.3 million were also capitalized in the three months ended December 31, 2009 and 2008, respectively.
During the three months ended December 31, 2009, a non-cash expense of $0.7 million (2008 - $0.9 million) was recorded as stock-based compensation. The decrease in stock-based compensation was mainly attributable to a lower fair value of options granted during 2009 compared to the fair value of options granted during 2008. Additionally, for the three months ended December 31, 2008, the company paid $0.2 million to certain non-officer employees resulting in the cancellation of 350,000 "out of the money" options. As a result of these optionees surrendering certain of their options, per Canadian GAAP any unvested options were deemed to have become vested, resulting in the recognition of an additional non-cash stock-based compensation expense of $0.7 million.
FINANCE CHARGES
Included in the finance charges of $1.0 million and $1.8 million for the three months ended December 31, 2009 and 2008, respectively, was interest paid and accrued on the company's outstanding current and long-term bank debt and deferred financing charges that are being allocated over the life of the reserve-backed credit facility. The decrease in finance charges during the three months ended December 31, 2009, compared to the same period in 2008, reflected a lower effective interest rate on the company's credit facilities of 3.5 percent for the three months ended December 31, 2009, compared to 7.6 percent for the same period during 2008 despite higher average outstanding loan amounts.
FOREIGN EXCHANGE
During the three months ended December 31, 2009, a foreign exchange loss was recognized on Argentinean and corporate working capital, as partially denominated in Argentinean pesos and US dollars, respectively, because as the Canadian dollar strengthened relative to both aforementioned foreign currencies, the company reported a corresponding reduction in working capital, as expressed in Canadian dollars. This foreign exchange loss was partially offset by the weakening of the US dollar relative to the Canadian dollar on a portion of the company's US dollar denominated debt, resulting in a foreign exchange gain on a corresponding reduction in reported debt, as expressed in Canadian dollars. Combined, this resulted in a net foreign exchange expense of $0.2 million for the three months ended December 31, 2009.
FAIR VALUE IMPAIRMENT
During the three months ended December 31, 2008, the company recognized a loss of liquidity in its investment in ABCP. A provision was made in the financial statements for a non-cash fair value impairment charge of $3.5 million for the fourth quarter of 2008. The company did not recognize any further impairment in the fair value of its investment in notes formerly known as ABCP during the three months ended December 31, 2009.
DEPLETION, DEPRECIATION & ACCRETION ("DD&A")
DD&A for the three months ended December 31, 2009 totaled $8.9 million, a decrease compared to $11.3 million in the same period in 2008, largely due to a lower production volumes. On a boe basis for the three months ended December 31, 2009, DD&A of $21.55 per boe was higher than $15.81 per boe as compared to the same period for 2008. The increase in DD&A on a per boe basis during the three months ended December 31, 2009 compared to the same period in 2008 was primarily due to higher estimated costs of future capital expenditures, the inclusion of Gobernador Ayala II exploration costs subject to depletion and a year-end reserve adjustment.
Accretion expense, which is included in DD&A expense, was $0.1 million for the three months ended December 31, 2009 and 2008.
TAXES
The current income tax provision of $0.5 million and recovery of $1.2 million for the three months ended December 31, 2009 and 2008, respectively, related mostly to income taxes payable or recoveries in Argentina. Additionally, a future income tax provision of $0.3 million and $3.2 million in the three months of 2009 and 2008, respectively, was recorded at the statutory rate to recognize the differences between the remaining tax pools and accounting carrying values. The implied effective tax rates of the Argentinean tax expense relative to the before tax net loss resulting from Argentinean net earnings, less general corporate deductions, is not indicative of the company's jurisdictional tax rates for the three months ended December 31, 2009. Taxes other than income taxes of $0.2 million and $0.4 million for the three months ended December 31, 2009 and 2008, respectively, represent taxes charged on all banking transactions in Argentina.
FOURTH QUARTER 2009 CASH FLOW
Reconciliation of net earnings to cash flow:
-------------------------------------------------------------------------
For the Three Months Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net earnings (loss) $(4,081) $ 2,662
Add (less) non-cash charges:
Depletion, depreciation and accretion 8,936 11,328
Fair value impairment - 3,505
Future income tax provision 268 3,166
Stock-based compensation 675 1,595
Amortization of deferred finance charges 212 222
Unrealized foreign exchange gain (143) (789)
-------------------------------------------------------------------------
Cash flow $ 5,867 $21,689
-------------------------------------------------------------------------
Per share, basic 0.05 0.39
Per share, diluted 0.05 0.39
-------------------------------------------------------------------------
Cash flow for the three months ended December 31, 2009 was $5.9 million or $0.05 per weighted average basic and diluted share, compared to $21.7 million or $0.39 per weighted average basic and diluted share for the same period in 2008. The 73 percent decrease in total cash flow during the fourth quarter of 2009, relative to the same period in 2008, primarily resulted from a reduction in sales volumes and average realized selling prices and increases in the current tax provision and realized foreign exchange losses. As previously discussed, cash flow during the three months ended December 31, 2009 was affected by the continuing effect of the attempted process to sell the Argentinean interest, as the company only made a minimal capital investment during prior periods when the sales process was underway. Also there were natural reservoir pressure declines and the waterflood program at PMN was less effective than anticipated. During the fourth quarter of 2009, the company embarked on a modest five well infill development program and invested capital to increase the water treatment capacity of its facilities, in an attempt to enhance production and cash flow. However, the impact of the infill well development program was not realized until late 2009. The company continues its tracers campaign, and reservoir studies to improve recovery through water redistribution or injection pattern corrections of the waterflood. Cash flow per share for the three months ended December 31, 2009 decreased relative to the same period for 2008 for the aforementioned reasons and from the impact of an increase in the number of shares outstanding.
OUTLOOK
What lies ahead? Clearly our testing program at La Pinta, our drilling program at Brillante and later drilling at San Angel, respectively, on our Sierra Nevada and adjacent Magdalena Licenses in Colombia, are of critical importance to Petrolifera. Renegotiating the terms of our bank credit facility is also important to give us more confidence and stability. Our ABCP holdings secure our long-term debt on a limited recourse basis, so that the related long-term indebtedness is covered by our holdings, regardless of their carrying value on our books. With our remaining debt at under two times 2009 cash flow, with renegotiations underway and with cash in the bank, we can advance our programs in a measured fashion, hopefully also benefiting from successful results at La Pinta and a modestly improved production profile in Argentina, such as we experienced in a modest way in the fourth quarter of 2009 as we push back declines.
FORWARD-LOOKING INFORMATION
This Annual Report, including the Letter to Shareholders, contains forward-looking information including, but not limited to the company's goals and growth strategy, estimates of reserves and future net revenues, anticipated remediation and further testing of the La Pinta 1X well in Colombia, drilling of the exploratory well, Brillante SE-1X on the Sierra Nevada License onshore Colombia, evaluation and implementation of remedial measures for the waterflood program in Argentina, future exploration and development opportunities in Argentina, Colombia and Peru, future drilling plans in Argentina, Colombia and Peru, and the anticipated timing associated therewith, anticipated results from the La Pinta 1X well and Brillante SE-1X well in Colombia, anticipated improvements in natural gas prices in Argentina, planned capital expenditures (including sources of funding and timing thereof), strategies for reducing the company's financial exposure to high cost exploration and drilling activities and eliminate residual commitments in Argentina including, planned farmout and/or joint ventures arrangements and reimbursement of sunk costs, the anticipated impact of the proposed conversion to IFRS on the company's consolidated financial statements, the company's plans to renegotiate its existing reserve-backed credit facility, planned payments to be made against the company's reserve-backed credit facility and the timing thereof and the company's ability to continue to comply with financial covenants imposed pursuant to its reserve-backed credit facility. Forward-looking information is not based on historical facts but rather on Management's expectations regarding the company's future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities and expectations with respect to general economic conditions. Such forward-looking information reflects Management's current beliefs and assumptions and is based on information currently available to Management. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information, including but not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production, delays or changes to plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of geological interpretations; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environment risks), the risk of commodity price and foreign exchange rate fluctuations, the uncertainty associated with negotiating with foreign governments and third parties located in foreign jurisdictions and the risk associated with international activity. There can be no assurance that remediation efforts and subsequent testing of the La Pinta 1X well drilled on the Sierra Nevada I License will yield commercial results. Readers are cautioned that instantaneous flow rates are not reflective of sustainable production rates and if the La Pinta 1X well is remediated, such that commercial production is established, the result and production rates may differ materially from recorded instantaneous flow rates reflected herein. The company's ability to complete its capital program and repay outstanding indebtedness is dependent upon completion of planned farmout arrangements and recovery of sunk costs, restoration of production in Argentina and stabilized or improved commodity prices. Petrolifera may have to bring participants into its acreage holdings and planned evaluation activities on less attractive terms than might otherwise have been the case due to the combination of tighter economic conditions and the influence of contractual commitments and deadlines on the terms of trade. There can be no assurance that the company will be successful in its efforts to secure planned farmouts and/or joint venture arrangements. Additionally, the company's discussions regarding the renegotiation of its reserve-backed credit facility are at a preliminary stage and there can be no assurance that these discussions will result in terms acceptable to Petrolifera or at all.
