Petrolifera announces second quarter results
CALGARY, Aug. 5 /CNW/ - Petrolifera Petroleum Limited (PDP - TSX) announced today the continued strengthening of the company's financial position. On August 4, 2010, the company announced it had successfully renegotiated its reserve backed credit facility with a term extension until June 30, 2012, with ongoing quarterly repayments until expiry. This improved working capital and will provide increased financial flexibility, which was supplemented by the $20.1 million gross proceeds of a successful bought deal equity financing completed in the reporting period. Cash balances were strong at $41.2 million at June 30, 2010. Subsequently, this balance was reduced upon repayment of $11.75 million of the company's reserve-backed debt. A measured capital program was conducted and active farmout discussions continue for our Colombian and Peruvian properties, having successfully farmed out all work obligations in Argentina. New discoveries in Colombia have begun to establish the basis for future growth and activity. Financial and operating results were as anticipated.
These results will be the subject of a Conference Call at 9:00 AM MT on August 6, 2010. To listen to or participate in the live conference call please dial either 1-647-427-7450 or 1-888-231-8191. A replay of the event will be available from Friday, August 6, 2010 at 12:00 MT until 21:59 MT on Friday, August 13, 2010. To listen to the replay please dial either 1-416-849-0833 or Toll Free at 1-800-642-1687 and enter the pass code 90975203. You can also listen to the conference call online, through the following webcast link: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=3169980
Highlights:
- Brillante SE-1X well confirmed as a significant Cienaga de Oro
("CDO") natural gas discovery; tested 8.4 MMcf/d with calculated
Absolute Open Flow ("AOF") of 18 MMcf/d; significant reserve and
resource potential identified
- Long term test of Brillante well approved in late July 2010 by ANH,
the Colombian agency; will be initiated near-term
- Testing of upper zones in the Upper Porquero Formation in the La
Pinta 1X well yielded average flow rates of 139 bbl/d of light
gravity crude oil with 739 Mcf/d of associated natural gas over a
four day period; will be frac'd
- 3D seismic over La Pinta structure completed, interpretation
underway; early assessment encouraging
- Seismic at Turpial completed; initial results suggest significant
resource potential
- Bought-deal equity financing completed, raised $20.1 million gross
proceeds for working capital
- Reserve-backed credit facility renegotiated, providing extended term,
improved working capital position and increased financial flexibility
Summary Results
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Three months ended Six months ended
or as at June 30 or as at June 30
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% %
2010 2009 Change 2010 2009 Change
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FINANCIAL ($000, except
per share amounts)
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Total revenue $16,794 $22,255 (25) $34,702 $48,662 (29)
Cash flow from
operations before
non-cash working
capital(1) 5,270 10,233 (48) 12,447 21,037 (41)
Per share, basic 0.04 0.19 (79) 0.09 0.38 (76)
Per share, diluted 0.04 0.18 (78) 0.09 0.38 (76)
Net earnings (loss) (297) 3,427 (109) (2,850) 4,615 (162)
Per share, basic 0.00 0.06 (100) (0.02) 0.08 (125)
Per share, diluted(4) 0.00 0.06 (100) (0.02) 0.08 (125)
Net capital spending 17,696 20,477 (14) 33,438 46,089 (27)
Cash 41,179 14,803 178 41,179 14,803 178
Working capital 17,156 22,895 (25) 17,156 22,895 (25)
Long-term
investments(2) 19,210 21,172 (9) 19,210 21,172 (9)
Long-term debt(2) 45,373 102,104 (56) 45,373 102,104 (56)
Shareholders' equity 251,260 201,749 25 251,260 201,749 25
Total assets $376,233 $353,424 6 $376,233 $353,424 6
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OPERATING
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Daily sales volumes
Crude oil and
natural gas
liquids - bbl/d 3,356 4,652 (28) 3,530 4,947 (29)
Natural gas - mcf/d 3,184 6,232 (49) 3,521 6,365 (45)
Barrels of oil
equivalent -
boe/d(3) 3,887 5,691 (32) 4,117 6,008 (31)
Average selling prices
Crude oil and natural
gas liquids -
$/bbl $52.13 $48.72 7 $51.36 $50.54 2
Natural gas - $/mcf $2.66 $2.87 (7) $2.60 $2.93 (11)
Barrels of oil
equivalent - $/boe $47.19 $42.97 10 $46.26 $44.72 3
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COMMON SHARES
OUTSTANDING (000s)
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Weighted average
Basic 141,835 54,948 158 131,867 54,948 140
Diluted(4) 141,835 55,600 155 131,870 55,443 138
End of period 145,478 54,948 165 145,478 54,948 165
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(1) Cash flow from operations before non-cash working capital changes
("cash flow") and cash flow per share do not have standardized
meanings prescribed by Canadian generally accepted accounting
principles ("GAAP") and therefore may not be comparable to similar
measures used by other companies. Cash flow includes all cash flow
from operating activities and is calculated before changes in non-
cash working capital. The most comparable measure calculated in
accordance with GAAP would be net earnings (loss). Cash flow is
reconciled with net earnings (loss) in the accompanying Management's
Discussion & Analysis ("MD&A"). Management uses these non-GAAP
measurements for its own performance measures and to provide its
shareholders and investors with a measurement of the company's
efficiency and its ability to fund a portion of its future growth
expenditures.
(2) Includes carrying value of notes received for Asset Backed Commercial
Paper ("ABCP") with a face value of $34.6 million and $37.6 million
as at June 30, 2010 and June 30, 2009, respectively. Bank debt and/or
long-term bank debt in the amount of $27.5 million and $26.5 million
as at June 30, 2010 and June 30, 2009, respectively, is 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 the three months and six months
ended June 30, 2010, 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.
Petrolifera Petroleum Limited continued to make progress during the second quarter and first half of 2010.
Our financial condition was strengthened with a successful "bought-deal" equity financing, which closed in April 2010 and yielded gross proceeds of $20.1 million. As a result, your company now has 145.5 million common shares outstanding.
Also, we successfully amended the terms of our reserve-backed credit facility, extending the term and reducing the principal amount outstanding to US$38.3 million. The extended term of our reserve-backed credit facility enhanced working capital. As agreed, we intend to continue our reduction of the balance of our reserve-backed indebtedness, by US$3.8 million per quarter, until June 30, 2012, when an estimated US$12 million balance would become due and payable. We anticipate sourcing funds from cash balances and cash flow from our Argentinean properties. Also we agreed that should we receive cash proceeds from the recovery of sunk costs incurred by the company from farmouts of our Colombian or Peruvian properties, if any, up to US$5.0 million in the aggregate would be applied to reduce outstanding indebtedness under the facility. Applications of such proceeds, if any, would reduce amount owing at June 30, 2012. We were already successful with this approach on a recent farmout in Argentina. Under the amended facility, Petrolifera retained the right to prepay or otherwise discharge any reserve-backed debt from any source, without penalty, prior to maturity.
The combination of transactions and continuing sales revenue in Argentina is anticipated to leave the company with adequate liquidity to advance its commitment programs, as it elects, during the balance of this year. We were also successful in arranging third party use of our contracted drilling rig in Colombia, which further reduced cash outlays for standby during the period of utilization by the third party. The rig is due back to us in time to enable the fulfillment of our drilling commitment on our Magdalena License later in 2010.
We continue to be enthusiastic about our Colombian assets. We discovered light gravity crude oil in two zones in the La Pinta well. Unfortunately, we were unable to adequately test the CDO Formation due to formation sand being produced with the crude oil, which plugged the tubing. Nevertheless, we have confirmed the presence of live oil and anticipate the final evaluation of our newly-acquired 3D seismic will confirm our early assessment that there are sizeable compartments, which would warrant further evaluation by drilling. Also, our successful test of a portion of the Upper Porquero Formation is also exciting. We are developing plans for further testing, after we finalize a design for a fracture stimulation, which we believe will enhance well productivity in a consequential manner. This program has been deferred until we establish a method for the capture and subsequent sale of the associated natural gas which would be produced with the crude oil. Various alternatives are presently under consideration and production and sales from the Upper Porquero reservoir could result in Petrolifera's first revenue and cash flow in Colombia.
We drilled a very important new natural gas discovery at Brillante, also on our Sierra Nevada License. The continuing analysis by management suggests that the productive CDO Formation could be very prolific when fully developed with stimulation, with the potential for significant per well reserves and anticipated productivity. The Brillante accumulation is located in a plains or farmland type of environment, thus avoiding the normal challenges of other natural gas accumulations in Colombia, including infrastructure over mountains and through the jungle. Brillante is relatively close to permanent infrastructure and with high indicated productivity, it could be developed with few wells in a relatively short period of time. In late July 2010 we received approval from the Colombian authority, ANH, to proceed with a long-term test of the Brillante well. With this data in hand, we anticipate being able to pursue an early development program, as dictated by final test results and other studies presently underway.
Later this year, we anticipate drilling our first high potential well on our San Angel gas prospect, located on the Magdalena License. We are enthused about the potential of this prospect, part of the overall significant resource potential our company believes it has identified in the general region. In our opinion, there is the potential of a looming, if not current, shortage of exploitable new natural gas reserves and deliverability in Colombia. We believe Petrolifera is very favorably positioned to capitalize on this opportunity, with the potential for solid and attractive economic returns, as we anticipate natural gas prices, once onstream, in the general US$5.00 per Mcf range. Other positive factors are proximity to underutilized infrastructure for domestic access to markets and also the longer-term prospect of exports as our resource base expands and is converted to reserves and production.
We continue to dialogue with prospective joint venturers for our Colombian program. We have received expressions of interest from third parties interested in securing exposure through farmins. Our goal is to secure as much drilling and activity on the Colombian blocks under acceptable terms. Despite relatively high costs which accompany the recognized high potential of our lands, we anticipate transactions will be consummated in the near future.
In Peru, we have continued to dialogue with large, multi-national companies about the potential of farming out both our 107/133 and 106 Licenses. These are complicated transactions, involving out of necessity large companies, due to the associated costs and risks of activity in the Peruvian jungle. We remain confident in the technical merit of both our Ucayali and Maranon Licenses. There has been general confirmation of our technical interpretation as a result of our dialogue with these interested parties.
Our activity in Argentina has largely dealt with the expansion of our water handling capability at Puesto Morales Norte, which is now complete. We have identified additional infill well locations for possible drilling later in 2010 or early 2011, depending upon economics and price movements for both crude oil and natural gas. Recently prices for crude oil sales have been improving. We have successfully farmed out all remaining exploratory commitments in Argentina with respect to our exploratory blocks and have made three new natural gas discoveries, with one being productive in multiple zones from within the Sierras Blancas, Loma Montosa and Centenario Formations. We also farmed out the northern portion of our Rinconada Block, which forms part of our Puesto Morales/Rinconada Concession, to a third party in exchange for operatorship and a three-well commitment, while retaining a meaningful interest upon completion of the program. Failure to complete the program would result in a significant cash payment to Petrolifera. These lands are logistically difficult for us whereas the farminee has operations north of the Colorado River which bisects Rinconada and also places this acreage in a separate province.
We recently announced the launching of a new website to assist our shareholders in accessing information about the company. We are naturally disappointed with the market share price performance but can assure you that your management team is working diligently to ensure that the company's assets are more fully evaluated by drilling under suitable and acceptable farmout terms, which agreements are being pursued with conviction. This will enable us to retain our financial integrity and deliver activity on our high potential lands, which should invigorate investor interest in the company and its publicly-traded shares.
Forward Looking Information
This report contains forward-looking information including, but not limited to, future exploration activities in Colombia including the planned drilling of an exploratory well, San Angel, on the Magdalena License, planned long term testing of the Brillante SE 1X well located in the Sierra Nevada License, the planned frac of the La Pinta 1X well and continued assessment of the La Pinta structure located in the Sierra Nevada License and the evaluation of recently completed seismic in respect of the Turpial License; anticipated results and potential development plans in respect of the company's exploration activities in Colombia; potential infill drilling opportunities in Argentina; strategies for reducing the company's financial exposure to high cost exploration and drilling activities in Colombia and Peru including planned farmout and/or joint ventures arrangements and reimbursement of sunk costs; and anticipated reductions in the company's reserve-backed indebtedness and anticipated sources of funding in respect thereof. Forward-looking information is not based on historical facts but rather on Management's expectations regarding the company's future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities and expectations with respect to general economic and capital market conditions. Such forward-looking information reflects Management's current beliefs and assumptions and is based on information currently available to Management. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information, including but not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production, delays or changes to plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of geological interpretations; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environment risks), the risk of commodity price and foreign exchange rate fluctuations, the uncertainty associated with negotiating with foreign governments and third parties located in foreign jurisdictions and the risk associated with international activity. There is no guarantee that further exploration or appraisal of the company's Colombian licenses will lead to commercial discoveries or, if there are commercial discoveries, that the company will be able to realize such reserves as intended. Few properties that are explored are ultimately developed into new reserves. Readers are cautioned that instantaneous flow rates, measured flow rates and calculated AOF rates may not be indicative of sustainable production rates. Additionally, further long term testing of the Brillante SE-1X well and additional testing of the La Pinta 1X well are required to assess the Sierra Nevada License and determine whether License warrants further evaluation by drilling. Petrolifera has the right to appraise its oil and 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. There can be no assurance that the company will be successful in its efforts to secure cash payments, if any, or any planned farmouts and/or joint venture arrangements in Peru or Colombia and thereby reduce its indebtedness under the reserve-backed credit facility. Additionally, the company's ability to pay quarterly principal repayments when due is dependent on cash balances and cash flow from operations. Cash flow from operations is dependent on future production levels, commodity prices and foreign exchange rates. Petrolifera may have to bring participants into its acreage holdings and planned evaluation activities on less attractive terms than might otherwise have been the case due to the combination of weaker economic conditions and the influence of contractual commitments and deadlines on the terms of trade. There can be no assurance that the company will be successful in its efforts to secure planned farmouts and/or joint venture arrangements. Additional risks and uncertainties associated with Petrolifera's future plans are described elsewhere in the attached MD&A and in Petrolifera's Annual Information Form for the year ended December 31, 2009. Although the forward-looking information contained herein is based upon assumptions which Management believes to be reasonable, the company cannot assure investors that actual results will be consistent with this forward-looking information. This forward-looking information is made as of the date hereof and the company assumes no obligation to update or revise this information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward-looking information, prospective investors in the company's securities should not place undue reliance on this forward-looking information.
Management's Discussion and Analysis ("MD&A")
The following is dated as of August 5, 2010 and should be read in conjunction with the unaudited Consolidated Financial Statements of Petrolifera Petroleum Limited ("Petrolifera" or the "company") for the three and six months ended June 30, 2010, as contained in this interim report and the audited Consolidated Financial Statements for the years ended December 31, 2009 and December 31, 2008 as contained in the company's annual report. Additional information relating to Petrolifera, including its Annual Information Form for the year ended December 31, 2009, is 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.
