Mar. 9, 2011 (Canada NewsWire Group) --
CALGARY, March 9 /CNW/ - Petrolifera Petroleum Limited (PDP - TSX) today released its fourth quarter 2010 and year end 2010 financial and operating results.
Highlights of the year are as follows:
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- Total proved ("1P") reserves increased 20 percent over 2009 levels to
reach 10.9 million boe
- Total proved and probable ("2P") reserves increased 17 percent over
2009 levels to reach 19.3 million boe
- PV 10 (pre-tax) of 2P reserves estimated at $251 million
- Brillante natural gas discovery in Colombia assigned 2P reserves of
6.4 million boe, 3P reserves of 18.9 million boe
- Company entered into Arrangement Agreement for a share exchange with
Gran Tierra Energy Inc. to be voted upon by Petrolifera Shareholders
on March 17, 2011
>>
Petrolifera today reported its fourth quarter 2010 ("Q4 2010") and full year 2010 ("FY 2010") operating and financial results. These results reflect the impact of capital constraints experienced by the company on its Argentinean producing property during the year and efforts to sell the property prior to engaging in a review of strategic options. The positive event of the year was the discovery of meaningful volumes of natural gas at Brillante on our Sierra Nevada License onshore Colombia. Associated reserve additions were considerable.
Summary Results
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%
Years ended December 31 2010 2009 Change
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FINANCIAL ($000, except per share amounts)
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Total revenue $63,355 $83,791 (24)
Cash flow from operations before non-cash
working capital(1) 20,852 32,407 (36)
Per share, basic and diluted 0.15 0.41 (63)
Net loss (9,592) (10,825) 11
Per share, basic and diluted(4) (0.07) (0.14) 50
Net capital expenditures 36,689 68,856 (47)
Cash 11,046 35,732 (69)
Working capital 13,038 (2,508) 620
Long-term investments(2) 18,670 19,395 (4)
Long-term debt 36,589 27,464 33
Shareholders' equity 239,109 232,126 3
Total assets 329,067 349,065 (6)
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OPERATING
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Daily sales volumes
Crude oil and natural gas liquids - bbl/d 3,072 4,340 (29)
Natural gas - mcf/d 3,665 5,251 (30)
Barrels of oil equivalent - boe/d(3) 3,683 5,215 (29)
Average selling prices
Crude oil and natural gas liquids - $/bbl $53.15 $49.47 7
Natural gas - $/mcf $2.62 $2.81 (7)
Barrels of oil equivalent - $/boe $46.94 $44.00 7
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COMMON SHARES OUTSTANDING (000s)
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Weighted average
Basic 138,728 78,712 76
Diluted(4) 138,730 78,976 76
End of period 145,478 121,759 19
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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 loss. Cash flow is reconciled with
net loss in the accompanying Management's Discussion & Analysis.
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 $30.9 million and $34.6 million
as at December 31, 2010 and 2009, respectively. Portions of bank debt
and long-term debt in the aggregate amount of $27.5 million as at
December 31, 2010 are primarily secured on a limited recourse basis
by the underlying notes formerly known as ABCP. Long-term bank debt
of $27.5 million as at December 31, 2009 was primarily secured on a
limited recourse basis by the underlying notes formerly known as
ABCP.
(3) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 mcf : 1 bbl. Boes 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 2010 and 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
calculations.
>>
Full Year 2010
Revenue in 2010 was $63.4 million, compared to $83.8 million in 2010. The decline primarily reflects lower sales volumes in Argentina. Cash flow from operations before non-cash working capital changes was $20.9 million, down 36 percent from 2009 levels. Cash flow per weighted average common share outstanding - 138.8 million in 2010 - was $0.15 compared to $0.41 per weighted average common share outstanding- 78.7 million - in 2009.
Petrolifera's loss in 2010 was $9.6 million compared to $10.8 million in 2009.
Sales in 2010 averaged 3,683 boe/d (83 percent crude oil) compared to 5,215 boe/d (83 percent crude oil) in 2009. Higher crude oil prices of $53.15 per barrel were achieved in 2010, compared to $49.47 per barrel in 2009, despite a stronger Canadian dollar compared to the US dollar. On an equivalent basis, the company's average 2010 selling price was $46.94 per boe, seven percent higher than in 2009.
Lower sales reflected the lack of any significant capital investment in the Argentinean properties during the year and particularly during a strategic review process underway for the last four months of 2010. As a consequence, well performance was erratic and production declines accelerated. Pump failures, increasing water cuts and higher operating costs per boe adversely impacted overall results.
Net capital expenditures during 2010 were $36.7 million, including recoveries of $13.8 million from the sale of 25 percent of the Sierra Nevada License and proceeds from Argentinean farmouts. Gross expenditures were $50.5 million, with $40.7 million in Colombia and $8.0 million in Argentina. Minor amounts were invested in Peru. The Colombian outlays included drilling and testing of the Brillante natural gas discovery which added 6.4 million boes to the company's 2P reserves and outlays for a further attempt to adequately test the Cienaga de Oro Formation in the La Pinta well on the Sierra Nevada License, in addition to costs to test and evaluate the Upper Porquero Formation, which was confirmed to contain both light gravity crude oil and natural gas.
Capital outlays were financed from cash balances, from the proceeds from the sale of treasury shares, cash flow and a property sale and farmouts. At year end 2010, cash balances were $11.0 million, working capital was $13.5 million, long term investments were $18.7 million and long-term debt was $36.6 million.
As highlighted, the company's 2P reserves at year end 2010 were estimated by GLJ Petroleum Consultants Ltd. ("GLJ"), independent evaluators, to have increased 17 percent over 2009 levels to reach 19.3 million boe, approximately two-thirds in Argentina and one-third in Colombia. GLJ assigned a 10 percent pre-tax percent present value of $251 million to the future net revenue from these reserves. For further information, refer to our press release of March 1, 2011 in this regard.
Fourth Quarter 2010
Revenue for the quarter was $13.0 million compared to $17.9 million in Q4 2009. Cash flow from operations before working capital adjustments was $4.1 million or $0.03 per weighted average common share outstanding - 145.5 million - compared to $5.9 million or $0.05 per weighted average common share outstanding - 121.8 million - in 2009. A loss of $4.1 million was recorded in both periods.
Sales in Q4 2010 were 2,947 boe/d (80 percent crude oil) at an average selling price of $47.78 per boe, with crude oil prices at $55.97 per barrel and natural gas prices at $2.54 per Mcf. Sales were 35 percent below 2009 levels, reflecting declines, pump failures, limited capital investment in Argentina during the strategic review process and time required for certain well workovers.
Q4 2010 capital expenditures were $5.7 million before recoveries of $10.0 million reflecting the cash proceeds from the sale of a 25 percent working interest in the Sierra Nevada License in Colombia to a third party. As a result, a credit of $4.3 million was realized.
Refer to the full year results for period end cash, working capital and debt.
Arrangement Agreement with Gran Tierra Energy Inc.
On January 17, 2011 Petrolifera and Gran Tierra Energy Inc. ("Gran Tierra Energy") announced the execution of an Arrangement Agreement whereby, Petrolifera would be acquired by Gran Tierra Energy on the basis of a share exchange and warrant exchange of Petrolifera shares and warrants for Gran Tierra shares and warrants, if approved by Petrolifera shareholders on March 17, 2011 and all other conditions are satisfied or waived, including approval of the associated Plan of Arrangement by the Court of Queen's Bench, Alberta. The transaction arose out of a strategic review conducted by Petrolifera under the direction of a special committee of independent directors of Petrolifera, who received independent legal and financial advice to assist them in their deliberations.
Upon approval, the transaction will result in Petrolifera common shareholders receiving 0.1241 of a common share of Gran Tierra Energy for each Petrolifera common share and Petrolifera warrant holders receiving 0.1241 of a Gran Tierra warrant, exercisable at $9.67 per Gran Tierra common share until August 28, 2011.
The transaction is more fully described in an Information Circular which was mailed to shareholders and is also posted on Sedar at www.sedar.com.
Supported by a fairness opinion, the directors of Petrolifera determined that the proposed arrangement was in the best interests of Petrolifera and recommended that shareholders vote FOR the transaction on March 17, 2011. If you are a shareholder of Petrolifera and require assistance in voting in the proposed arrangement, please contact Laurel Hill Advisory Group, toll-free in North America at 1.877.304.2014 or by calling collect at 416.304.0211.
Subsequent Event
On March 4, 2011 Petrolifera issued a letter to Perupetro, the state agency of Peru, advising of its intention to surrender the license covering Block 106 in the Maranon Basin, Peru. The company retains licenses covering Blocks 107 and 133 in the Ucayali Basin, Peru.
Petrolifera is a Calgary-based crude oil, natural gas and natural gas liquids exploration, development and production company with activities in Argentina, Colombia and Peru.
Forward-Looking Information
This press release contains forward looking information including, but not limited to, reserves and future net revenues associated therewith and the completion of the proposed arrangement with Gran Tierra Energy. 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. The proposed arrangement with Gran Tierra Energy is subject to the satisfaction of a number of conditions, including the approval of a special resolution by not less than 66 2/3% of the votes cast by Petrolifera shareholders, either in person or by proxy, at the shareholders meeting to be held on March 17, 2011, approval by the Court of Queen's Bench of Alberta of the final order approving the arrangement, receipt of all required regulatory and third party consents and approvals and such other conditions as are set forth in the Arrangement Agreement dated January 17, 2011 and filed on SEDAR at www.sedar.com. Additional risks and uncertainties associated with Petrolifera's future plans are described in Petrolifera's Annual Information Form which is also available on SEDAR at www.sedar.com and in the MD&A attached hereto.
The reserves and future net revenue in this press release represent estimates only. The reserves and future net revenue from the company's properties have been independently evaluated by GLJ with an effective date of December 31, 2010. These evaluations include 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 and royalties and other government levies that may be imposed during the producing life of the reserves. These assumptions were based on price forecasts in use at December 31, 2010 and many of these assumptions are subject to change and are beyond the control of the company. Actual production, sales and cash flows derived therefrom will vary from the evaluations 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 and natural gas reserves attributable to the company's properties. Reference is made to the Company's Annual Information Form for a detailed description of the assumptions utilized in the reserves report prepared by GLJ. Readers are cautioned that boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
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 does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow is reconciled to net earnings (loss) in the attached MD&A.
Management's Discussion and Analysis ("MD&A")
The following is dated as of March 9, 2011 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, 2010 and 2009 as contained in this annual report. Additional information relating to Petrolifera, including its Annual Information Form for the year ended December 31, 2010, will be available on SEDAR at www.sedar.com. 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.
This report contains forward-looking information including but not limited to reserves and future net revenues associated therein, the planned completion of the arrangement with Gran Tierra and the anticipated benefits thereof, the drilling of the San Angel 1001x well, including the projected total depth, timing of completion and costs associated therewith, future exploration and development opportunities in Argentina, Colombia and Peru including the planned sales of natural gas from the Colombian Brillante SE-1X well and longer term field development plans for the Sierra Nevada License, future drilling plans in Argentina, Colombia and Peru and the anticipated timing associated therewith, planned capital expenditures (including sources of funding and timing thereof) and the anticipated impact of the proposed conversion to International Financial Reporting Standards ("IFRS") on the company's Consolidated Financial Statements. 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, 2010. 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. Future net revenues do not represent fair market values.
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 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) 2010 2009 2008
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($000, except per share amounts)
Total revenue $63,355 $83,791 130,326
Net earnings (loss) (9,592) (10,825) 11,554
Per share, basic and diluted (0.07) (0.14) 0.22
Total assets 329,067 349,065 355,658
Long-term bank debt $36,589 $27,464 $77,150
(1) No cash dividends have been declared by the company since
incorporation.
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The company's production had declined from 2008 levels due to complications with the efficiency of its PMN waterflood program in the northern portion of the field, natural field declines and the absence of sustained capital investment, firstly during attempts in 2009 to sell the company's Argentinean interests and secondly, in 2010 during a strategic alternative review process, resulting in lower revenues and net losses in 2009 and in 2010.
The company has reported lower total assets since December 31, 2008 to December 31, 2010, primarily due to a strengthening Canadian dollar relative to the United States dollar. This reduced the company's reported total assets. There was also a reduction in current assets, a 2009 impairment on the company's long-term investment formerly known as asset backed commercial paper ("ABCP") and recognized depletion of the company's producing petroleum and natural gas Argentinean property. Long-term debt fluctuations are primarily due to the classification of the company's line-of-credit facilities as either long-term or current bank debt that are primarily secured by the company's long-term notes formerly known as ABCP and its petroleum and natural gas reserves. The stronger Canadian dollar also diminished the carry value of the US dollar-denominated reserve-backed credit facility. The repayments made against this facility of US$13.0 million and US$19.2 million during 2009 and 2010, respectively also affected the reported long-term bank debt.
STRATEGIC ALTERNATIVES & PROPOSED ARRANGEMENT
During 2010 the management and Board of Directors of the company determined that it was an appropriate time to assess all available strategic alternatives following a thorough review of the company's current operations, its exploration opportunities, contractual obligations and anticipated capital requirements to develop and exploit the company's lands in Argentina, Colombia and Peru, and an evaluation of its current financial position and future financing plans. The process of reviewing strategic alternatives was overseen by an independent special committee of the Petrolifera Board ("Special Committee"). The Special Committee, comprised of three independent directors, had a mandate to identify, examine and consider a range of strategic alternatives available to the company and to make recommendations to the Board of Directors with respect thereto. In this process, the Special Committee received independent legal and financial advice. Arising from the strategic alternatives review process, in January 2011 the company announced that it had entered into an arrangement agreement (the "Arrangement Agreement") with Gran Tierra Energy Inc. ("Gran Tierra Energy") pursuant to which Gran Tierra Energy would acquire all of the issued and outstanding common shares of Petrolifera ("Petrolifera Shares") and all of the issued and outstanding common share purchase warrants of Petrolifera ("Petrolifera Warrants") pursuant to a plan of arrangement (the "Arrangement") following a vote on the matter by Petrolifera's shareholders, and other requisite approvals. See "SUBSEQUENT EVENT" for further details.
FINANCIAL AND OPERATING REVIEW
SALES VOLUMES, PRICING AND REVENUE
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%
Years Ended December 31 2010 2009 change
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Daily sales volumes:
Crude oil and natural gas liquids - bbl/d 3,072 4,340 (29)
Natural gas - mcf/d 3,665 5,251 (30)
Equivalent - boe/d 3,683 5,215 (29)
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Average selling prices:
Crude oil and natural gas liquids - $/bbl $53.15 $49.47 7
Natural gas - $/mcf 2.62 2.81 (7)
Weighted average selling price - $/boe $46.94 $44.00 7
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Petroleum and natural gas sales ($000) $63,090 $83,752 (25)
Interest and other income ($000) 265 39 579
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Total revenue ($000) $63,355 $83,791 (24)
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Petroleum and natural gas revenues in 2010 were $63.1 million on average sales volumes of 3,683 boe per day, compared to $83.8 million on sales of 5,215 boe per day during 2009, decreases of 25 percent and 29 percent, respectively. The reduction in petroleum and natural gas revenues in 2010, compared to 2009, reflected lower sales volume, partially offset by higher average selling prices. The lower sales volume for 2010, compared to 2009, was mainly attributable to natural production declines, the lack of sustained capital investment during the strategic alternatives review process and the temporary shut-in of two key producing wells, PMN - 1002 and 1012, caused by pump failures. Also, as commonly happens on high water-cut wells after pump replacements, it took some time for crude oil production from these two wells to recover toward their pre shut-in levels. In addition, operational downtime included scheduled equipment maintenance on well PMN - 1061, which also encountered a larger reservoir pressure drop than the rest of the field; wells which had large watercut increases and lower petroleum volumes, such as PMN - 1075 and 1101; and to a lesser extent production anomalies from less significant wells, in addition to the shutting-in of the company's Gobernador Ayala II Concession wells. Associated natural gas sale volumes from crude oil wells were also unfavorably impacted by the same production issues in addition to scheduled maintenance work programs on the company's natural gas pipeline.
For 2010 and 2009, sales of crude oil and natural gas liquids represented 83 percent of the company's sales volumes. Upon receipt of all required production permits, the company anticipates initial natural gas sales volumes from the Colombian Brillante SE-1X exploratory well and its Argentinean Vaca Mahuida exploratory wells during 2011. The new sales from the Brillante well will provide the company its initial Colombian revenue, while management formulates longer term field development plans to more fully exploit this recent significant discovery of natural gas reserves and related liquids. All of Petrolifera's sales during 2010 were from its Puesto Morales/Rinconada and Puesto Morales Este Concessions in Argentina and the majority (92 percent) of its crude oil sales were made to the Argentinean operation of a large multinational company.
Prices realized for the company's crude oil and natural gas liquids sales increased seven percent to average $53.15 per barrel in 2010, compared to the $49.47 per barrel realized in 2009. Higher realized US dollar crude oil pricing averaging US$52.38 per barrel in 2010, compared favorably to the average US$44.13 per barrel received in 2009, an increase of 19 percent. The favorable US dollar crude oil and natural gas liquids pricing was partially offset by an average ten percent strengthening of the Canadian dollar relative to the US dollar, which lowered the company's reported average crude oil and natural gas liquids selling prices. During 2010, the crude oil price realized by Petrolifera averaged approximately 66 percent of the WTI average of US$79.38 per barrel, compared to the 2009 average of approximately 72 percent of the WTI average of US$61.46 per barrel. Lower crude oil pricing relative to WTI prices was due to price controls in Argentina.