The reserves and future net revenue in this Interim Report represent estimates only. The reserves and future net revenue from the company's properties have been independently evaluated by GLJ with effective dates of December 31, 2009 and December 31, 2008, respectively. This evaluation includes a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of crude oil and natural gas, operating costs, well abandonment and salvage values, royalties and other government levies that may be imposed during the producing life of the reserves. These assumptions were based on price forecasts prepared by GLJ for use as at the dates of these reports and many of these assumptions are subject to change and are beyond the control of the company. Details of these assumptions are contained in the company's Annual Information Form for the year ended December 31, 2009. Actual production, sales and cash flows derived therefrom will vary from the evaluation and such variations could be material. The present value of estimated future net cash flows referred to herein should not be construed as the current market value of estimated crude oil, NGL's and natural gas reserves attributable to the company's properties. Actual future net revenue will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, curtailments or increases in consumption by purchasers and changes in governmental regulations or taxation. Additional risks and uncertainties associated with Petrolifera's future plans are described elsewhere in this Interim Report and in Petrolifera's Annual Information Form for the year ended December 31, 2009. Although the forward-looking information contained herein is based upon assumptions which Management believes to be reasonable, the company cannot assure investors that actual results will be consistent with this forward- looking information. This forward-looking information is made as of the date hereof and the company assumes no obligation to update or revise this information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward- looking information, prospective investors in the company's securities should not place undue reliance on this forward-looking information. Additionally, readers are reminded that cash flow from operations and EBITDA do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow from operations and EBITDA are reconciled to net earnings in the MD&A.
QUARTERLY RESULTS(4)
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
For the Three Months Ended Mar 31 June 30 Sept 30 Dec 31
-------------------------------------------------------------------------
FINANCIAL RESULTS
($000, EXCEPT PER SHARE
AMOUNTS) - UNAUDITED
-------------------------------------------------------------------------
Total revenue 27,167 33,622 32,126 37,411
-------------------------------------------------------------------------
Cash flow(1) 11,902 13,485 15,726 21,689
Basic, per share(1) 0.24 0.27 0.29 0.39
Diluted, per share(1) 0.23 0.26 0.28 0.39
Net earnings (loss) 1,738 3,590 3,564 2,662
Basic, per share 0.04 0.07 0.06 0.05
Diluted, per share(5) 0.03 0.07 0.06 0.05
Capital expenditures 31,056 29,110 21,046 35,539
Cash 11 41,039 14,865 30,701
Working capital (51,546) 13,295 8,148 19,956
Long-term investments(6) 31,967 29,947 28,488 25,428
Long-term bank debt - 43,800 45,576 77,150
Shareholders' equity 127,225 168,735 178,069 202,347
Total assets 231,278 292,882 279,174 355,658
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OPERATING RESULTS
-------------------------------------------------------------------------
Sales volumes:
Crude oil and natural gas
liquids - bbl/d 6,726 7,111 6,850 6,877
Natural gas - mcf/d 7,044 5,922 5,363 5,451
Equivalent - boe/d(2) 7,900 8,098 7,744 7,786
Pricing:
Crude oil and natural gas
liquids - $/bbl 41.99 49.90 48.93 56.76
Natural gas - $/mcf 2.20 2.38 2.58 2.88
Selected highlights -
$/boe(2):
Weighted average selling
price 37.72 45.56 45.07 52.15
Interest and other income 0.07 0.07 0.02 0.08
Royalties 4.71 6.33 6.80 7.66
Operating costs 8.24 8.60 9.00 10.28
Corporate netback(3) 24.84 30.69 29.29 34.29
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
(000, EXCEPT SHARE PRICE)
-------------------------------------------------------------------------
Shares outstanding at end of
period 50,353 54,798 54,948 54,948
Weighted average shares
outstanding for the period:
Basic 50,212 50,500 54,884 54,948
Diluted(5) 51,562 51,735 55,897 55,043
Volume traded during quarter 7,721 4,590 7,884 8,826
Common share price ($):
High 11.96 11.25 8.72 3.99
Low 6.61 8.25 3.16 0.75
Close (end of period) 9.10 8.69 3.37 1.05
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-------------------------------------------------------------------------
2009
-------------------------------------------------------------------------
For the Three Months Ended Mar 31 June 30 Sept 30 Dec 31
-------------------------------------------------------------------------
FINANCIAL RESULTS
($000, EXCEPT PER SHARE
AMOUNTS) - UNAUDITED
-------------------------------------------------------------------------
Total revenue 26,407 22,255 17,229 17,900
Cash flow(1) 10,804 10,233 5,503 5,867
Basic, per share(1) 0.20 0.19 0.07 0.05
Diluted, per share(1) 0.20 0.18 0.07 0.05
Net earnings (loss) 1,188 3,427 (11,359) (4,081)
Basic, per share 0.02 0.06 (0.14) (0.03)
Diluted, per share(5) 0.02 0.06 (0.14) (0.03)
Capital expenditures 25,612 20,477 13,389 12,145
Cash 30,994 14,803 55,953 35,732
Working capital 33,768 22,895 724 (2,508)
Long-term investments(6) 21,501 21,172 19,873 19,395
Long-term bank debt 104,649 102,104 27,464 27,464
Shareholders' equity 209,240 201,749 238,475 232,126
Total assets 371,054 353,424 368,288 349,065
-------------------------------------------------------------------------
OPERATING RESULTS
-------------------------------------------------------------------------
Sales volumes:
Crude oil and natural gas
liquids - bbl/d 5,245 4,652 3,653 3,833
Natural gas - mcf/d 6,500 6,232 4,252 4,056
Equivalent - boe/d(2) 6,328 5,691 4,362 4,509
Pricing:
Crude oil and natural gas
liquids - $/bbl 52.17 48.72 48.07 48.08
Natural gas - $/mcf 2.98 2.87 2.74 2.53
Selected highlights -
$/boe(2):
Weighted average selling
price 46.30 42.97 42.93 43.15
Interest and other income 0.06 - - -
Royalties 6.02 6.74 6.09 6.40
Operating costs 10.33 11.04 14.36 13.42
Corporate netback(3) 30.01 25.20 22.48 23.33
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
(000, EXCEPT SHARE PRICE)
-------------------------------------------------------------------------
Shares outstanding at end
of period 54,948 54,948 121,759 121,759
Weighted average shares
outstanding for the period:
Basic 54,948 94,948 82,418 121,759
Diluted(5) 55,195 55,600 82,539 121,777
Volume traded during quarter 10,053 13,268 55,032 35,921
Common share price ($):
High 1.60 3.47 2.85 1.09
Low 0.80 1.49 0.76 0.79
Close (end of period) 1.60 2.85 1.08 0.97
-------------------------------------------------------------------------
(1) Cash flow from operations before non-cash working capital changes
("cash flow") and cash flow per share do not have standardized
meanings prescribed by Canadian generally accepted accounting
principles ("GAAP") and therefore may not be comparable to similar
measures used by other companies. Cash flow includes all cash flow
from operating activities and is calculated before changes in non-
cash working capital. The most comparable measure calculated in
accordance with GAAP would be net earnings (loss). Cash flow is
reconciled with net earnings (loss) in this Management's Discussion &
Analysis ("MD&A"). Management uses these non-GAAP measurements for
its own performance measures and to provide its shareholders and
investors with a measurement of the company's efficiency and its
ability to fund a portion of its future growth expenditures.
(2) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 Mcf : 1 bbl. Boe may be misleading particularly if
used in isolation. This conversion is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
(3) Corporate netback is a non-GAAP measure used by management as a
measure of operating efficiency and profitability. It is calculated
as petroleum and natural gas revenue and other income less royalties
and operating costs. For a reconciliation of netbacks to net earnings
(loss) see "MD&A".
(4) Fluctuations in results over the previous quarters are due
principally to variations in oil and gas prices (including variations
in foreign exchange rates), production mix and production volumes. In
addition, the net loss for the quarter ended September 30, 2009 was
adversely affected by the inclusion of depletion and depreciation
from March 2, 2009 to June 30, 2009. Depletion and depreciation was
initially not recognized after March 2, 2009 due to the decision, at
that time, to sell the company's Argentinean interests. Attributing
to fluctuations in working capital is the classification of debt as
either current or long-term.
(5) As the company has net losses during the three months ended September
30 and December 31, 2009, the dilutive effect of stock options and
share purchase warrants became anti-dilutive causing the basic
weighted average common shares outstanding to be used as the
denominator in the dilutive per share net loss calculation.
(6) Includes carrying value of notes received for Asset Backed Commercial
Paper ("ABCP") with a face value of $34.6 million and $37.7 million
as at December 31, 2009 and 2008 respectively. Long-term debt in the
amount of $27.5 million as at December 31, 2009 is primarily secured
on a limited recourse basis by the underlying notes formerly known as
ABCP. Bank debt of $16.6 million as at December 31, 2008 was secured
by the ABCP.