Information in this report, including the letter to shareholders, contains forward-looking information including but not limited to future exploration and development opportunities in Argentina, Colombia and Peru, future drilling plans in Argentina, Colombia and Peru and the anticipated timing associated therewith, planned capital expenditures (including sources of funding and timing thereof), strategies for reducing the company's financial exposure to high cost exploration and drilling activities, including planned farmout and/or joint ventures arrangements, anticipated improvements in natural gas prices in Argentina, the anticipated impact of the proposed conversion to International Financial Reporting Standards ("IFRS") on the company's consolidated financial statements, planned debt repayments and the timing thereof and the company's ability to continue to comply with financial covenants imposed pursuant to its reserve-backed credit facility. See "Forward-Looking Information" for a discussion of the forward-looking information contained in this report and the risks and uncertainties associated therewith. Additional risks and uncertainties relating to Petrolifera and its business and affairs are also described in detail in its Annual Information Form for the year ended December 31, 2009. Throughout this MD&A, per barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil (6:1). The conversion is based on an energy equivalency conversion method primarily applicable to the burner tip and does not represent a value equivalency at the wellhead. Boe may be misleading, particularly if used in isolation.
2009 COMPARATIVE INFORMATION
Petrolifera announced on March 2, 2009 that its Board of Directors had authorized the company to initiate a process to dispose of its Argentinean interests. Petrolifera's Argentinean interests represented all of its current production, related revenues and substantially all of its reserves. During early July 2009, several bids for the company's Argentinean interests were received from third parties. After careful consideration, on July 15, 2009 the company announced that the process to dispose of its interests did not result in any acceptable bids and accordingly management decided to retain the company's Argentinean operations. As a result, the comparative information within the unaudited Consolidated Financial Statements and MD&A, for the three and six months ended June 30, 2010, presents the Argentinean interests as though the operations were part of continuing operations despite the previous classification of these interests as "discontinued operations" in the three and six months ended June 30, 2009 unaudited Consolidated Financial Statements and MD&A.
For the three and six months ended June 30, 2010, the comparative periods' presentation of the Argentinean interests as though the operations were part of continuing operations does not give effect to depletion and depreciation related to the period from March 2, 2009 to June 30, 2009 as a result of the previous classification of Argentinean interests as "discontinued operations". Because depletion and depreciation was not recognized from March 2, 2009 to June 30, 2009 in the unaudited Consolidated Financial Statements for the three and six months ended June 30, 2009, depletion, depreciation and accretion expense ("DD&A") and net earnings recognized for the three and six months ended June 30, 2009 are not comparable to the DD&A and the net losses recognized for the three and six months ended June 30, 2010, respectively.
FINANCIAL AND OPERATING REVIEW
SALES VOLUMES, PRICING AND REVENUE
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Three months ended June 30 Six months ended June 30
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% %
2010 2009 Change 2010 2009 Change
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Daily sales volumes:
Crude oil and
natural gas
liquids - bbl/d 3,356 4,652 (28) 3,530 4,947 (29)
Natural gas - mcf/d 3,184 6,232 (49) 3,521 6,365 (45)
Equivalent - boe/d 3,887 5,691 (32) 4,117 6,008 (31)
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Average selling
prices:
Crude oil and
natural gas liquids
- $/bbl $52.13 $48.72 7 $51.36 $50.54 2
Natural gas - $/mcf $2.66 $2.87 (7) $2.60 $2.93 (11)
Weighted average
selling price -
$/boe $47.19 $42.97 10 $46.26 $44.72 3
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Petroleum and
natural gas sales
($000) $16,691 $22,254 (25) $34,467 $48,625 (29)
Interest and
other income
($000) 103 1 - 235 37 535
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Total revenue
($000) $16,794 $22,255 (25) $34,702 $48,662 (29)
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Petroleum and natural gas revenues for the six months ended June 30, 2010 were $34.5 million on average sales volumes of 4,117 boe per day, compared to $48.6 million on average sales volumes of 6,008 boe per day during the same period in 2009, decreases of 29 percent and 31 percent, respectively. Petroleum and natural gas revenues for the second quarter of 2010 were $16.7 million on average sales volumes of 3,887 boe per day, compared to $22.3 million on average sales volumes of 5,691 boe per day during the second quarter of 2009, decreases of 25 percent and 32 percent, respectively. For the three and six months ended June 30, 2010, sales of crude oil and natural gas liquids represented 86 percent of the company's sales volumes, which is comparable to 82 percent for the same periods in 2009. The reduction in petroleum and natural gas revenues for the three and six months ended June 30, 2010 as compared to the same periods in 2009 reflect lower sales volume, partially offset by higher average selling prices. The lower sales volume was mainly attributable to natural production declines and operational downtime that included scheduled equipment maintenance on PMN a-1061, workovers on key producing wells, PMN x- 1082 and PMN - 1111 and production anomalies from less significant wells such as PMN-1113. Additionally, there was a temporary shut-in of another key producing well, PMN -1002, caused by a pump failure and, as commonly happens on these high water-cut wells, production took some time to recover to previous levels. Natural gas sale volumes were impacted for the three and six months ended June 30, 2010 by scheduled maintenance work programs on the company's natural gas pipeline. The company is evaluating a drilling campaign for late 2010 which will target proved, non-producing reserves from within the Puesto Morales Norte ("PMN") Field in the Neuquen Basin, Argentina. In addition, the company is considering and evaluating various proposals to accelerate drilling on its Puesto Morales/Rinconada ("PM/R") Concession, including a multi-well program within the PMN Field to access identified, but non-producing, crude oil and natural gas reserves. All of Petrolifera's sales during 2010 were from PM/R, Puesto Morales Este and, to a lesser extent, Vaca Mahuida Concessions in Argentina and the majority (88 percent) of its crude oil sales were made to the Argentinean operation of a large multinational company.
Relative to the first quarter of 2010, when petroleum and natural gas revenues were $17.8 million on sales volumes of 4,349 boe per day, lower revenues due to lower sales volumes were experienced during the second quarter of 2010. During June 2010, the company completed an expansion of its produced water treatment capacity, which enables it to handle increased fluid volumes resulting from production from five infill wells drilled in the fourth quarter of 2009. This capacity expansion is anticipated to extend the ability to sustain production and recover increased volumes of crude oil.
Prices realized for the company's crude oil and natural gas liquids sales increased seven and two percent respectively, to average $52.13 per barrel and $51.36 per barrel for the three months and six months ended June 30, 2010, compared to $48.72 per barrel and $50.54 per barrel realized during the same periods in 2009. Higher realized US dollar crude oil pricing, respectively averaging US$51.44 per barrel and US$50.47 per barrel during the three and six months ended June 30, 2010, compared favorably to the average US$42.68 and US$42.54 per barrel, respectively received during the same periods in 2009. This favorable US dollar pricing was offset by an average 14 percent and 17 percent strengthening, respectively, of the Canadian dollar relative to the US dollar for the three and six months ended June 30, 2010, compared to the same periods in 2009.
The company's second quarter 2010 realized crude oil and natural gas liquids prices increased three percent relative to the price of $50.65 per barrel realized during the first quarter in 2010. Petrolifera negotiated a new crude oil sales agreement with a well-established multinational purchaser during the second quarter of 2010 and secured a higher US dollar crude oil price than received during the first quarter of 2010 and throughout 2009. During the three and six months ended June 30, 2010, the crude oil price realized by Petrolifera averaged approximately 66 and 65 percent of the WTI average of US$77.77 and US$78.22 per barrel, respectively, lower relatively than the 72 percent and 83 percent of the WTI averages of US$59.54 and US$51.26 per barrel, respectively, received in the same periods in 2009. This reduction is due to price controls in Argentina relative to WTI prices.
The company successfully negotiated a price increase for 2010 South American winter sales volumes of natural gas to US$2.61 per mcf. This was a four percent improvement relative to the US$2.51 per mcf realized on sales volumes during the South American winter of 2009. However, during the three and six months ended June 30, 2010, natural gas prices decreased seven and 11 percent, respectively, over the levels realized during the same periods in 2009 to average $2.66 per mcf and $2.60 per mcf. The lower realized natural gas pricing during the three and six months ended June 30, 2010 relative to the same periods in 2009, as expressed in Canadian dollars, resulted from an average 14 and 17 percent strengthening of the Canadian dollar as compared to the US dollar, respectively. The realized natural gas price was five percent higher on the improved South American winter pricing during the second quarter of 2010, compared to the first quarter of 2010 where it averaged $2.54 per mcf. Natural gas prices are believed to have the potential of further improvement in the longer term, due to market conditions and new Argentinean policy initiatives.
Interest and other income was minimal during the three and six months ended June 30, 2010 and 2009 and primarily reflects interest earned on short-term cash and restricted cash deposits. Interest on the investment in notes, formerly known as Asset Backed Commercial Paper ("ABCP"), with a face value of $34.6 million, has not been recognized since August 2007, due to the lack of market liquidity for these notes. During the three and six months ended June 30, 2010, the company did not receive any 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.
ROYALTIES, OPERATING EXPENSES AND CORPORATE NETBACKS
CORPORATE NETBACKS(1)
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Three months ended June 30
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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) 3,887 5,691
Petroleum and natural
gas sales $16,691 $47.19 $22,254 $42.97
Interest and other income 103 0.29 1 -
Royalties (2,391) (6.76) (3,488) (6.74)
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Net revenue 14,403 40.72 18,767 36.24
Operating costs (5,278) (14.92) (5,717) (11.04)
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Corporate netback $9,125 $25.80 $13,050 $25.20
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Six months ended June 30
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2010 2009
-------------------------------------------------------------------------
($000, except per
unit amounts) Total Per boe Total Per boe
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Average daily sales (boe/d) 4,117 6,008
Petroleum and natural
gas sales $34,467 $46.26 $48,625 $44.72
Interest and other income 235 0.32 37 0.03
Royalties (4,935) (6.62) (6,917) (6.36)
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Net revenue 29,767 39.95 41,745 38.38
Operating costs (10,461) (14.04) (11,599) (10.67)
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Corporate netback $19,306 $25.91 $30,146 $27.72
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(1) Calculated by dividing related revenue and costs by total boe sold,
resulting in a corporate netback. Netback does not have a
standardized meaning prescribed by GAAP and therefore is unlikely to
be comparable to similar measures used by other companies. The most
comparable measure calculated in accordance with GAAP would be net
earnings (loss). Nevertheless, Petrolifera's management uses netbacks
as a performance measurement of operating efficiency and the
prevailing royalty regime. A high ratio of netback to selling price
is a positive indicator. A reconciliation of corporate netback to net
income (loss) can be found in the Net Earnings (Loss) table.
Compared to the second quarter of 2009, Petrolifera's corporate netback of $25.80 per boe remained relatively unchanged for the same period in 2010, mainly due to higher realized selling prices offsetting higher operating costs per boe. Petrolifera's corporate netback of $25.91 per boe decreased six percent during the six months ended June 30, 2010, compared to that recorded in the same period of 2009. Higher realized commodity pricing during the six months ended June 30, 2010, compared to the same period in 2009 was more than offset by higher operating costs per boe. Petrolifera's calculated unit netbacks of $25.80 per boe and $25.91 per boe for the three and six months ended June 30, 2010, was 55 percent and 56 percent of the average selling prices per boe, respectively, a reduction from the 59 percent and 62 percent achieved during the same periods in 2009.
The corporate netback in the second quarter 2010 of $25.80 per boe was comparable to the $26.01 per boe realized in the first quarter in 2010. Improved average realized selling prices offset higher operating costs per boe during the second quarter of 2010, compared to the first quarter 2010.
ROYALTIES
Royalties represent charges levied by governments and landowners against production or revenue. Included in royalties are revenue taxes imposed by provincial jurisdictions. Royalties during the six months ended June 30, 2010 were $4.9 million ($6.62 per boe), or 14 percent of oil and natural gas revenue, compared to $6.9 million ($6.36 per boe), or 14 percent of oil and natural gas revenue, in the same period in 2009. On a boe basis, the increase is primarily attributable to the higher realized commodity pricing during the six months of 2010 compared to the same period in 2009. Royalties in the second quarter of 2009 were $2.4 million ($6.76 per boe), or 14 percent of oil and natural gas revenue, as compared to $3.5 million ($6.74 per boe), or 16 percent of oil and natural gas revenue in the same period in 2009 and $2.5 million ($6.50 per boe), or 14 percent of oil and natural gas revenue in the first quarter of 2010.
OPERATING COSTS
Total operating costs during the three and six months ended June 30, 2010, respectively, decreased by approximately eight percent and 10 percent compared to the same periods in 2009, largely due to lower sales volumes and 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. On a per boe basis, however, operating costs increased 35 and 32 percent, respectively, for the three and six months ended June 30, 2010 to $14.92 per boe and $14.04 per boe, compared to $11.04 per boe and $10.67 per boe for the same periods in 2009. Lower petroleum sales volumes, combined with increased costs for contract operator and equipment rentals (with more pumping crude oil wells) during the three and six months ended 2010, resulted in the increase. Total fluid throughput increased during the period, partially due to the late 2009 infill well drilling program, although the average amount of crude oil produced decreased. Accordingly, the additional fluid handling costs contributed to the further increase in the operating costs per boe for the three and six months ended June 30, 2010, relative to the same periods in 2009.
NET EARNINGS (LOSS) AND SHARES OUTSTANDING
NET EARNINGS (LOSS)
-------------------------------------------------------------------------
Three months ended June 30
-------------------------------------------------------------------------
2010 2009
-------------------------------------------------------------------------
($000, except per
unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Corporate netback $9,125 $25.80 $13,050 $25.20
General and administrative (1,824) (5.16) (2,155) (4.16)
Stock-based compensation (1,104) (3.12) (846) (1.63)
Finance charges (1,032) (2.92) (1,348) (2.60)
Foreign exchange
gain (loss) (483) (1.37) 1,453 2.81
Depletion, depreciation
and accretion (7,454) (21.07) (138) (0.27)
Fair value of debt
agreement option 4,800 13.57 - -
Income tax provision (1,754) (4.96) (5,634) (10.87)
Taxes other than
income taxes (571) (1.61) (955) (1.84)
-------------------------------------------------------------------------
Net earnings (loss) $(297) $(0.84) $3,427 $6.62
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30
-------------------------------------------------------------------------
2010 2009
-------------------------------------------------------------------------
($000, except per
unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Corporate netback $19,306 $25.91 $30,146 $27.72
General and administrative (3,599) (4.83) (4,092) (3.76)
Stock-based compensation (1,781) (2.39) (2,438) (2.24)
Finance charges (2,092) (2.81) (2,925) (2.69)
Foreign exchange
gain (loss) (802) (1.08) (992) (0.91)
Depletion, depreciation
and accretion (15,541) (20.86) (7,042) (6.48)
Fair value of debt
agreement option 4,800 6.44 - -
Income tax provision (2,296) (3.08) (6,678) (6.14)
Taxes other than
income taxes (845) (1.13) (1,364) (1.25)
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Net earnings (loss) $(2,850) $(3.82) $4,615 $4.24
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For the six months ended June 30, 2010, the company reported a net loss of $2.9 million ($0.02 per weighted average basic and diluted share), compared to net earnings of $4.6 million ($0.08 per weighted average basic and diluted share) for the same period in 2009. The change was primarily attributable to lower commodities sales volumes and higher non-cash DD&A in 2010. In the second quarter of 2010, the company reported a net loss of $0.3 million ($0.00 per weighted average basic and diluted share) compared to net earnings of $3.4 million ($0.06 per weighted average basic and diluted share) for the same period in 2009. In addition to lower sales volumes and higher DD&A, a foreign exchange loss and higher non-cash stock based compensation were contributing factors to the change in the net loss from the second quarter of 2010 relative to net earnings in the comparable period of 2009. Due to the 2009 sales process relating to the company's Argentinean interests, DD&A is not comparable on a quarter-over-quarter and year-over-year basis. See "DEPLETION, DEPRECIATION AND ACCRETION EXPENSE" for further details.