The company successfully negotiated a price increase for 2010 Argentinean winter sales volumes of natural gas to US$2.61 per mcf. This was a four percent improvement relative to the US$2.40 per mcf realized during the winter sales volumes of 2009. However, 2010 full year natural gas prices decreased seven percent over the level realized during 2009 to average $2.62 per mcf. The lower realized natural gas pricing during 2010 relative to the same period in 2009, as expressed in Canadian dollars, resulted from an average ten percent strengthening of the Canadian dollar as compared to the US dollar.
Interest and other income including interest earned on short-term cash and restricted cash deposits were minimal in 2010 and 2009. Interest on the investment in notes formerly known as ABCP, with a face value of $30.9 million as at December 31, 2010 (December 31, 2009 - $ 34.6 million) has not been recognized since August 2007, due to the lack of market liquidity for these notes. During 2010 and 2009 the company received minimal interest payments on its investment formerly known as ABCP, as the specified short term interest rate approximated the 50 basis points required to be paid out on this investment. See "Restricted Cash, DEBT AGREEMENT OPTION and Long-Term Investments" for additional details including estimates of valuation and the reduction in the face value of these longer-term notes.
ROYALTIES, OPERATING EXPENSES AND CORPORATE NETBACKS
CORPORATE NETBACKS(1)
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Years Ended December 31 2010 2009
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($000, except per
unit amounts) Total Per boe Total Per boe
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Average daily sales
(boe/d) 3,683 5,215
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Petroleum and natural gas
sales $63,090 $46.93 $83,752 $44.00
Interest and other income 265 0.20 39 0.02
Royalties (9,053) (6.73) (12,017) (6.31)
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Net revenue $54,302 $40.39 $71,774 $37.71
Operating costs (21,046) (15.66) (22,930) (12.05)
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Corporate netback $33,256 $24.73 $48,844 $25.66
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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
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 loss
can be found in the Net Loss table.
>>
Petrolifera's corporate netback of $24.73 per boe in 2010 was four percent lower than the corporate netback of $25.66 per boe recorded in 2009. The company realized higher commodity pricing in 2010, compared to 2009. However, in 2010 the higher realized commodity pricing was more than offset by higher operating costs per boe. Petrolifera's calculated unit netback of $24.73 per boe in 2010 was 53 percent of the average selling price per boe; a reduction from 58 percent achieved during 2009.
ROYALTIES
Royalties represent charges levied by governments and landowners against production or revenue. Included in royalties are revenue taxes imposed by provincial jurisdictions. Royalties in 2010 were $9.1 million ($6.73 per boe), compared to $12.0 million ($6.31 per boe) in 2009. The ratio of royalties to petroleum and natural gas sales was 14 percent for 2010 and 2009. On a boe basis, the royalty increase is primarily attributable to the higher realized commodity pricing during 2010, compared to 2009.
OPERATING COSTS
Total operating costs during 2010 decreased by approximately eight percent, compared to 2009, largely due to lower petroleum sales volumes, the benefit of proceeds from third party oil treatment, which reduced the company's operating costs while allowing the company to better utilize its crude oil processing facility, lower fuel costs from replacement of diesel power generators with natural gas equipment and a strengthening of the Canadian dollar relative to the US dollar.
On a per boe basis, however, operating costs increased 30 percent in 2010 to $15.66 per boe, compared to $12.05 per boe for 2009. This resulted from lower petroleum sales volumes, increased costs for contract operator salaries and payments to surface owners both prescribed by Argentinean law alongside increased repair and maintenance costs of the company's natural gas pipeline, water injection and pumping well engines during 2010 as compared to 2009. Total fluid throughput at our processing plant increased during the current year, partially due to the late 2009 infill well drilling program, although the average amount of crude oil produced decreased due to higher average water cuts and a maturing waterflood. Accordingly, the additional fluid handling costs contributed to additional increases in the operating costs per boe in 2010, relative to 2009.
NET LOSS AND SHARES OUTSTANDING
NET LOSS
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Years Ended December 31 2010 2009
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($000, except per
unit amounts) Total Per boe Total Per boe
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Corporate netback $33,256 $24.73 $48,844 $25.66
General and administrative (7,769) (5.78) (8,285) (4.35)
Stock-based compensation (2,695) (2.00) (4,674) (2.46)
Finance charges (4,204) (3.13) (5,097) (2.68)
Foreign exchange loss (834) (0.62) (115) (0.06)
Fair value increase (loss) 4,817 3.58 (2,104) (1.11)
Depletion, depreciation
and accretion (28,951) (21.54) (33,546) (17.62)
Income tax provision (1,746) (1.30) (3,974) (2.09)
Taxes other than income
taxes (1,466) (1.09) (1,874) (0.98)
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Net loss $(9,592) $(7.14) (10,825) $(5.69)
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For 2010, the company reported a net loss of $9.6 million ($0.07 per weighted average basic and diluted share) compared to net loss of $10.8 million ($0.14 per weighted average basic and diluted share) for 2009. The decrease in the net loss for 2010, relative to 2009, was primarily attributable to higher realized crude oil and natural gas liquids pricing and a fair value increase attributable to the recognition of a debt agreement option, and lower expenses for general and administrative, depletion, depreciation and accretion, stock-based compensation, finance charges, income taxes and taxes other than income taxes. See "RESTRICTED CASH, DEBT AGREEMENT OPTION AND LONG-TERM INVESTMENTS" for further details on the fair value increase.
The company's Argentinean operation is considered self-sustaining. Accordingly, changes in this operation's reported net assets, expressed in Canadian dollars resulting from foreign exchange differences between the US dollar and Canadian dollar, is recognized as other comprehensive losses. For 2010 and 2009, the company's other comprehensive losses were $5.1 million and $20.0 million, respectively. The other comprehensive loss for 2010 was due to a five percent strengthening of the Canadian dollar as at December 31, 2010, compared to the US/Canadian dollar relationship at December 31, 2009. This resulted in a decrease in the carrying value of the net assets of the company's Argentinean operations, which are denominated in US dollars and reported in Canadian dollars. Similarly, the other comprehensive losses for 2009, was due to a 15 percent strengthening of the Canadian dollar at December 31, 2009, compared to the US/Canadian dollar relationship as at December 31, 2008.
SHARES OUTSTANDING
In 2010, the weighted average number of common shares outstanding was 138.7 million, compared to 78.7 million in 2009. The increase in the weighted average number of common shares for 2010, relative to the same periods in 2009, primarily reflected the weighed average inclusion of the April 2010 public offering issuance of 23.7 million common shares from treasury for gross proceeds of $20.1 million; the August 2009 public offering issuance and September 2009 private placement issuance of 65.3 million and 1.1 million common shares from treasury, respectively, for gross proceeds of $57.5 million and $1.0 million; and 0.4 million options that were exercised during 2010 or 2009, resulting in the issuance of a like number of common shares. As the company had net losses for 2010 and 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 calculations.
As at the close of business on March 8, 2011, the company had the following securities issued and outstanding:
<<
- 145,650,660 common shares; and
- 8,560,654 stock options; and
- 33,239,600 warrants.
>>
GENERAL & ADMINISTRATIVE ("G&A") AND STOCK-BASED COMPENSATION
G&A expenses were $7.8 million in 2010, compared to $8.3 million in 2009; in 2009 amounts included one-time expenses related to the company's process to dispose of its Argentinean interests. G&A expenses primarily consist of management and administrative salaries, legal and professional fees, insurance, travel and other administrative expenses including increased professional fees and a non-executive retention payment to certain staff related to the company's strategic alternatives process. See "STRATEGIC ALTERNATIVES & PROPOSED ARRANGEMENT" for further details. G&A expenses of $5.3 million and $4.7 million, primarily related to further exploration and evaluation of the prospects in Colombia, Peru and Argentina, were also respectively capitalized in 2010 and 2009.
On a per boe basis, G&A was $5.78 per boe of sales in 2010 compared to $4.35 per boe in 2009. The increase in G&A per boe in 2010 compared to 2009 was primarily due to lower sales volumes.
During 2010, a non-cash expense of $2.7 million ($3.6 million in 2009) 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 in 2010, as compared to 2009, primarily reflected a decrease in the weighted average fair value assigned to each granted option combined with a reduction in the number of granted options.
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 in 2009.
FINANCE CHARGES
Included in the finance charges of $4.2 million and $5.1 million in 2010 and 2009, respectively, was interest paid and accrued on the company's outstanding current and long-term bank debt and deferred financing charges that are being amortized over the term of the revised reserve-backed credit agreement. The decrease in finance charges in 2010, compared to 2009, primarily reflected lower average company borrowings and a modestly lower effective interest rate of 4.1 percent as compared to 4.2 percent in 2009.
FOREIGN EXCHANGE
During 2010, the strengthening of the Canadian dollar relative to the US dollar resulted in a foreign exchange gain on a portion of the company's 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. 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 $0.8 million for 2010, compared to $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 its reserve-backed credit facility, which is denominated in US dollars. The company's main exposure to foreign currency risk in its Peru and Colombia segments and to a lesser extent its corporate segment relates to working capital in support of the company's local capital expenditure programs, which is predominately funded in US dollars.
FAIR VALUE OF DEBT AGREEMENT OPTION
Upon the company's April 2010 decision to not extend the term of a credit facility agreement that gives the company the option to settle a portion of its debt in consideration for a portion of its investment in notes formerly known as ABCP, the company estimated the fair value of a debt agreement option in the amount of $4.8 million. See "RESTRICTED CASH, DEBT AGREEMENT OPTION AND LONG-TERM INVESTMENTS" for further details.
DEPLETION, DEPRECIATION & ACCRETION ("DD&A")
DD&A is calculated using the unit-of-production method relative to total estimated proved reserves. DD&A in 2010 totaled $29.0 million, a decrease compared to $33.5 million in 2009, largely due to lower petroleum sales volumes and the strengthening of the Canadian dollar relative to the US dollar, which reduced the reported DD&A. On a per boe basis, however, DD&A increased 22 percent in 2010 to $21.54 per boe as compared to $17.62 per boe in 2009. The increase in DD&A on a per boe basis in 2010 compared to 2009 was primarily due to the higher estimated costs of future capital expenditures and 2010 and 2009 year-end reserve adjustments.
Capital costs of $5.9 million (Dec. 31, 2009 - $14.0 million) incurred for unevaluated properties and other assets in Argentina and $57.9 million (2009 - $56.1 million) and $77.3 million (2009 - $47.5 million) for unproven properties, 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 in 2010 and 2009. Accretion expense will continue at appropriate levels in the future to accrete the discounted liability of $10.0 million (Dec. 31, 2009 - $9.6 million) over the estimated timing of reclamation expenditures on the company's oil and gas properties.
CEILING TEST
Petroleum and natural gas companies are required, at a minimum, to compare the recoverable value of their petroleum and natural gas assets per cost centre to their recorded carrying values at the end of each reporting period. Excess carrying value per cost centre over fair value are to be written off to losses. No write-down was required in 2010 or 2009. The following benchmark prices were applied in determining the recoverable value of the company's petroleum and natural gas assets:
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Argentina Colombia
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Crude Oil Natural Gas Crude Oil Natural Gas
Price ($/bbl) Price ($/mcf) Price ($/bbl) Price ($/mcf)
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2011 61.22 2.58 89.90 2.04
2012 62.45 2.70 90.82 2.08
2013 63.70 2.76 91.84 2.12
2014 64.97 2.81 93.88 2.17
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+ approximately + approximately + approximately + approximately
2% thereafter 2% thereafter 2% thereafter 2% thereafter
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>>
TAXES
The respective current income tax provision of $1.9 million and $3.4 million in 2010 and 2009 relates primarily to income taxes payable in Argentina. Additionally, a future income tax recovery of $0.2 million and a future tax expense of $0.6 million in 2010 and 2009, respectively, were 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 2010 and 2009. Taxes other than income taxes of $1.5 million and $1.9 million in 2010 and 2009, respectively, represent taxes charged on all banking transactions in Argentina.
CAPITAL RESOURCES, CAPITAL EXPENDITURES AND LIQUIDITY
In April 2010, the company successfully completed a bought deal public offering of common shares from treasury (the "2010 Public Offering") for gross proceeds of $20.1 million. The proceeds were used to fund a portion of the company's exploration capital spending program, including exploration activity on the company's Sierra Nevada and Magdalena licenses, located onshore Colombia, the repayment of a portion of the company's reserve-backed debt and for working capital.
During 2010, the company entered into farmout agreements on its Puesto Guevara and Vaca Mahuida Concessions, both located in Rio Negro Province, Argentina and on the undeveloped northern portion of the Rinconada Block, located in La Pampa Province, Argentina. Under each farmout agreement, the farmee agreed to incur all of the remaining capital spending requirements to fulfill the respective concession's work program, or to drill wells at no cash cost to the company, in the case of the undeveloped northern portion of the Rinconada Block. In addition, the company was reimbursed $3.7 million for recent drilling activity on its Vaca Mahuida Concession. Under the Rinconada Block farmout agreement, the farmee agreed to finance a three well drilling program or to reimburse the company with a cash payment of $1.0 million for each well not drilled by November 30, 2011.
In August 2010, the company signed a revised reserve-backed credit facility agreement with scheduled repayments until expiry on June 30, 2012. The company made a one-time payment of US$11.7 million prior to signing the revised credit facility agreement and, subsequent thereto, made two quarterly permanent debt repayments totaling US$7.5 million to reduce the availability under the facility from US$50.0 million to US$30.8 million. Pursuant to the terms of the revised agreement, the company will make regular quarterly permanent debt repayments through to expiry, at which time all borrowings will be repaid, with a final payment of US$12.0 million at maturity. The revised reserve-backed credit facility improved the company's working capital position, as a portion of its reserve-backed debt, previously recognized as a current liability, is now classified as long-term. Under the terms of the reserve-backed credit facility agreement between the company and its syndicate of lenders, the company may retire this debt prior to the expiry of the agreement without penalty and anticipates repayment of this facility, under the existing terms of the agreement, from cash flows, cash balances and non-cash working capital.
In November 2010, Petrolifera executed a three year contract with a crude oil and natural gas exploration and production company for the sale of up to eight mmcf/d of natural gas from the company's Brillante SE-1X well, situated on its Sierra Nevada License in the Upper Magdalena Basin, onshore Colombia. Commencement of natural gas production and sales is anticipated during the first half of 2011 and the natural gas will be sold into the available market as compressed natural gas. The negotiated well head price for the natural gas under this early production system is set at an initial price of US$2.00 per MMBTU and will be adjusted annually based on changes in the U.S. Consumer Price Index.
In December 2010, the company entered into a purchase and sale agreement with Gran Tierra Energy Colombia Ltd., a wholly-owned subsidiary of Gran Tierra Energy, to sell a 25 percent working interest in the company's Sierra Nevada License in Colombia in consideration for a cash receipt of US$10.0 million. The assignment of this working interest by the Colombian authorities has been requested and is expected but if not provided, the agreement can be cancelled by either party. Proceeds of the transaction are primarily being used to finance the drilling of an exploratory well, San Angel 1001X, on the company's Magdalena License in the Lower Magdalena Basin onshore Colombia. The well was spudded on February 1, 2011 and is anticipated to be drilled to a projected total depth of approximately 7,500 feet with a forecast drilling time of approximately 33 days. Upon acknowledgement from the appropriate Colombian authority that the company has reached targeted depth, the company will have fulfilled its phase three work commitment on this License. See "Commitments, Contractual Obligations, Guarantees & Off-Balance Sheet Financing" for a detailed discussion of the status of the company's various work commitments.
During 2010, the management and Board of Directors of the company determined that it was an appropriate time to assess all strategic alternatives available to the company following a thorough review of current operations, exploration opportunities, contractual obligations and anticipated capital requirements to develop and exploit the company's lands in Argentina, Colombia and Peru, in combination with an evaluation of its current financial position and future financing plans. The process of reviewing strategic alternatives was overseen by the Special Committee with independent legal and financial advisors. The Special Committee, comprised of three independent directors, had a mandate to identify, examine and consider a range of strategic alternatives available to the company and to make recommendations to the Board of Directors with respect thereto. Pursuant to the strategic alternatives review process, in January 2011 the company announced that it had entered into an Arrangement Agreement with Gran Tierra Energy pursuant to which Gran Tierra Energy will acquire all of the issued and outstanding common Petrolifera Shares and all of the issued and outstanding Petrolifera Warrants pursuant to the Arrangement Agreement. See "SUBSEQUENT EVENT" for further details.