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED BALANCE SHEETS
-------------------------------------------------------------------------
As at December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
ASSETS
Current
Cash $ 35,732 $ 30,701
Accounts receivable 20,871 37,331
Restricted cash (Note 3) 3,247 -
Income taxes receivable 4,636 4,736
Inventory (Note 4) 958 658
Prepaid expenses 464 535
Deferred financing costs (Note 6) 706 -
-------------------------------------------------------------------------
66,614 73,961
Long-term investments (Note 3) 19,395 25,428
Property and equipment (Note 5) 263,056 254,644
Deferred financing costs (Note 6) - 1,625
-------------------------------------------------------------------------
$ 349,065 $ 355,658
-------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities $ 15,850 $ 35,882
Income taxes payable 913 1,444
Bank debt (Note 6) 52,330 16,637
Due to a related company (Note 7) 29 42
-------------------------------------------------------------------------
69,122 54,005
Long-term bank debt (Note 6) 27,464 77,150
Asset retirement obligations (Note 8) 9,552 10,106
Future income taxes (Note 9) 10,801 12,050
-------------------------------------------------------------------------
116,939 153,311
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital and warrants (Note 10(a)) 148,264 92,408
Contributed surplus (Note 10(e)) 20,453 15,846
Accumulated other comprehensive income (loss) (3,753) 16,106
Retained earnings 67,162 77,987
-------------------------------------------------------------------------
232,126 202,347
-------------------------------------------------------------------------
$ 349,065 $ 355,658
-------------------------------------------------------------------------
Commitments and guarantees (Note 13)
Approved by the Board
Signed, Signed,
"C.J. Smith" "A.A. Gustajtis"
Director Director
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
$000 (except per share amounts)
-------------------------------------------------------------------------
REVENUE
Petroleum and natural gas sales $ 83,752 $ 130,148
Interest income 39 178
-------------------------------------------------------------------------
83,791 130,326
Royalties (12,017) (18,381)
-------------------------------------------------------------------------
71,774 111,945
-------------------------------------------------------------------------
EXPENSES
Operating 22,930 26,040
General and administrative 8,285 8,425
Finance charges (Note 6) 5,097 5,417
Taxes other than income taxes 1,874 2,185
Foreign exchange loss 115 180
Depletion, depreciation and accretion (Note 5) 33,546 28,984
Stock-based compensation (Note 10(e)) 4,674 5,847
Fair value impairment (Note 3) 2,104 8,882
-------------------------------------------------------------------------
78,625 85,960
-------------------------------------------------------------------------
Earnings (loss) before income taxes (6,851) 25,985
Current income tax provision (Note 9) 3,362 7,905
Future income tax provision (Note 9) 612 6,526
-------------------------------------------------------------------------
3,974 14,431
------------------------------------------------------------------------
NET EARNINGS (LOSS) (10,825) 11,554
RETAINED EARNINGS, BEGINNING OF YEAR 77,987 66,433
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $ 67,162 $ 77,987
-------------------------------------------------------------------------
NET EARNINGS (LOSS) PER SHARE (Note 12(a))
Basic $ (0.14) $ 0.22
Diluted $ (0.14) $ 0.22
-------------------------------------------------------------------------
-------------------------------------------------------------------------
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net earnings (loss) $(10,825) $11,554
Foreign currency translation adjustment (19,859) 26,780
-------------------------------------------------------------------------
Comprehensive income (loss) $(30,684) $38,334
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
Accumulated other comprehensive income (loss),
beginning of year $16,106 $(10,674)
Foreign currency translation adjustment (19,859) 26,780
-------------------------------------------------------------------------
Accumulated other comprehensive income (loss),
end of year $(3,753) $16,106
-------------------------------------------------------------------------
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Cash provided by (used in) the following activities:
OPERATING
Net earnings (loss) $(10,825) $11,554
Items not involving cash:
Depletion, depreciation and accretion (Note 5) 33,546 28,984
Stock-based compensation (Note 10(e)) 4,674 5,847
Fair value impairment (Note 3) 2,104 8,882
Unrealized foreign exchange loss 1,428 180
Amortization of deferred charges (Note 6) 868 829
Future income tax provision (Note 9) 612 6,526
-------------------------------------------------------------------------
Cash flow from operations before non-cash working
capital changes 32,407 62,802
Changes in non-cash working capital (Note 12(b)) 8,989 (12,482)
-------------------------------------------------------------------------
41,396 50,320
-------------------------------------------------------------------------
FINANCING
Proceeds of bank debt or long-term bank debt 19,896 69,507
Repayment of bank debt or long-term bank debt (21,938) (15,825)
Issue of common shares and common share purchase
warrants (Note 10(a)) 58,768 40,230
Share issue costs (Note 10(b)) (3,060) (2,217)
Deferred financing costs - (153)
-------------------------------------------------------------------------
53,666 91,542
-------------------------------------------------------------------------
INVESTING
Exploration and development of oil and gas
properties (71,623) (116,751)
Proceeds from farmout agreement (Note 5) 2,767 -
Receipt of interest on long-term investment (Note 3) 1,789 -
Investment in restricted cash (4,674) (324)
Proceeds from restricted cash 2,965 -
Changes in non-cash working capital (Note 12(b)) (14,158) (6,540)
-------------------------------------------------------------------------
(82,934) (123,615)
-------------------------------------------------------------------------
INCREASE IN CASH 12,128 18,247
Impact of foreign exchange on foreign currency
denominated cash balances (7,097) (598)
CASH, BEGINNING OF YEAR 30,701 13,052
-------------------------------------------------------------------------
CASH, END OF YEAR $35,732 $30,701
-------------------------------------------------------------------------
Supplementary cash flow information (Note 12(c))
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2009
PETROLIFERA PETROLEUM LIMITED
1. FINANCIAL STATEMENT PRESENTATION
The financial statements include the accounts of Petrolifera Petroleum Limited and its wholly-owned subsidiaries and foreign branches (collectively "Petrolifera" or the "company") and are presented in Canadian dollars and in accordance with Canadian generally accepted accounting principles. Petrolifera is engaged in petroleum and natural gas exploration, development and production activities in South America.
2. SIGNIFICANT ACCOUNTING POLICIES
Inventory
Crude oil inventory is measured at the lower of cost (on a weighted average cost basis) net realizable value.
Income taxes
The company follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributed to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs. Future tax assets are assessed by management at each balance sheet date and recognized when realization is more likely than not.
Petroleum and natural gas operations
The company follows the full cost method of accounting whereby all costs relating to the exploration for and development of crude oil and natural gas reserves are capitalized on a country by country cost centre basis.
Capitalized costs of petroleum and natural gas properties and related equipment within a cost centre are depleted and depreciated using the unit-of-production method based on estimated proved crude oil and natural gas reserves, as determined by independent consulting engineers. For the purpose of this calculation, production and reserves of natural gas are converted to equivalent units of crude oil based on relative energy content (6:1).
The company applies a "ceiling test" to the net book value of petroleum and natural gas properties for each cost centre to ensure that such carrying value does not exceed the estimated fair value of the properties. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves and the cost, less impairment, of unproved properties exceeds the carrying value. If the carrying value is assessed to not be recoverable, the calculation compares the carrying value to the sum of the discounted cash flows expected from the production of proved and probable reserves and the cost, less impairment, of unproved properties. Should the carrying value exceed this sum, an impairment loss is recognized. The cash flows are estimated using projected future product prices and costs and are discounted using the risk-free interest rate.
Costs of acquiring and evaluating unproved properties and major development projects are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves are attributable to the properties, the project becomes commercial, or impairment occurs. These costs are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.
Gains or losses on sales of properties are recognized only when crediting the proceeds to cost would result in a change of 20 percent or more in the depletion and depreciation rate.
Asset retirement obligations
The company provides for the costs of retirement obligations associated with long-lived assets, including the abandonment of oil and natural gas wells, related facilities, compressors and gas plants, removal of equipment from leased acreage and returning such land to its original condition. The estimated fair value of each asset retirement obligation is recorded in the period a well or related asset is drilled and evaluated, constructed or acquired. Fair value is estimated using the present value of the estimated future cash outflows to abandon the asset using the company's credit adjusted risk-free interest rate and expected inflation rate. The obligation is reviewed regularly by management based upon current regulations, costs, technologies and industry standards. The discounted obligation is initially capitalized as part of the carrying amount of the related oil and natural gas properties and a corresponding liability is recognized. The liability is accreted against income until it is settled or the property is sold and is included as a component of depletion and depreciation expense. The increase in oil and natural gas properties is depleted and depreciated on the same basis as the remainder of the oil and natural gas properties. Actual restoration expenditures are charged against the accumulated obligation as incurred.
Revenue recognition
Crude oil, natural gas liquids and natural gas sales are recognized as revenue at the time the respective commodities are delivered to purchasers at the point of sale.
Stock-based compensation
The company uses the fair value method for valuing stock option grants. Compensation costs attributed to share options granted are measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon exercise of the stock options, consideration paid by the option holder together with the amount previously recognized in contributed surplus is recorded as an increase to share capital.