Compared to the first quarter 2010, when the company reported a net loss of $2.6 million ($0.02 per weighted average basic and diluted share), the decrease in the second quarter 2010 net loss was mostly attributable to the recognition of 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.
The company's Argentinean operation is considered self-sustaining. Accordingly, changes in this operation's reported net assets, as expressed in Canadian dollars, resulting from foreign exchange differences between the US dollar and Canadian dollar is recognized as other comprehensive income (loss). For the three and six months ended June 30, 2010, the company's other comprehensive income was $4.5 million and $1.3 million, respectively, compared to other comprehensive losses of $11.8 million and $7.7 million for the same periods in 2009, respectively. The other comprehensive income for the three and six months ended June 30, 2010 was due to a four percent and one percent strengthening of the US dollar as at June 30, 2010, compared to the Canadian/US dollar relationship at March 31, 2010 and December 31, 2009, respectively. This resulted in an increase 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. The other comprehensive losses during the three and six months ended June 30, 2009, were due to an eight percent and five percent strengthening of the Canadian dollar at June 30, 2009, compared to the Canadian/US dollar relationship as at March 31, 2009 and December 31, 2008, respectively. This decreased the Canadian dollar value of the carrying value of the reported net assets of the company's Argentinean operations.
SHARES OUTSTANDING
During the three months and six months ended June 30, 2010, the weighted average number of common shares outstanding was 141.8 million and 131.9 million, respectively, compared to 54.9 million for the same periods in 2009. The increase in the weighted average number of common shares for the three and six months ended June 30, 2010, relative to the same periods in 2009, reflected the April 2010 and August 2009 issuances of 23.7 million and 65.3 million common shares from treasury, respectively, for gross proceeds of $20.1 million and $57.5 million; the September 2009 private placement issuance of 1.1 million common shares from treasury, for gross proceeds of $1.0 million; and 0.4 million options or warrants that were exercised during the second half of 2009 or first half of 2010, resulting in the issuance of a like number of common shares. As the company had net losses for the three and six months ended June 30, 2010, 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, whereas for the same periods in 2009, 0.7 million and 0.5 million additional common shares were included in the calculations of diluted net earnings per share, respectively.
As at the close of business on August 4, 2010, the company had the following securities issued and outstanding:
- 145,477,660 common shares; and
- 9,872,521 stock options; and
- 33,239,600 warrants, exercisable at $1.20 per warrant until
August 28, 2011.
GENERAL & ADMINISTRATIVE AND STOCK-BASED COMPENSATION
General and administrative ("G&A") expenses were $1.8 million and $3.6 million for the three and six months ended June 30, 2010, respectively, compared to $2.2 million and $4.1 million for the same periods in 2009. These costs primarily consist of management and administrative salaries, legal and professional fees, insurance, travel and other administrative expenses. G&A expenses of $2.6 million and $2.2 million primarily related to further exploration and evaluation of prospects in Colombia, Peru and Argentina were also capitalized during the six months ended June 30, 2010 and 2009, respectively.
On a per boe basis, expensed G&A was $4.83 per boe of sales in the six months ended June 30, 2010, compared to $3.76 per boe in the same period in 2009. The increase in G&A per boe for the six months ended June 30, 2010, relative to the same period in 2009, was primarily due to lower sales volumes.
For the six months ended June 30, 2010, a non-cash expense of $1.8 million ($1.3 million in 2009) was recorded as stock-based compensation, reflecting the amortization of the fair value of stock options over the vesting period. The slight increase in stock-based compensation during the second quarter of 2010, as compared to the same quarter of 2009, primarily reflects an increase in the number of options granted.
During the six months ended June 30, 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.
FINANCE CHARGES
Included in the finance charges of $2.1 million and $2.9 million for the six months ended June 30, 2010 and six months ended June 30, 2009, respectively, were interest paid and accrued on the company's outstanding current and long-term bank debt and deferred financing charges that are normally allocated over the life of the reserve-backed credit facility. The decrease in finance charges during the six months ended June 30, 2010, compared to the same period in 2009, reflected lower average company borrowings and a lower effective interest rate of 3.1 percent as compared to 5.0 percent for the respective periods.
During the second quarter of 2010, the company expensed the remaining $0.3 million of deferred financing costs that related to a previous credit facility agreement, as the terms of this agreement were modified in a revised credit facility agreement. See "CREDIT FACILITIES" for further details.
FOREIGN EXCHANGE
For the three and six months ended June 30, 2010, the strengthening of the Canadian dollar relative to the Argentinean peso resulted in a foreign exchange loss on working capital, as partially denominated in Argentinean pesos. As the spot Canadian dollar strengthened relative to the Argentinean peso, the company reported a corresponding reduction in working capital, as expressed in Canadian dollars. During the same periods, the weakening of the Canadian dollar relative to the US dollar further contributed to the foreign exchange loss on higher reported US dollar denominated debt, as expressed in Canadian dollars. These foreign exchange losses were partially offset by foreign exchange gains on higher Canadian dollar reported Argentinean and corporate working capital to the extent it was held in US dollars. Combined, this resulted in a net foreign exchange loss of $0.8 million for the six months ended June 30, 2010, compared to a loss of $1.0 million during the same period in 2009.
DEPLETION, DEPRECIATION & ACCRETION ("DD&A")
DD&A is calculated using the unit-of-production method relative to total estimated proved reserves. DD&A for the six months ended June 30, 2010 totaled $15.5 million or $20.86 per boe, an increase compared to $7.0 million or $6.48 per boe, respectively, in the same period in 2009. In accordance with Canadian GAAP, depletion and depreciation on the company's Argentinean interests, as previously disclosed as "discontinued operations", was not recognized in the June 30, 2009 unaudited Consolidated Financial Statements during the period from March 2, 2009 to June 30, 2009 when these interests were for sale. As a result of management's decision to terminate the sales process, the company's Argentinean interests were again classified as "held for use", resulting in the recognition of depletion and depreciation on the company's Argentinean interests from March 2, 2009 to June 30, 2009 in addition to DD&A for the third quarter of 2009 in the three months ended September 30, 2009. As a result of not recognizing depletion and depreciation expense for the period from March 2, 2009 to March 31, 2009 and in the second quarter of 2009 in the financial results for the three and six months June 30, 2009, total DD&A and DD&A per boe for the three and six months ended June 30, 2009 is not comparable to the same measures in the same periods of 2010.
Capital costs of $10.7 million (Dec. 31, 2009 - $14.0 million) incurred for unevaluated properties and other assets in Argentina and $56.8 million (Dec. 31, 2009 - $56.1 million) and $78.9 million (Dec. 31, 2009 - $47.5 million) for major development projects and other assets in the pre-production stage located in Peru and Colombia, respectively, have been excluded from the cost pool subject to depletion and depreciation. As at June 30, 2010, proceeds received from the company's partners on its Vaca Mahuida Concession resulted in a decrease in Argentinean capital costs for unevaluated properties relative to prior reported periods. See "Capital spending" for further details.
Accretion expense, which is included in DD&A, was $0.1 million and $0.3 million for the three months and six months ended June 30, 2010 and 2009. Accretion expense will continue to be recorded 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.
FAIR VALUE OF DEBT AGREEMENT OPTION
During the second quarter of 2010, the company estimated the fair value of a debt agreement option in the amount of $4.8 million upon the company's 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 ABCP. See "RESTRICTED CASH, DEBT AGREEMENT OPTION AND LONG-TERM INVESTMENTS" for further details.
TAXES
The current income tax provision of $0.9 million and $2.4 million in the six months ended June 30, 2010 and 2009, respectively, related primarily to income taxes payable in Argentina. Additionally, a future income tax expense of $1.4 million and $4.3 million for the six months ended June 30, 2010 and June 30, 2009 was recorded at the statutory rate to recognize the differences between the remaining tax pools and accounting carrying values, respectively. The implied effective tax rate of the income tax provision is not indicative of the company's jurisdictional tax rates for the three and six months ended June 30, 2010 and June 30, 2009. Taxes other than income taxes of $0.8 million and $1.4 million for the six months ended June 30, 2010 and June 30, 2009, respectively, represent taxes charged on all banking transactions in Argentina.
CAPITAL RESOURCES, CAPITAL EXPENDITURES AND LIQUIDITY
In April 2010 the company improved its liquidity and balance sheet with a successful bought deal public equity offering of common share from treasury for gross proceeds of $20.1 million. The equity was raised primarily to fund a portion of the company's exploration capital spending program, primarily in Colombia, including exploration activity on the company's Sierra Nevada and Magdalena licenses, located onshore Colombia, to repay a portion of the company's reserve-backed debt and for working capital. This equity raise, in combination with the company's cash balances and cash flows from its Argentinean interest, are expected to provide the company with the required liquidity to meet existing work commitments and reduce outstanding reserve-backed debt in accordance with the terms of the revised reserve-backed credit facility. The company continues to negotiate farmout arrangements aimed at enhancing shareholder value at lower risk from its strong ownership positions and early stage geological and geophysical activity in Peru and Colombia.
During the six months ended June 30, 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 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 concession's work program or to drill wells at no cost to the company in the case of the Rinconada North area. In addition, the company was reimbursed $3.6 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. With the signing of the 2010 Argentinean farmout agreements, the company has no remaining work commitments in Argentina. When combined with the Rinconada Block farmout agreement, existing cash reserves and cash flows can be either directed to debt reduction or to evaluating more prospective land holdings in Peru and Colombia. The company also maintains meaningful working interests in its Argentinean properties.
The company continues to engage in farmout discussions with respect to its lands in Peru and Colombia. Recent stronger crude oil prices and company drilling success have interested third parties. The company's Colombian Sierra Nevada and Magdalena Licenses are currently being evaluated by several potential joint venturers. The company anticipates that any joint venture will include securing new drilling commitments to further evaluate the potential identified during drilling on the Sierra Nevada License, to further appraise the Brillante discovery and to accelerate the evaluation of prospects in the Magdalena License. Farmout discussions with several major multinational companies continue on the company's Peruvian Licenses 107/133 and 106.
For the remainder of 2010, upon the recent completion of the company's seismic programs on the Sierra Nevada and Turpial Licenses, respectively located in the Lower and Middle Magdalena Basins, onshore Colombia, the company's only remaining significant work obligation is the drilling of an exploratory well on the Magdalena License, located in the lower Magdalena Basin onshore Colombia. See "Commitments, Contractual Obligations, Guarantees & Off-Balance Sheet Financing" for a detailed discussion of the status of the company's various work commitments.
In August 2010, the company signed a revised credit facility agreement with scheduled repayments until expiry on June 30, 2012. At the time of signing the revised credit facility agreement, the company made a one-time payment of US$11.7 million to reduce the availability under the facility from US$50.0 million to US$38.3 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 completion of the new facility improves the company's working capital position. The company anticipates repayment of its reserve-backed debt from cash flows from its Argentinean interests, cash balances, prospective potential cash proceeds from farmout arrangements and proceeds from the April 2010 equity offering. Should farmout arrangements not proceed as planned, the company has the ability to defer budgeted capital expenditures on certain licenses. The company anticipates potentially reducing its reserve-backed credit facility by up to a total of US$20.0 million during 2010 of which US$11.7 million has been paid to date.
CASH FLOW
Cash flow and cash flow per share do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital. The most comparable measure calculated in accordance with GAAP would be net earnings (loss). Cash flow is reconciled with net earnings (loss) below. Cash flow per share is calculated by dividing cash flow by the weighted average shares outstanding. Management uses these non-GAAP measurements for its own performance measures and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund a portion of its future growth expenditures.
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Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Net earnings (loss) $(297) $3,427 $(2,850) $4,615
Add (deduct) non-cash charges:
Depletion, depreciation
and accretion 7,454 138 15,541 7,042
Fair value of debt
agreement option (4,800) - (4,800) -
Stock-based compensation 1,104 846 1,781 2,438
Future income tax provision 1,375 4,208 1,350 4,288
Unrealized foreign
exchange loss 105 1,396 723 2,211
Amortization of deferred
charges 329 218 702 443
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Cash flow $5,270 $10,233 $12,447 $21,037
-------------------------------------------------------------------------
Per share, basic $0.04 $0.19 $0.09 $0.38
Per share, diluted $0.04 $0.18 $0.09 $0.38
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash flow in the first six months of 2010 was $12.4 million, or $0.09 per weighted average basic and diluted share, compared to $21.0 million, or $0.38 per weighted average basic and diluted share in the same period of 2009. The 41 percent decrease in cash flow during the first six months of 2010, relative to the same period in 2009, primarily resulted from lower sales volumes that were mainly attributable to natural reservoir pressure declines, the impact of a 17 percent strengthening of the Canadian dollar relative to the US dollar, thereby lowering the company's Canadian dollar reported cash flows and higher realized foreign exchange losses on the company's working capital. The company implemented a waterflood program at PMN in order to mitigate the observed natural reservoir pressure declines, but in a portion of the field the program has been less effective than anticipated. The company is considering a drilling campaign which will target proved, non-producing reserves from within the PMN Field. Successful drilling of new wells and the company's recent expansion of its water treatment capacity, are anticipated to extend the ability to sustain production and recover increased volumes of crude oil.
Cash flow in the second quarter of 2010 was $5.3 million or $0.04 per weighted average basic and diluted share, compared to $10.2 million or $0.19 per weighted average basic and $0.18 per weighed average diluted per share for the same period of 2009. The 48 percent decrease in total cash flow during the second quarter of 2010, relative to the same period in 2009, reflects the same issues as explained for the first six months of 2010 relative to the same period in 2009. Cash flow per share for the three and six months ended June 30, 2010 also decreased relative to the same periods in 2009 for the aforementioned reasons and from the impact of an increase in the number of shares outstanding.
Second quarter 2010 cash flow was 27 percent lower, compared to the first quarter 2010 cash flow of $7.2 million or $0.06 per weighted average basic and diluted share, primarily due to lower sales volumes and higher taxes other than income taxes and realized foreign exchange losses on settlement of the company's working capital. During June 2010, the company completed an expansion of its produced water treatment capacity, which enables it to handle increased fluid volumes resulting from production from its five well infill development program in the fourth quarter of 2009. The recent capacity improvement is anticipated to extend the ability to sustain production and recover increased volumes of crude oil.
EQUITY FINANCING & PRIVATE PLACEMENT FROM TREASURY
In March 2010, the company announced that it entered into an underwriting agreement with a syndicate of underwriters to issue 20,590,000 common shares at a price of $0.85 per common share on a "bought deal" basis for gross proceeds of approximately $17.5 million ("2010 Public Offering"). The underwriters were granted an over-allotment option (the "Over-Allotment Option"), which included the right to purchase up to an additional 15 percent of the offering of common shares, exercisable in whole or in part up to 30 days following closing of the 2010 Public Offering. The Over-Allotment Option was exercised in whole by the underwriters on April 14, 2010 (the closing date of the 2010 Public Offering) and accordingly resulted in a total issuance of 23,678,500 common shares with gross proceeds of approximately $20.1 million.
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. As at June 30, 2010, the net proceeds of the 2010 Public Offering had been used to fund approximately $7.0 million of capital expenditures in Colombia, to fund a US$2.4 million trust account for a portion of the company's Colombia work commitments, with the remainder of the funds held as cash, pending further expenditures, primarily anticipated to be in Colombia and to repay up to US$5.0 million of the company's reserve backed credit facility, which was paid in August 2010.