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 loss. Cash flow is reconciled with net 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 loss to cash flow:
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Years Ended December 31 2010 2009
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($000)
-------------------------------------------------------------------------
Net loss $(9,592) $(10,825)
Add non-cash charges:
Depletion, depreciation and accretion 28,951 33,546
Fair value impairment (increase) (4,817) 2,104
Amortization of deferred finance and other charges 2,890 868
Stock-based compensation 2,695 4,674
Unrealized foreign exchange loss 912 1,428
Future income tax provision (187) 612
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Cash flow $20,852 $32,407
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Per share, basic $0.15 $0.41
Per share, diluted $0.15 $0.41
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>>
Cash flow in 2010 was $20.9 million or $0.15 per weighted average basic and diluted share, compared to $32.4 million or $0.41 per weighted average basic and diluted share in 2009. The 36 percent decrease in total cash flow during 2010, relative to 2009, primarily resulted from lower sales volumes of both crude oil and natural gas, the impact of a strengthening Canadian dollar relative to the US dollar, thereby lowering the company's Canadian dollar reported cash flows and lower realized foreign exchange gains on the company's working capital. The company implemented a waterflood program at PMN in order to mitigate natural reservoir pressure declines, but in a portion of the field the program has been less effective than anticipated. A restricted level of continuing capital expenditures on the Puesto Morales Concession has also contributed to lower production and related sales volumes as funds were redirected to more expensive but higher potential projects, primarily in Colombia.
EQUITY FINANCING FROM TREASURY
In April 2010, the company completed a "bought-deal" public offering of 20,590,000 common shares at a price of $0.85 per common share for gross proceeds of approximately $17.5 million. The underwriters were granted an over-allotment option (the "2010 Over-Allotment Option"), which included the right to purchase up to an additional 15 percent of the common shares, exercisable in whole or in part up to 30 days following closing of the 2010 Public Offering. The 2010 Over-Allotment Option was exercised in whole by the underwriters on April 14, 2010, the closing date of the 2010 Public Offering and resulted in a total issuance of 23,678,500 common shares, raising gross proceeds to approximately $20.1 million. Issue costs of $1.3 million were incurred with respect to the equity financing.
The net proceeds of the 2010 Public Offering, in the amount of $18.8 million, were added to working capital 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. During 2010, the net proceeds of the 2010 Public Offering were fully deployed to fund approximately $11.7 million of capital expenditures in Colombia, repayment of US$5.0 million of the reserve-backed credit facility and to augment working capital.
The proposed use of net proceeds per the 2010 Public Offering relative to actual use of net proceeds as at December 31, 2010, were as follows:
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-------------------------------------------------------------------------
($000) Use of Net
Use of Net Proceeds
Proceeds Per as at
2010 Public December
Offering 31, 2010
-------------------------------------------------------------------------
Capital expenditure program, primarily in
Colombia $ 10,520 $11,651
Reduction of reserve-backed credit facility Up to US$5,000 US$5,000
Working capital 3,300 1,962
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$ 18,820 $ 18,820
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>>
During August 2009, the company issued 65,343,000 units (each, a "Unit") at a price of $0.88 per Unit, with each Unit consisting of one common share and one-half of one common share purchase warrant of the company (each whole common share purchase warrant, a "Warrant", exercisable at $1.20 per Warrant until August 28, 2011), for gross proceeds of approximately $57.5 million (the "2009 Public Offering") and during September 2009, a non-brokered private placement was completed with certain directors and officers of the company to issue 1,137,500 Units on identical terms to the 2009 Public Offering for gross proceeds of approximately $1.0 million (the "2009 Private Placement").
The net proceeds in the amount of $55.4 million of the 2009 Public Offering and 2009 Private Placement were initially added to working capital as subsequently 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. During 2009 and 2010, the net proceeds of the 2009 Public Offering and 2009 Private Placement were fully deployed to repay US$15.0 million of the company's reserve-backed credit facility, to fund approximately $35.3 million of capital expenditures in Colombia and to fund a US$4.1 million trust account as drawn down in 2010 to fund a portion of the company's Colombian work commitments.
The proposed use of net proceeds per the 2009 Public Offering and Private Placement relative to actual use of net proceeds as at December 31, 2010, were as follows:
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-------------------------------------------------------------------------
($000) Use of Net Use of Net
Proceeds Per Proceeds
2009 Public as at
Offering and December
Private Placement 31, 2010
-------------------------------------------------------------------------
Capital expenditure program, primarily
in Colombia $ 32,743 $35,300
Reduction of reserve-backed credit facility Up to US$16,000 US$15,000
Working capital 6,700 -
Trust account - 4,100
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$ 55,443 $ 55,443
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CAPITAL EXPENDITURES
-------------------------------------------------------------------------
Years Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
Colombia $40,680 $37,036
Argentina 7,983 27,082
Peru 1,732 7,462
Corporate 111 43
Capital expenditures 50,506 71,623
Proceeds from disposition and farmout arrangements (13,817) (2,767)
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Net capital expenditures $36,689 $68,856
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>>
Net capital spending for 2010 was $36.7 million, compared to $68.9 million for 2009. Net capital spending for 2010 was financed from available cash, cash flow from operations and portions of the proceeds from the 2010 and 2009 Public Offerings. Expenditures in Colombia were primarily for the drilling and long term testing of the Brillante SE-1X well and the La Pinta 1X well remedial work, both on the Sierra Nevada License.
Colombia
In February 2010, the company spudded its 100 percent-owned Brillante SE-1X exploratory well, located on the Sierra Nevada License in the Lower Magdalena Basin, onshore Colombia. During the third quarter of 2010, the company concluded a 21-day extended flow term test of its Brillante SE-1X well on the upper portion of the Cienago de Oro ("CDO") reservoir. The total recovery during the test equaled the government permitted volumes of 66 mmcf of natural gas, 284 barrels of 57.6 degrees API gravity condensate and 28 barrels of water. Government permitted restricted production rates during the final 24 hours of the flow period were 3.1 mmcf of natural gas, 19.0 barrels of condensate and 1.1 barrels of water. No flowing wellhead pressure loss or natural decline in the natural gas rate was experienced during the 21-day flow period. The flowing wellhead pressure increased from 1,016 psi to 1,055 psi, while the daily natural gas production increased slightly from 3.0 mmcf per day to 3.1 mmcf per day.
In November 2010, Petrolifera executed a three year contract with a crude oil and natural gas exploration and production company for the sale of up to eight mmcf/d of natural gas from the company's Brillante SE-1X well, situated on its Sierra Nevada License in the Upper Magdalena Basin, onshore Colombia and received a permit from the Colombian authority, the Agencia Nacional de Hidrocarburos ("ANH") to sell natural gas from the Brillante well.
Commencement of natural gas production and sales is anticipated during the first half of 2011 and the natural gas will be sold into the available market as compressed natural gas. The negotiated well head price for the natural gas under this early production system is set at an initial price of US$2.00 per MMBTU and will be adjusted annually based on changes in the U.S. Consumer Price Index.
In January 2010, a snubbing unit was mobilized from the United States to the 100 percent-owned La Pinta 1X exploration well, drilled during 2009 on the company's Sierra Nevada License, situated onshore the Lower Magdalena Basin. Previously, the well had been suspended following evidence of sand plugging in the production tubing, which precluded further testing. The La Pinta 1X well bore was reentered with an objective of cleaning out the tubing string blockage to enable a test of the well. Unfortunately, on test the tubing again plugged and a decision was made to plug off the CDO and to move up hole to attempt to test a zone in the upper Porquero Formation. During May 2010, a drill stem test was conducted in the upper Porquero Formation at subsurface depths between 7,804 feet and 7,834 feet that flowed 47 degrees light gravity crude oil and natural gas at an average measured rate of 139 barrels of crude oil per day and 739 mcf of natural gas per day, through a 32/64" choke with a surface pressure of 238 psi. The company is studying the feasibility of various productivity stimulation, appraisal and production methods to place the La Pinta 1X well onstream.
Readers are cautioned that measured flow rates may not be indicative of stabilized production rates for the Brillante SE-1X or La Pinta 1X exploratory wells. Also, further evaluation, testing and appraisal of the La Pinta 1X well is required before an assessment of commerciality can be made. The company has a right to appraise its petroleum and natural gas rights in Colombia but it does not have a right to produce same until such time as the reserves are determined to be commercial.
During the second half of 2010, the company's technical staff interpreted 3D seismic which was acquired over the La Pinta structure earlier in the year. This interpretation has resulted in additional well-defined structures being mapped over La Pinta in various prospective horizons.
In December 2010, the company entered into a purchase and sale agreement ("Purchase and Sale Agreement") with Gran Tierra Energy Colombia Ltd. ("Gran Tierra Energy Colombia"), a wholly-owned subsidiary of Gran Tierra Energy, to sell a 25 percent working interest in the company's Sierra Nevada License in Colombia in consideration for a cash receipt of US$10.0 million. If the ANH does not acknowledge Gran Tierra Energy Colombia's working interest through a written resolution within 180 days after all required documentation is submitted, either the company or Gran Tierra Energy Colombia may terminate the Purchase and Sale Agreement. Proceeds of this transaction are primarily being used to finance the drilling of an exploratory well, San Angel 1001X, on the company's Magdalena License in the Lower Magdalena Basin onshore Colombia. The well was spudded on February 1, 2011 and is anticipated to be drilled to a projected total depth of approximately 7,500 feet with a forecast drilling time of approximately 33 days. Upon acknowledgement from the appropriate Colombian authority that the company has reached targeted depth, the company will fulfill its phase three work commitment on this License.
The company commenced and completed a 144 km(2) 2D seismic program during 2010 on its Turpial License in the Middle Magdalena Basin, onshore Colombia, and multiple prospects have been defined. The company was carried through the first US$1.9 million of costs related to this work program by its joint venturer; which earned an undivided 50 percent working interest in the Turpial License. The company retained a 50 percent working interest and operatorship of the Turpial License.
Argentina
Included in 2010 expenditures were those incurred to increase the capacity of the company's water treatment and water handling facilities at PMN, Argentina to 33,000 barrels per day. The expanded water treatment capacity was installed to enable the company to handle increased fluid volumes. The company also capitalized certain workover costs in 2010 related to perforation of additional new intervals in the Centenario, Loma Montosa and Pre-Cuyo Formations and adjustments to the water injection rates to sustain crude oil production on certain PMN wells, including PMN 1111.
In January 2010, the company announced that it had entered into a farmout agreement of the Vaca Mahuida ("VM") Concession, situated southeast of Puesto Morales, Argentina, whereby the company would continue as operator and retain a 25 percent carried interest in exchange for a $1.0 million recovery of back costs incurred on the VM X-2014 exploratory well, subsequently completed as a shut-in natural gas well and the completion of the company's remaining committed work program for the Concession. Four exploratory wells ranging in depth from 1,000 to 1,500 meters were drilled by the company during 2010 under the terms of the agreement. The VM farmout agreements also provided for the reimbursement to the company of $3.8 million for the cost of wells drilled during 2010. The 2010 VM drilling campaign and a payment for remaining work units fulfilled this Concession's work commitment as confirmed by the Province of Rio Negro, Argentina and also the terms of the farmout agreement. All five of the VM exploratory wells encountered hydrocarbons in at least one of the Centenario, Loma Montosa, Sierras Blancas, Punta Rosada or Pre-Cuyo Formations. This validated the geological model through the confirmation of both hydrocarbon migration and trapping in the VM Concession. The company has applied to the Province of Rio Negro, Argentina, for an exploitation license, which it anticipates will require a work commitment of laying flowlines, further well testing and drilling. Results for these wells were as follows:
<<
- VM X-2014 well was completed as a natural gas well and tested dry
natural gas at approximately 1.0 mmcf per day from the Centenario
Formation;
- LFe.X-1 well tested 80 barrels per day of crude oil and 1.5 mmcf per
day of dry natural gas from the Centenario Formation with the Sierra
Blancas Formation to be further evaluated at a later date;
- LG.x-1 well tested dry natural gas at rates of 1.5 mmcf per day from
the Centenario Formation, 2.2 mmcf per day from the Loma Montosa and
1.5 mmcf per day from the Sierra Blancas Formation; and
- Pa. x-1 and YA.x-1 wells encountered hydrocarbons during drilling in
at least one of several formations, but during completion all tested
intervals produced water or negligible amounts of crude oil.
>>
During 2010, the company successfully farmed out a working interest in its Puesto Guevara Concession, also situated southeast of Puesto Morales in the Province of Rio Negro, Argentina. Upon completion by the farmee of the committed work program, which requires the drilling of one exploratory well, the company's ownership in this Concession will be reduced to 44 percent, with Petrolifera continuing as the operator. The farmee has also agreed to the drilling of a second exploratory well at its cost. The two exploratory well program is anticipated during 2011 or early 2012 with each well ranging in depth from 1,000 meters to 1,700 meters. The company also completed an agreement to farmout the northern portion of its undeveloped Rinconada Block, located in La Pampa Province, Argentina, in exchange for a 35 percent carried working interest in three wells. The company retains operatorship of the southern portion of Rinconada.
Peru
Minimal capital expenditures were incurred for pre-drilling activities during 2010 on the company's three Peruvian blocks. The company has met, or exceeded, all of its current work commitments for Block 106, in the Maranon Basin, Peru and for Block 107, located in the Ucayali Basin, Peru, in a timely manner. The first phase work commitment for Block 133 is minimal. See "SUBSEQUENT EVENTS" for details on the company's March 2011 relinquishment of Block 106.
CREDIT FACILITIES
During 2009, the company negotiated an expansion of a line-of-credit to a maximum of $23.2 million with a Canadian chartered bank (the "First ABCP line-of-credit"). For this line-of-credit, a maximum of $13.9 million was secured by the eligible master asset vehicles Classes A1 through C received by the company in exchange for a portion of the ABCP whereas a maximum of $9.3 million was unsecured under the existing terms of this agreement between the company and its lender. Any of the borrowings from the expanded First ABCP line-of-credit are categorized as long-term, as the facility's initial maturity is April 2012 and the company can make up to four extension requests with each extension for an additional one-year period. The First ABCP line-of-credit bears interest at a floating rate. As at December 31, 2010 and December 31, 2009 the outstanding draws on the First ABCP line-of-credit facility were $22.5 million.
The company has a second line-of-credit agreement to a maximum of $5.0 million, which was fully drawn as at December 31, 2010 and December 31, 2009. This second line-of-credit, which has an initial expiry in April 2011, is secured by the ineligible master asset vehicles Classes 1 & 2 ("MAV IA 1 & 2") notes (the "Second ABCP line-of-credit") under the existing terms of this agreement between the company and its lender. During April 2010, the company advised its lender it would not renew this facility beyond its expiry date, at which time it will exercise its option to deliver to the lender the MAV IA 1 & 2 notes. At the time of acquisition in 2007 these notes had a face value of $6.6 million but through subsequent impairment provisions had no carrying value on the company's accounts, as at December 31, 2010 and December 31, 2009. As the company has the option to settle its $5.0 million in borrowings, as drawn, on the Second ABCP line-of-credit agreement through delivery to its lender of the MAV IA 1 & 2 notes, the company advised its lender that it intends to settle such borrowings with the MAV IA 1 & 2 notes and accordingly, as at December 31, 2010, the company has classified the $5.0 million in borrowings made under this facility as a current liability (Dec. 31, 2009 - $5.0 million was classified as a long-term liability).
In August 2010, the company signed a revised reserve-backed credit facility agreement with a syndicate of banks with scheduled repayments over a term expiring on June 30, 2012. The company made a one-time payment of US$11.7 million prior to signing the revised reserve-backed credit facility agreement and subsequent thereto, made two quarterly permanent debt reduction repayments totaling US$7.5 million, with US$5.0 million financed from the 2010 Public Offering and the remainder from existing cash balances and cash flow from operations. These payments had the effect of reducing the availability under the facility from US$50.0 million to US$30.8 million. The company has remaining quarterly permanent debt repayments to expiry of the agreement in June 2012, at which time all borrowings under this credit facility will be due and payable, as follows:
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As at
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(US$000)
March 31, 2011 $3,750
June 30, 2011 $3,750
September 30, 2011 $3,750
December 31, 2011 $3,750
March 31, 2012 $3,750
June 30, 2012 $12,000
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>>
Under the terms of the revised reserve-backed credit facility, one-half of any potential farmout proceeds received by the company, up to a maximum of US$5.0 million, are to be first allocated to reduce the final US$12.0 million permanent debt repayment due, until retired, with any additional proceeds from other potential farmout agreements thereafter allocated to the scheduled quarterly payments.
The extension of the expiry date of the revised reserve-backed credit facility agreement immediately improved the company's working capital position, as a portion of its reserve-backed debt previously held as a current liability was classified as long-term. The company intends to finance the permanent debt repayments from existing cash balances, cash flow and non-cash working capital.
The revised reserve-backed credit facility bears interest at LIBOR plus a margin, is partially 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, 2010, 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, 2010, the outstanding reserve-backed facility was US$30.8 million (Dec. 31, 2009 - US$50.0M) with $14.9 million recognized as a current liability (Dec. 31, 2009 - $52.3 million) and $14.1 million as long-term (Dec. 31, 2009 - $-). As at December 31, 2010, the outstanding First and Second ABCP line-of-credit facilities totaled $27.5 million (Dec. 31, 2009 - $27.5 million) with $5.0 million recognized as a current liability (Dec. 31, 2009 - $-) and $22.5 million as a long-term liability (Dec. 31, 2009 - $27.5 million).
The company's Canadian and US dollar debt agreements have change of control provisions that would require the prior consent of the company's Canadian dollar lender and/or at least two-thirds of the syndicated US dollar lenders, respectively, for continued access to the rights and benefits pursuant to each of its debt agreements following a change of control.