Financial instruments
Financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods depends on the following financial instruments classification:
(a) Held-for-trading financial instruments are subsequently measured at
fair value with changes in those fair values charged immediately to
earnings.
(b) Other financial liabilities are subsequently measured at amortized
cost using the effective interest method.
The company does not have available for sale financial assets.
The company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange and interest rates in the normal course of operations. The company has not entered into any financial derivative contracts to reduce its exposure to fluctuations in market risks, does not enter into these contacts for speculative purposes and has not recorded any assets or liabilities as a result of embedded derivatives.
Deferred financing costs
Deferred financing costs include amounts incurred in relation to the company's revolving credit facility and are recognized against earnings over the life of the associated credit facility.
Measurement uncertainty
The timely preparation of the financial statements in conformity with Canadian generally accepted accounting principles requires that management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
Amounts recorded for depreciation, depletion and accretion, amounts used for ceiling test and impairment calculations and amounts used in the determination of the future tax liability are based, in part, on estimates of natural gas and crude oil reserves and future costs required to develop those reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs and the related future cash flows are subject to measurement uncertainty. Asset retirement obligations are based, in part, on estimates of future costs to settle the obligation, in addition to estimates of the useful lives of the underlying assets, the rate of inflation and the credit adjusted risk-free interest rate. When the future removal and site restoration costs cannot be reasonably determined, a contingent liability may exist. Contingent liabilities are accrued and eventually charged to earnings only when management is able to determine the amount and the likelihood of the future obligation. Stock-based compensation is based upon volatility, expected lives and risk-free interest rates. Actual results could differ materially from estimated amounts.
Per share amounts
Basic per share amounts are calculated using the weighted average number of common shares outstanding for the period. The company follows the treasury stock method to calculate diluted per share amounts. The treasury stock method assumes that any proceeds from the exercise of in-the-money share options, share purchase warrants and other dilutive instruments, in addition to stock-based compensation not yet recognized, would be used to purchase common shares at the average market price during the period.
Foreign currency translation
Colombia, Peru, Barbados and the US subsidiaries are considered to be "integrated foreign operations" for accounting purposes and, therefore, these foreign operations' financial statements are translated into Canadian dollars using the temporal method. Under the temporal method, the company translates foreign denominated monetary assets and liabilities at the exchange rate prevailing at year end; non-monetary assets, liabilities and related depletion and depreciation are translated at historic rates; revenues and expenses are translated at the average rate of exchange for the period; and any resulting foreign exchange gains or losses are included in earnings.
As a "self-sustaining foreign operation", the Argentinean financial statements are translated into Canadian dollars using the current rate method, whereby assets and liabilities are translated at the rate of exchange in effect at the balance sheet date; revenues and expenses are translated at the average monthly rates of exchange during the period; and gains or losses on translation are included as a foreign currency translation adjustment in the consolidated statements of comprehensive income and accumulated other comprehensive income (loss).
Impact of New Accounting Pronouncements and Standards
During August, 2009, the CICA issued amendments to Section 3855, Financial Instruments - Recognition and Measurement. The amendments included the definitions of a financial asset or financial liability held for trading and loans and receivables, provided guidance concerning the assessment of embedded derivatives upon reclassification of a financial asset out of the held-for-trading category and requires that Section 3025, Impaired Loans, be applied to assess whether held-to-maturity investments are impaired and to account for any such impairment. The amendment concerning the embedded derivates was adopted for any reclassification made on or after July 1, 2009 and did not have any impact on the company's financial statements. The remaining amendments to Section 3855 apply to the company's annual financial statements for the year ended December 31, 2009. The adoption of the amendments to Section 3855 did not have an impact on the company's financial statements.
During June, 2009, the CICA issued amendments to Section 3855, Financial Instruments - Recognition and Measurement, and Section 3862, Financial Instruments - Disclosures. The amendment to Section 3855 clarifies when an embedded prepayment option is separated from its host debt instrument for accounting purposes. The company prospectively adopted the CICA amendment to Section 3855 which did not have an impact on the company's consolidated financial statements. The amendments to Section 3862 enhance financial instrument disclosure requirements about liquidity risk and provide new disclosure requirements for fair value measurements. The amendments to Section 3862 apply to the company's annual consolidated financial statements for the year ended December 31, 2009. Upon adoption of the Section 3862 amendments, the company need not provide comparative information for the disclosures required by the amendments.
Effective January 1, 2009 the company adopted CICA Handbook section 3064, Goodwill and Intangible Assets, which replaced section 3062, Goodwill and Other Intangible Assets and section 3450, Research and Development Costs. Various changes have been made to other sections of the CICA Handbook for consistency purposes. Section 3064 establishes new standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous section 3062. As the company does not carry goodwill or intangible assets, as defined by section 3064, this new standard had no impact on the presentation and disclosures of the company.
In January 2009, the CICA issued EIC-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. The abstract provides guidance on how to take into account credit risk of an entity and counterparty when determining the fair value of financial assets and financial liabilities, including derivative instruments. This abstract is effective for the company's interim and annual Consolidated Financial Statements for periods ending on or after March 31, 2009 with retrospective application without reinstatement of prior periods. The application of this abstract did not have a material effect on the company's Consolidated Financial Statements.
In December 2008, the CICA issued Section 1582, Business Combinations, which will replace CICA Section 1581 of the same name. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The company is currently evaluating the impact of this changeover on its Consolidated Financial Statements.
In December 2008, the CICA issued Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests, which replaces existing Section 1600. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011, with earlier application permitted. Section 1602 currently does not impact the company as it has full controlling interest of all of its subsidiaries. The company is currently evaluating the impact of Section 1601 on its Consolidated Financial Statements.
International Financial Reporting Standards
In October 2009, the Canadian Accounting Standards Board issued a third and final International Financial Reporting Standards ("IFRS") Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to adopt IFRS in place of Canadian GAAP for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011. The company is currently evaluating the impact of adopting IFRS on its Consolidated Financial Statements.
3. FINANCIAL INSTRUMENTS
Summary
The company is exposed to various risks that arise from its business environment and the financial instruments it holds. The Audit Committee of the Board of Directors assists the Board in the discharge of its responsibility for overseeing the process that management has in place to identify, assess and manage financial risks. The following outlines the company's risk exposures, quantifies these risks, and explains how these risks and its capital structure are managed.
Capital management
The company's objective is to maintain a strong capital position in order to execute its business plans and maximize value to shareholders. The company defines its capital as shareholders' equity, bank debt and long-term bank debt. Changes to the relative weighting of the capital structure is driven by the company's business plans, changes in economic conditions and risks inherent in the global oil and gas industry. Although during the year ended December 31, 2009 there were changes in the relative weighting of capital, there have been no material changes to the company's processes and objectives related to capital management compared to prior periods. Methods to adjust the company's capital structure could include any or all of the following activities:
- Repurchase shares pursuant to a normal course issuer bid;
- Issue new shares through a public offering or private placement; such
as occurred in the third quarter of 2009 (Note 10(b));
- Raise fixed or floating rate debt; and
- Refinance existing debt facilities to change amounts or terms
(Note 6).
The company periodically reviews certain quantitative measures of its capital structure, in order to understand its position relative to industry peers. These measures include calculations such as return on equity, return on capital employed and the debt to equity ratio. The company does not set certain limits or ranges with respect to these quantitative measures.
The company is subject to external restrictions on its reserve-backed revolving credit facility. As at December 31, 2009, the facility had an overall limit of US$100.0 million, with an availability of US$50.0 million (2008 - US$70.0 million), based on producing crude oil and natural gas reserves as at December 31, 2008. This facility has a provision for a borrowing base adjustment every six months, with the next adjustment to be calculated based on information as at June 30, 2009, which is in progress. Outstanding bank debt and a portion of long-term debt cannot exceed two times the 12 month trailing EBITDA. EBITDA is defined by the credit facility agreement as net earnings (loss) prior to deduction of interest, income taxes, depletion, depreciation and accretion expense and other non-cash expenses and is reconciled to net loss as follows:
-------------------------------------------------------------------------
Year Ended December 31 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net loss $(10,825)
Add Interest, income taxes, depletion, depreciation
and accretion expense and other non-cash expenses:
Depletion, depreciation, and accretion 33,546
Finance Charges 5,097
Fair value impairment 2,104
Stock-based compensation 4,674
Income tax provision 3,974
Unrealized foreign exchange loss 1,428
-------------------------------------------------------------------------
EBITDA $39,998
-------------------------------------------------------------------------
As at December 31, 2009, outstanding draws on bank debt and a portion of long-term debt were $60.9 million and two times EBITDA was $80.0 million, for a ratio of 0.76:1.00, which is in compliance with the imposed limit.
Fair values of financial instruments
Financial instruments are recognized initially at fair value on the balance sheet, and include cash, accounts receivable, restricted cash, long-term investments, accounts payable and accrued liabilities, bank debt, due to a related company and long-term bank debt. The company has classified all of its financial instruments as held for trading, with the exception of the bank debt and long-term bank debt, which are classified as other liabilities. Held for trading instruments are measured at fair value, while other liabilities are measured at amortized cost.