The proposed use of net proceeds per the 2010 Public Offering relative to actual use of net proceeds as at June 30, 2010, are as follows:
-------------------------------------------------------------------------
Use of Net
Use of Net Proceeds
Proceeds Per as at
2010 Public June 30,
($000) Offering 2010
-------------------------------------------------------------------------
Capital expenditure program,
primarily in Colombia $ 10,520 6,953
Reduction of reserve-backed credit facility Up to US5,000 -
Working capital 3,300 2,528
Cash to be deployed in 2010 to capital
expenditure program and reduction of
reserve-backed credit facility - 9,339
-------------------------------------------------------------------------
$ 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 September 30, 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 "Private Placement"). Each Warrant entitles the holder thereof to purchase one Common Share at an exercise price of $1.20 per Warrant until August 28, 2011.
The net proceeds in the amount of $55.4 million of the 2009 Public Offering and Private Placement were initially added to working capital to augment cash balances to be used to fund a portion of the company's exploration capital expenditure program, primarily in Colombia and to reduce indebtedness relating to the company's reserve-backed credit facility. As at June 30, 2010, the net proceeds of the 2009 Public Offering and Private Placement had been 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 for a portion of the company's Colombian work commitments.
CAPITAL SPENDING
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Colombia $18,065 $9,270 $32,065 $24,275
Argentina 1,887 10,488 4,202 15,126
Peru 313 708 759 6,668
Corporate 7 11 12 20
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Capital spending $20,272 $20,477 $37,038 $46,089
Proceeds from
farmout arrangements (2,576) - (3,600) -
-------------------------------------------------------------------------
Net capital spending $17,696 $20,477 $33,438 $46,089
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Net capital spending in the three and six months ended June 30, 2010 was $17.7 million and $33.4 million, respectively, compared to $20.5 million and $46.1 million for the same periods in 2009. Net capital spending during the three and six months ended June 30, 2010 was financed from available cash, cash flow and proceeds from the 2010 Public Offering, the 2009 Public Offering and the Private Placement. Expenditures in Colombia were primarily for the drilling of the Brillante SE-1X well and the La Pinta 1X well remedial work, both on the Sierra Nevada License.
Colombia
During mid-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 April 2010 a preliminary drill stem test was conducted in the Cienaga de Oro Formation ("CDO") between 3,138 feet and 3,312 feet subsurface resulting in a flow of dry natural gas and no water from the CDO at a measured rate of 8.4 mmcf per day through a 48/64" choke with surface pressure at 570 psi. The company calculated the absolute open flow ("AOF") rate of the well to be 18.0 mmcf per day of dry natural gas, based on the recorded data from the downhole pressure gauge during the flow and shut-in periods of the production test. Log evaluations conducted by a third party independent petrophysical consultant of the interval from 3,138 feet to the total depth of the well of 9,500 feet, indicate the presence of a total of 429.5 feet of possible net natural gas pay. No resource or reserve calculations can be made until the company conducts a long-term test of the perforated interval, which is anticipated to be conducted during the third quarter of 2010 as approval for such a test was received in late July 2009. The duration of the long-term test is anticipated to be approximately three weeks. Evaluations of deeper pay intervals drilled in the Brillante SE-1X well may be conducted in subsequent appraisal wells.
In January 2010 a snubbing unit was mobilized from the United States to the 100 percent-owned La Pinta 1X exploration well, which spudded on January 23, 2009 on the company's Sierra Nevada License, situated onshore the Lower Magdalena Basin. Previously, the well had been suspended following evidence of sand plugging in the production tubing, which precluded further testing. The snubbing unit arrived in the Lower Magdalena Basin location on February 1, 2010 and after approximately one week to rig up, 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 again the tubing again plugged and a decision was made to plug off the CDO and to move uphole 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, natural gas and as yet unmeasured associated natural gas liquids 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. Only the upper portion of the Porquero reservoir was perforated. The company is studying the feasibility of various productivity stimulation, appraisal and production methods while it waits for a permit to conduct a long-term test and determines the best method to manage produced natural gas volumes.
Readers are cautioned that measured flow rates and calculated AOF rates may not be indicative of stabilized production rates for the Brillante SE-1X or La Pinta 1X wells. Also, further evaluation, testing and appraisal of the La Pinta 1X well may be required before an assessment of commerciality can be made and further long term testing of the Brillante SE-1X well is also required. The company has a right to appraise its oil and 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.
A 3D seismic program over the company's La Pinta structure commenced and was completed during the six months ended June 30, 2010. Data is now being processed with final interpretation anticipated during the third quarter of 2010.
The company commenced and substantially completed a 144 km(2) 2D seismic program in the first six months of 2010 on its Turpial License in the Middle Magdalena Basin, onshore Colombia. The company was carried through the first US$1.9 million of costs related to this work program by its joint venturer. The seismic data is now being processed with final interpretation anticipated during the third quarter of 2010. Upon completion of this work program, the joint venturer 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
In the first six months of 2010, expenditures were 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 will also enable the company to handle increased fluid volumes from new drilling, which is anticipated to extend the ability to sustain production with increased recovery of crude oil volumes. During the first six months of 2010, the company also capitalized certain workover costs related to reperforations, perforation of additional intervals in the Centenario Formation and adjustments to 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 the second quarter of 2010 under the terms of the agreement. The 2010 VM drilling campaign fulfilled this Concession's work commitment and the terms of the farmout agreement subject to confirmation that the company's work commitments have been met by the Province of Rio Negro, Argentina. 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. Results to date 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 1.45 mmcf per day from
the Centenario, 2.2 mmcf per day from the Loma Montosa and 1.5 mmcf
per day from the Sierra Blancas; 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 the first quarter of 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. The two exploratory wells program is anticipated prior to the end of 2010 with each well ranging in depth from 1,000 meters to 1,700 meters.
During the second quarter of 2010, the company completed an agreement to farmout the northern portion of its 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 this portion of Rinconada.
Peru
Minimal capital expenditures were incurred for pre-drilling activities for the first six months of 2010 on the company's three Peruvian blocks. The company has met, or surpassed, 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.
The company continues the process of discussing the terms of farmout agreements with respect to Blocks 107 and 133 with several large international companies, in an attempt to secure recovery of a portion of its sunk costs incurred on these Blocks and to secure work commitments for new drilling and/or seismic activity. On Block 106, further discussions are also underway or anticipated with a number of qualified, interested third parties, also with a view to farming out an interest in this License.
CREDIT FACILITIES
During 2009, the company negotiated an expansion of its ABCP line-of-credit to a maximum of $23.2 million with a Canadian chartered bank. The ABCP line-of-credit was primarily secured by the eligible master asset vehicles Classes A through C1 received by the company in exchange for a portion of the ABCP. Any of the borrowings from the expanded 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 representing an additional one-year period. The ABCP line-of-credit bears interest at a floating rate. As at June 30, 2010 and December 31, 2009 the outstanding ABCP line-of-credit facility was $22.5 million.
The company has a second agreement on the ABCP line-of-credit to a maximum of $5.0 million which was fully drawn as at June 30, 2010 and December 31, 2009. This second ABCP line-of-credit, which has an initial expiry in April 2011, is solely secured by the ineligible master asset vehicles Classes 1 & 2 ("MAV IA 1 & 2") notes as received by the company in 2009 in exchange for a portion of the ABCP. During the second quarter of 2010, the company advised its lender it would not renew this facility beyond its expiry date of April 2011, at which time 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 on the company's accounts as at 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 during the second quarter of 2010 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 June 30, 2010 made under this facility as a current liability (December 31, 2009 - $5.0 million was classified as a long-term liability).
In August 2010, the company signed a revised credit facility agreement with a syndicate of banks with scheduled repayments over the term, expiring on June 30, 2012. Prior to signing the revised credit facility agreement, the company made a one-time payment of US$11.7 million to reduce the availability under the facility from US$50.0 million to US$38.3 million. The company agreed to make the following quarterly permanent debt repayments through to expiry of the agreement in June 2012 at which time all borrowings under this credit facility will be due and payable:
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Three months ended
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(US$000)
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September 30, 2010 $3,750
December 31, 2010 3,750
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 as due and payable upon expiry of the revised agreement in June 2012.
The extension of the expiry date of the revised credit facility agreement over the expiry date of the previous agreement immediately improved the company's working capital position, as a portion of its reserve-backed debt previously held as a current liability is now classified as long-term. The company anticipates approximately US$20.0 million in reserve-backed debt repayments during 2010 (including the US$11.7 million payment made in August 2010), which the company intends to finance from existing cash balances, cash flows and a portion of proceeds, if any, from farmout agreements.
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.
As at June 30, 2010 the outstanding reserve-backed facility was US$50.0 million (Dec. 31, 2009 - US$50.0M) with $28.4 million recognized as a current liability (Dec. 31, 2009 - US$50.0 million) and $24.6 million as long-term (Dec. 31, 2009 - $-). As at June 30, 2010, the outstanding ABCP line-of-credit facility was $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 long-term (Dec. 31, 2009 - $27.5 million).
The company is subject to external restrictions on its revised reserve-backed revolving credit facility. Under this facility's agreement, the outstanding draws cannot exceed two and half times the 12 month trailing EBITDA. EBITDA is a non-GAAP measure and is defined by the revised credit facility agreement as net earnings (loss) prior to deduction of finance charges, income taxes, depletion, depreciation and accretion expense, stock-based compensation and unrealized foreign exchange losses. As at June 30, 2010, outstanding draws on the revised reserve-backed credit facility and a portion of long-term bank debt were $61.6 million and EBITDA was $28.9 million, for a ratio of debt to EBITDA of 2.1, which is in compliance with the two and half times EBITDA imposed limit. With existing realized commodity pricing, the company's cost structure and a scheduled 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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12
Months
Three Months Ended Ended
-------------------------------------------------------------------------
Sept. 30, Dec. 31, Mar 31, June 30, June 30,
($000) 2009 2009 2010 2010 2010
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Net loss $(11,359) $ (4,081) $ (2,553) $ (297) $(18,290)
Add (deduct) interest,
income taxes, depletion,
depreciation and
accretion expense and
other non-cash expenses:
Depletion, depreciation
and accretion 17,568 8,936 8,087 7,454 42,045
Fair value of option
on debt agreement - - - (4,800) (4,800)
Finance charges 1,132 1,040 1,060 1,032 4,264
Stock-based compensation 1,561 675 677 1,104 4,017
Fair value impairment
of ABCP 2,104 - - - 2,104
Income tax provision
(recovery) (3,428) 724 542 1,754 (408)
Unrealized foreign
exchange loss (gain) (640) (143) 618 105 (60)
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EBITDA $ 6,938 $ 7,151 $ 8,431 $ 6,352 $ 28,872
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RESTRICTED CASH, DEBT AGREEMENT OPTION AND LONG-TERM INVESTMENTS
As at June 30, 2010, the debt agreement option represents the company's option to settle $5.0 million in borrowings solely 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 $34.6 million (Dec. 31, 2009 - $34.6 million) and a carrying value of $18.7 million (Dec. 31, 2009 - $18.7 million) and collateral to support issued letters of credit of $0.5 million (Dec. 31, 2009 - $0.7 million). As at June 30, 2010, restricted cash included collateral to support issued letters of credit of $1.0 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 the second quarter of 2010 the company advised its lender that upon expiry of the $5.0 million 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 solely 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 as at December 31, 2009. As the company has the option to settle its $5.0 million in borrowings solely through delivery to its lender of the MAV IA 1 & 2 notes and has 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 for the three months ended June 30, 2010 using a probabilistic valuation model.
In the first six months of 2010, the company did not receive any cash interest receipts on any class of notes formerly known as ABCP it holds, as the specified short term interest rate was below the 50 basis points required to be paid out from this investment. Current interest rates are marginally above the 50 basis points threshold so the company does not anticipate any significant cash interest receipts during the second half of 2010.
Although we understand there have been some third party transactions during the first six months of 2010, no active market quotations have developed for the longer term notes. As a result, management has estimated the fair value of the company's investment in the longer term notes at June 30, 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 June 30, 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 longer term notes was an approximation of the risk-free rate for the expected life of the longer term notes to be received. As the rate used for discounting was an approximation of the risk-free rate, all other risks have been incorporated in the estimated probability-adjusted expected outcomes. This methodology applied all risking information into the various scenarios and discounted the fully-risked cash flow stream only for the time value of money. The recovery factors used were as follows:
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Face Risk- Risk-
Value adjusted adjusted Capital Interest
Class of Capital Interest Weighted Weighted Risk-free
of Notes Recovery Recovery Average Average Term Discount
Note ($000s) Range Range Recovery Recovery (yrs) Rate
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A-1 $13,978 0 - 80% 0 - 60% 75% 54% 3 - 7 3%
A-2 13,543 0 - 70% 0 - 30% 64% 27% 7 3%
B 2,459 0 - 30% 0% 27% 0% 7 3%
C 928 0% 0% 0% 0% 7 3%
IA -1 3,674 0% 0% 0% 0% 7 3%
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Total $34,582
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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 June 30, 2010 and December 31, 2009. Since 2007, the total recognized impairment on the longer term notes is approximately 46 percent of the original cost of the investment, including impairments or recoveries recognized on the ABCP.
The theoretical fair value of the company's longer-term notes could range from $14.0 million to $25.0 million, using the valuation methodology described above, with reasonably possible alternative assumptions. The outcome of the actual timing and amount ultimately recoverable from these notes may differ materially from this estimate, which would impact the company's earnings. To date, no active market for the longer term notes has developed to permit liquidation of the company's investment for proceeds equal to or greater than the collateral value pursuant to the ABCP line-of credit agreement.
IMPACT OF NEW AND PROPOSED ACCOUNTING PRONOUNCEMENTS
In December 2008, the CICA issued Section 1582, Business Combinations, which will replace CICA Section 1581 of the same name. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The company is currently evaluating the impact of adopting this standard to any business combination entered on or after January 1, 2011 on its Consolidated Financial Statements.
In December 2008, the CICA issued Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests, which replaces existing Section 1600. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The company is currently evaluating the impact of adopting Section 1601 and on the accounting of non-controlling interests resulting from any business combinations entered on or after January 1, 2011 on its Consolidated Financial Statements.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In October 2009, the Canadian Accounting Standards Board issued a third and final International Financial Reporting Standards ("IFRS") Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to adopt IFRS in place of Canadian GAAP for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011. The company'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 has been progressing towards completion throughout 2009 and into 2010. The company's IFRS transition project consists of three key phases: the preliminary phase, the impact and evaluation phase and the implementation phase. A fulsome description of the company's IFRS transition project phases and the company's progress to the end of 2009 is contained within the company's MD&A for the year ended December 31, 2009.
Management is in the process of finalizing its chosen IFRS accounting policies and as such is unable to quantify the impact of adopting IFRS on its financial statements. In accordance with its transition plan, the company is continuing the process of evaluating its accounting policy choices and making recommendations of chosen accounting policies to senior management for approval and presentation to the audit committee of the Board of Directors for their review and approval. It is anticipated that accounting policies will be determined, subject to modification in connection with the implementation of such policies, during the second half of 2010. Once the accounting policies have been finalized, the company plans to quantify the expected effects and provide preliminary disclosure on such effects in the 2010 MD&A.