The company is subject to external restrictions on its revised reserve-backed credit facility. Under this facility's agreement, the company is required to maintain certain operating conditions in addition to the financial covenants where certain outstanding draws cannot exceed two and half times the 12 month trailing EBITDA and a minimum working capital ratio, where working capital is defined by the terms of the revised reserve-backed credit facility agreement to exclude bank debt primarily secured by the longer term notes previously known as ABCP, of 1.25: 1.00. EBITDA is a non-GAAP measure and is defined by the revised reserve-backed credit facility agreement as net loss prior to deduction of finance charges, income taxes, depletion, depreciation and accretion expense, stock-based compensation, unrealized foreign exchange losses and any other non-cash expenses. As at December 31, 2010, outstanding draws on the revised reserve-backed credit facility and a portion of long-term bank debt were $39.2 million and EBITDA was $24.1 million, for a ratio of debt-to-EBITDA of 1.6, which is in compliance with the imposed limit. With existing realized commodity pricing, the company's cost structure and a scheduled permanent debt repayment program, Petrolifera anticipates that it will continue to be in compliance with this financial covenant.
Reconciliation of net loss to EBITDA is as follows:
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-------------------------------------------------------------------------
Year Ended December 31 2010
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net loss $(9,592)
Add Interest, income taxes, depletion, depreciation and
accretion expense and other non-cash expenses:
Depletion, depreciation, and accretion 28,951
Finance charges 4,204
Fair value increase (4,817)
Stock-based compensation 2,695
Income tax provision 1,746
Unrealized foreign exchange loss 912
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EBITDA $24,099
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RESTRICTED CASH, DEBT AGREEMENT OPTION AND LONG-TERM INVESTMENTS
As at December 31, 2010, the debt agreement option, a current asset, represented the company's option to settle $5.0 million in borrowings through the delivery of its MAV IA 1 & 2 notes, whereas long-term investments included notes received in exchange for ABCP, with a face value of $30.9 million (Dec. 31, 2009 - $34.6 million) and a carrying value of $18.7 million (Dec. 31, 2009 - $18.7 million). As at December 31, 2009, long-term investments also included collateral to support issued letters of credit of $0.7 million. As at December 31, 2010, restricted cash included collateral to support issued letters of credit of $1.5 million, with terms to maturity of less than one year (Dec. 31, 2009 - $3.2 million). These investments were classified as held for trading and were carried at fair value, which is assessed each reporting date. The fair value of the debt agreement option and notes received in exchange for ABCP is explained herein.
As discussed under "CREDIT FACILITIES", during April 2010, the company advised its lender that upon expiry of the $5.0 million Second ABCP line-of-credit agreement, the company will deliver to the lender the MAV IA 1 & 2 notes that were issued to the company in 2009 in replacement for a portion of its investment in ABCP. The lender's recourse on the company's borrowings of $5.0 million is limited to the MAV IA 1 & 2 notes, which at the time of acquisition in 2007 had a face value of approximately $6.6 million but through subsequent years' impairment provisions had no carrying value in the company's accounts as at December 31, 2009. As the company has the option to settle its $5.0 million in borrowings through delivery to its lender of the MAV IA 1 & 2 notes and advised its lender, during the second quarter of 2010, that it will settle the $5.0 million in borrowings through delivery of the MAV IA 1 & 2 notes, the company has recognized the fair value of the debt agreement option of $4.8 million as at December 31, 2010 using a probabilistic valuation model.
In 2010, the company received minor cash interest receipts on certain classes of notes formerly known as ABCP that it holds, as the specified short term interest rate approximated the 50 basis points required to be paid out from these investments.
During 2010, the company was advised the ineligible master asset vehicle Class 1 ("MAV IA 1") notes, with total pledged market collateral of $500.0 million, incurred several credit events within its market portfolio resulting in losses greater than the pledged market collateral. The company had an investment in the MAV IA 1 notes with an original face value of $3.7 million and a carrying value as at December 31, 2009 of nil. The company has removed the MAV IA 1 notes from its reported portfolio of longer-term notes previously known as ABCP, thereby reducing the outstanding principal amount of its portfolio by $3.7 million for the year ended December 31, 2010.
During 2009, the company reported a $2.1 million fair value impairment on its MAV IA 1 and ineligible master asset vehicle Class 2 ("MAV IA 2") notes which when combined forms the MAV IA 1 & 2 notes as previously defined, thereby reducing the December 31, 2009 carrying value of its MAV IA 1 & 2 notes to nil. The recognition of the fair value impairment during 2009 was accompanied by the removal of the original face value of the MAV IA 2 notes of $2.9 million from the company's reported portfolio of longer-term notes previously known as ABCP. Despite the permanent impairment in the MAV IA 1 & 2 notes as at December 31, 2010, the company still retains the right, subject to the terms of the credit agreement between the company and its lender, to exercise its debt agreement option in April 2011 to settle $5.0 million in borrowings through the delivery of its MAV IA 1 & 2 notes.
Although management understands there have been some third party transactions during 2010, no transparent active market quotations have developed for the eligible master asset vehicle longer term notes. As a result, management has continued to estimate the fair value of the company's investment in the eligible master asset vehicle longer term notes at December 31, 2010 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, 2010. 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 eligible master asset vehicle longer term notes approximates the risk-free rate over the expected life of the eligible master asset vehicle longer term notes. 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
of Capital Interest Weighted Weighted Risk-free
Class Notes Recovery Recovery Average Average Term Discount
of Note ($000s) Range Range Recovery Recovery (years) Rate
-------------------------------------------------------------------------
A-1 $13,970 30 - 85% 10 - 70% 81% 67% 2 - 6 3%
A-2 13,543 0 - 70% 0 - 30% 64% 27% 6 3%
B 2,459 0 - 40% 0 - 10% 36% 9% 6 3%
C 928 0 - 10% 0% 10% 0% 6 3%
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Total $30,900
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Based on the above approach the fair value of the investment in the longer term notes was $18.7 million as at December 31, 2010 and 2009 as reconciled in the following table:
<<
Years Ended December 31 2010 2009
($000)
-------------------------------------------------------------------------
Notes formerly known as ABCP, beginning of year $18,689 $22,582
Fair value impairment - (2,104)
Interest received and capital recoveries previously
included in fair value of investment (19) (1,789)
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Notes formerly known as ABCP, end of year $18,670 $18,689
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>>
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.
The theoretical fair value of the company's longer-term notes could range from $13.8 million to $23.1 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 losses. 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 First ABCP line-of credit agreement.
RELATED PARTY TRANSACTIONS
Under the terms of an administrative agreement with Connacher Oil and Gas Limited ("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 2010 (2009 - $0.2 million). From time to time, Connacher also paid bills on behalf of the company, for which it is reimbursed, in addition to providing office space for the company's Canadian Corporate office, for which it was paid fair market value rates.
In 2009, 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 total issuance of 65,343,000 units, for gross proceeds of approximately $57.5 million. Connacher is a significant shareholder of the company with a 18.5 percent equity interest as at December 31, 2010 and the Executive Chairman of the company is the Chairman and Chief Executive Officer of Connacher.
During 2010 the company incurred professional legal fees and common share issue costs of $0.6 million (2009 - $0.5 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.
Directors and officers of the company purchased 1,137,500 units from treasury for gross proceeds of $1.0 million pursuant to the 2009 Private Placement which closed on September 15, 2009. The issuance of units to the directors and officers of the company pursuant to this private placement was completed on the same terms as those units offered pursuant to the 2009 Public Offering and over allotment option (the "2009 Over Allotment"), which respectively closed on August 28 and September 4, 2009.
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, are most likely to be impacted by critical accounting estimates: debt agreement option and fair value increase, 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.
Financial instruments
Financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods depends on the following financial instruments classification:
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(a) Held-for-trading financial instruments are subsequently measured at
fair value with changes in those fair values charged immediately to
losses.
(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.
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 ACCOUNTING STANDARDS
In January 2009, the CICA issued section 1582, "Business Combinations", which replaces CICA section 1581 of the same name. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at their market price at the date of the exchange. The new guidance will require all costs of the acquisition to be expensed, which currently are capitalized as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and re-measured at fair value through earnings until settled. Currently only contingent liabilities that are resolved and payable are included in the cost to acquire the enterprise. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from non-current assets in the purchase price allocation. Section 1582 is effective on January 1, 2011, with prospective application, and early adoption is permitted. To date, the adoption of this standard has not impacted the company's Consolidated Financial Statements as the company has not acquired a business.
In January 2009, the CICA issued section 1601, "Consolidated Financial Statements", which will replace CICA section 1600 of the same name. This guidance requires consistent application of accounting policies throughout all consolidated entities. Section 1601 is effective on January 1, 2011, with prospective application, and early adoption is permitted. The adoption of this standard will have no impact on the company's Consolidated Financial Statements as the company had previously applied consistent application of accounting policies throughout its branches and subsidiaries.
In January 2009, the CICA issued section 1602, "Non-controlling Interests", which will replace CICA section 1600, Consolidated Financial Statements. This standard establishes the accounting for a non-controlling interest in a subsidiary in the Consolidated Financial Statements subsequent to a business combination. This standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net losses and components of other comprehensive losses are attributed to both the parent and non-controlling interest. Section 1602 is effective on January 1, 2011, with prospective application, and early adoption is permitted. To date, the adoption of this standard has not impacted the company as it does not have any non-controlling interests 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.
During 2008, the company commenced the transition process to IFRS and was progressing towards completion throughout 2009 and 2010. In January 2011, the company entered into an Arrangement Agreement whereby Gran Tierra Energy will acquire all of the company's outstanding common shares and common share purchase warrants pursuant to a court-approved plan of arrangement. The Arrangement is subject to approval by not less than two thirds of the company's shareholders at a meeting to be held on March 17, 2011, in addition to being subject to other customary conditions, including the approval of the Court of Queen's Bench of Alberta (see "SUBSEQUENT EVENT" for further details). Gran Tierra Energy is a company that files its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America as it is a company that is incorporated and primarily trades in the Unites States. If the Arrangement is approved by the Petrolifera Shareholders and the other conditions to closing are satisfied as presently contemplated, the Arrangement will be completed on March 18, 2011. Assuming the completion of the Arrangement, Petrolifera will become an indirect wholly-owned subsidiary of Gran Tierra Energy, Petrolifera will cease to be a reporting issuer under applicable securities laws and the Petrolifera Shares and Petrolifera Warrants will be delisted by the Toronto Stock Exchange, and the accounts of Petrolifera will be consolidated with the accounts of Gran Tierra Energy in accordance with accounting principles generally accepted in the United States of America. For this reason, in January 2011 the company's management deferred its IFRS transition project pending the result of the Petrolifera Shareholders' vote on the Arrangement.
At the time of the decision to defer the company's IFRS transition project, management was in the final implementation phase where it was preparing the quantified impact of recommended IFRS accounting policies for adoption and the selection of "IFRS - 1, First-time Adoption" elective exemptions for presentation to the Audit Committee. Although management has not completed this analysis, management anticipates that it could conclude the IFRS implementation phase by completing this analysis and providing to the company's Audit Committee, for its approval, quantified analysis of management's recommended IFRS accounting policies and IFRS - 1 elective exemptions prior to the preparation of Consolidated Financial Statements as at and for the three months ended March 31, 2011.
WORK AND OPERATING LEASE COMMITMENTS, 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. During 2009 and 2010, Petrolifera relinquished approximately one-third and one-half of Block 106 and 107, respectively. Based on its interpretation of the 476 km and 950 km 2D seismic programs acquired over Blocks 106 and 107, respectively, by the company in 2007 and 2008, Petrolifera believes it has retained the most prospective acreage under Block 106 and 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 received approval of its Block 107 Environmental Impact Assessment ("EIA") for several potential drilling sites and is awaiting approval of its recently filed EIA amendment, at which time it can commence with the fourth period's work commitment requiring one well to be completed by 2013. At December 31, 2010, the company was in the process of completing its EIA for Block 106 prior to entering the fifth period's work commitment, which requires one well to be drilled or 300 km of seismic to be completed by 2012. See" SUBSEQUENT EVENTS" for futher detail. The company has the right to withdraw from the licenses at the end of each period associated with the term of the licenses.
In 2007, the company was granted three Colombian concessions comprised of one license, Sierra Nevada, and two Technical Evaluation Agreements ("TEAs"). Petrolifera converted the Turpial and Sierra Nevada II TEAs into exploration licenses with the latter renamed Magdalena. The company has completed the second phase of its Sierra Nevada License work program by drilling an exploratory well, Brillante SE-1X, to a total depth of 9,500 feet during 2010. The company also completed a 3D seismic program over the La Pinta structure which, when combined with the Brillante SE-1X exploratory well, is anticipated to complete the Sierra Nevada's second phase work program. The completion of this phase is still to be acknowledged by the ANH. The company has notified the ANH that it will proceed with phase three of the Sierra Nevada License work program, which requires the drilling of one exploration well prior to June 2011. While still to be acknowledged by ANH, the company recently completed the second phase 2D seismic acquisition and interpretation work program on its Turpial License. This was disproportionately financed by the company's joint venturer. The company is in the first phase of its Magdalena License, which requires an exploratory well to reach targeted depth prior to March 2011. The company spudded a well on its San Angel prospect in February 2011 with a projected drilling targeted depth of approximately 7,500 feet and forecast drilling time of 33 days.
The company is in the first phase of its Magdalena License, which requires an exploratory well to reach targeted depth prior to March 2011. The company spudded a well on its San Angel prospect in February 2011 with a projected drilling targeted depth of approximately 7,500 feet and forecast drilling time of 33 days.
In Argentina, the company has farmed out its Puesto Guevara Concession work commitment of US$0.6 million through an agreement reached in 2010. Once the company's joint venturer has funded the work commitment for the Puesto Guevara Concession, the company's working interests will be reduced to 44 percent. The company is negotiating with the Province of Rio Negro, Argentina, that the Vaca Mahuida Concession includes exploitation rights which, if provided, are anticipated to allow the company and its joint venture partners with the right to realize production during 2011 from the 2010 drilling program. The company's remaining Argentinean work commitment of US$2.4 million on its Puesto Morales Este Concession requires the drilling of two development wells and associated facilities in 2011.
OPERATING LEASE COMMITMENTS
The company's gross operating 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
2011 2012 to 2012 Total
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($000)
-------------------------------------------------------------------------
Drilling service contracts,
leases and administrative
services agreement $4,227 $1,072 $781 $6,080
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GUARANTEES
As at December 31, 2010 the company has issued letters of credit in the total amount of US$1.4 million and US$0.1 million, respectively, to secure the capital expenditure requirements associated with the Colombian and Peruvian work commitments (Dec. 31, 2009 - US$2.1 million and US$1.7 million, respectively). As at December 31, 2009, a deposit of US$4.1 million was held in a trust account in Colombia which financed the 2010 work obligations on the Magdalena License as they occurred.
OFF-BALANCE SHEET ARRANGEMENTS
The company does not have any off-balance sheet arrangements.
SUBSEQUENT EVENTS
a) Arrangement Agreement with Gran Tierra Energy Inc.
On January 17, 2011, the company announced that it has entered into an Arrangement Agreement whereby Gran Tierra Energy will indirectly acquire all of the Petrolifera Shares and Petrolifera Warrants pursuant to a court-approved plan of arrangement. The Arrangement is subject to approval by not less than two thirds of the company's shareholders, either in person or by proxy, at the ("Special Meeting of Shareholders") to be held in Calgary, Alberta on March 17, 2011, in addition to being subject to other customary conditions. Under the terms of the Arrangement Agreement, the company's shareholders will receive, from Gran Tierra Energy's treasury, 0.1241 of a share of Gran Tierra Energy for each Petrolifera Share held. In addition, each holder of Petrolifera Warrants will receive 0.1241 of a common share purchase warrant of Gran Tierra Energy ("Replacement Warrant") with an exercise price of $9.67 per share and an expiry date of August 28, 2011 for each Petrolifera Warrant held. Each Replacement Warrant will be exercisable for one Gran Tierra Energy common share and upon being exercised, holders would not be required to make a cash payment as they would receive a net number of Gran Tierra common shares equal to the intrinsic value of the Replacement Warrants.
All of the company's directors and officers, together with the company's largest shareholder, Connacher, representing in aggregate 21 percent of the issued and outstanding Petrolifera Shares as at January 31, 2011, have entered into agreements with Gran Tierra Energy to vote in favour of, and otherwise support the Arrangement, subject to customary exceptions.
In the event that the Arrangement Agreement is terminated due to a breach of representation, warranty or covenant by the company that has a material adverse effect on the company, the company will be required to pay to Gran Tierra Energy a termination fee in the amount of $7.9 million.
b) Relinquishment of Exploration License Rights to Peruvian Block 106
On March 4, 2011 Petrolifera issued a letter to Perupetro, the state agency of Peru, advising of its intention to surrender the license covering Block 106 in the Maranon Basin, Peru. The company's Block 106 carrying value of approximately $21.3 million was included as an unproved property cost in properties and equipment in the Consolidated Balance Sheet as at December 31, 2010. The company retains licenses covering Blocks 107 and 133 in the Ucayali Basin, Peru.
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 Vice President, Finance 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, 2010 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 2010 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.
The completion of the proposed Arrangement with Gran Tierra Energy, which is the result of a broad and extensive strategic review process, is subject to a number of conditions precedent, certain of which are outside of the control of Petrolifera, including the receipt of the final order of the Court of Queen's Bench of Alberta. There can be no certainty, nor can Petrolifera provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied. If the Arrangement is not approved and the Petrolifera Board of Directors decides to pursue another merger or business combination, there can be no assurance that it will be able to find a party willing to pay an equivalent or more attractive price than the consideration to be received pursuant to the arrangement with Gran Tierra Energy.