The fair value measurement of each of the company's significant held for trading financial instruments is summarized in the following fair value hierarchy table that reflects the lowest level input of significance as used in the measurement as the basis of the assigned level. The three levels of the fair value hierarchy are as follows:
- Level 1 includes financial instruments with fair value measurements
based upon quoted prices (unadjusted) in active markets for identical
assets or liabilities.
- Level 2 includes financial instruments from inputs other than quoted
prices included in level 1 that are observable for the asset or
liability, either directly or indirectly.
- Level 3 includes fair value measurements from inputs for the
financial instruments that are not based on observable market date.
-------------------------------------------------------------------------
Fair Value Hierarchy
-------------------------------------------------------------------------
As at December 31, 2009 Total Level 1 Level 2 Level 3
-------------------------------------------------------------------------
Held for trading financial
instruments:
-------------------------------------------------------------------------
Cash $35,732 $35,732 $ - $ -
Accounts receivable 20,871 - 20,871 -
Restricted cash 3,247 - 3,247 -
Long-term investments 19,395 - 706 18,689
Accounts payable and
accrued liabilities (15,850) - (15,850) -
-------------------------------------------------------------------------
Total $63,395 $35,732 $8,974 $18,689
-------------------------------------------------------------------------
As no active market exists for the company's accounts receivable, restricted cash, collateral to support issued letters of credit as recognized as long-term investments and accounts payable and accrued liabilities, these financial instruments have been classified as Level 2. Long-term investments includes notes received in exchange for Asset Backed Commercial Paper ("ABCP") with a face value of $34.6 million (2008 - $37.7 million) and a carrying value of $18.7 million (2008 - $22.5 million) and collateral to support issued letters of credit of $0.7 million. The fair value of the collateral to support issued letters of credit, Level 2 financial asset approximates its carrying value as the collateral earns a floating market rate of interest. The fair and face values, and changes therein, for the Level 3 financial asset notes formerly known as ABCP is explained below.
In January, 2009, the Pan-Canadian Investors Committee for Third-Party Structured ABCP announced that the Superior Court of Ontario granted the Plan Implementation Order and that, accordingly, the plan for restructuring ABCP had been fully implemented. In exchange for the shorter-term ABCP, the company has now received the longer term notes with maturities that generally approximate those of the assets previously contained in the underlying conduits.
During 2009, the company was advised that the ineligible asset tracking note Class 2 ("IA - Class 2") had total pledged market collateral of $400.0 million. Several credit events have occurred in the IA - Class 2 portfolio resulting in losses greater than the pledged market collateral, thereby reducing the outstanding principal amount of this investment to nil (the company had an investment in IA - Class 2 notes with an original face value of $2.9 million and a carrying value as at December 31, 2008 of $0.8 million). Further, the ineligible asset tracking note Class 1 ("IA - Class 1") has total pledged market collateral of $500.0 million and a third party portfolio investment manager expects no principal returns given the likelihood of multiple credit events (the company has an investment in the IA - Class 1 notes with an original face value of $3.7 million and a carrying value as at December 31, 2008 of $1.0 million). On August 11, 2009 a third party credit rating agency downgraded the Class A-2 notes to "BBB" from "A" and maintained the rating under review with negative implications due to a series of credit events.
For 2009, the company received $1.7 million in payments, representing interest that had accrued on the previous holdings of ABCP during the period from mid-August 2007 until January 21, 2009, net of its pro-rata portion of expenses, including legal costs associated with the resolution agreed and approved under the Canada Business Corporations Act and the Companies Creditors' Arrangement Act. It is expected that substantially all of the restructuring costs and reserves were deducted from these payments and are not expected to have any further impact on future payments to the company, although there may be other deductions related to alternative banking, legal or administrative fees. For 2009, the company received an additional $0.1 million of interest and return of capital payments that had accrued on the investments formerly known as ABCP during the period from January 21, 2009 until December 31, 2009. For 2009, the company has recognized a $2.1 million impairment in the carrying value of its longer-term notes received in exchange for ABCP primarily due to the loss in its IA - Class 1 and IA - Class 2 notes resulting from a series of third party credit defaults or expected defaults, respectively, and a lowered rating from a third party credit rating agency on the company's A-2 class of investment notes. During the year ended December 31, 2008, the company recognized an impairment in fair value of $8.9 million on its investment in ABCP.
Although there have been some isolated third party transactions during 2009, as no active market quotations has developed for the longer term notes, management has estimated the fair value of the company's investment in the longer term notes at December 31, 2009, based on a probabilistic recovery of principal and interest, after taking into account all available information. Under this valuation method, several different outcomes of the recovery of the principal and interest are estimated, considering the information available as at December 31, 2009. A weighted average recovery is then calculated. This weighted average recovery is used to determine the discounted cash flows that are expected from these investments. The discount rate used to discount the expected cash flows from the longer term notes was an approximation of the risk-free rate for the expected life of the longer term notes to be received. As the rate used for discounting was an approximation of the risk-free rate, all other risks have been incorporated in the estimated probability-adjusted expected outcomes. This methodology applied all risking information into the various scenarios and discounted the fully-risked cash flow stream only for the time value of money. The recovery factors used were as follows:
-------------------------------------------------------------------------
Face Risk- Risk-
Value adjusted adjusted Capital Interest
Class of Capital Interest Weighted Weighted Risk-free
of Notes Recovery Recovery Average Average Term Discount
Note ($000s) Range Range Recovery Recovery (years) Rate
-------------------------------------------------------------------------
A-1 13,978 0 - 80% 0 - 60% 75% 54% 3 - 7 3%
A-2 13,543 0 - 70% 0 - 30% 64% 27% 7 3%
B 2,459 0 - 30% 0% 27% 0% 7 3%
C 928 0% 0% 0% 0% 7 3%
IA-1 3,674 0% 0% 0% 0% 7 3%
-------------------------------------------------------------------------
Total 34,582
-------------------------------------------------------------------------
Based on the above approach the fair value of the investment in the longer term notes was $18.7 million as at December 31, 2009 compared to $22.5 million as at December 31, 2008 as reconciled in the following table:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
ABCP, beginning of year $22,582 $31,464
Fair value impairment (2,104) (8,882)
Interest received previously included in fair value
of investment (1,789) -
-------------------------------------------------------------------------
Notes formerly known as ABCP, end of 2009
or ABCP, end of 2008 $18,689 $22,582
-------------------------------------------------------------------------
Since 2007, the total impairment recognized is approximately 46 percent of the original cost of the investment on the longer term notes, including impairments recognized in prior years on the ABCP, which is an increase compared to the 40 percent of impairment relative to the original cost of the ABCP recognized at December 31, 2008.
The theoretical fair value of the company's longer-term notes could range from $14.0 million to $25.0 million using the valuation methodology described above with reasonably possible alternative assumptions. The outcome of the actual timing and amount ultimately recoverable from these notes may differ materially from this estimate, which would impact the company's earnings.
Credit risk
The company is exposed to credit risk in relation to its cash, accounts receivable, restricted cash and long-term investments:
Cash, restricted cash and the collateral to support issued letters-of-credit as recognized as a portion of long-term investments are held with highly rated international banks and therefore the company considers these assets to have negligible credit risk.
The company's accounts receivable are primarily with multinational purchasers, oil and gas marketers and local government agencies. The company conducts a small portion of its business through joint ventures, so its overall exposure to credit risk from joint venture partners is considered to be low. The company's production base is entirely located in Argentina and is heavily weighted to crude oil. The company has a concentration of credit risk as it sold US$63.9 million of crude oil production to one multinational purchaser and US$4.7 million in natural gas production to a reputable local gas marketing company during 2009. Receivables with local government agencies mainly pertain to excise taxes paid on certain expenditures. The company has not experienced any collection problems with its counterparties and does not currently have any overdue amounts.
Refer to the fair values of financial instruments contained herein for further discussion regarding the credit risk of the longer term notes formerly known as ABCP as recognized as a portion of long-term investments.
The carrying amounts of cash, accounts receivable, restricted cash and long-term investments represent the company's maximum credit exposure. The company does not have an allowance for doubtful accounts and did not write off any receivables during 2009.
Liquidity risk
The company manages the risk of not meeting its financial obligations through management of its capital structure, annual budgeting of its revenues, expenditures and cash flows, cash flow forecasting and maintaining an unused credit facility where practicable.
Accounts payable, as disclosed on the Consolidated Balance Sheet, fall due within the next year and are anticipated to be funded through the company's cash and collections of accounts receivable. The revolving reserve-backed credit facility has a current available limit of US$50.0 million, of which all is drawn at December 31, 2009. Changes in the availability of the reserve-backed credit facility are anticipated to occur, from time-to-time, through significant reserve additions, disposals or revisions. This facility expires on September 5, 2010. The company holds a $28.2 million ABCP line-of-credit (of which $27.5 million is drawn at December 31, 2009) that is primarily secured by the longer term notes received in exchange for the ABCP.