IFRS 1, First Time Adoption of IFRS provides companies adopting IFRS with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Management is analyzing the various accounting policy choices available and will implement those determined to be the most appropriate and significant for the company which at this time are summarized as follows:
- Property, Plant & Equipment ("PP&E") - IFRS 1 provides an exemption
allowing companies who follow the full cost accounting guideline
under Canadian GAAP, such as Petrolifera, to value the PP&E assets at
their deemed cost being the Canadian GAAP net book value assigned to
these assets as at the date of the transition, January 1, 2010. The
net book value of the PP&E assets will be allocated to new cost
centres on the basis of the company's reserve volumes or values on
the date of transition.
- Cumulative Translation Adjustments ("CTA") - IFRS 1 provides an
exemption allowing the company to not comply with IAS 21 - The
Effects of Changes in Foreign Exchange Rates that existed at the date
of transition to IFRS. Instead, the company will elect to deem the
CTA for its foreign operations to be zero at the date of transition.
The company will then recognize directly in retained earnings at the
date of transition its CTA as measured in accordance with Canadian
GAAP.
- Asset Retirement Obligation ("ARO") - IFRS 1 provides another
exemption for full cost accounting companies under Canadian GAAP,
such as Petrolifera, to measure its ARO liability at the date of
transition in accordance with IAS 37 - Provisions, Contingent
Liabilities and Contingent Assets. The company will then recognize
directly in retained earnings at the date of transition any
difference in the measures between IFRS and the company's previous
measure in accordance with Canadian GAAP.
The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect the company's reported financial position and results of operations. However, this does not reflect a change in the underlying economics of Petrolifera's business. At this time, the company has identified key differences that may impact the financial statements as follows:
- Classification of Exploration and Evaluation ("E&E") expenditures
from PP&E - Upon transition to IFRS, the company will separately
classify all E&E expenditures on the Consolidated Balance Sheet.
Under Canadian GAAP, E&E expenditures are included in PP&E. E&E
expenditures consist of the book value for the company's undeveloped
land that relate to exploration properties primarily in Colombia and
Peru. E&E expenditures will not be depleted and must be assessed for
impairment when indicators suggest the possibility of impairment.
- Calculation of depletion expense for PP&E assets - Upon transition to
IFRS, the company has the option to calculate depletion using a
reserve-base of proved reserves or proved and probable reserves, as
compared to the Canadian GAAP method of calculating depletion using
only proved reserves. The company has not concluded at this time
which method for calculating depletion will be used.
- Impairment of PP&E assets - Under IFRS, impairment of PP&E must be
calculated at a more granular level than what is currently required
under Canadian GAAP. Impairment calculations will be performed at a
"Cash Generating Unit" level ("CGUs") by comparing the CGUs carrying
value to a risk adjusted recovery of either proved or proved and
probable reserves.
- The effects of foreign changes in foreign exchange rates - Under
IFRS, the translations of the company's US dollar functional currency
Colombian, Peruvian and certain Corporate operations (the "Integrated
Operations") to the company's Canadian dollar presentation currency
is performed by applying the closing and average US dollar relative
to Canadian dollar rates at the date and period of the consolidated
balance sheet and statement of operations, respectively, with the
resulting exchange difference recognized in other comprehensive
income. Under Canadian GAAP, the Integrated Operations' monetary
assets and liabilities and associated income and expenses would be
translated using the aforementioned technique with the exception that
the exchange difference is recognized in net earnings (loss), while
the Integrated Operations' non-monetary assets and liabilities and
associated income and expenses are translated at the historical
average US dollar relative to Canadian dollar rates.
- Provisions for asset retirement costs - Under IFRS, the company is
required to revalue its entire liability for asset retirement costs
at each balance sheet date using a current liability - specific
discount rate. Under Canadian GAAP, once recorded, asset retirement
obligations are not adjusted for future changes in discount rates.
In addition to accounting policy differences, the company's transition to IFRS is expected to impact its internal controls over financial reporting, disclosure controls and procedures, certain of the company's business activities and IT systems as follows:
- Internal controls over financial reporting ("ICFR") - as the
transition of the company's accounting polices is completed, an
assessment will be made to determine changes required for ICFR. As an
example, additional controls will be implemented for transition
adjustments under IFRS 1 such as the allocation of the company's PP&E
on a reserve or value basis to cost centres or the process for
reclassifying the companies E&E expenditures from PP&E. This will be
an ongoing process throughout 2010 to ensure that all changes in
accounting policies include the appropriate additional controls and
procedures and training of impacted staff for future IFRS reporting
requirements.
- Disclosure controls and procedures - Throughout the transition
process, the company will be assessing its stakeholders' information
requirements and will ensure that adequate and timely information is
provided to meet these needs.
- Business activities - Management has been cognizant of the upcoming
transition to IFRS and as such has worked with its counterparties and
lenders to ensure that any agreements that contain references to
Canadian GAAP financial statements are modified to allow for IFRS
statements. Based on the expected changes to the company's accounting
policies at this time, no issues are anticipated with the existing
wording of debt covenants and related agreements as a result of the
transition to IFRS.
- IT systems - the company is currently updating its accounting system
in order to ready the company for IFRS reporting. The modifications
are not significant, however, deemed critical in order to allow for
reporting of both Canadian GAAP and IFRS statements in 2010 as well
as the modifications required to track PP&E and E&E expenditures at a
more granular level of detail for IFRS reporting. Additional system
modifications may be required based on final policy choices.
Management's timeframe to complete the third and final implementation phase of its IFRS adoption efforts is scheduled during the second half of 2010, which will allow the company to adopt IFRS in place of Canadian GAAP, effective January 1, 2011.
COMMITMENTS, CONTRACTUAL OBLIGATIONS, GUARANTEES & OFF-BALANCE SHEET ARRANGEMENTS
WORK COMMITMENTS
In 2005, Petrolifera acquired two significant oil and gas exploration licenses onshore Peru for Blocks 106 and 107, respectively, located in the Maranon and Ucayali Basins. During April 2009, Petrolifera was awarded a license over Block 133, offsetting and contiguous with Block 107 and also relinquished approximately one half of Block 107 during May 2009. Based on its interpretation of the 950 km 2D seismic program acquired over the acreage by the company in 2007 and 2008, Petrolifera believes it has retained the most prospective acreage under Block 107.
The Peruvian licenses have negotiated work programs through 2016, unless extended. Each work program has a specified minimum financial commitment that must be met for the company to maintain its rights to these licenses. Specifically, the immediate minimum work commitments of US$0.3 million for Block 133 are primarily comprised of geological field studies and as such are not capital intensive. The company has met, or surpassed, all of its current work commitments for Blocks 106 and 107 in a timely manner. The company is awaiting the approval of its Block 107 Environmental Impact Assessment for several potential drilling sites, at which time it can commence with the fourth period's work commitment requiring one well to be completed by 2013. The ability to defer drilling activity until 2013 positions the company to maintain these properties in good standing at low cost. 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 Assessments ("TEAs"). Petrolifera converted the Turpial and Sierra Nevada II TEAs into exploration licenses with the latter renamed Magdalena. The company recently completed the second phase of its Sierra Nevada License work program, which required the drilling of one exploratory well and acquiring additional seismic, with the completion of this phase still to be acknowledged by the Colombian authority, Agencia Nacional de Hidrocarburos ("ANH"). The company completed the Sierra Nevada License's second phase exploratory well, Brillante SE-1X, during March 2010, to a total depth of 9,500 feet. During the second quarter of 2010, the company 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. Whilst still to be acknowledged by ANH, the company completed the second phase 2D seismic work program on its Turpial License. This was disproportionally financed by the company's joint venturer. Completion of seismic interpretation is expected to occur on the company's Turpial License prior to the work program deadline of September, 2010. The company is in the first phase of its Magdalena License, which requires an exploration well to be completed prior to December 2010. The company anticipates the drilling of an exploratory well on its San Angel prospect during the fourth quarter of 2010 to meet this requirement.
The company's Colombian and Peruvian 2010 exploration budget is anticipated to be sufficient to satisfy the aforementioned work commitments. Financing of the company's 2010 capital program is anticipated from existing cash reserves, the 2010 Public Offering and completion of farmouts or joint ventures arrangements. Should these farmout arrangements not proceed as planned, the company has the ability to defer capital expenditures on certain licenses.
In Argentina, the company has farmed out its Vaca Mahuida and Puesto Guevara Concessions work commitments of US$2.9 million and US$0.6 million, respectively, through agreements reached in the first quarter of 2010. At Vaca Mahuida, a total of five exploratory wells have been drilled by the company, financed by the company's joint venturers. The company's working interest in the Vaca Mahuida Concession will reduce to 25 percent upon the Province of Rio Negro, Argentina, acknowledging that the company's existing work commitment has been met. Once the company's joint venturer has funded the work commitment for the Puesto Guevara Concession, the company's working interests will be 44 percent in this Concession. The company has no remaining work commitments in Argentina.
CONTRACTUAL OBLIGATIONS
The company's gross contractual obligations for drilling, leases for office premises and other equipment and an administrative services agreement for the six months ended December 31, 2010 and annually thereafter are as follows:
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Subsequent to
($000) 2010 2011 2011 Total
-------------------------------------------------------------------------
Drilling contracts
and other leases $7,900 $810 $251 $8,961
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GUARANTEES
As at June 30, 2010 the company has issued letters of credit in the total amount of US$1.3 million and US$0.2 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 June 30, 2010, a deposit of US$2.8 million (Dec. 31, 2009 - US$4.1 million) is held in a trust account in Colombia to meet certain work obligations on the Magdalena License as they occur.
OFF-BALANCE SHEET ARRANGEMENTS
The company does not have any off-balance sheet arrangements.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the company is also responsible for designing 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. There have been no changes in the company's systems of internal controls over financial reporting during the three and six months ended June 30, 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 its six months ended June 30, 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.
Farmout (and joint venture) efforts continue with respect to much of the company's prospect inventory. Current capital market conditions may make this process more challenging and time consuming than under more buoyant and stable economic conditions, resulting in the company having to bring participants into its acreage holdings and planned activities on less attractive terms than might otherwise have been negotiated. There can be no assurances as to the timing or completion of possible farmout (and/or joint venture) arrangements.
Farmout or joint venture arrangements can expose Petrolifera to additional risks and uncertainties where the concurrence of co-venturers is required to pursue various actions or the co-venturer is required to fund expenditures on behalf of Petrolifera to meet contractual work commitments. Other parties influencing the timing of events may have priorities that differ from Petrolifera's, even if they generally share Petrolifera's objectives. Additionally, Petrolifera is exposed to the credit risk of its co-venturers and possible default if its co-venturer fails to meet contractual work commitments initially undertaken by Petrolifera under its Licenses.
The success of the company's capital programs as embodied in its productivity and reserve base, could also impact its prospective liquidity and pace of future activities. Control of finding, development, operating and overhead costs per boe is an important long-term criterion in determining company growth, success and access to new capital sources.
To date, the company has utilized debt and equity financing and has had a bias towards conservatively financing its operations under normal industry conditions to offset the inherent risks of international oil and gas exploration, development and production activities. The company may be required to raise additional capital to fund its activities in light of overall industry conditions, the remaining work commitments associated with the company's exploratory lands and the slow pace at which farmout negotiations are preceding. Capital markets may not be receptive to offerings of new equity from treasury, whether by way of private placement or public offerings. Additionally, there can be no assurance that the outstanding Warrants will be exercised to provide the company with additional liquidity.
Access to financing has been impacted by sub-prime mortgage defaults, the liquidity crisis affecting the ABCP and collateralized debt obligation markets and deterioration in the global economy. Banks have been adversely affected by the worldwide economic crisis and have severely curtailed existing liquidity lines, increased pricing and introduced new and tighter borrowing restrictions to corporate borrowers, with extremely limited access to new facilities or for new borrowers. These factors may impact Petrolifera's ability to obtain equity, debt or bank financing on terms that are commercially reasonable, or at all, and could negatively impact its ability to access liquidity needed for its operations in the longer term. This may be further complicated by the limited market liquidity for shares of smaller companies, restricting access to some institutional investors.
Periodic fluctuations in energy prices 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.
OUTLOOK
The company made progress during the first half of 2010 with new farm-outs and new crude oil and natural gas discoveries in Colombia and Argentina. Also, additional equity capital was raised, commodity prices strengthened and our reserve-backed credit facility was re-negotiated with an extended term, thereby improving working capital. We look to continue to build on these achievements in the second half of the year as our focus is on increased drilling activity financed by third parties and other possible transactions to enhance liquidity and add value.
FORWARD-LOOKING INFORMATION
This interim report, including the Letter to Shareholders, contains forward-looking information including, but not limited to, continued exploration activities in respect of the Sierra Nevada, Magdalena and Turpial Licenses in Colombia, the anticipated drilling of an exploratory well on the San Angel prospect within the Magdalena License onshore Colombia during 2010, anticipated results and potential development plans in respect of the company's exploration activities in Colombia, strategies for reducing the company's financial exposure to high cost exploration and drilling activities in Colombia and Peru including, planned farmout and/or joint ventures arrangements, planned infill drilling at PMN and PM/R, Argentina, anticipated production sustainability and increased recovery of crude oil as a result of expanded water handling facilities in Argentina, anticipated improvements in natural gas prices in Argentina, planned capital expenditures (including sources of funding and timing thereof) and anticipated reductions in the company's reserve-backed indebtedness and anticipated sources of funding in respect thereof, expectations regarding the company's ability to continue to comply with financial covenants imposed pursuant to its reserve-backed credit facility and otherwise meet its existing work commitments and the anticipated impact of the proposed conversion to IFRS on the company's consolidated financial statements. Forward-looking information is not based on historical facts but rather on Management's expectations regarding the company's future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities and expectations with respect to general economic and capital market conditions. Such forward-looking information reflects Management's current beliefs and assumptions and is based on information currently available to Management. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information, including but not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production, delays or changes to plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of geological interpretations; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environment risks), the risk of commodity price and foreign exchange rate fluctuations, the uncertainty associated with negotiating with foreign governments and third parties located in foreign jurisdictions and the risk associated with international activity. There can be no assurance that further exploration or approval of the company's Colombian licenses will lead to commercial discoveries or, if there are commercial discoveries, that the company will be able to realize such resources as intended. Few properties that are explored are ultimately developed into new reserves. Readers are cautioned that instantaneous flow rates, measured flow rates and calculated AOF rates may not be indicative of sustainable production rates. Additional evaluation of seismic data, further testing and the possibility of additional drilling are required to assess the CDO and Upper Porquero Formations encountered in the La Pinta 1X well. Further long term testing of the Brillante SE-1X well is required to evaluate productivity and commerciality. Petrolifera has the right to appraise its oil and 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. The company's ability to complete its capital program and repay outstanding indebtedness is dependent upon completion of planned farmout arrangements and recovery of sunk costs, maintenance of stable production in Argentina, stabilized or improved commodity prices and the satisfaction of all commitments by joint venturers in connection with the properties that have been farmed out. Petrolifera may have to bring participants into its acreage holdings and planned evaluation activities on less attractive terms than might otherwise have been the case due to the combination of tighter economic conditions and the influence of contractual commitments and deadlines on the terms of trade. There can be no assurance that the company will be successful in its efforts to secure planned farmouts and/or joint venture arrangements. There can be no assurance that the company will be successful in its efforts to secure cash payments, if any, or any planned farmouts and/or joint venture arrangements in Peru or Colombia and thereby reduce its indebtedness under the reserve-backed credit facility. Additionally, the company's ability to pay quarterly principal repayments when due is dependent on cash balances and cash flow from operations. Cash flow from operations is dependent on future production levels, commodity prices and foreign exchange rates. Additional risks and uncertainties associated with Petrolifera's future plans are described elsewhere in this interim report and in Petrolifera's Annual Information Form for the year ended December 31, 2009. Although the forward-looking information contained herein is based upon assumptions which Management believes to be reasonable, the company cannot assure investors that actual results will be consistent with this forward-looking information. This forward-looking information is made as of the date hereof and the company assumes no obligation to update or revise this information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward-looking information, prospective investors in the company's securities should not place undue reliance on this forward-looking information. Additionally, readers are reminded that cash flow from operations and EBITDA do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow from operations and EBITDA are reconciled to net earnings (loss) in the MD&A.