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. If the Arrangement with Gran Tierra Energy is not completed as anticipated, the company may be required to raise additional capital to fund its activities, including the remaining work commitments associated with the company's exploratory lands and mandatory debt repayments. Capital markets may not be receptive to offerings of new equity from treasury, whether by way of private placement or public offerings and future equity offerings could result in significant dilution to shareholders. Additionally, there can be no assurance that the outstanding Petrolifera Warrants will be exercised to provide the company with additional liquidity.
Access to financing is impacted by the nature and location of the company's assets. The company's principal producing properties are located in Argentina which is subject to political, economic and other uncertainties. These risks and uncertainties 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 and changes in economic, political and social conditions in jurisdictions in which the company operates 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 2010 SUMMARY RESULTS
<<
-------------------------------------------------------------------------
For the Three Months Ended December 31 2010 2009 % Change
-------------------------------------------------------------------------
FINANCIAL ($000, except per share
amounts)
-------------------------------------------------------------------------
Total revenue $12,959 $17,900 (28)
Cash flow from operations before
non-cash working capital(1) 4,066 5,867 (31)
Per share, basic and diluted 0.03 0.05 (40)
Net loss (4,040) (4,081) 1
Per share, basic and diluted (0.03) (0.03) -
Net capital expenditures (recovery) (4,278) 9,378 (146)
Cash 11,046 35,732 (69)
Working capital 13,038 (2,508) 620
Long-term investment(2) 18,670 19,395 (4)
Long-term debt 36,589 27,464 33
Shareholders' equity 239,109 232,126 3
Total assets $329,067 $349,065 (6)
-------------------------------------------------------------------------
OPERATING
-------------------------------------------------------------------------
Daily sales volumes
Crude oil and natural gas
liquids - bbl/d 2,358 3,833 (38)
Natural gas - mcf/d 3,535 4,056 (13)
Barrels of oil equivalent - boe/d 2,947 4,509 (35)
Average selling prices
Crude oil and natural gas
liquids - $/bbl $55.97 $48.08 16
Natural gas - $/mcf $2.54 $2.53 -
Barrels of oil equivalent - $/boe $47.78 $43.15 11
-------------------------------------------------------------------------
COMMON SHARES OUTSTANDING (000s)
-------------------------------------------------------------------------
Weighted average
Basic 145,478 121,759 19
Diluted(3) 145,478 121,777 19
End of period 145,478 121,759 19
-------------------------------------------------------------------------
(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 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 fourth quarter 2010 Cash
Flow table. 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 ABCP with a face value
of $30.9 million and $34.6 million as at December 31, 2010 and 2009,
respectively. Portions of bank debt and long-term debt in the
aggregate amount of $27.5 million as at December 31, 2010 were
primarily secured on a limited recourse basis by the underlying notes
formerly known as ABCP. Long-term bank debt of $27.5 million as at
December 31, 2009 was primarily secured on a limited recourse basis
by the underlying notes formerly known as ABCP.
(3) As the company has net losses during the three months ended December
31, 2010 and 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 calculations.
>>
FOURTH QUARTER 2010 FINANCIAL AND OPERATING REVIEW
SALES VOLUMES, PRICING AND REVENUE
<<
-------------------------------------------------------------------------
For the Three Months Ended December 31 2010 2009 % Change
-------------------------------------------------------------------------
Daily sales volumes:
Crude oil and natural gas
liquids - bbl/d 2,358 3,833 (38)
Natural gas - mcf/d 3,535 4,056 (13)
Equivalent - boe/d 2,947 4,509 (35)
-------------------------------------------------------------------------
Average selling prices:
Crude oil and natural gas
liquids - $/bbl $55.97 $48.08 16
Natural gas - $/mcf 2.54 2.53 -
Weighted average selling
price - $/boe $47.78 $43.15 11
-------------------------------------------------------------------------
Petroleum and natural gas sales
($000) $12,952 $17,898 (28)
Interest and other income ($000) 7 2 250
-------------------------------------------------------------------------
Total revenue ($000) $12,959 $17,900 (28)
-------------------------------------------------------------------------
>>
Petroleum and natural gas revenues in the fourth quarter of 2010 were $13.0 million on sales volumes of 2,947 boe per day, compared to $17.9 million on sales of 4,509 boe per day during the fourth quarter of 2009, a decrease of 28 percent for revenue and 35 percent for sales volumes. For the three months ended December 31, 2010, sales of crude oil and natural gas liquids represented 80 percent of the company's sales volumes, which was lower than the 85 percent for the comparable period in 2009.
The reduction in petroleum and natural gas revenues during the three months ended December 31, 2010, compared to the same period in 2009, reflects lower sales volumes for both crude oil and natural gas, partially offset by higher average selling prices. The lower sales volume for 2010, compared to 2009, was mainly attributable to natural production declines, the lack of sustained capital investment during the strategic alternatives review process and the temporary shut in of two key producing wells, PMN - 1002 and 1012, caused by pump failures. In addition the company also experienced watercut increases and petroleum rate declines on its PMN-1022 and 1108 wells, not corrected to date by chemical treatments and, to a lesser extent, production anomalies from less significant wells. Both revenues and sales volumes, at $13.0 million and 2,947 boe per day, respectively, were 17 percent lower than experienced during the third quarter of 2010, when petroleum and natural gas revenues were $15.7 million on sales volumes of 3,564 boe per day,
Prices realized for the company's crude oil and natural gas liquids sales increased 16 percent to average $55.97 per barrel for the three months ended December 31, 2010, compared to $48.08 per barrel realized during the same period in 2009. Higher realized US dollar crude oil pricing averaging US$54.90 per barrel during the three months ended December 31, 2010, compared favorably to the average US$53.70 per barrel received during the same period in 2009. During the three months ended December 31, 2010 and December 31, 2009, the respective crude oil price realized by Petrolifera averaged approximately 65 percent and 61 percent of the WTI average of US$85.07 and US$76.06 per barrel. For the three months ended December 31, 2010, the natural gas price averaged $2.54 per mcf (US$2.52 per mcf), is comparable to the average of $2.53 per mcf (US$2.40 per mcf) realized during the same period in 2009. Despite improvements in commodities pricing, the weighted average selling price was tempered by an 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 and an average four percent strengthening of the Canadian dollar, relative to the US dollar.
FOURTH QUARTER 2010 ROYALTIES, OPERATING EXPENSES AND CORPORATE NETBACKS
CORPORATE NETBACKS(1)
<<
For the Three Months
Ended December 31 2010 2009
($000, except per unit
amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Average daily sales
(boe/d) 2,947 4,509
Petroleum and natural
gas sales $12,952 $47.78 $17,898 $43.15
Interest and other income 7 0.03 2 0.00
Royalties (1,897) (7.00) (2,655) (6.40)
-------------------------------------------------------------------------
Net revenue $11,062 $40.80 $15,245 $36.75
Operating costs (5,175) (19.09) (5,568) (13.42)
-------------------------------------------------------------------------
Corporate netback $5,887 $21.71 $9,677 $23.33
-------------------------------------------------------------------------
(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
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 the quarterly corporate
netback to net loss can be found in the Fourth Quarter 2010 Net Loss
table.
>>
The corporate netback per boe decreased seven percent during the fourth quarter of 2010 relative to same period in 2009. Higher realized commodities pricing was offset by higher operating costs per boe. Petrolifera's calculated unit netback of $21.71 per boe for the three months ended December 31, 2010, was 45 percent of the average selling price per boe, which was a reduction from the 54 percent achieved during the same period in 2009.
The corporate netback in the fourth quarter of 2010 fell 12 percent, compared to the third quarter in 2010, due to comparable average commodities selling prices being offset by higher operating costs per boe.
FOURTH QUARTER 2010 ROYALTIES
Royalties in the fourth quarter of 2010 were $1.9 million ($7.00 per boe), or 15 percent of petroleum and natural gas sales, compared to $2.7 million ($6.40 per boe), or 15 percent of petroleum and natural gas sales in the same period in 2009, and to $2.2 million ($6.77 per boe) or 14 percent of petroleum and natural gas sales in the third quarter of 2010.
FOURTH QUARTER 2010 OPERATING COSTS
Total operating costs during the three months ended December 31, 2010, decreased by approximately seven percent compared to the same period in 2009, largely due to lower sales volumes, lower fuel costs from replacement of diesel power generators with natural gas equipment and a strengthening of the Canadian dollar relative to the US dollar.
On a per boe basis, operating costs increased 42 percent for the three months ended December 31, 2010, compared to the same period for 2009. Lower sales volumes, higher well service costs from the replacement of pumping rods in several wells, in addition to higher renegotiation costs for certain Argentinean concessions during the three months ended December 31, 2010, compared to the same period in 2009, resulted in the increase per boe produced.
Total operating costs were four percent lower in the fourth quarter of 2010 compared to the third quarter of 2010, largely due to lower sales volumes. On a per boe basis, operating costs were 16 percent higher for the three months ended December 31, 2010, compared to the third quarter of 2010, again largely due to lower sales volumes and higher well service costs from the replacement of pumping rods in several wells.
FOURTH QUARTER 2010 NET LOSS AND SHARES OUTSTANDING
FOURTH QUARTER 2010 NET LOSS
<<
-------------------------------------------------------------------------
For the Three Months Ended
December 31 2010 2009
-------------------------------------------------------------------------
($000, except per unit
amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Corporate netback $5,887 $21.71 $9,677 $23.33
General and administrative (2,261) (8.34) (1,915) (4.62)
Stock-based compensation (377) (1.39) (675) (1.63)
Finance charges (1,071) (3.95) (1,040) (2.51)
Foreign exchange gain
(loss) 545 2.00 (225) (0.54)
Fair value increase 17 0.06 - -
Depletion, depreciation
and accretion (6,239) (23.01) (8,936) (21.55)
Income tax provision (281) (1.25) (724) (1.75)
Taxes other than income
taxes (260) (0.96) (243) (0.59)
-------------------------------------------------------------------------
Net loss $(4,040) $(15.12) $(4,081) $(9.85)
-------------------------------------------------------------------------
>>
For the fourth quarter of 2010 and 2009, the company reported net losses of $4.0 million, which equated to net losses of $0.03 per weighted average basic and diluted share. The slight decrease in the net loss recognized during the fourth quarter of 2010, compared to the net loss in the same quarter in 2009, was primarily due to a lower DD&A expense, income taxes, and stock-based compensation in addition to a foreign exchange gain, partially offset by higher G&A.
For the three months ended December 31, 2010, the company's other comprehensive loss was $7.4million, compared to the other comprehensive loss in the same 2009 period of $7.1 million. The other comprehensive losses during the three months ended December 31, 2010 and 2009, were due to a three percent strengthening, in each respective period, of the Canadian dollar, relative to the US dollar, which reduced the reported net assets of the company's Argentinean operations.
SHARES OUTSTANDING
During the three months ended December 31, 2010, the weighted average number of common shares outstanding was 145.5 million compared to 121.8 million during the same period in 2009. The increase in the weighted average number of common shares for the three months ended December 31, 2010, relative to the same period in 2009, primarily reflected the April 2010 issuance of 23.7 million common shares from treasury for gross proceeds of $20.1 million. As the company had net losses during the three months ended December 31, 2010 and 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 calculations.
G&A AND STOCK-BASED COMPENSATION
G&A expenses were $2.3 million and $1.9 million for the three months ended December 31, 2010 and 2009, respectively. The increase in G&A for the fourth quarter of 2010, relative to the same period in 2009, was primarily due to increased professional fees and non-executive retention payments related to the company's strategic alternatives process. On a per boe basis, G&A was $8.34 per boe of sales for the three months ended December 31, 2010 compared to $4.62 per boe in the same period in 2009. The increase in G&A per boe was for the reasons cited above but primarily due to lower sales volumes. G&A expenses of $1.4 million and $1.1 million were also capitalized in the three months ended December 31, 2010 and 2009, respectively.
During the three months ended December 31, 2010, a non-cash expense of $0.4 million (2009 - $0.7 million) was recorded as stock-based compensation. The decrease in stock-based compensation in the fourth quarter of 2010, as compared to the same period in 2009, primarily reflects a reduction in the number of granted options as granted in the prior months of each respective year combined with a decrease in the weighted average fair value assigned to each granted option.
FINANCE CHARGES
Comparable finance charges of $1.1 million and $1.0 million for the three months ended December 31, 2010 and December 31, 2009, respectively, primarily reflected lower average company borrowings in the fourth quarter of 2010, as compared to the same period in 2009, offset by a higher effective interest rate of 6.0 percent as compared to 3.5 percent, due to the revised reserve-backed credit facility.
FOREIGN EXCHANGE
During the three months ended December 31, 2010 a foreign exchange gain of $0.5 million was recognized on Argentinean and Corporate working capital, compared to a foreign exchange loss of $0.2 million in the same period of 2009.
FAIR VALUE OF DEBT AGREEMENT OPTION
During the three months ended December 31, 2010, the company recognized a modest present value increase in its debt agreement option as exercisable in April 2011. See "RESTRICTED CASH, DEBT AGREEMENT OPTION AND LONG-TERM INVESTMENTS" for further details.
DEPLETION, DEPRECIATION & ACCRETION ("DD&A")
DD&A for the three months ended December 31, 2010 totaled $6.2million, a decrease compared to $8.9 million in the same period in 2009, largely due to a lower production volumes. On a boe basis, for the three months ended December 31, 2010, DD&A of $23.01 per boe was higher than the $21.55 per boe in the same period for 2009, primarily due to higher estimated future costs and a 2010 year-end reserve adjustment.
Accretion expense, which is included in DD&A expense, was $0.1 million for the three months ended December 31, 2010 and 2009.
TAXES
The current income tax provision of $0.7 million and $0.5 million for the three months ended December 31, 2010 and December 31, 2009, respectively, related mostly to income taxes payable in Argentina. Additionally, a future income tax recovery of $0.4 million and provision of $0.3 million in the relevant three months of 2010 and 2009, 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 a certain Argentinean entity's earnings, less general corporate deductions, is not indicative of the company's jurisdictional tax rates for the three months ended December 31, 2010 and December 31, 2009. Taxes other than income taxes of $0.3 million and $0.2 million for the three months ended December 31, 2010 and December 31, 2009, respectively, represent taxes charged on all banking transactions in Argentina.
CAPITAL EXPENDITURES
<<
-------------------------------------------------------------------------
For the Three Months Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Colombia $3,917 $4,482
Argentina 1,349 7,169
Peru 439 485
Corporate 39 9
-------------------------------------------------------------------------
Capital expenditures $5,744 $12,145
Proceeds from disposition and farmout arrangements (10,022) (2,767)
-------------------------------------------------------------------------
Net capital expenditures (recovery) $(4,278) $9,378
-------------------------------------------------------------------------
>>
The company had a net capital recovery during the three months ended December 31, 2010 of $4.3 million, compared to net capital expenditures of $9.4 million for the same period in 2009. The net capital recovery during the fourth quarter of 2010 primarily resulted from the selling of a 25 percent working interest in the company's Sierra Nevada License in Colombia for cash proceeds of US$10.0 million. These disposition proceeds assisted in part in financing capital spending activity during the fourth quarter of 2010, which primarily included pre-drilling activities of an exploratory well, San Angel 1001X, on the company's Magdalena License in the Lower Magdalena Basin onshore Colombia and to a lesser extent some facilities expenditures related to the company's 2010 expanded water treatment capacity increase in addition to certain capitalized workover costs on the company's Puesto Morales/Rinconada Concession.
FOURTH QUARTER 2010 CASH FLOW
Reconciliation of net earnings to cash flow:
<<
-------------------------------------------------------------------------
For the Three Months Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net loss $(4,040) $(4,081)
Add (less) non-cash charges:
Depletion, depreciation and accretion 6,239 8,936
Fair value increase (17) -
Future income tax provision (recovery) (386) 268
Stock-based compensation 377 675
Amortization of deferred finance and other charges 2,015 212
Unrealized foreign exchange gain (122) (143)
-------------------------------------------------------------------------
Cash flow $4,066 $5,867
-------------------------------------------------------------------------
Per share, basic $0.03 $0.05
Per share, diluted $0.03 $0.05
-------------------------------------------------------------------------
>>
Cash flow for the three months ended December 31, 2010 was $4.1 million or $0.3 per weighted average basic and diluted share, compared to $5.9 million or $0.05 per weighted average basic and diluted share for the same period in 2009. The 31 percent decrease in total cash flow during the fourth quarter of 2010, relative to the same period in 2009, primarily resulted from a reduction in sales volumes and, to a lesser extent, an increase in cash G&A expenses attributable to the strategic alternatives review process. Cash flow per share for the three months ended December 31, 2010 decreased relative to the same period for 2009 for the aforementioned reasons and from the impact of an increase in the number of shares outstanding.
OUTLOOK
If necessary approvals are secured at the Special Meeting of Shareholders scheduled for March 17, 2011, and all other conditions to the Arrangement are satisfied or waived, Petrolifera will be indirectly acquired by Gran Tierra Energy pursuant to the Arrangement and Petrolifera Shareholders and Warrantholders will respectively become Gran Tierra shareholders and warrant holders.