Market risk
Changes in commodity prices, interest rates and foreign currency exchange rates can expose the company to fluctuations in its net earnings (loss) and in the fair value of its financial assets and liabilities.
Commodity price risk
Price fluctuations for crude oil, natural gas liquids and natural gas are a risk to the company over which the company has little influence. Due to pricing controls present in Argentina and a domestic crude oil sales agreement with a multinational purchaser, crude oil selling prices reflect both current market conditions in Argentina and the movement of crude oil prices in international markets. Natural gas prices are impacted by the Argentine government and local demand with historic prices at low levels compared to world prices.
Interest rate risk
Floating rate debt exposes the company to fluctuations in cash flows and net earnings (loss) due to changes in market interest rates. Based on the existing debt balance, a one percent increase (decrease) in the underlying market interest rates would have increased (decreased) the net loss by approximately $0.8 million on an annual basis.
Foreign currency exchange rate risk
Substantially all of the company's operations are conducted in foreign jurisdictions, so the company is exposed to foreign currency exchange rate risk on most of its activities as reported in Canadian Dollars (CAD). Oil and natural gas sales contracts are denominated in US Dollars (USD) and settled in Argentine Pesos (ARS). Operating and capital expenditures are incurred in USD, ARS and Colombian Pesos (COP) and to a lesser extent in Peruvian Nuevos Soles (PEN). The revolving reserve-backed credit facility is denominated in USD, which partially limits the company's exposure in terms of cash outflows (interest expense) being inversely correlated to cash inflows (oil and gas revenues). The table below details the company's financial instruments exposure to foreign currencies:
-------------------------------------------------------------------------
Per CAD USD ARS PEN COP
Balance --------------------------------------------
($000) Sheet CAD $ equivalent amounts
-------------------------------------------------------------------------
Cash $35,732 $20,619 $5,410 $3,526 $22 $6,155
Accounts receivable 20,871 88 7,911 7,145 1,205 4,522
Restricted cash 3,247 - 3,247 - - -
Long-term
investments 19,395 18,689 706 - - -
Accounts payable
and accrued
liabilities (15,850) (643) (3,630) (7,798) (12) (3,767)
Bank debt (52,330) - (52,330) - - -
Long-term bank debt (27,464) (27,464) - - - -
-------------------------------------------------------------------------
Net financial assets
(liabilities) $(16,399) $11,289 $(38,686) $2,873 $1,215 $6,910
-------------------------------------------------------------------------
The company estimates a 20 percent change in the Canadian Dollar against the above listed foreign currencies could be reasonably possible over a twelve month period. A 20 percent strengthening in the CAD would result in a change to earnings (loss) before taxes and other comprehensive income (loss) as follows (an equal but opposite impact to earnings (loss) before taxes and other comprehensive income (loss) would result if the CAD weakened by 20 percent):
-------------------------------------------------------------------------
USD ARS PEN COP
----------------------------------
($000) CAD $ equivalent amounts
-------------------------------------------------------------------------
Decrease in
earnings before
taxes $(277) $ - $(203) $(1,152)
Increase in other
comprehensive
income $6,246 $ - $ - $ -
-------------------------------------------------------------------------
4. INVENTORY
-------------------------------------------------------------------------
As at December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Crude oil $ 958 $ 658
-------------------------------------------------------------------------
The company maintains inventory as a consequence of the sales process for crude oil which has been produced and not delivered to customers for periods of up to several days, during which time it must be held in storage at the company's facilities and in transportation pipelines. Crude oil inventory was measured at December 31, 2009 and 2008 using a weighted average cost basis and is carried at the lower of cost and net realizable value.
5. PROPERTY AND EQUIPMENT
-------------------------------------------------------------------------
Accu-
mulated
Depletion Net
and De- Book
($000) Cost preciation Value
-------------------------------------------------------------------------
As at December 31, 2009
-------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $345,119 $(83,294) $261,825
Furniture, equipment and leaseholds 2,149 (918) 1,231
-------------------------------------------------------------------------
$347,268 $(84,212) $263,056
-------------------------------------------------------------------------
As at December 31, 2008
-------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $315,349 $(62,143) $253,206
Furniture, equipment and leaseholds 2,186 (748) 1,438
-------------------------------------------------------------------------
$317,535 $(62,891) $254,644
-------------------------------------------------------------------------
Included in property and equipment are estimated future asset retirement costs of $8.5 million (2008 - $9.5 million). In 2009, the company capitalized $4.7 million (2008 - $5.1 million) of general and administrative expenses related to exploration and development activities.
During 2009, the company received cash proceeds of $2.8 million and a commitment to spend an additional US$1.9 million (Note 13) on the company's Turpial, Colombian unproven property from a third party in consideration for a 50 percent working interest in the aforementioned property. A portion of the $2.8 million in cash proceeds was recognized as a recovery of unproven properties cost from the company's Colombian full cost pool.
Depletion, depreciation and accretion expense includes a charge of $0.6 million (2008 - $0.4 million) to accrete the company's estimated asset retirement obligations (Note 8).
Capital costs of $14.0 million (2008 - $14.5 million) incurred for unevaluated properties and other assets in Argentina and $56.1 million (2008 - $48.6 million) and $47.5 million (2008 - $13.8 million) for major development projects and other assets in a pre-production stage located in Peru and Colombia, respectively, have been excluded from the calculation of depletion and depreciation expense. No proved reserves have been assigned to these projects. These costs have been separately evaluated by management for impairment. No impairment has been recorded at December 31, 2009 or 2008.
Based on the ceiling test as at December 31, 2009, which excludes the above costs incurred for unevaluated properties, no impairment has been recorded at December 31, 2009 or 2008.
Petrolifera's petroleum and natural gas reserves, as used in the ceiling test, were evaluated by independent reservoir engineers as at December 31, 2009 in a report dated March 5, 2010. The evaluation was conducted in accordance with Canadian Securities Administrators' National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook, using the following price assumptions:
-------------------------------------------------------------------------
Crude Oil Price Natural Gas Price
($USD/bbl)
-------------------------------------------------------------------------
2010 $49.88 $2.66
2011 51.00 2.72
2012 52.02 2.77
2013 53.06 2.83
2014 $54.12 $2.88
-------------------------------------------------------------------------
+ approximately 2% + approximately 2%
-------------------------------------------------------------------------
6. BANK DEBT AND LONG-TERM BANK DEBT
In 2007 the company entered into a US$100.0 million reserve-backed revolving credit facility with availability as at December 31, 2009 of US$50.0 million. During 2009, the availability of the reserve-backed facility was reduced from US$70.0 million based on crude oil and natural gas reserves as at December 31, 2008. This facility expires on September 5, 2010, bears interest at LIBOR plus a margin, is secured by the pledge of the shares of Petrolifera's subsidiaries and has a provision for a borrowing base adjustment every six months, with the next adjustment to be calculated based on information as at June 30, 2009, which is in progress.
As at December 31, 2009 the outstanding reserve-backed facility was $52.3 million (US$50.0 million), classified as bank debt. As at December 31, 2008 the outstanding reserve-backed facility was $77.2 million (US$63.0 million), classified as long-term debt. Deferred financing costs of $0.7 million related to this facility are being amortized up to September 5, 2010, the expiration of the facility, and, accordingly, is classified as a current asset (2008 - $1.6 million was being amortized over the remaining term of this facility and, accordingly, was classified as a long-term asset). For 2009, the company recognized amortization of deferred charges of $0.9 million (2008 - $0.8 million).
During 2009, the company negotiated with a Canadian chartered bank an expansion of a line-of-credit ("ABCP line-of-credit") to a maximum of $28.2 million. The ABCP line-of-credit was primarily secured by the longer term notes exchanged for the ABCP. Any borrowings from the expanded ABCP line-of-credit are categorized as long-term, as the facility's initial maturity is April, 2011 and the company can make up to five extension requests with each extension representing an additional one-year period. The ABCP line-of-credit bears interest at a floating rate. As at December 31, 2008, the prevailing terms of the line-of-credit was a maximum draw of $18.0 million, bore interest at a floating rate and was due on demand, resulting in the company then categorizing its borrowings as a current liability. As at December 31, 2009 the outstanding ABCP line-of-credit facility was $27.5 million whereas as at December 31, 2008, the outstanding amount of the facility was $16.6 million.
Interest expense on the facilities for 2009 was $4.2 million (2008 - $4.3 million), as disclosed on the Consolidated Statement of Operations and Retained Earnings as finance charges which also includes the amortization of deferred finance charges. The effective interest rate on the company's facilities was 4.2 percent for 2009 (2008 - 8.8 percent). The unused credit on the ABCP line-of-credit facility was $0.7 million as at December 31, 2009 (2008 - $1.4 million).
7. RELATED PARTY TRANSACTIONS
Connacher Oil and Gas Limited ("Connacher") purchased 13,556,000 units for gross proceeds to the company of $11.9 million pursuant to a public equity financing from treasury, which closed on August 28, 2009, that resulted in the issuance of a total of 65,343,000 units, for gross proceeds of approximately $57.5 million (See Note 10(b)).