QUARTERLY RESULTS(4)
-------------------------------------------------------------------------
2008 2009
-------------------------------------------------------------------------
For the Three Months Ended
or As At Sept 30 Dec 31 Mar 31 June 30
-------------------------------------------------------------------------
FINANCIAL RESULTS
($000, EXCEPT PER SHARE
AMOUNTS) - UNAUDITED
-------------------------------------------------------------------------
Total revenue 32,126 37,411 26,407 22,255
Cash flow(1) 15,726 21,689 10,804 10,233
Basic, per share(1) 0.29 0.39 0.20 0.19
Diluted, per share(1) 0.28 0.39 0.20 0.18
Net earnings (loss) 3,564 2,662 1,188 3,427
Basic, per share 0.06 0.05 0.02 0.06
Diluted, per share(5) 0.06 0.05 0.02 0.06
Net capital spending 21,046 35,539 25,612 20,477
Cash 14,865 30,701 30,994 14,803
Working capital (deficit) 8,148 19,956 33,768 22,895
Long-term investments(6) 28,488 25,428 21,501 21,172
Long-term bank debt(6) 45,576 77,150 104,649 102,104
Shareholders' equity 178,069 202,347 209,240 201,749
Total assets 279,174 355,658 371,054 353,424
-------------------------------------------------------------------------
OPERATING RESULTS
-------------------------------------------------------------------------
Sales volumes:
Crude oil and natural
gas liquids - bbl/d 6,850 6,877 5,245 4,652
Natural gas - mcf/d 5,363 5,451 6,500 6,232
Equivalent - boe/d(2) 7,744 7,786 6,328 5,691
Pricing:
Crude oil and natural
gas liquids - $/bbl 48.93 56.76 52.17 48.72
Natural gas - $/mcf 2.58 2.88 2.98 2.87
Selected highlights - $/boe(2):
Weighted average
selling price 45.07 52.15 46.30 42.97
Interest and other income 0.02 0.08 0.06 -
Royalties 6.80 7.66 6.02 6.74
Operating costs 9.00 10.28 10.33 11.04
Corporate netback(3) 29.29 34.29 30.01 25.20
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
(000, EXCEPT SHARE PRICE)
-------------------------------------------------------------------------
Shares outstanding at
end of period 54,948 54,948 54,948 54,948
Weighted average shares
outstanding for the period:
Basic 54,884 54,948 54,948 54,948
Diluted(5) 55,897 55,043 55,195 55,600
Volume traded during quarter 7,884 8,826 10,053 13,268
Common share price ($):
High 8.72 3.99 1.60 3.47
Low 3.16 0.75 0.80 1.49
Close (end of period) 3.37 1.05 1.60 2.85
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2009 2010
-------------------------------------------------------------------------
For the Three Months Ended
or As At Sept 30 Dec 31 Mar 31 June 30
-------------------------------------------------------------------------
FINANCIAL RESULTS
($000, EXCEPT PER SHARE
AMOUNTS) - UNAUDITED
-------------------------------------------------------------------------
Total revenue 17,229 17,900 17,908 16,794
Cash flow(1) 5,503 5,867 7,177 5,270
Basic, per share(1) 0.07 0.05 0.06 0.04
Diluted, per share(1) 0.07 0.05 0.06 0.04
Net earnings (loss) (11,359) (4,081) (2,553) (297)
Basic, per share (0.14) (0.03) (0.02) 0.00
Diluted, per share(5) (0.14) (0.03) (0.02) 0.00
Net capital spending 13,389 9,378 15,742 17,696
Cash 55,953 35,732 32,207 41,179
Working capital (deficit) 724 (2,508) (10,659) 17,156
Long-term investments(6) 19,873 19,395 19,202 19,210
Long-term bank debt(6) 27,464 27,464 27,456 45,373
Shareholders' equity 238,475 232,126 227,097 251,260
Total assets 368,288 349,065 345,509 376,233
-------------------------------------------------------------------------
OPERATING RESULTS
-------------------------------------------------------------------------
Sales volumes:
Crude oil and natural
gas liquids - bbl/d 3,653 3,833 3,706 3,356
Natural gas - mcf/d 4,252 4,056 3,862 3,184
Equivalent - boe/d(2) 4,362 4,509 4,349 3,887
Pricing:
Crude oil and natural
gas liquids - $/bbl 48.07 48.08 50.65 52.13
Natural gas - $/mcf 2.74 2.53 2.54 2.66
Selected highlights - $/boe(2):
Weighted average
selling price 42.93 43.15 45.41 47.19
Interest and other income - - 0.34 0.29
Royalties 6.09 6.40 6.50 6.76
Operating costs 14.36 13.42 13.24 14.92
Corporate netback(3) 22.48 23.33 26.01 25.80
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
(000, EXCEPT SHARE PRICE)
-------------------------------------------------------------------------
Shares outstanding at
end of period 121,759 121,759 121,789 145,478
Weighted average shares
outstanding for the period:
Basic 82,418 121,759 121,789 141,835
Diluted(5) 82,539 121,777 121,812 141,835
Volume traded during quarter 55,032 35,921 47,157 15,295
Common share price ($):
High 2.85 1.09 1.31 1.01
Low 0.76 0.79 0.84 0.64
Close (end of period) 1.08 0.97 0.96 0.65
-------------------------------------------------------------------------
(1) Cash flow from operations before non-cash working capital changes
("cash flow") and cash flow per share do not have standardized
meanings prescribed by Canadian generally accepted accounting
principles ("GAAP") and therefore may not be comparable to similar
measures used by other companies. Cash flow includes all cash flow
from operating activities and is calculated before changes in non-
cash working capital. The most comparable measure calculated in
accordance with GAAP would be net earnings (loss). Cash flow is
reconciled with net earnings (loss) in this Management's Discussion &
Analysis ("MD&A") and MD&A for prior periods. Management uses these
non-GAAP measurements for its own performance measures and to provide
its shareholders and investors with a measurement of the company's
efficiency and its ability to fund a portion of its future growth
expenditures.
(2) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 Mcf : 1 bbl. Boe may be misleading particularly if
used in isolation. This conversion is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
(3) Corporate netback is a non-GAAP measure used by management as a
measure of operating efficiency and profitability. It is calculated
as petroleum and natural gas revenue and other income less royalties
and operating costs. For a reconciliation of netbacks to net earnings
(loss) see "MD&A".
(4) Fluctuations in results over the previous quarters are due
principally to variations in oil and gas prices (including variations
in foreign exchange rates), production mix and production volumes. In
addition, the net loss for the quarter ended September 30, 2009 was
adversely affected by the inclusion of depletion and depreciation
from March 2, 2009 to June 30, 2009. Depletion and depreciation was
initially not recognized from March 2, 2009 to June 30, 2009 due to
the decision, at that time, to sell the company's Argentinean
interests. Attributing to fluctuations in working capital is the
classification of debt as either current or long-term.
(5) As the company has net losses during the three months ended
September 30 and December 31, 2009 and March 31 and June 30, 2010,
the dilutive effect of stock options and share purchase warrants
became anti-dilutive, causing the basic weighted average common
shares outstanding to be used as the denominator in the dilutive per
share net loss calculation.
(6) Includes carrying value of notes received for ABCP with a face value
of $34.6 million as at June 30, 2010 and December 31, 2009. Long-term
debt in the amount of $27.5 million as at June 30, 2010 and
December 31, 2009 is primarily secured on a limited recourse basis by
the underlying notes formerly known as ABCP.
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
-------------------------------------------------------------------------
As at June 30, Dec. 31,
2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
ASSETS
Current
Cash $ 41,179 $ 35,732
Accounts receivable 21,895 20,871
Restricted cash 1,066 3,247
Inventory (Note 3) 695 958
Financial instrument - debt
agreement option (Note 5) 4,800 -
Income taxes receivable 4,199 4,636
Prepaid expenses 668 464
Deferred financing costs (Note 4) - 706
-------------------------------------------------------------------------
74,502 66,614
Long-term investments (Note 5) 19,210 19,395
Property and equipment 282,521 263,056
-------------------------------------------------------------------------
$ 376,233 $ 349,065
-------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities $ 23,129 $ 15,850
Income taxes payable 858 913
Bank debt (Note 4) 33,331 52,330
Due to a related company 28 29
-------------------------------------------------------------------------
57,346 69,122
-------------------------------------------------------------------------
Long-term bank debt (Note 4) 45,373 27,464
Asset retirement obligations (Note 6) 9,962 9,552
Future income taxes 12,292 10,801
-------------------------------------------------------------------------
124,973 116,939
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital and warrants (Note 7(a)) 167,156 148,264
Contributed surplus (Note 7(e)) 22,232 20,453
Accumulated other comprehensive loss (2,440) (3,753)
Retained earnings 64,312 67,162
-------------------------------------------------------------------------
251,260 232,126
-------------------------------------------------------------------------
$ 376,233 $ 349,065
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments and guarantees (Note 10)
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (UNAUDITED)
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) (except per
share amounts) 2010 2009 2010 2009
-------------------------------------------------------------------------
REVENUE
Petroleum and natural
gas sales $16,691 $22,254 $34,467 $48,625
Interest and other income 103 1 235 37
-------------------------------------------------------------------------
16,794 22,255 34,702 48,662
Royalties (2,391) (3,488) (4,935) (6,917)
-------------------------------------------------------------------------
14,403 18,767 29,767 41,745
-------------------------------------------------------------------------
EXPENSES
Operating 5,278 5,717 10,461 11,599
General and administrative 1,824 2,155 3,599 4,092
Finance charges (Note 4) 1,032 1,348 2,092 2,925
Taxes other than income taxes 571 955 845 1,364
Foreign exchange loss (gain) 483 (1,453) 802 992
Depletion, depreciation
and accretion (Note 11) 7,454 138 15,541 7,042
Fair value of debt
agreement option (Note 5) (4,800) - (4,800) -
Stock-based compensation
(Note 7(c)) 1,104 846 1,781 2,438
-------------------------------------------------------------------------
12,946 9,706 30,321 30,452
-------------------------------------------------------------------------
Earnings (loss) before
income taxes 1,457 9,061 (554) 11,293
Current income
tax provision 379 1,426 946 2,390
Future income tax provision 1,375 4,208 1,350 4,288
-------------------------------------------------------------------------
1,754 5,634 2,296 6,678
-------------------------------------------------------------------------
NET EARNINGS (LOSS) (297) 3,427 (2,850) 4,615
RETAINED EARNINGS,
BEGINNING OF PERIOD 64,609 79,175 67,162 77,987
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RETAINED EARNINGS,
END OF PERIOD $64,312 $82,602 $64,312 $82,602
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS (LOSS)
PER SHARE (Note 9(a))
-------------------------------------------------------------------------
Basic $0.00 $0.06 $(0.02) $0.08
Diluted $0.00 $0.06 $(0.02) $0.08
-------------------------------------------------------------------------
-------------------------------------------------------------------------
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Net earnings (loss) $(297) $3,427 $(2,850) $4,615
Foreign currency
translation adjustment 4,486 (11,764) 1,313 (7,651)
-------------------------------------------------------------------------
Comprehensive income (loss) $4,189 $(8,337) $(1,537) $(3,036)
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Accumulated other
comprehensive income (loss),
beginning of period $(6,926) $20,219 $(3,753) $16,106
Foreign currency
translation adjustment 4,486 (11,764) 1,313 (7,651)
-------------------------------------------------------------------------
Accumulated other
comprehensive income (loss),
end of period $(2,440) $8,455 $(2,440) $8,455
-------------------------------------------------------------------------
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Cash provided by (used in)
the following activities:
OPERATING
Net earnings (loss) $(297) $3,427 $(2,850) $4,615
Items not involving cash:
Depletion, depreciation
and accretion 7,454 138 15,541 7,042
Fair value of debt
agreement option (Note 5) (4,800) - (4,800) -
Stock-based compensation
(Note 7(c)) 1,104 846 1,781 2,438
Future income tax provision 1,375 4,208 1,350 4,288
Unrealized foreign
exchange loss 105 1,396 723 2,211
Amortization of deferred
charges (Note 4) 329 218 702 443
-------------------------------------------------------------------------
Cash flow from operations
before non-cash working
capital changes 5,270 10,233 12,447 21,037
Changes in non-cash working
capital (Note 9(b)) (572) 1,902 (3,123) 11,556
-------------------------------------------------------------------------
4,698 12,135 9,324 32,593
-------------------------------------------------------------------------
FINANCING
Issue of common shares
(Note 7(a)) 20,128 - 20,148 -
Deferred financing cost
and other (Note 4) (1,782) (218) (1,782) (218)
Share issue costs
(Note 7(a)) (1,306) - (1,306) -
Proceeds of long-term
bank debt - 10,256 - 18,972
Repayment of long-term
bank debt - (5,783) (8) (5,985)
Changes in non-cash
working capital (Note 9(b)) 1,836 - 1,836 -
-------------------------------------------------------------------------
18,876 4,255 18,888 12,769
-------------------------------------------------------------------------
INVESTING
Exploration and development
of oil and gas properties (20,272) (20,477) (37,038) (46,089)
Proceeds from farmout
agreements (Note 10) 2,576 - 3,600 -
Proceeds from
restricted cash - 294 2,475 294
Investment in
restricted cash (144) - (144) -
Receipt of interest on
long-term investment - 445 - 1,526
Changes in non-cash
working capital (Note 9(b)) 2,225 (7,807) 7,688 (12,263)
-------------------------------------------------------------------------
(15,615) (27,545) (23,419) (56,532)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH 7,959 (11,155) 4,793 (11,170)
Effect of foreign exchange
on foreign currency
denominated cash balances 1,013 (5,036) 654 (4,728)
CASH, BEGINNING OF PERIOD 32,207 30,994 35,732 30,701
-------------------------------------------------------------------------
CASH, END OF PERIOD $41,179 $14,803 $41,179 $14,803
-------------------------------------------------------------------------
Supplementary cash flow information (Note 9(c))
PETROLIFERA PETROLEUM LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED JUNE 30, 2010
(UNAUDITED)
1. FINANCIAL STATEMENT PRESENTATION
The interim unaudited Consolidated Financial Statements as at and for the
three and six months ended June 30, 2010 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. Petrolifera is engaged in petroleum and
natural gas exploration, development and production activities in South
America.
The interim unaudited Consolidated Financial Statements have been
prepared following the same accounting policies and methods of
computation as the annual audited Consolidated Financial Statements for
the year ended December 31, 2009. The disclosures provided below do not
conform in all respects to those included with the annual audited
Consolidated Financial Statements. The interim unaudited Consolidated
Financial Statements should be read in conjunction with the annual
audited Consolidated Financial Statements and the notes thereto.