FORWARD-LOOKING INFORMATION
Forward-looking information contained in this report 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, expectations with respect to general economic conditions and expectations regarding the proposed Arrangement with Gran Tierra Energy. 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. The proposed arrangement with Gran Tierra Energy is subject to the satisfaction of a number of conditions, including the approval of a special resolution by not less than 66 2/3% of the votes cast by Petrolifera Shareholders, either in person or by proxy, at the shareholders meeting to be held on March 17, 2011, approval by the Court of Queen's Bench of Alberta of the final order approving the arrangement, receipt of all required regulatory and third party consents and approvals and such other conditions as are set forth in the Arrangement Agreement dated January 17, 2011 and filed on SEDAR at www.sedar.com.
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, 2010 and December 31, 2009, 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, 2010. 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, 2010. 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, corporate netbacks 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, corporate netbacks and EBITDA are reconciled to net earnings in the MD&A.
QUARTERLY RESULTS(4)
<<
-------------------------------------------------------------------------
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 and diluted(5), per
share 0.02 0.06 (0.14) (0.03)
Net capital expenditures
(recovery) 25,612 20,477 13,389 9,378
Cash 30,994 14,803 55,953 35,732
Working capital (deficit) 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 -
$/boe(2):
Weighted average selling
price 46.30 42.97 42.93 43.15
Interest and other income 0.06 - - -
Royalties 6.02 6.74 6.09 6.40
Operating costs 10.33 11.04 14.36 13.42
Corporate netback(3) 30.01 25.20 22.48 23.33
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
(000, EXCEPT SHARE PRICE)
-------------------------------------------------------------------------
Shares outstanding at end
of period 54,948 54,948 121,759 121,759
Weighted average shares
outstanding for the period:
Basic 54,948 54,948 82,418 121,759
Diluted(5) 55,195 55,600 82,539 121,777
Volume traded during quarter 10,053 13,268 55,032 35,921
Common share price ($):
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2010
-------------------------------------------------------------------------
For the Three Months Ended Mar 31 June 30 Sept 30 Dec 31
-------------------------------------------------------------------------
FINANCIAL RESULTS ($000,
EXCEPT PER SHARE AMOUNTS)
- UNAUDITED
-------------------------------------------------------------------------
Total revenue 17,908 16,794 15,694 12,959
Cash flow(1) 7,177 5,270 4,339 4,066
Basic, per share(1) 0.06 0.04 0.03 0.03
Diluted, per share(1) 0.06 0.04 0.03 0.03
Net earnings (loss) (2,553) (297) (2,702) (4,040)
Basic and diluted(5), per
share (0.02) 0.00 (0.02) (0.03)
Net capital expenditures
(recovery) 15,742 17,696 7,530 (4,278)
Cash 32,207 41,179 11,477 11,046
Working capital (deficit) (10,659) 17,156 10,354 13,038
Long-term investments(6) 19,202 19,210 18,689 18,670
Long-term bank debt 27,456 45,373 40,693 36,589
Shareholders' equity 227,097 251,260 246,050 239,109
Total assets 345,509 376,233 339,575 329,067
-------------------------------------------------------------------------
OPERATING RESULTS
-------------------------------------------------------------------------
Sales volumes:
Crude oil and natural gas
liquids - bbl/d 3,706 3,356 2,885 2,358
Natural gas - mcf/d 3,862 3,184 4,077 3,535
Equivalent - boe/d(2) 4,349 3,887 3,564 2,947
Pricing:
Crude oil and natural gas
liquids - $/bbl 50.65 52.13 55.14 55.97
Natural gas - $/mcf 2.54 2.66 2.72 2.54
Selected highlights -
$/boe(2):
Weighted average selling
price 45.41 47.19 47.79 47.78
Interest and other income 0.34 0.29 0.07 0.03
Royalties 6.50 6.76 6.77 7.00
Operating costs 13.24 14.92 16.50 19.09
Corporate netback(3) 26.01 25.80 24.59 21.71
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
(000, EXCEPT SHARE PRICE)
-------------------------------------------------------------------------
Shares outstanding at end
of period 121,798 145,478 145,478 145,478
Weighted average shares
outstanding for the period:
Basic 121,798 141,835 145,478 145,478
Diluted(5) 121,812 141,835 145,478 145,478
Volume traded during quarter 47,157 15,295 13,739 15,778
Common share price ($):
High 1.31 1.01 0.81 0.79
Low 0.84 0.64 0.55 0.58
Close (end of period) 0.96 0.65 0.79 0.62
-------------------------------------------------------------------------
(1) Cash flow from operations before non-cash working capital changes 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) in this, or the corresponding period's 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 the MD&A in respect of the applicable quarter.
(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. Fluctuations in results for the quarters
ended September 30, 2010 and December 31, 2010 were adversely
affected by increased professional fees and a non-executive retention
payment related to the company's strategic alternatives process and
lack of sustained capital investment during the strategic
alternatives review process.
(5) As the company has net losses during the three months ended September
30 2009 and for each subsequent quarter thereafter, 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
calculations.
(6) Includes carrying value of notes received for ABCP with a face value
of $30.9 million and $34.6 million as at December 31, 2010 and 2009
respectively. Long-term debt in the amount of $22.5 million as at
December 31, 2010 is primarily secured on a limited recourse basis by
the underlying notes formerly known as ABCP. Bank debt of $27.5
million as at December 31, 2009 was secured by the ABCP.
>>
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED BALANCE SHEETS
<<
-------------------------------------------------------------------------
As at December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
ASSETS
Current
Cash $11,046 $35,732
Accounts receivable 25,667 20,871
Restricted cash 1,502 3,247
Inventory (Note 3) 937 958
Financial instrument - debt agreement option
(Note 6) 4,817 -
Income taxes receivable 2,163 4,636
Prepaid expenses 296 464
Deferred financing costs - 706
-------------------------------------------------------------------------
46,428 66,614
Long-term investments (Note 6) 18,670 19,395
Properties and equipment (Note 4) 263,969 263,056
-------------------------------------------------------------------------
$329,067 $349,065
-------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities $12,439 $15,850
Income taxes payable 1,026 913
Bank debt (Note 5) 19,879 52,330
Due to a related company (Note 7) 46 29
-------------------------------------------------------------------------
33,390 69,122
Long-term bank debt (Note 5) 36,589 27,464
Asset retirement obligations (Note 8) 9,952 9,552
Future income taxes (Note 9) 10,027 10,801
-------------------------------------------------------------------------
89,958 116,939
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital and warrants (Note 10(a)) 167,210 148,264
Contributed surplus (Note 10(f)) 23,146 20,453
Accumulated other comprehensive loss (8,817) (3,753)
Retained earnings 57,570 67,162
-------------------------------------------------------------------------
239,109 232,126
-------------------------------------------------------------------------
$329,067 $349,065
-------------------------------------------------------------------------
Commitments and guarantees (Note 13)
Subsequent events (Note 14)
>>
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
<<
Years Ended December 31 2010 2009
$000 (except per share amounts)
-------------------------------------------------------------------------
REVENUE
Petroleum and natural gas $63,090 $83,752
Interest and other income 265 39
-------------------------------------------------------------------------
63,355 83,791
Royalties (9,053) (12,017)
-------------------------------------------------------------------------
54,302 71,774
-------------------------------------------------------------------------
EXPENSES
Operating 21,046 22,930
General and administrative 7,769 8,285
Finance charges (Note 5) 4,204 5,097
Taxes other than income taxes 1,466 1,874
Foreign exchange loss 834 115
Depletion, depreciation and accretion (Note 4) 28,951 33,546
Fair value impairment (increase) (Note 6) (4,817) 2,104
Stock-based compensation (Note 10(e)) 2,695 4,674
-------------------------------------------------------------------------
62,148 78,625
-------------------------------------------------------------------------
Loss before income taxes (7,846) (6,851)
Current income tax provision (Note 9) 1,933 3,362
Future income tax provision (recovery) (Note 9) (187) 612
-------------------------------------------------------------------------
1,746 3,974
-------------------------------------------------------------------------
NET LOSS (9,592) (10,825)
RETAINED EARNINGS, BEGINNING OF YEAR 67,162 77,987
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $57,570 $67,162
-------------------------------------------------------------------------
NET LOSS PER SHARE (Note 12(a))
Basic and diluted $(0.07) $(0.14)
-------------------------------------------------------------------------
>>
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
<<
-------------------------------------------------------------------------
Years Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net loss $(9,592) $(10,825)
Foreign currency translation adjustment (5,064) (19,859)
-------------------------------------------------------------------------
Comprehensive loss $(14,656) $(30,684)
-------------------------------------------------------------------------
>>
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
<<
-------------------------------------------------------------------------
Years Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Accumulated other comprehensive income (loss),
beginning of year $(3,753) $16,106
Foreign currency translation adjustment (5,064) (19,859)
-------------------------------------------------------------------------
Accumulated other comprehensive loss, end of year $(8,817) $(3,753)
-------------------------------------------------------------------------
>>
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
<<
-------------------------------------------------------------------------
Years Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Cash provided by (used in) the following activities:
OPERATING
Net loss $(9,592) $(10,825)
Items not involving cash:
Depletion, depreciation and accretion (Note 4) 28,951 33,546
Fair value impairment (increase) (Note 6) (4,817) 2,104
Amortization of deferred & other charges 2,890 868
Stock-based compensation (Note 10(e)) 2,695 4,674
Unrealized foreign exchange loss 912 1,428
Future income tax provision (recovery) (Note 9) (187) 612
-------------------------------------------------------------------------
Cash flow from operations before non-cash working
capital changes 20,852 32,407
Changes in non-cash working capital (Note 12(b)) (658) 8,989
-------------------------------------------------------------------------
20,194 41,396
-------------------------------------------------------------------------
FINANCING
Issue of common shares and common share purchase
warrants (Note 10(a)) 20,148 58,768
Repayment of bank debt and long-term bank debt (19,897) (21,938)
Deferred financing costs (2,078) -
Share issue costs (Note 10(b)) (1,254) (3,060)
Proceeds of bank debt or long-term bank debt - 19,896
-------------------------------------------------------------------------
(3,081) 53,666
-------------------------------------------------------------------------
INVESTING
Exploration and development of petroleum and
natural gas properties (50,506) (71,623)
Proceeds from farmout and property sale
agreements (Note 4) 13,817 2,767
Proceeds from restricted cash 2,475 2,965
Investment in restricted cash (158) (4,674)
Receipt of interest and capital recoveries on
long-term investment (Note 6) 19 1,789
Changes in non-cash working capital (Note 12(b)) (7,198) (14,158)
-------------------------------------------------------------------------
(41,551) (82,934)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH (24,438) 12,128
Impact of foreign exchange on foreign currency
denominated cash balances (248) (7,097)
CASH, BEGINNING OF YEAR 35,732 30,701
-------------------------------------------------------------------------
CASH, END OF YEAR $11,046 $35,732
-------------------------------------------------------------------------
Supplementary cash flow information (Note 12(c))
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2010
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
accordance with Canadian generally accepted accounting principles in
Canadian dollars, unless otherwise noted. 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) and 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 petroleum 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 petroleum 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, at least annually, a "ceiling test" to the net book
value of petroleum and natural gas properties for each cost centre to
determine if an impairment loss should be recognized when the carrying
value of each cost centre is not recoverable and exceeds its fair value.
The carrying value is assessed to be recoverable when the sum of each
cost centre's undiscounted cash flows expected from the production of
proved reserves exceeds its carrying value less impairment, unproved
properties and major development project costs. If the carrying value is
assessed to not be recoverable, the calculation then compares each cost
centre's carrying value less impairment, unproved properties and major
development project costs to the sum of the discounted cash flows
expected from the production of proved and probable reserves. Should the
carrying value exceed this sum, an impairment loss is recognized. The
cash flows are estimated using projected future commodity prices and
costs and are discounted using a 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 losses.
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 rate.
Asset retirement obligations
The company provides for the costs of retirement obligations associated
with long-lived assets, including the abandonment of petroleum and
natural gas wells, related facilities, compressors and gas plants and the
removal of equipment from leased acreage. 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, as adjusted for the expected inflation rate, to abandon such
assets using the company's credit adjusted risk-free interest rate. The
obligation is reviewed regularly by management based upon current
regulations, costs, technologies and industry standards. The discounted,
recognized obligation is initially capitalized as part of the carrying
amount of the related petroleum and natural gas properties. The liability
is accreted to losses, as included as a component of depletion and
depreciation expense, until it is settled or the property is sold. The
increase in petroleum and natural gas properties is depleted on the same
basis as the remainder of the petroleum 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 when 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
losses.
(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.
Measurement uncertainty
The timely preparation of the Consolidated 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 the ceiling test and impairment calculations and amounts used in the
determination of the future tax liability are based, in part, on
estimates of petroleum and natural gas 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. Long-term investments
and the debt agreement option fair valuations are based on probabilistic
valuation models. 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 losses 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 and share purchase warrants, in addition to the
fair value of granted options not yet recognized as stock-based
compensation, 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, depreciation and accretion 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 the net loss as shown in the
Consolidated Statements of Operations and Retained 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
Losses and Accumulated Other Comprehensive income (loss).
Impact of New Accounting Standards
In January 2009, the CICA issued section 1582, "Business Combinations",
which replaces CICA section 1581 of the same name. Under this guidance,
the purchase price used in a business combination is based on the fair
value of shares exchanged at their market price at the date of the
exchange. The new guidance will require all costs of the acquisition to
be expensed, which currently are capitalized as part of the purchase
price. Contingent liabilities are to be recognized at fair value at the
acquisition date and re-measured at fair value through earnings until
settled. Currently only contingent liabilities that are resolved and
payable are included in the cost to acquire the enterprise. In addition,
negative goodwill is required to be recognized immediately in earnings,
unlike the current requirement to eliminate it by deducting it from non-
current assets in the purchase price allocation. Section 1582 is
effective on January 1, 2011, with prospective application, and early
adoption is permitted. To date, the adoption of this standard has not
impacted the company's Consolidated Financial Statements as the company
has not acquired a business.
In January 2009, the CICA issued section 1601, "Consolidated Financial
Statements", which will replace CICA section 1600 of the same name. This
guidance requires consistent application of accounting policies
throughout all consolidated entities. Section 1601 is effective on
January 1, 2011, with prospective application, and early adoption is
permitted. The adoption of this standard will have no impact on the
company's Consolidated Financial Statements as the company had previously
applied consistent application of accounting policies throughout its
branches and subsidiaries.
In January 2009, the CICA issued section 1602, "Non-controlling
Interests", which will replace CICA section 1600, "Consolidated Financial
Statements". This standard establishes the accounting for a non-
controlling interest in a subsidiary in the Consolidated Financial
Statements subsequent to a business combination. This standard requires a
non-controlling interest in a subsidiary to be classified as a separate
component of equity. In addition, net losses and components of other
comprehensive losses are attributed to both the parent and non-
controlling interest. Section 1602 is effective on January 1, 2011, with
prospective application, and early adoption is permitted. To date, the
adoption of this standard has not impacted the company as there are no
non-controlling interests of its subsidiaries.
3. INVENTORY
-------------------------------------------------------------------------
As at December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Crude oil $937 $958
-------------------------------------------------------------------------
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, 2010 and 2009 using a
weighted average cost basis and is carried at the lower of cost and net
realizable value.
4. PROPERTIES AND EQUIPMENT
-------------------------------------------------------------------------
Accumulated
Depletion and Net
($000) Cost Depreciation Book Value
-------------------------------------------------------------------------
As at December 31, 2010
Petroleum and natural gas properties
and equipment $368,861 $(105,990) $262,871
Furniture, equipment and leaseholds 2,590 (1,492) 1,098
-------------------------------------------------------------------------
$371,451 $(107,482) $263,969
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Included in the cost of petroleum and natural gas properties and
equipment are estimated future asset retirement costs of $8.4 million
(2009 - $8.5 million). In 2010, the company capitalized $5.3 million
(2009 - $4.7 million) of general and administrative expenses related to
exploration and development activities.
Depletion, depreciation and accretion expense includes a charge of
$0.6 million (2009 - $0.6 million) to accrete the company's estimated
asset retirement obligations (Note 8).
In December 2010, the company entered into a purchase and sale agreement
("Purchase and Sale Agreement") with Gran Tierra Energy Colombia Ltd.
("Gran Tierra Energy Colombia"), a wholly-owned subsidiary of Gran Tierra
Energy Inc. ("Gran Tierra Energy"), to sell a 25 percent working interest
in the company's Sierra Nevada License in Colombia in consideration for
cash of US$10.0 million. If the Agencia Nacional de Hidrocarburos ("ANH")
does not acknowledge Gran Tierra Energy Colombia's working interest,
through a written resolution, within 180 days after all required
documentation is submitted, either the company or Gran Tierra Energy
Colombia may terminate the Purchase and Sale Agreement, unless this
condition is waived by both parties.
During 2010, the company received cash proceeds of $3.7 million on the
company's Vaca Mahuida, Argentinean exploratory property from third
parties, which was recognized as a recovery of property costs from the
company's Argentinean full cost pool, in addition to being reimbursed for
all incurred expenditures in consideration for a 75 percent working
interest in the aforementioned proved property.
During 2009, the company received cash proceeds of $2.8 million and a
commitment to spend an additional US$1.9 million 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.