Directors and officers of the company purchased 1,137,500 units for gross proceeds of $1.0 million pursuant to the private placement (see Note 10(c)) which closed on September 15, 2009. The issuance of units to the directors and officers of the company pursuant to the private placement was completed on the same terms as those units offered pursuant to the public equity financing and over-allotment option, which respectively closed on August 28 and September 4, 2009.
Under the terms of an Administrative Agreement with Connacher, which has been in effect since January 1, 2008, Connacher provided certain administrative services at the direction of the company. The fee for this services was $0.2 million for 2009 (2008 - $0.2 million). From time to time Connacher also paid bills on behalf of the company, for which it is reimbursed. Connacher also provided certain support and services to the company in its pursuit of exploration opportunities in Colombia, for which it was indemnified and reimbursed, without further economic interest in the secured opportunities. Connacher is a significant shareholder of the company with a 22 percent equity interest as at December 31, 2009 and the Executive Chairman of the company is the President and Chief Executive Officer of Connacher.
During 2009 the company paid professional legal fees and common share issue costs for 2009 of $0.5 million (2008 - $0.9 million), to a law firm in which an officer of the company is a partner. Transactions with the related party occurred within the normal course of business and have been measured at the exchange amount on normal business terms. The exchange amount is the amount of consideration established and agreed with the related party.
8. ASSET RETIREMENT OBLIGATIONS
At December 31, 2009, the estimated total undiscounted amount required to settle the asset retirement obligations was $17.3 million (December 31, 2008 - $19.2 million). These obligations are expected to be settled over the useful lives of the underlying assets, which currently extend up to 18 years into the future. This amount has been discounted using a credit-adjusted risk-free interest rate of six percent and an annual inflation rate of two percent. Changes to asset retirement obligations were as follows:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Asset retirement obligations, beginning of year $10,106 $5,639
Liabilities incurred 406 2,102
Changes to estimate - 384
Cumulative translation adjustment (1,529) 1,587
Accretion expense 569 394
-------------------------------------------------------------------------
Asset retirement obligations, end of year $9,552 $10,106
-------------------------------------------------------------------------
9. INCOME TAXES
The following table reconciles income taxes calculated at the Canadian statutory rate with recorded income taxes:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Earnings (loss) before income taxes $(6,851) $25,985
Statutory income tax rate 29.00% 29.50%
Expected income tax (recovery) $(1,987) $7,666
Future tax rate changes 3,355 376
Current tax adjustments from prior periods 1,123 (739)
Future tax recoveries from prior periods (682) (461)
Valuation allowance increase 1,635 539
Foreign tax rate changes 73 4,473
Stock compensation 1,355 1,725
Other (898) 852
-------------------------------------------------------------------------
Tax expense $3,974 $14,431
-------------------------------------------------------------------------
Future income taxes relate to the following temporary differences:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Property and equipment $16,758 $4,513
Net operating loss carryforwards (17,708) (5,141)
Future foreign tax credit 10,080 11,014
Asset retirement obligation (140) (22)
Valuation allowance 2,291 637
Other (480) 1,049
-------------------------------------------------------------------------
Future income tax liability $10,801 $12,050
-------------------------------------------------------------------------
10. SHARE CAPITAL, WARRANTS AND CONTRIBUTED SURPLUS
(a) Authorized:
The authorized capital is comprised of an unlimited number of common shares and 33,240,250 warrants, respectively.
Issued common shares:
-------------------------------------------------------------------------
Number of
Common Amount
Year Ended December 31, 2009 Shares ($000)
-------------------------------------------------------------------------
Common shares, beginning of year 54,948,010 $92,408
Issuance of common shares through public
offering (b) 65,343,000 52,928
Issuance of common shares through private
placement (c) 1,137,500 921
Issued common shares upon exercise of options (f) 330,000 265
Assigned value of options exercised (e) 67
Issue costs net of tax-effect (b) (2,979)
-------------------------------------------------------------------------
Common shares, end of year 121,758,510 $143,610
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number of
Common Amount
Year Ended December 31, 2008 Shares ($000)
-------------------------------------------------------------------------
Common shares, beginning of year 50,126,510 $54,356
Issuance of common shares through public
offering (b) 4,445,000 40,005
Issued common shares upon exercise of options (f) 226,500 165
Issued common shares upon exercise of warrants (d) 150,000 60
Assigned value of options exercised (e) 39
Issue costs (b) (2,217)
-------------------------------------------------------------------------
Common shares, end of year 54,948,010 $92,408
-------------------------------------------------------------------------
Issued warrants:
-------------------------------------------------------------------------
Number of Amount
Year Ended December 31, 2009 Warrants ($000)
-------------------------------------------------------------------------
Warrants, beginning of year - $ -
Issuance of warrants through public
offering (b)(d) 32,671,500 4,574
Issuance of warrants through private
placement (c)(d) 568,750 80
-------------------------------------------------------------------------
Warrants, end of year 33,240,250 $4,654
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number of Amount
Year Ended December 31, 2008 Warrants ($000)
-------------------------------------------------------------------------
Warrants, beginning of year 160,000 $ -
Exercise of warrants (d) (150,000) -
Expired warrants (10,000) -
-------------------------------------------------------------------------
Warrants, end of year - $ -
-------------------------------------------------------------------------
Share capital and warrants:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
Share capital and warrants $148,264 $92,408
-------------------------------------------------------------------------
(b) Equity Financing:
2009
During August 2009, the company entered into an underwriting agreement with a syndicate of underwriters to issue 56,820,000 units (each, a "Unit") at a price of $0.88 per Unit, with each Unit consisting of one common share in the capital of the company (each, a "Common Share") and one-half of one Common Share purchase warrant of the company (each whole Common Share purchase warrant, a "Warrant"), for gross proceeds of approximately $50.0 million. The price of $0.88 per Unit is comprised of $0.81 per Common Share and $0.07 per one-half Warrant (Note 10(d)). The underwriters were granted an over-allotment option (the "Over-Allotment Option"), which included the right to purchase up to an additional 15 percent of the Units, exercisable in whole or in part up to 30 days following closing on August 28, 2009. The Over-Allotment Option was exercised in whole by the underwriters, closed on September 4, 2009 and resulted in a total issuance of 65,343,000 Units, raising gross proceeds of approximately $57.5 million. Issue costs of $3.1 million were incurred with respect to this equity financing less a $0.1 million tax effect.
2008
Effective June 11, 2008, the company entered into an underwriting agreement with a syndicate of underwriters to issue on a "bought deal" basis 4,445,000 common shares ("Common Shares") at $9.00 per Common Share, for gross proceeds of approximately $40.0 million. The underwriters had an over-allotment option to purchase up to an additional 666,750 Common Shares on the same terms and conditions, exercisable in whole or in part up to 30 days following closing. This financing was closed on June 27, 2008 and the over-allotment option was not exercised subsequent to the closing. Issue costs of $2.2 million were incurred with respect to this equity financing.
(c) Private Placement:
On September 15, 2009, the company closed a non-brokered private placement with certain directors and officers of the company to issue 1,137,500 Units at a price of $0.88 per Unit, with each Unit consisting of a Common Share and one-half of one Warrant, for gross proceeds of approximately $1.0 million. The Units offered pursuant to the private placement were issued on the same terms as those offered pursuant to the company's equity financing, which closed on August 28, 2009.
(d) Warrants:
Each Warrant issued pursuant to the 2009 equity financing and private placement, entitles the holder thereof to purchase one Common Share (each a "Warrant Share") at an exercise price of $1.20 per Warrant Share until August 28, 2011. In the event that the 20-day volume weighted average price of the Common Shares on the Toronto Stock Exchange exceeds $2.50, the company may, within five business days after such an event, provide notice to the holders of the Warrants ("Warrantholders") of early expiry and thereafter the Warrants can either be exercised or they will expire on the date which is 30 days after the date of the notice to the Warrantholders.
The fair value of each Warrant issued for 2009 was estimated on the date of issuance using the Black-Scholes option-pricing model with assumptions for Warrants as follows:
-------------------------------------------------------------------------
Risk-free
Dividend interest Expected Expected
yield rate life volatility
-------------------------------------------------------------------------
2009 -% 1.5% 2 years 90%
-------------------------------------------------------------------------
The weighted average fair value of all Warrants issued in 2009 was $0.14 per Warrant.
For the year ended December 31, 2008, no Common Share purchase warrants ("warrants") were issued and 150,000 warrants were exercised for proceeds of $0.1 million.