2. NEW ACCOUNTING PRONOUNCEMENTS AND STANDARDS
In December 2008, the CICA issued Section 1582, Business Combinations,
which will replace CICA Section 1581 of the same name. Section 1582
establishes principles and requirements of the acquisition method for
business combinations and related disclosures. This statement applies
prospectively to business combinations for which the acquisition date is
on or after the beginning of the first annual reporting period beginning
on or after January 2011 with earlier application permitted. The company
is currently evaluating the impact of adopting this standard to any
business combination entered on or after January 1, 2011 on its
Consolidated Financial Statements.
In December 2008, the CICA issued Sections 1601, Consolidated Financial
Statements, and 1602, Non-Controlling Interests, which replaces existing
Section 1600. Section 1601 establishes standards for the preparation of
consolidated financial statements. Section 1602 provides guidance on
accounting for a non-controlling interest in a subsidiary in consolidated
financial statements subsequent to a business combination. These
standards are effective on or after the beginning of the first annual
reporting period beginning on or after January 2011 with earlier
application permitted. The company is currently evaluating the impact of
adopting Section 1601 and on the accounting of non-controlling interests
resulting from any business combinations entered on or after January 1,
2011 on its Consolidated Financial Statements.
3. INVENTORY
-------------------------------------------------------------------------
As at June 30, Dec. 31,
2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Crude oil $ 695 $ 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 June 30, 2010 and December 31, 2009
using a weighted average cost basis and is carried at the lower of cost
and net realizable value.
4. BANK DEBT
-------------------------------------------------------------------------
As at June 30, Dec. 31,
2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Current bank debt
Reserve-backed credit facility $28,371 $52,330
ABCP line-of-credit 4,960 -
-------------------------------------------------------------------------
$33,331 $52,330
-------------------------------------------------------------------------
Long-term bank debt
Reserve-backed credit facility $24,659 $-
ABCP line-of-credit 22,496 27,464
Deferred financing costs (1,782) -
-------------------------------------------------------------------------
$45,373 $27,464
-------------------------------------------------------------------------
Total bank debt
Reserve-backed credit facility $51,248 $52,330
ABCP line-of-credit 27,456 27,464
-------------------------------------------------------------------------
$78,704 $79,794
-------------------------------------------------------------------------
In 2007, the company entered into a US$100.0 million reserve-backed
credit facility with availability as at June 30, 2010 of US$50.0 million.
In August 2010, the company signed a 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 to reduce its
borrowings from US$50.0 million to the revised credit facility's
availability of US$38.3 million. The company agreed to make scheduled
permanent debt repayments of US$3.8 million per quarter through to expiry
of the agreement in June 2012, at which time all borrowings under this
credit facility will be due and payable. 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 as due and payable upon expiry of the revised agreement in June
2012. 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 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.
As at June 30, 2010 the outstanding reserve-backed facility was
$53.0 million (US$50.0 million) less approximately $1.8 million in
deferred financing costs which were recognized on the revised agreement
and will be amortized through to expiry of the facility in June 2012. As
the terms of the revised facility agreement were substantially changed,
the deferred financing costs related to the previous agreement were fully
amortized during the three months ended June 30, 2010 resulting in total
amortization of $0.3 million and $0.7 million for the three and six
months ended June 30, 2010, respectively (2009 - $0.2 million and
$0.4 million, respectively).
During 2009, the company negotiated with a Canadian chartered bank an
expansion of its line-of-credit to a maximum of $23.2 million, with an
initial expiry in April 2012 where the company can make up to four
extension requests with each extension representing an additional one-
year period. The line-of-credit was primarily secured by the eligible
master asset vehicles Classes A through C1 as received by the company in
exchange for a portion of the long term notes formerly known as Asset
Backed Commercial Paper ("ABCP"). The line-of-credit as primarily
secured by the ABCP bears interest at a floating rate.
The company has a second line-of-credit agreement to a maximum of
$5.0 million which was fully drawn as at June 30, 2010 and December 31,
2009. This second line-of-credit, which has an initial expiry in April,
2011, is solely secured by the ineligible master asset vehicle Classes 1
& 2 ("MAV IA 1 & 2") notes received by the company in 2009 in exchange
for a portion of the ABCP ("ABCP line-of-credit"). During the second
quarter of 2010, the company advised its lender it would not renew this
facility beyond its expiry date of April, 2011 at which time 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 on the
company's accounts as at December 31, 2009. As the company has the option
to settle its $5.0 million in borrowings as drawn on this ABCP line-of-
credit agreement through delivery to its lender of the MAV IA 1 & 2
notes, the company advised its lender during the second quarter of 2010
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 June 30, 2010 made under this facility as a current liability
(December 31, 2009 - $5.0 million was classified as a long-term
liability).
Interest expense on the facilities for the three and six months ended
June 30, 2010 was $0.6 million and $1.2 million, respectively (2009 -
$1.0 million and $2.4 million, respectively). These amounts were
disclosed on the Consolidated Statement of Operations and Retained
Earnings as finance charges, and also include the amortization of
deferred finance charges, facilities administration fees and vendor
interest charges. The combined effective interest rate on the company's
facilities was 3.1 percent for the three and six months ended June 30,
2010 (2009 - 4.5 percent and 5.0 percent, respectively). The unused
credit on the line-of-credit facility as primarily secured by the ABCP
was $0.7 million as at June 30, 2010 and December 31, 2009.
5. FINANCIAL INSTRUMENTS
Capital management
The company is subject to external restrictions on its reserve-backed
credit facility. As at June 30, 2010 and December 31, 2009, the facility
had an overall limit of US$100.0 million, with an established
availability of US$50.0 million based on producing crude oil and natural
gas reserves as at June 30, 2009. During August 2010, the company agreed
to the terms of a revised reserve-backed credit facility, which included
a reduced availability of US$38.3 million, based on producing crude oil
and natural gas reserves as at December 31, 2009. The company repaid
US$11.7 million against its reserve-backed credit facility at the signing
of the revised credit facility agreement, thereby reducing the total
draws against this facility to the revised availability of
US$38.3 million. The revised facility has a provision for a borrowing
base adjustment every six months, with the next adjustment to be
calculated based on information as at June 30, 2010. Outstanding bank
debt and long-term debt excludes amounts borrowed against the long term
notes formerly known as ABCP and cannot exceed two and a half times
("2.5X") the 12 month trailing EBITDA. EBITDA is defined by the revised
credit facility agreement as net loss prior to deduction of interest,
income taxes, depletion, depreciation and accretion expense and other
non-cash expenses and is reconciled to net loss as follows:
-------------------------------------------------------------------------
12
Months
Three Months Ended Ended
-------------------------------------------------------------------------
Sept. 30, Dec. 31, Mar 31, June 30, June 30,
($000) 2009 2009 2010 2010 2010
-------------------------------------------------------------------------
Net loss $(11,359) $ (4,081) $ (2,553) $ (297) $(18,290)
Add (deduct) interest,
income taxes, depletion,
depreciation and
accretion expense
and other non-cash
expenses:
Depletion, depreciation
and accretion 17,568 8,936 8,087 7,454 42,045
Fair value of option
on debt agreement - - - (4,800) (4,800)
Finance charges 1,132 1,040 1,060 1,032 4,264
Stock-based
compensation 1,561 675 677 1,104 4,017
Fair value impairment
of ABCP 2,104 - - - 2,104
Income tax provision
(recovery) (3,428) 724 542 1,754 (408)
Unrealized foreign
exchange loss (gain) (640) (143) 618 105 (60)
-------------------------------------------------------------------------
EBITDA $ 6,938 $ 7,151 $ 8,431 $ 6,352 $ 28,872
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at June 30, 2010, outstanding draws on portions of bank debt and long-
term bank debt were $61.6 million and EBITDA was $28.9 million, for a
ratio of debt to EBITDA of 2.1 : 1, which is 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:
-------------------------------------------------------------------------
Fair Value Hierarchy
-------------------------------------------------------------------------
Per Balance
($000) Sheet Level 1 Level 2 Level 3
-------------------------------------------------------------------------
Held for trading
financial assets:
Cash $ 41,179 $ 41,179 $ - $ -
Accounts receivable 21,895 - 21,895 -
Restricted cash 1,066 - 1,066 -
Debt agreement option 4,800 - 4,800
Long-term investments 19,210 - 521 18,689
-------------------------------------------------------------------------
Total held for trading
financial assets $ 88,150 $ 41,179 $ 23,482 $ 23,489
-------------------------------------------------------------------------
As no active market exists for the company's accounts receivable,
restricted cash and collateral to support issued letters of credit which
are partially recognized as long-term investments, these financial assets
have been classified as Level 2. As at June 30, 2010, long-term
investments includes notes received in exchange for ABCP with a face
value of $34.6 million (Dec. 31, 2009 - $34.6 million) and a carrying
value of $18.7 million (Dec. 31, 2009 - $18.7 million) and collateral to
support issued letters of credit of $0.5 million (Dec. 31, 2009 -
$0.7 million). The fair value of the collateral to support issued letters
of credit, a Level 2 financial asset, approximates its carrying value as
the collateral earns a floating market rate of interest. As at June 30,
2010, the debt agreement option represents the company's option to settle
$5.0 million in borrowings solely 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 the second quarter of 2010, the company advised its lender that
upon the expiry of the $5.0 million 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 solely limited to the MAV IA 1 & 2 notes. As the company
has the option to settle its $5.0 million in borrowings solely through
delivery to its lender of the MAV IA 1 & 2 notes and has 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 for the three months ended June 30, 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.
Although there have been some isolated third party transactions during
the six months ended June 30, 2010, no active market quotations have
developed for the longer term notes. As a result, management has
estimated the fair value of the company's investment in the longer term
notes at June 30, 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 June 30, 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 longer
term notes was an approximation of the risk-free rate for the expected
life of the longer term notes to be received. As the rate used for
discounting was an approximation of the risk-free rate, all other risks
have been incorporated in the estimated probability-adjusted expected
outcomes. This methodology applied all risking information into the
various scenarios and discounted the fully-risked cash flow stream only
for the time value of money. The recovery factors used were as follows:
-------------------------------------------------------------------------
Face Risk- Risk-
Value adjusted adjusted Capital Interest
Class of Capital Interest Weighted Weighted Risk-free
of Notes Recovery Recovery Average Average Term Discount
Note ($000s) Range Range Recovery Recovery (yrs) Rate
-------------------------------------------------------------------------
A-1 $13,978 0 - 80% 0 - 60% 75% 54% 3 - 7 3%
A-2 13,543 0 - 70% 0 - 30% 64% 27% 7 3%
B 2,459 0 - 30% 0% 27% 0% 7 3%
C 928 0% 0% 0% 0% 7 3%
-------------------------------------------------------------------------
IA -1 3,674 0% 0% 0% 0% 7 3%
-------------------------------------------------------------------------
Total $34,582
-------------------------------------------------------------------------
Based on the above approach the fair value of the investment in the
longer term notes was $18.7 million as at June 30, 2010 and December 31,
2009. Since 2007, the total impairment recognized is approximately
46 percent of the original cost of the investment on the longer term
notes, including impairments recognized in prior years on the ABCP.
The theoretical fair value of the company's longer-term notes could range
from $14.0 million to $25.0 million using the valuation methodology
described above with reasonably possible alternative assumptions. The
outcome of the actual timing and amount ultimately recoverable from these
notes may differ materially from this estimate, which would impact the
company's net loss.
Credit risk
The company's maxiumum credit exposure on cash, accounts receivable,
restricted cash, debt agreement option and long-term investments is equal
to each financial asset's carrying value as at June 30, 2010.
Cash, restricted cash, debt agreement option and the collateral to
support issued letters-of-credit, partially recognized as a portion of
long-term investments, are held with highly rated international banks and
therefore the company considers these assets to have negligible credit
risk.
The company's accounts receivable are primarily with multinational
purchasers, oil and gas marketers and local government agencies. The
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 expenditure.
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$12.9 million and US$28.1 million of crude oil
production to one multinational purchaser and US$0.8 million and
US$1.6 million in natural gas production to a reputable local gas
marketing company during the three and six months ended June 30, 2010,
respectively. Receivables with local government agencies mainly pertain
to excise taxes paid on certain expenditures. The company has not
experienced any collection problems with its counterparties and does not
currently have any overdue amounts.The company does not have an allowance
for doubtful accounts and did not write off any receivables during the
three and six months ended June 30, 2010.
Refer to the fair values of financial instruments contained herein for
further discussion regarding the credit risk of the longer term notes
formerly known as ABCP as recognized as a portion of long-term
investments.
Liquidity risk
The company manages the risk of not meeting its financial obligations
through management of its capital structure, annual budgeting of its
revenues, expenditures and cash flows, cash flow forecasting and
maintaining an unused credit facility where practicable.
Accounts payable, as disclosed on the Consolidated Balance Sheet, fall
due within the next year and are anticipated to be funded through the
company's cash and collections of accounts receivable. The reserve-backed
credit facility has a current available limit of US$50.0 million, all of
which is drawn at June 30, 2010. During August 2010, the company agreed
to the terms of a revised reserve-backed credit facility, which included
a reduced availability of US$38.3 million and the following quarterly
permanent debt repayments through to expiry of the agreement in June 2012
at which time all borrowings under this credit facility will be due and
payable:
-------------------------------------------------------------------------
Three months ended
-------------------------------------------------------------------------
(US$000)
-------------------------------------------------------------------------
September 30, 2010 $3,750
December 31, 2010 3,750
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
-------------------------------------------------------------------------
In August 2010, the company made a one-time payment of US$11.7 million to
comply with the facility's reduced availability of US$38.3 million.
This one-time repayment and quarterly repayments thereafter are
anticipated to be funded from existing cash balances, cash flows from
operations and proceeds, if any, from farmout agreements. The company
holds a combined $28.2 million line-of-credit, of which $27.5 million is
drawn at June 30, 2010. Of the $28.2 million line-of-credit, $5.0 million
expires in April 2011 as solely secured by the MAV IA 1 & 2 notes and
$23.2 million expires in April 2012 as primarily secured on a recourse
basis by the eligible master asset vehicles Classes A through C1 notes
received in exchange for the ABCP.
Market risk
Changes in commodity prices, interest rates and foreign currency exchange
rates can expose the company to fluctuations in its net earnings (loss)
and in the fair value of its financial assets and liabilities.
Commodity price risk
Price fluctuations for crude oil, natural gas liquids and natural gas are
a risk to the company over which the company has little influence. Due to
pricing controls present in Argentina and a domestic crude oil sales
agreement with a multinational purchaser, crude oil selling prices
reflect both current market conditions in Argentina and the movement of
crude oil prices in international markets. Natural gas prices are
impacted by the Argentine government and local demand with historic
prices at low levels compared to world prices.
Interest rate risk
Floating rate debt exposes the company to fluctuations in cash flows and
net earnings (loss) due to changes in market interest rates. Based on the
existing debt balance, a one percent increase (decrease) in the
underlying market interest rates would have increased (decreased) the net
loss by approximately $0.8 million on an annual basis.