Capital costs of $5.9 million (2009 - $14.0 million) incurred for an
unproven property and other assets in Argentina and $57.9 million (2009 -
$56.1 million) and $77.3 million (2009 - $47.5 million) for major
development projects, unproved properties and other assets in a pre-
production stage located in Peru and Colombia, respectively, have been
excluded from the calculation of depletion expense. These costs have been
separately evaluated by management for impairment. No impairment has been
recorded at December 31, 2010 or 2009.
Petrolifera's petroleum and natural gas reserves, as used in the ceiling
test, were evaluated by independent reservoir engineers as at December
31, 2010 in a report dated March 4, 2011. The evaluation was conducted in
accordance with Canadian Securities Administrators' National Instrument
51-101 and the Canadian Oil and Gas Evaluation Handbook, using the
following price assumptions for Argentina and Colombia:
Argentina Colombia
-------------------------------------------------------------------------
Crude Oil Natural Gas Crude Oil Natural Gas
Price ($/bbl) Price ($/mcf) Price ($/bbl) Price($/mcf)
-------------------------------------------------------------------------
2011 61.22 2.58 89.90 2.04
2012 62.45 2.70 90.82 2.08
2013 63.70 2.76 91.84 2.12
2014 64.97 2.81 93.88 2.17
-------------------------------------------------------------------------
+ approximately + approximately + approximately + approximately
2% thereafter 2% thereafter 2% thereafter 2% thereafter
5. BANK DEBT AND LONG-TERM BANK DEBT
-------------------------------------------------------------------------
As at Dec. 31, 2010 Dec. 31, 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Current bank debt
Reserve-backed credit facility $14,919 $52,330
Second ABCP line-of-credit 4,960 -
-------------------------------------------------------------------------
$19,879 $52,330
-------------------------------------------------------------------------
Long-term bank debt
Reserve-backed credit facility $15,665 $-
ABCP line-of-credit 22,496 27,464
Deferred financing costs (1,572) -
-------------------------------------------------------------------------
$36,589 $27,464
-------------------------------------------------------------------------
Total bank debt
Reserve-backed credit facility $30,584 $52,330
Combined ABCP line-of-credit facilities 27,456 27,464
Deferred financing costs (1,572) -
-------------------------------------------------------------------------
$56,468 $79,794
-------------------------------------------------------------------------
In 2007, the company entered into a US$100.0 million reserve-backed
credit facility with availability as at December 31, 2010 of
US$30.8 million. In August 2010, the company signed a revised reserve-
backed credit facility ("Revised Credit Facility") agreement with a
syndicate of banks, which expires on June 30, 2012. In August 2010, the
company made a one-time payment of US$11.7 million prior to signing the
Revised Credit Facility agreement and subsequent thereto, made two
quarterly permanent debt repayments totaling US$7.5 million. These
payments had the effect of reducing the availability under the facility
from US$50.0 million as at December 31, 2009 to US$30.8 million as at
December 31, 2010. The company agreed to make scheduled permanent debt
repayments of US$3.8 million per quarter through to expiry of the Revised
Credit Facility agreement in June 2012, at which time all borrowings
under this Revised Credit Facility will be due and payable. Under the
terms of the Revised Credit Facility agreement, one-half of any potential
farmout proceeds received by the company up to a maximum of
US$5.0 million are to be first allocated to reduce the final
US$12.0 million permanent debt repayment as due and payable upon expiry
of the revised agreement in June 2012 with any excess farmout proceeds to
then be evenly allocated to reduce the company's quarterly debt
repayments. The Revised Credit Facility bears interest at LIBOR plus a
margin, is partially 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, which is in progress, to be
calculated based on information as at June 30, 2010.
As at December 31, 2010, the outstanding Revised Credit Facility was
$30.6 million (US$30.8 million) less approximately $1.6 million in
deferred financing costs, which were recognized on the Revised Credit
Facility agreement and are being amortized through to expiry of the
facility in June 2012. As the terms of the Revised Credit Facility
agreement were substantially changed, $0.7 million of deferred financing
costs related to the previous agreement were amortized during the year.
For 2010, total deferred financing costs amortization is $1.1 million
(2009 - $0.9 million).
During 2009, the company secured from a Canadian chartered bank an
expansion of its Asset Backed Commercial Paper ("ABCP") line-of-credit
("ABCP line-of-credit"), to a maximum of $23.2 million, with an initial
expiry in April 2012. The company can make up to four extension requests,
with each extension for an additional one-year period. Of this line-of-
credit, a maximum of $13.9 million is secured by the eligible master
asset vehicles Classes A1 through C ("MAV A1 to C") notes as received by
the company in exchange for a portion of the long term notes formerly
known as ABCP, whereas a maximum of $9.3 million is unsecured under the
existing terms of this ABCP line-of-credit. The ABCP line-of-credit bears
interest at a floating rate. The company has classified as long-term bank
debt the $22.5 million in borrowings under this facility as at December
31, 2010 and 2009.
The company also has a second line-of-credit agreement ("Second ABCP
line-of-credit") with the same Canadian chartered bank to a maximum of
$5.0 million, which was fully drawn as at December 31, 2010 and 2009.
This Second ABCP line-of-credit, which expires on April 8, 2011, is
secured by the ineligible master asset vehicles Classes 1 & 2 ("MAV IA 1
& 2") notes received by the company in 2009, in exchange for a portion of
the ABCP. During 2010, the company advised its lender it will exercise
its option to deliver to the lender the MAV IA 1 & 2 notes, which at the
time of acquisition in 2007 had a face value of $6.6 million but through
subsequent impairment provisions had no carrying value in the company's
accounts, as at December 31, 2010 and 2009. As the company has the option
to settle its $5.0 million in borrowings as drawn on this Second ABCP
line-of-credit agreement through delivery to its lender of the MAV IA 1 &
2 notes, the company advised its lender that it intends to settle such
borrowings with the MAV IA 1 & 2 notes and accordingly, the company has
classified the $5.0 million in borrowings as at December 31, 2010 made
under this facility as a current liability. At December 31, 2009 this
amount of $5.0 million was classified as long-term bank debt.
Interest expense on the facilities for 2010 was $3.0 million (2009 -
$4.2 million). These amounts are disclosed on the Consolidated Statements
of Operations and Retained Earnings as finance charges which also include
the amortization of deferred finance charges, debt facilities
administration fees and vendor interest charges. The combined effective
interest rate on the company's facilities was 4.1 percent for 2010
(2009 - 4.2 percent). The unused credit on the ABCP line-of-credit
facility, as primarily secured by the ABCP, was $0.7 million as at
December 31, 2010 and 2009.
6. 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 petroleum and natural gas
industry. Although during the year ended December 31, 2010, 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 second quarter of 2010 and 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
5).
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 in its Revised Credit
Facility. As at December 31, 2010, this facility was fully drawn and had
an overall limit of US$30.8 million, based on producing petroleum and
natural gas reserves as at December 31, 2009. This facility has a
provision for a borrowing base adjustment every six months, with the next
adjustment, which is in progress, to be calculated based on information
as at June 30, 2010. The company's financial covenants include a debt-to-
EBITDA ratio whereby outstanding bank debt and long-term debt, as defined
by the terms of the Revised Credit Facility to exclude amounts secured by
the long term notes formerly known as ABCP, cannot exceed two and a half
times ("2.5X") the 12 month trailing EBITDA in addition to a minimum
working capital ratio of 1.25 : 1.00. EBITDA is defined by the Revised
Credit Facility agreement as net loss prior to deduction of interest,
income taxes, depletion, depreciation and accretion expense, stock-based
compensation, unrealized foreign exchange losses and any other non-cash
expenses and is reconciled to the net loss as follows:
-------------------------------------------------------------------------
Year Ended December 31 2010
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net loss $(9,592)
Add (deduct) Interest, income taxes, depletion,
depreciation and accretion expense and other non-cash
expenses:
Depletion, depreciation, and accretion 28,951
Fair value increase (4,817)
Finance charges 4,204
Stock-based compensation 2,695
Income tax provision 1,746
Unrealized foreign exchange loss 912
-------------------------------------------------------------------------
EBITDA $24,099
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2010, relevant outstanding draws were $39.2 million
and EBITDA was $24.1 million, for a debt-to-EBITDA financial covenant
ratio of 1.6:1.0, which was in compliance with the 2.5X 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,
debt agreement option, 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 continue to be measured at fair value, while other
liabilities are subsequently measured at amortized cost.
The fair value measurement of each of the company's significant held for
trading financial assets 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 assets with fair value measurements based
upon quoted prices (unadjusted) in active markets for identical
assets.
- Level 2 includes financial assets from inputs other than quoted
prices included in Level 1 that are observable for the asset, either
directly or indirectly.
- Level 3 includes fair value measurements from inputs for the
financial assets that are not based on observable market date.
-------------------------------------------------------------------------
Fair Value Hierarchy
-------------------------------------------------------------------------
As at December 31, 2010 Total Level 1 Level 2 Level 3
-------------------------------------------------------------------------
Held for trading financial
assets:
Cash $11,046 $11,046 $ - $ -
Accounts receivable 25,667 - 25,667 -
Restricted cash 1,502 - 1,502 -
Debt agreement option 4,817 - - 4,817
Long-term investments 18,670 - - 18,670
-------------------------------------------------------------------------
Total held for trading
financial assets $61,702 $11,046 $27,169 $23,487
-------------------------------------------------------------------------
As no active market exists for the company's accounts receivable and
restricted cash, these financial assets have been classified as Level 2.
As at December 31, 2010, long-term investments is comprised of notes
received in exchange for ABCP with a face value of $30.9 million (2009 -
$34.6 million) and a carrying value of $18.7 million (2009 -
$18.7 million). As at December 31, 2010, the debt agreement option
represents the company's option to settle $5.0 million in borrowings
through the delivery of its MAV IA 1 & 2 notes. The fair and face values
for the Level 3 financial assets is explained below.
During 2010, the company advised its lender that upon the expiry of the
$5.0 million Second ABCP line-of credit agreement, the company will
deliver to the lender the MAV IA 1 & 2 notes that were issued to the
company in 2009 in replacement for a portion of its investment in ABCP.
The lender's recourse on the company's borrowings of $5.0 million is
limited to the MAV IA 1 & 2 notes. As the company has the option to
settle its $5.0 million in borrowings through delivery to its lender of
the MAV IA 1 & 2 notes and has advised its lender that during the year
ended December 31, 2010 it will settle the $5.0 million in borrowings
through delivery of the MAV IA 1 & 2 notes, the company has recognized
the fair value of the debt agreement option of $4.8 million as at
December 31, 2010 using a probabilistic valuation model.
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 2010, the company was advised the ineligible master asset vehicle
Class 1 ("MAV IA 1") notes, with total pledged market collateral of
$500.0 million, incurred several credit events within its market
portfolio, resulting in losses greater than the pledged market
collateral. The company had an investment in the MAV IA 1 notes with an
original face value of $3.7 million and a carrying value as at December
31, 2009 of nil. The company has removed the MAV IA 1 notes from its
reported portfolio of longer-term notes previously known as ABCP, thereby
reducing the outstanding principal amount of its portfolio by
$3.7 million for the year ended December 31, 2010.
During 2009, the company reported a $2.1 million fair value impairment on
its MAV IA 1 and ineligible master asset vehicle Class 2 ("MAV IA 2")
notes, which when combined forms the MAV IA 1 & 2 notes as previously
defined, that reduced the December 31, 2009 carrying value of its MAV IA
1 & 2 notes to nil. The recognition of the fair value impairment during
2009 was accompanied by the removal of the original face value of the MAV
IA 2 notes of $2.9 million from the company's reported portfolio of
longer-term notes previously known as ABCP.
Despite the permanent impairment in the MAV IA 1 & 2 notes as at December
31, 2010, the company still retains the right, subject to the terms of
the Second ABCP line-of-credit agreement between the company and its
lender, to exercise its debt agreement option in April 2011 to settle
$5.0 million in borrowings through the delivery to its lenders of its MAV
IA 1 & 2 notes.
Although there have been some third party transactions during 2010, no
transparent active market quotations have developed for the MAV A1 to C
notes. As a result, management has estimated the fair value of the
company's investment in the MAV A1 to C notes at December 31, 2010, 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, 2010.
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 MAV A1 to C notes approximates the risk-free rate
over the expected life of the MAV A1 to C notes. 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
of Capital Interest Weighted Weighted Risk-free
Class of Notes Recovery Recovery Average Average Term Discount
Notes ($000s) Range Range Recovery Recovery (years) Rate
-------------------------------------------------------------------------
A-1 $ 13,970 30 - 85% 10 - 70% 81% 67% 2 - 6 3%
A-2 13,543 0 - 70% 0 - 30% 64% 27% 6 3%
B 2,459 0 - 40% 0 - 10% 36% 9% 6 3%
C 928 0 - 10% 0% 10% 0% 6 3%
-------------------------------------------------------------------------
Total $ 30,900
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Based on the above approach the fair value of the investment in the MAV
A1 to C notes was $18.7 million as at December 31, 2010 and 2009 as
reconciled in the following table:
-------------------------------------------------------------------------
Years Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Notes formerly known as ABCP, beginning of year $18,689 $22,582
Fair value impairment - (2,104)
Interest received and capital recoveries
previously included in fair value of investment (19) (1,789)
-------------------------------------------------------------------------
MAV A1 to C notes, end of year $18,670 $18,689
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Since 2007, the total recognized impairment on the MAV A1 to C and MAV IA
1 & 2 notes is approximately 46 percent of the original cost of the
investments, including impairments recognized on the ABCP.
The theoretical fair value of the company's MAV A1 to C notes could range
from $13.8 million to $23.1 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 losses.
Credit risk
The company's maximum credit exposure on cash, accounts receivable,
restricted cash, debt option agreement and long-term investments is equal
to each financial asset's carrying value as at December 31, 2010.
Cash, restricted cash and the debt agreement option 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
credit risk from joint venturers is considered to be low as generally the
company requires that funding from joint venture partners is received
prior to the company incurring the related work commitment expenditures.
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$52.7 million of crude oil production to one
multinational purchaser and US$3.4 million in natural gas production to a
reputable local gas marketing company during 2010. Receivables with local
government agencies of $11.7 million mainly pertain to excise taxes paid
on certain expenditures and can take several months prior to receipt
after filing the appropriate returns. The company had a $5.0 million
receivable from Gran Tierra Energy for partial consideration of the
disposition of the company's Sierra Nevada License in Colombia (see Note
4), which was subsequently received in January 2011. The company has not
experienced nor is it aware of any collection problems with its
counterparties. The company does not have an allowance for doubtful
accounts with respect to credit risk, nor did it write off any
receivables during 2010.
Refer to the fair values of financial instruments contained herein for
further discussion regarding the credit risk of the MAV A1 to C notes
recognized as at December 31, 2010 on the Consolidated Balance Sheet as
long-term investments.
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 availability of credit facilities 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, collections of accounts receivable and/or cash flow from
operations.
During 2010, the company agreed to the terms of a Revised Credit
Facility, resulting in a reduction to this facility's availability from
US$50.0 million to the current available limit of US$30.8 million, all of
which is drawn at December 31, 2010. Changes in the availability of the
Revised Credit Facility are anticipated to occur, from time-to-time,
through significant reserve additions, disposals or revisions. The
company also agreed to the following quarterly permanent debt repayments
through to expiry of the agreement in June 2012 at which time all
borrowings under this Revised Credit Facility will be due and payable:
-------------------------------------------------------------------------
As at
-------------------------------------------------------------------------
(US$000)
-------------------------------------------------------------------------
March 31, 2011 $3,750
June 30, 2011 $3,750
September 30, 2011 $3,750
December 31, 2011 $3,750
March 31, 2012 $3,750
June 30, 2012 $12,000
-------------------------------------------------------------------------
The quarterly repayments hereafter are anticipated to be funded from
existing cash balances, collections of accounts receivable and/or cash
flow from operations.
The company holds a combined ABCP line-of-credit availability of
$28.2 million, of which $27.5 million is drawn at December 31, 2010. Of
the $27.5 million drawn against the ABCP line-of-credit facilities,
$5.0 million, as secured by the MAV IA 1 & 2 notes received in exchange
for a portion of ABCP, expires in April 2011 and $22.5 million, primarily
secured on a recourse basis by the MAV A1 to C notes received in exchange
for the other portion of ABCP, expires in April 2012.
The company's Canadian and US dollar credit agreements have change-of-
control provisions, such that upon being triggered they would require
the consent of the company's Canadian dollar lender and at least two-
thirds of the syndicated US dollar lenders, respectively, for the company
to retain continued access to the rights and benefits pursuant to each of
its credit agreements.
Market risk
Changes in commodity prices, interest rates and foreign currency exchange
rates can expose the company to fluctuations in its net loss and in the
fair value of its financial instruments.