(e) Contributed Surplus:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
Contributed surplus, beginning of year $15,846 $10,188
Stock-based compensation (f) 4,674 5,847
Cash consideration on cancelled options (f) - (150)
Assigned value of options exercised (a) (67) (39)
-------------------------------------------------------------------------
Contributed surplus, end of year $20,453 $15,846
-------------------------------------------------------------------------
(f) Stock Options:
As at December 31, 2009 and 2008, the company had outstanding stock options to acquire common shares, as follows:
-------------------------------------------------------------------------
As at December 31 2009 2008
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding, beginning
of year 4,576,327 $ 6.85 3,228.867 $ 8.71
Granted 5,490,900 1.29 2,162,000 4.92
Exercised (330,000) (0.80) (226,500) (0.73)
Forfeited or cancelled (2,054,160) (12.59) (588,040) (12.89)
-------------------------------------------------------------------------
Outstanding, end of year 7,683,067 1.60 4,576,327 6.85
Exercisable, end of year 3,349,135 $ 1.70 2,557,914 $ 7.69
-------------------------------------------------------------------------
Options granted under the plan are generally fully exercisable after two or three years and expire five years after the date granted. The table below summarizes unexercised stock options and the weighted average recurring contractual life, in years, by ranges of exercise prices as at December 31, 2009 and 2008:
-------------------------------------------------------------------------
As at December 31 2009 2008
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Remaining Remaining
Number Out- Contractual Number Out- Contractual
standing Life (yrs) standing Life (yrs)
-------------------------------------------------------------------------
$0.50 - $1.00 4,961,067 4.3 787,667 1.4
$1.09 - $1.75 326,500 1.0 418,000 1.9
$2.00 - $2.64 1,991,000 4.1 1,107,000 4.9
$3.37 - $19.20 404,500 2.9 2,263,660 3.3
-------------------------------------------------------------------------
Total 7,683,067 4.1 4,576,327 3.2
-------------------------------------------------------------------------
During 2009, a non-cash expense of $3.6 million (2008 - $5.1 million) was recorded as stock-based compensation, reflecting the amortization of the fair value of stock options over the vesting period.
During 2009 certain employees, officers and non-managerial directors of the company voluntarily surrendered 1,786,660 options with a weighted average exercise price of $13.79 per option. Any unvested options that were voluntarily surrendered were deemed to have become vested, resulting in the recognition of an additional non-cash stock-based compensation expense of $1.1 million.
During 2008, the company paid $0.2 million to certain non-officer employees, resulting in the cancellation of 350,000 "out of the money" options. As a result of these optionees surrendering certain of their options, any unvested options were deemed to have become vested resulting in the recognition of an additional non-cash stock-based compensation expense of $0.7 million.
The fair value of each option granted for 2009 and 2008 is estimated on the date of grant using the Black-Scholes option-pricing model with assumptions for grants as follows:
-------------------------------------------------------------------------
Risk-free
Dividend interest Expected Expected
yield rate life volatility
-------------------------------------------------------------------------
2009 -% 2.0%-2.7% 4 years 81%-90%
-------------------------------------------------------------------------
2008 -% 2.5%-3.4% 4 years 73%-94%
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of all options granted for 2009 was $0.83 per option (2008 - $2.85 per option).
11. SEGMENTED INFORMATION
The company has corporate offices in Canada, the US and Barbados (combined to comprise the "Corporate" segment), petroleum and natural gas operations in Argentina and exploration activities in Peru and Colombia. Financial information pertaining to these segments is presented below.
-------------------------------------------------------------------------
Corporate Argentina Peru Colombia Total
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Year Ended
December 30,
2009
-------------------------------------------------------------------------
Revenue,
gross $9 $83,760 $22 $ - $83,791
Net earnings
(loss) (12,574) 1,816 (18) (49) (10,825)
Property and
equipment 311 158,756 56,190 47,799 263,056
Capital ex-
penditures 43 27,082 7,462 37,036 71,623
Total assets $44,180 $183,986 $60,327 $60,572 $349,065
-------------------------------------------------------------------------
Year Ended
December 31,
2008
-------------------------------------------------------------------------
Revenue,
gross $70 $130,256 $ - $ - $130,326
Net earnings
(loss) (17,401) 28,998 (36) (7) 11,554
Property and
equipment 267 191,815 48,599 13,963 254,644
Capital ex-
penditures 43 70,792 33,306 12,610 116,751
Total assets $48,104 $235,839 $55,449 $16,266 $355,658
-------------------------------------------------------------------------
Crude oil sales totaling US$63.9 million were made to one large international oil company and natural gas sales totaling US$4.7 million were made to one reputable local gas marketing company during 2009 and US$115.7 million in crude oil sales were made to another large international oil company and natural gas sales totaling US$5.1 million were made to the same gas marketing company during 2008.
12. SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the calculation of basic and diluted common shares:
-------------------------------------------------------------------------
Years Ended December 31 2009 2008
-------------------------------------------------------------------------
Weighted average common shares outstanding 78,711,781 52,648,485
Dilutive effect of stock options and share
purchase warrants 264,022 924,118
-------------------------------------------------------------------------
Weighted average common shares outstanding
- diluted 78,975,803 53,572,603
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As the company has net losses for 2009, the dilutive effect of stock options and share purchase warrants became anti-dilutive causing 78,711,781 weighted average dilutive common shares outstanding to be used as the denominator in the diluted per share net loss calculation for 2009.
(b) Net change in non-cash working capital
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($000) 2009 2008
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Accounts receivable $14,127 $(3,664)
Income taxes receivable (668) (4,592)
Prepaid expenses 52 10
Inventory (129) 527
Accounts payable and accrued liabilities (18,194) (6,138)
Income taxes payable (344) (5,207)
Due to a related company (13) 42
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$(5,169) $(19,022)
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Operating $8,989 $(12,482)
Investing (14,158) (6,540)
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$(5,169) $(19,022)
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(c) Supplementary cash flow information
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($000) 2009 2008
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Interest paid $3,950 $4,261
Income taxes paid $6,107 $12,434
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13. COMMITMENTS AND GUARANTEES
Work commitments
Each of the Peruvian licenses have negotiated work programs for a period of seven years and the company has the right to withdraw from the licenses at the end of each work program. In 2005 Petrolifera acquired Blocks 106 and 107, two significant oil and gas exploration licenses in Peru. In April, 2009 the company was awarded a third license with Block 133, a block that is contiguous with Block 107.
On Block 106, the company has recently completed the second phase work program and made an application with the Peruvian authority for recognition of completion of the third phase of the work program. The fourth phase work program of Block 106 has a commitment to invest a minimum of US$1.6 million in at least 60 km of 2D seismic prior to April, 2011. On Block 107, the company has completed the first two phases of work programs and is in the process of applying for completion of the third phase. Upon completion of an Environmental Impact Assessment that will detail proposed drilling sites, the company will be able to proceed with the fourth phase of the work program on Block 107 with a commitment to invest a minimum of US$10.0 million through the drilling of one well prior to May, 2014. The company is in the first phase of its Block 133 license which requires a minimum investment of US$0.3 million through the acquisition of 20 km of seismic, field geology and satellite mapping prior to February, 2011.
In 2007, the company was granted three concessions comprised of one license and two technical evaluation agreements ("TEA") in Colombia. Petrolifera has converted the Turpial and Sierra Nevada II TEAs into exploration licenses with the latter renamed Magdalena. Each of the Colombian licenses have annual negotiated work programs for a period of six years and the company has the right to withdraw from the licenses at the end of each work program. Petrolifera has drilled the La Pinta 1X well on the Sierra Nevada License, which fulfilled the first phase work program on this License. The second phase work program of the Sierra Nevada License requires the drilling of one exploratory well and 70 km(2) of 3D seismic acquisition and processing prior to June, 2010. Drilling of the Brillante SE-1X exploratory well is underway. On the company's Turpial License, the company has completed its first year's program comprised of 3D seismic acquisition, processing and interpretation. The second phase of the work program for the Turpial License will be mostly financed by the company's equal working interest joint venturer and consists of a minimum acquisition and interpretation of 114 km(2) of 2D seismic prior to September, 2010. The company is in the first phase of its Magdalena License which requires an exploration well be completed prior to December, 2010.
In Argentina, the company has net work commitments of US$0.6 million related to the Puesto Guevara Concession that are to be completed during 2010. During 2009, the company completed its licensed work commitments related to the Gobernador Ayala II Block. All of the Argentinean work commitments related to the Vaca Mahuida Block, estimated at a minimum of US$2.9 million, have been farmed out to third parties.
Contractual commitments
The company's contractual commitments under service contracts for drilling, leases for office premises and other equipment and an administrative services agreement are as follows:
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Subsequent
Years ended December 31, 2010 2011 to 2011 Total
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($000)
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Drilling service contracts
and other leases $16,609 $507 $ - $17,116
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Guarantees
The company has issued letters of credit in the total amount of US$1.7 million to secure the capital expenditure requirements associated with two exploration licenses in Peru and US$2.1 million in support of the Colombian work commitments. A deposit of US$4.1 million was placed in a trust account in Colombia to meet certain work obligations on the Magdalena License as they occur.
For further information: Petrolifera Petroleum Limited, R. A. Gusella, Executive Chairman, (403) 538-6201 Or Gary D. Wine, President and Chief Operating Officer, (403) 539-8450 Or Kristen J. Bibby, Vice President Finance and Chief Financial Officer, (403) 539-8450, [email protected], www.petrolifera.ca
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