Foreign currency exchange rate risk
Substantially all of the company's operations are conducted in foreign
jurisdictions, so the company is exposed to foreign currency exchange
rate risk on most of its activities as reported in Canadian Dollars
(CAD). Oil and natural gas sales contracts are denominated in US Dollars
(USD) and settled in Argentine Pesos (ARS). Operating and capital
expenditures are incurred in USD, ARS and Colombian Pesos (COP), and to a
lesser extent in Peruvian Nuevos Soles (PEN). The revolving reserve-
backed credit facility is denominated in USD, which partially limits the
company's exposure in terms of cash outflows (interest expense) being
inversely correlated to cash inflows (oil and gas revenues). The table
below details the company's financial instruments exposure to foreign
currencies:
-------------------------------------------------------------------------
Per CAD USD ARS PEN COP
Balance --------------------------------------------
($000) Sheet CAD $ equivalent amounts
-------------------------------------------------------------------------
Cash $41,179 $15,729 $ 1,805 $19,938 $ 13 $ 3,694
Accounts receivable 21,895 89 5,060 7,512 1,281 7,953
Restricted cash 1,066 - 1,066 - - -
Debt agreement
option 4,800 4,800 - - - -
Long-term
investments 19,210 18,689 521 - - -
Accounts payable
and accrued
liabilities (23,129) (2,183) (6,259) (9,828) (12) (4,847)
Bank debt (33,331) (4,960) (28,371) - - -
Long-term
bank debt (45,373) (22,496) (22,877) - - -
-------------------------------------------------------------------------
Net financial assets
(liabilities) $(13,683) $ 9,668 $(49,055) $17,622 $ 1,282 $ 6,800
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The company estimates a 20 percent change in the Canadian Dollar against
the above listed foreign currencies could be reasonably possible over a
twelve month period. A 20 percent strengthening in the CAD would result
in a change to earnings (loss) before taxes and other comprehensive
income (loss) as follows (an equal but opposite impact to earnings (loss)
before taxes and other comprehensive income (loss) would result if the
CAD weakened by 20 percent):
-------------------------------------------------------------------------
USD ARS PEN COP
------------------------------------------
($000) CAD $ equivalent amounts
-------------------------------------------------------------------------
Increase (decrease) in earnings
before taxes $ 1,374 $ - $ (214) $(1,133)
Increase in other comprehensive
income $ 3,865 $ - $ - $ -
-------------------------------------------------------------------------
6. ASSET RETIREMENT OBLIGATIONS
At June 30, 2010 the estimated total undiscounted amount required to
settle the asset retirement obligations was $17.5 million (2009 -
$17.3 million). These obligations are expected to be settled over the
useful lives of the underlying assets, which currently extend up to 18
years into the future. This amount has been discounted using a credit-
adjusted risk-free interest rate of six percent and an annual inflation
rate of two percent. Changes to asset retirement obligations were as
follows:
-------------------------------------------------------------------------
Six Months Ended June 30 2010
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Asset retirement obligations, beginning of period $9,552
Liabilities incurred 21
Change in estimate (22)
Cumulative translation adjustment 135
Accretion expense 276
-------------------------------------------------------------------------
Asset retirement obligations, end of period $9,962
-------------------------------------------------------------------------
7. 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, respectively.
Issued common shares:
-------------------------------------------------------------------------
Number of Amount
Six Months Ended June 30, 2010 Common Shares ($000)
-------------------------------------------------------------------------
Common shares, beginning of period 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 (c) 40,000 20
Issued common shares upon exercise
of warrants (d) 650 1
Assigned value of options exercised (e) - 2
Issue costs net of tax-effect (b) - (1,258)
-------------------------------------------------------------------------
Common shares, end of period 145,477,660 $162,502
-------------------------------------------------------------------------
Issued warrants:
-------------------------------------------------------------------------
Number of Amount
Six Months Ended June 30, 2010 Warrants ($000)
-------------------------------------------------------------------------
Warrants, beginning of period 33,240,250 $ 4,654
Exercised warrants (d) (650) -
-------------------------------------------------------------------------
Warrants, end of period 33,239,600 $ 4,654
-------------------------------------------------------------------------
Share capital and warrants:
-------------------------------------------------------------------------
June 30, December 31,
As at 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Share capital and warrants $ 167,156 $ 148,264
-------------------------------------------------------------------------
(b) Equity Financing:
In March 2010, the company announced that it entered into an underwriting
agreement with a syndicate of underwriters to issue 20,590,000 common
shares at a price of $0.85 per common share on a "bought deal" basis for
gross proceeds of approximately $17.5 million ("Public Offering"). The
underwriters were granted an over-allotment option (the "Over-Allotment
Option"), which included the right to purchase up to an additional
15 percent of the common shares, exercisable in whole or in part up to 30
days following closing of the Public Offering. The Over-Allotment Option
was exercised in whole by the underwriters on April 14, 2010, the closing
date of the 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.
(c) Stock Options:
As at June 30, 2010 and 2009, the company had outstanding stock options
to acquire common shares, as follows:
-------------------------------------------------------------------------
Six Months Ended June 30 2010 2009
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding,
beginning of
period 7,683,067 $ 1.60 4,576,327 $ 6.85
Granted 2,229,454 0.91 984,000 2.64
Exercised (40,000) (0.50) - -
Forfeited or
cancelled - - (1,891,160) (13.14)
-------------------------------------------------------------------------
Outstanding,
end of period 9,872,521 $ 1.45 3,669,167 $ 2.48
-------------------------------------------------------------------------
Exercisable,
end of period 4,345,288 $ 1.65 1,722,667 $ 2.45
-------------------------------------------------------------------------
Options granted under the plan are generally fully exercisable after two
or three years and expire five years after the date granted. The table
below summarizes unexercised stock options and the weighted average
recurring contractual life, in years, by ranges of exercise prices as at
June 30, 2010 and 2009:
-------------------------------------------------------------------------
As at June 30 2010 2009
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Remaining Remaining
Number Contractual Number Contractual
Outstanding Life (yrs) Outstanding Life (yrs)
-------------------------------------------------------------------------
$0.50 - - 240,000 0.6
$0.86 - $1.09 7,164,021 4.1 547,667 1.1
$1.70 - $1.75 313,000 0.4 418,000 1.4
$2.00 1,007,000 3.4 1,007,000 4.4
$2.64 - $3.37 1,209,000 3.8 1,209,000 4.8
$5.40 - $19.20 179,500 1.4 247,500 2.3
-------------------------------------------------------------------------
Total 9,872,521 3.9 3,669,167 3.3
-------------------------------------------------------------------------
During the three and six months ended June 30, 2010, a non-cash expense
of $1.1 million and $1.8 million, respectively, (2009 - $0.8 million and
$1.3 million) was recorded as stock-based compensation, reflecting the
amortization of the fair value of stock options over the vesting period.
Additionally, during the six months ended June 30, 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 for the six months ended June 30, 2009 of $1.1 million.
The fair value of each option granted for 2010 is estimated on the date
of grant using the Black-Scholes option-pricing model with assumptions
for grants as follows:
-------------------------------------------------------------------------
Dividend Risk-free Expected Expected
yield interest rate life volatility
-------------------------------------------------------------------------
2010 -% 2.0% - 2.8% 4 years 81.1% - 81.8%
-------------------------------------------------------------------------
2009 -% 2.0% 4 years 89%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of all options
granted for the three and six months ended June 30, 2010 was $0.55 and
$0.56 per option, respectively (2009 - $1.69 per option).
(d) Warrants:
Each warrant entitles the holder thereof to purchase one common share at
an exercise price of $1.20 per warrant until August 28, 2011. The
weighted average fair value of all issued warrants is $0.14 per warrant.
(e) Contributed Surplus:
-------------------------------------------------------------------------
Six Months Ended June 30 2010
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Contributed surplus, beginning of period $ 20,453
Stock-based compensation (c) 1,781
Assigned value of options exercised (2)
-------------------------------------------------------------------------
Contributed surplus, end of period $ 22,232
-------------------------------------------------------------------------
8. SEGMENTED INFORMATION
The company has corporate offices in Canada, the US and Barbados
(combined to comprise the "Corporate" segment), petroleum and natural gas
operations in Argentina and exploration activities in Peru and Colombia.
Financial information pertaining to these segments is presented below.
-------------------------------------------------------------------------
Corporate Argentina Peru Colombia Total
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Three months ended or
as at June 30, 2010
-------------------------------------------------------------------------
Revenue, gross $3 $16,698 $- $93 $16,794
Net earnings (loss) 2,756 (3,122) (7) 76 (297)
Property and equipment 322 145,949 56,907 79,343 282,521
Capital expenditures 7 1,887 313 18,065 20,272
Total assets $41,755 $185,235 $58,252 $90,991 $376,233
-------------------------------------------------------------------------
Three months ended or
as at June 30, 2009
-------------------------------------------------------------------------
Revenue, gross $- $22,255 $- $- $22,255
Net earnings (loss) (2,777) 6,056 146 2 3,427
Property and equipment 287 190,773 55,467 37,471 283,998
Capital expenditures 11 10,488 708 9,270 20,477
Total assets $38,442 $213,476 $60,144 $41,362 $353,424
-------------------------------------------------------------------------
Six months ended or
as at June 30, 2010
-------------------------------------------------------------------------
Revenue, gross $3 $34,606 $- $93 $34,702
Net earnings (loss) 790 (3,681) (20) 61 (2,850)
Property and equipment 322 145,949 56,907 79,343 282,521
Capital expenditures 12 4,202 759 32,065 37,038
Total assets $41,755 $185,235 $58,252 $90,991 $376,233
-------------------------------------------------------------------------
Six months ended or
as at June 30, 2009
-------------------------------------------------------------------------
Revenue, gross $9 $48,631 $22 $ - $48,662
Net earnings (loss) (5,826) 10,365 97 (21) 4,615
Property and equipment 287 190,773 55,467 37,471 283,998
Capital expenditures 20 15,126 6,668 24,275 46,089
Total assets $38,442 $213,476 $60,144 $41,362 $353,424
-------------------------------------------------------------------------
Crude oil sales totaling US$12.9 million and US$28.1 million (2009 -
US$15.6 million and US$38.3 million) were made to a large international
oil company and natural gas sales totaling US$0.8 million and
US$1.6 million (2009 - US$1.4 million and US$2.8 million) were made to a
local gas marketing company during the three and six months ended
June 30, 2010, respectively.
9. SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the calculation of basic and diluted
common shares:
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Weighted average common
shares outstanding 141,834,764 54,948,010 131,867,124 54,948,010
Dilutive effect of
stock options and
share purchase
warrants - 651,897 2,617 494,843
-------------------------------------------------------------------------
Weighted average common
shares outstanding
- diluted 141,834,764 55,599,907 131,869,741 55,442,853
-------------------------------------------------------------------------
As the company has net losses for the six months ended June 30, 2010, the
dilutive effect of stock options and share purchase warrants became anti-
dilutive, causing 131,867,124 weighted average dilutive common shares
outstanding to be used as the denominator in the diluted per share net
loss calculation for the six months ended June 30, 2010.
(b) Net change in non-cash working capital
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Accounts receivable $(290) $ 3,172 $(832) $12,530
Inventory (3) 144 191 67
Income taxes receivable 523 256 469 -
Prepaid expenses 292 325 (197) (73)
Accounts payable and
accrued liabilities 3,094 (9,216) 6,830 (12,350)
Income taxes payable (137) (584) (59) (914)
Due to a related company 10 (2) (1) 33
-------------------------------------------------------------------------
$3,489 $(5,905) $6,401 $(707)
-------------------------------------------------------------------------
Operating $(572) $1,902 $(3,123) $11,556
Financing 1,836 - 1,836 -
Investing 2,225 (7,807) 7,688 (12,263)
-------------------------------------------------------------------------
$3,489 $(5,905) $6,401 $(707)
-------------------------------------------------------------------------
(c) Supplementary cash flow information
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Interest paid $618 $1,038 $1,236 $2,360
Income taxes paid $1,435 $2,421 $1,943 $2,421
-------------------------------------------------------------------------
-------------------------------------------------------------------------
10. COMMITMENTS AND GUARANTEES
Work commitments
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 is awaiting the approval of its Block 107
Environmental Impact Assessment for several potential drilling sites, at
which time it can commence with the fourth period's work commitment
requiring one well to be completed by 2013. 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 Assessments
("TEAs"). Petrolifera converted the Turpial and Sierra Nevada II TEAs
into exploration licenses with the latter renamed Magdalena. The company
recently completed the second phase of its Sierra Nevada License work
program, which required the drilling of one exploratory well and
acquiring additional seismic, with the completion of this phase still to
be acknowledged by the Colombian authority, Agencia Nacional de
Hidrocarburos ("ANH"). The company completed the Sierra Nevada License's
second phase exploratory well, Brillante SE-1X, during March 2010, to a
total depth of 9,500 feet. During the second quarter of 2010, the company
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. Whilst still to
be acknowledged by ANH, the company completed the second phase 2D seismic
work program on its Turpial License. This was disproportionally financed
by the company's joint venturer. Completion of seismic interpretation is
expected to occur on the company's Turpial License prior to the work
program deadline of September 2010. The company is in the first phase of
its Magdalena License, which requires an exploration well to be completed
prior to December 2010. The company anticipates the drilling of an
exploratory well on its San Angel prospect during the fourth quarter of
2010 to meet this requirement.
In Argentina, the company has farmed out its Vaca Mahuida and Puesto
Guevara Concessions work commitments of US$2.9 million and
US$0.6 million, respectively, through agreements reached in the first
quarter of 2010. At Vaca Mahuida, a total of five exploratory wells have
been drilled by the company, financed by the company's joint venturers.
The Vaca Mahuida farmout agreement also provided for the reimbursement to
the company of $2.6 million and $3.6 million for the costs of drilled
wells during the three and six months ended June 30, 2010, respectively.
The company's working interest in the Vaca Mahuida Concession will reduce
to 25 percent upon acknowledgement by the Province of Rio Negro,
Argentina, that the existing work commitment has been met. 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 in this Concession. The company has no remaining work commitments
in Argentina.
Contractual commitments
The company's gross contractual commitments under service contracts for
drilling, leases for office premises and other equipment and an
administrative services agreement for the six months ended December 31,
2010 and annually thereafter are as follows:
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Subsequent to
($000) 2010 2011 2011 Total
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Drilling contracts
and other leases $7,900 $810 $251 $8,961
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Guarantees
As at June 30, 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 June 30, 2010, a deposit of
US$2.8 million (Dec. 31, 2009 - US$4.1 million) is held in a trust
account in Colombia to meet certain work obligations on the Magdalena
License as they occur.
11. COMPARATIVE INFORMATION
The company announced on March 2, 2009 that its Board of Directors had
authorized the company to initiate a process to dispose of its
Argentinean interests. As originally presented within the unaudited
Consolidated Financial Statements as at and for the three and six months
ended June 30, 2009, the company's Argentinean interests were classified
as discontinued operations. Depletion and depreciation, as disclosed on
the Consolidated Statement of Operations and Retained Earnings as
depletion, depreciation and accretion expense, were not recognized for
the period March 2, 2009 to June 30, 2009, the dates the Argentinean
operations were classified as discontinued operations. During early July
2009, several bids for the company's Argentinean interests were received
from third parties and, after careful consideration, on July 15, 2009 the
company announced that the process to dispose of its interests did not
result in any acceptable bids. Accordingly, the comparative information
within these unaudited Consolidated Financial Statements for the three
and six months ended June 30, 2010 presents the Argentinean interests as
though the operations were part of continuing operations without giving
effect to depletion and depreciation expense for the period March 2, 2009
to June 30, 2009.
For further information: Petrolifera Petroleum Limited, R. A. Gusella, Executive Chairman, (403) 538-6201 Or Gary D. Wine, President and Chief Operating Officer, (403) 539-8450 Or Kristen J. Bibby, Vice President Finance and Chief Financial Officer, (403) 539-8450, [email protected], www.petrolifera.ca
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