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 policy of 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 losses 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 $0.6 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
Revised Credit Facility is denominated in USD, which partially limits the
company's exposure in terms of cash outflows (interest expense as
classified as financing charges on the Consolidated Statement of
Operations and Retained Earnings) which are of the same denomination 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 $11,046 $1,824 $4,293 $4,435 $10 $484
Accounts receivable 25,667 86 5,999 4,848 354 14,380
Restricted cash 1,502 - 1,502 - - -
Debt option
agreement 4,817 4,817 - - - -
Long-term
investments 18,670 18,670 - - - -
Accounts payable
and accrued
liabilities (12,439) (752) (4,733) (4,041) (12) (2,901)
Bank debt (19,879) (4,960) (14,919) - - -
Long-term bank
debt (36,589) (22,496) (14,093) - - -
-------------------------------------------------------------------------
Net financial
assets
(liabilities) $(7,205) $(2,811) $(21,951) $5,242 $352 $11,963
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The company estimates a 15 percent change in the CAD against the above
listed foreign currencies could be reasonably possible over a twelve
month period. A 15 percent strengthening in the CAD would result in a
change to loss before taxes and other comprehensive loss as follows (an
equal but opposite impact to loss before taxes and other comprehensive
loss would result if the CAD weakened by 15 percent):
-------------------------------------------------------------------------
USD ARS PEN COP
------------------------------------
($000) CAD $ equivalent amounts
-------------------------------------------------------------------------
Increase in loss before taxes $(536) $- $(46) $(1,560)
Decrease in other comprehensive loss $2,715 $- $- $-
-------------------------------------------------------------------------
-------------------------------------------------------------------------
7. RELATED PARTY TRANSACTIONS
Under the terms of an administrative agreement with Connacher Oil and Gas
Limited ("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 service was $0.2 million for 2010 and 2009.
Connacher also paid bills on behalf of the company, for which it is
reimbursed, in addition to providing office space for the company's
Canadian Corporate office, for which it was paid at the exchange amounts.
These transactions gave rise to the company recognizing an amount owing
to Connacher as at December 31, 2010 and 2009.
During 2010, the company paid professional legal fees and common share
issue costs of $0.6 million (2009 - $0.5 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.
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, representing a portion of the issuance of a
total of 65,343,000 units, for gross proceeds of approximately
$57.5 million (See Note 10(b)). Connacher is a significant shareholder of
the company with a 18.5 percent equity interest as at December 31, 2010
and the Executive Chairman of the company is the Chairman and Chief
Executive Officer of Connacher.
Directors and officers of the company purchased 1,137,500 units for gross
proceeds of $1.0 million pursuant to a 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 units sold pursuant to a public
offering and over-allotment option, which respectively closed on August
28 and September 4, 2009.
8. ASSET RETIREMENT OBLIGATIONS
At December 31, 2010, the estimated total undiscounted amount required to
settle the asset retirement obligations was $18.0 million (December 31,
2009 - $17.3 million). These obligations are expected to be settled upon
completion of the useful lives of the underlying assets, which currently
extend up to 15 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 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Asset retirement obligations, beginning of year $9,552 $10,106
Liabilities incurred 236 406
Changes to estimate 102 -
Cumulative translation adjustment (496) (1,529)
Accretion expense 558 569
-------------------------------------------------------------------------
Asset retirement obligations, end of year $9,952 $9,552
-------------------------------------------------------------------------
9. INCOME TAXES
The following table reconciles income taxes calculated at the Canadian
statutory rate with recorded income taxes:
-------------------------------------------------------------------------
Years Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Loss before income taxes $(7,846) $(6,851)
Statutory income tax rate 28.00% 29.00%
Expected income tax recovery $(2,197) $(1,987)
Foreign tax rate changes 2,225 73
Future tax rate changes 1,036 3,355
Non-taxable portion of gains (791) (923)
Stock compensation 755 1,355
Valuation allowance increase 505 1,635
Future tax recoveries from prior periods 162 (682)
Current tax adjustments from prior periods 32 1,123
Other 19 25
-------------------------------------------------------------------------
Tax expense $1,746 $3,974
-------------------------------------------------------------------------
Current tax expense $1,933 $3,362
Future tax expense (recovery) (187) 612
-------------------------------------------------------------------------
$1,746 $3,974
-------------------------------------------------------------------------
Future income taxes relate to the following temporary differences:
-------------------------------------------------------------------------
Years Ended December 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Property and equipment $1,784 $16,758
Net operating loss carryforwards (3,326) (17,708)
Future foreign tax credit 9,192 10,080
Finance fees (138) (128)
Asset retirement obligation (127) (140)
Valuation allowance 3,029 2,291
Other (387) (352)
-------------------------------------------------------------------------
Future income tax liability $10,027 $10,801
-------------------------------------------------------------------------
10. SHARE CAPITAL, WARRANTS AND CONTRIBUTED SURPLUS
(a) Authorized:
The authorized capital is comprised of an unlimited number of common
shares and 33,239,600 warrants.
Issued common shares:
-------------------------------------------------------------------------
Number of Amount
Year Ended December 31, 2010 Common Shares ($000)
-------------------------------------------------------------------------
Common shares, beginning of year 121,758,510 $143,610
Issuance of common shares through public
offering (b) 23,678,500 20,127
Issued common shares upon exercise of
options (e) 40,000 20
Assigned value of options exercised (f) 2
Issued common shares upon exercise of warrants 650 1
-------------------------------------------------------------------------
Issue costs net of tax-effect (b) (1,204)
-------------------------------------------------------------------------
Common shares, end of year 145,477,660 $162,556
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number of Amount
Year Ended December 31, 2009 Common 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 (e) 330,000 265
Assigned value of options exercised (f) 67
Issue costs (b) (2,979)
-------------------------------------------------------------------------
Common shares, end of year 121,758,510 $143,610
-------------------------------------------------------------------------
Issued warrants:
-------------------------------------------------------------------------
Number Amount
Year Ended December 31, 2010 of Warrants ($000)
-------------------------------------------------------------------------
Warrants, beginning of year 33,240,250 $4,654
Exercise of warrants (650) -
-------------------------------------------------------------------------
Warrants, end of year 33,239,600 $4,654
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number Amount
Year Ended December 31, 2009 of 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
-------------------------------------------------------------------------
Share capital and warrants:
-------------------------------------------------------------------------
Years Ended December 31 2010 2009
-------------------------------------------------------------------------
Share capital and warrants $167,210 $148,264
-------------------------------------------------------------------------
(b) Equity Financing:
2010
In March 2010, the company announced that it entered into an underwriting
agreement with a syndicate of underwriters to issue on a "bought deal"
basis 20,590,000 common shares at a price of $0.85 per common share for
gross proceeds of approximately $17.5 million ("2010 Public Offering").
The underwriters were granted an over-allotment option (the "2010 Over-
Allotment Option"), which included the right to purchase up to an
additional 15 percent of the common shares, exercisable in whole or in
part up to 30 days following closing of the 2010 Public Offering. The
2010 Over-Allotment Option was exercised in whole by the underwriters on
April 14, 2010, the closing date of the 2010 Public Offering and resulted
in a final total issuance of 23,678,500 common shares, raising gross
proceeds to approximately $20.1 million. Issue costs of $1.3 million were
incurred with respect to this 2010 Public Offering, less a $0.1 million
tax effect.
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 ("2009 Public Offering"), 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 was allocated on the basis 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 "2009 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 2009 Over-Allotment Option was exercised in whole by the
underwriters, closed on September 4, 2009 and as a result there was a
final 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.
(c) Private Placement:
On September 15, 2009, the company closed a non-brokered private
placement ("2009 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 2009 Public Offering, which closed on
August 28, 2009.
(d) Warrants:
Each Warrant issued pursuant to the 2009 Public Offering and 2009 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 during 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 Warrants issued in 2009 was $0.14 per
Warrant.
(e) Stock Options:
As at December 31, 2010 and 2009, the company had outstanding stock
options to acquire common shares, as follows:
-------------------------------------------------------------------------
As at December 31 2010 2009
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding, beginning of
year 7,683,067 $1.60 4,576,327 $6.85
Granted 2,229,454 0.91 5,490,900 1.29
Exercised (40,000) 0.50 (330,000) (0.80)
Forfeited or cancelled (393,400) 3.10 (2,054,160) (12.59)
Expired (452,667) 1.04 - -
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Outstanding, end of year 9,026,454 1.40 7,683,067 1.60
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Exercisable, end of year 5,518,089 $3.42 3,349,135 $1.70
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Options granted under the company's stock option plan are generally fully
exercisable after two or three years and expire five years after the date
granted. The table below summarizes outstanding stock options and the
weighted average remaining contractual life, in years, by ranges of
exercise prices as at December 31, 2010 and 2009:
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As at December 31 2010 2009
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Weighted Weighted
Average Average
Remaining Remaining
Number Contractual Number Contractual
Out- Life Out- Life
standing (yrs) standing (yrs)
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$0.50 - 40,000 0.9
$0.86 - $1.09 6,518,954 3.9 4,892,567 4.4
$1.70 - $1.75 288,000 0.1 313,000 1.1
$2.00 932,000 2.9 977,000 3.9
$2.64 - $3.37 1,208,000 3.3 1,209,000 4.3
$5.40 - $19.20 79,500 2.0 179,500 1.9
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Total 9,026,454 3.6 7,683,067 4.1
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During 2010, a non-cash expense of $2.7 million (2009 - $3.6 million)
was recorded as stock-based compensation expense, 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 during 2009 of $1.1 million.
The fair value of each option granted for 2010 and 2009 is estimated on
the date of grant using the Black-Scholes option-pricing model with
assumptions for grants as follows:
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Dividend Risk-free Expected Expected
yield interest rate life volatility
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2010 -% 2.0% - 2.8% 4 years 81% - 82%
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2009 -% 2.0% - 2.7% 4 years 81% - 90%
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The weighted average fair value at the date of grant of all options
granted for 2010 was $0.56 per option (2009 - $0.83 per option).
(f) Contributed Surplus:
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Years Ended December 31 2010 2009
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Contributed surplus, beginning of year $20,453 $15,846
Stock-based compensation 2,695 4,674
Assigned value of options exercised (2) (67)
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Contributed surplus, end of year $23,146 $20,453
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11. SEGMENTED INFORMATION
The company has corporate offices in Canada, the US and Barbados
(combined to comprise the "Corporate" segment), petroleum and natural
gas production in Argentina and exploration activities in Peru and
Colombia. Financial information pertaining to these segments is presented
below.
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Corporate Argentina Peru Colombia Total
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($000)
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Year Ended
December 31, 2010
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Revenue, gross $34 $63,230 $- $91 $63,355
Net loss (3,100) (6,390) (33) (69) (9,592)
Property and equipment 115 128,218 57,901 77,735 263,969
Capital expenditures 111 7,983 1,732 40,680 50,506
Total assets $27,483 $148,387 $59,025 $94,172 $329,067
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Year Ended
December 31, 2009
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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 expenditures 43 27,082 7,462 37,036 71,623
Total assets $44,180 $183,986 $60,327 $60,572 $349,065
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Crude oil sales totaling US$52.7 million were made to one large
international oil company and natural gas sales totaling US$3.4 million
were made to one reputable local gas marketing company in 2010. In 2009,
US$63.9 million in crude oil sales were made to another large
international oil company and natural gas sales totaling US$4.7 million
were made to the same gas marketing company.
12. SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the calculation of basic and diluted
common shares:
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Years Ended December 31 2010 2009
-------------------------------------------------------------------------
Weighted average common shares outstanding 138,728,326 78,711,781
Dilutive effect of stock options and
share purchase warrants 1,469 264,022
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Weighted average common shares
outstanding - diluted 138,729,795 78,975,803
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As the company has net losses for 2010 and 2009, the dilutive effect of
stock options and share purchase warrants became anti-dilutive causing
138,728,326 and 78,711,781 weighted average dilutive common shares
outstanding to be used as the denominator in the diluted per share net
loss calculation for 2010 and 2009, respectively.
(b) Net change in non-cash working capital
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($000) 2010 2009
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Accounts receivable $(5,478) $14,127
Income taxes receivable 2,383 (668)
Prepaid expenses (1,601) 52
Inventory 16 (129)
Accounts payable and accrued liabilities (3,316) (18,194)
Income taxes payable 123 (344)
Due to a related company 17 (13)
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$(7,856) $(5,169)
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Operating $(658) $ 8,989
Investing (7,198) (14,158)
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$(7,856) $(5,169)
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(c) Supplementary cash flow information
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($000) 2010 2009
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Interest paid $2,962 $3,950
Income taxes paid $1,324 $6,107
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13. COMMITMENTS AND GUARANTEES
Work commitments
The Peruvian licenses have negotiated work programs through 2016, unless
extended. The company has the right to withdraw from each license upon
completion of its current period work commitment associated with the term
of the license. 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 commitment of
US$0.3 million for Block 133 as required to be met by February 2011 was
primarily comprised of geological field studies. The company has met, or
surpassed, all of its current work commitments for Blocks 106 and 107 in
a timely manner. The company has received approval of its Block 107
Environmental Impact Assessment ("EIA") for several potential drilling
sites and is awaiting approval of its recently filed EIA amendment, at
which time it can commence with the fourth period's work commitment
requiring one well to be completed by 2013. As at December 31, 2010, the
company was completing its EIA for Block 106 prior to entering the fifth
period's work commitment requiring one well to be completed or 300 km of
seismic to be acquired and processed by 2012 (See Note 14(b)).
The company has three Colombian exploration licenses: Sierra Nevada,
Turpial, and Magdalena. The company anticipates it has completed the
second phase of its Sierra Nevada License work program by drilling an
exploratory well, Brillante SE-1X, and completing a 3D seismic program
over the La Pinta structure. The completion of this phase is still to be
acknowledged by the ANH. The company has notified the ANH that it will
proceed with phase three of the Sierra Nevada License work program,
which requires the drilling of one exploration well to the targeted depth
of the reservoir prior to June 2011. While still to be acknowledged by
ANH, the company recently completed the second phase 2D seismic
acquisition and interpretation work program on its Turpial License. This
was disproportionately financed by the company's joint venturer. The
company is in the first phase of its Magdalena License, which requires
the drilling of an exploratory well prior to March 2011. The company
spudded an exploratory well on its San Angel prospect in February 2011.
In Argentina, the company has farmed out its Puesto Guevara work
commitment of US$0.6 million through an agreement reached in 2010. Once
the company's joint venturer has funded the work commitment requiring
the drilling of an exploration well for the Puesto Guevara Concession,
in addition to the drilling of a second exploration well, the company's
working interests therein will be reduced to 44 percent. The company's
remaining Argentinean work commitment of US$2.4 million on its Puesto
Morales Este Concession requires the drilling of two development wells
and associated facilities in 2011.
Operating lease commitments
The company's gross operating lease commitments under service contracts
for drilling, leases for office premises and other equipment and an
administrative services agreement are as follows:
-------------------------------------------------------------------------
Subsequent to
Years ended December 31, 2011 2012 2012 Total
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($000)
-------------------------------------------------------------------------
Drilling service contracts,
leases and administrative
services agreement $4,227 $1,072 $781 $6,080
-------------------------------------------------------------------------
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Guarantees
As at December 31, 2010 the company has issued letters of credit in the
total amount of US$1.4 million and $0.1 million, respectively, to secure
the capital expenditure requirements associated with the Colombian and
Peruvian work commitments (December 31, 2009 - US$2.1 million and
US$1.7 million, respectively). As at December 31, 2009, a deposit of
US$4.1 million was held in a trust account in Colombia which financed
the 2010 work obligations on the Magdalena License as they occurred.
14. SUBSEQUENT EVENTS
a) Arrangement Agreement with Gran Tierra Energy Inc.
On January 17, 2011, the company announced that it has entered into an
arrangement agreement (the "Arrangement Agreement") where Gran Tierra
Energy will acquire all of the company's outstanding common shares and
Warrants pursuant to a plan of arrangement (the "Arrangement"). The
Arrangement is subject to approval by at least two thirds of the
company's shareholders, either in person or by proxy, at a meeting to be
held in Calgary, Alberta on March 17, 2011, in addition to being subject
to other customary conditions, including the approval of the Court of
Queen's Bench of Alberta. Under the terms of the Arrangement Agreement,
the company's shareholders will receive from Gran Tierra Energy's
treasury 0.1241 of a share of Gran Tierra Energy for each Petrolifera
share held. In addition, Warrantholders will receive 0.1241 of a common
share purchase warrant of Gran Tierra Energy ("Replacement Warrants")
with an exercise price of $9.67 per share and an expiry date of
August 28, 2011. Each Replacement Warrant will be exercisable for one
Gran Tierra Energy common share and upon being exercised, holders would
not be required to make a cash payment as they would receive a net
number of Gran Tierra common shares equal to the intrinsic value of the
Replacement Warrants.
All of the company's directors and officers, together with the company's
largest shareholder, Connacher, representing in aggregate 21 percent of
the issued and outstanding company shares as at January 31, 2011, have
entered into agreements with Gran Tierra Energy to vote in favour of,
and otherwise support the Arrangement, subject to customary exceptions.
In the event that the Arrangement Agreement is terminated due to a
breach of representation, warranty or covenant by the company that has a
material adverse effect on the company, the company will be required to
pay to Gran Tierra Energy a termination fee in the amount of
$7.9 million.
b) Relinquishment of Exploration License Rights to Peruvian Block 106
On March 4, 2011 Petrolifera issued a letter to Perupetro, the state
agency of Peru, advising of its intention to surrender the license covering
Block 106 in the Maranon Basin, Peru. The company's Block 106 carrying value
of approximately $21.3 million was included as an unproved property cost in
properties and equipment in the Consolidated Balance Sheet as at December 31,
2010. The company retains licenses covering Blocks 107 and 133 in the Ucayali
Basin, Peru.
>>
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