Petrolifera Petroleum Enhances Liquidity, Makes Significant Colombian Natural
Gas Discovery, Stabilizes Argentinean Production During First Quarter 2010
CALGARY, May 5 /CNW/ - Petrolifera Petroleum Limited (PDP - TSX) was successful in expanding corporate liquidity, while also making a significant natural gas discovery at Brillante on its 100 percent-owned Sierra Nevada License in the Lower Magdalena Basin onshore Colombia, during the first quarter of 2010. Additionally, the company's five well infill program, conducted in late 2009 at the Puesto Morales Norte ("PMN") in Argentina, contributed to improved production stability during the reporting period. An additional four infill wells are planned for 2010 to reinforce the positive impact of the 2009 program and the first quarter 2010 expansion of water treatment and handling facilities at PMN.
These results will be the subject of a Conference Call at 9:00 AM MT on May 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 Thursday, May 6, 2010 at 12:00 MT until 21:59 MT on Thursday, May 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 72037923. You can also listen to the conference call online, through the following webcast link: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=3057120
Highlights:
- Initiated a successful bought deal equity financing to strengthen
working capital, raising $20 million
- Successful drilling at Brillante SE-1X well on Sierra Nevada License
with a significant natural gas discovery announced
- La Pinta 1X well remediated but unable to successfully test Cienaga
de Oro ("CDO") Formation; moving uphole to test Porquero Formation
for oil
- Farmed out remaining interest in Vaca Mahuida Block in Argentina for
a multi-well commitment and also farmed out Puesto Guevara while
retaining a meaningful interest and operatorship in both
- Progress made in revamping existing credit facility to secure
extended term; anticipate finalization in Q2 2010
Summary Results
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For The Three Months Ended or As At March 31 2010 2009 % Change
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FINANCIAL ($000, except per share amounts)
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Total revenue $ 17,908 $ 26,407 (32)
Cash flow from operations before non-cash
working capital(1) 7,177 10,804 (34)
Per share, basic 0.06 0.20 (70)
Per share, diluted 0.06 0.20 (70)
Net earnings (loss) (2,553) 1,188 (315)
Per share, basic (0.02) 0.02 (200)
Per share, diluted(4) (0.02) 0.02 (200)
Net capital expenditures 15,742 25,612 (39)
Cash 32,207 30,994 4
Working capital (deficit) (10,659) 33,768 (132)
Long-term investments(2) 19,202 21,501 (11)
Long-term debt(2) 27,456 104,649 (74)
Shareholders' equity 227,097 209,240 9
Total assets $345,509 $371,054 (7)
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OPERATING
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Daily sales volumes
Crude oil and natural gas liquids - bbl/d 3,706 5,245 (29)
Natural gas - mcf/d 3,862 6,500 (41)
Barrels of oil equivalent - boe/d(3) 4,349 6,328 (31)
Average selling prices
Crude oil and natural gas liquids - $/bbl $ 50.65 $ 52.17 (3)
Natural gas - $/mcf $ 2.54 $ 2.98 (15)
Barrels of oil equivalent - $/boe $ 45.41 $ 46.30 (2)
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COMMON SHARES OUTSTANDING (000s)
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Weighted average
Basic 121,789 54,948 122
Diluted(4) 121,812 55,195 121
End of period 121,798 54,948 122
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(1) Cash flow from operations before non-cash working capital changes
("cash flow") and cash flow per share do not have standardized
meanings prescribed by Canadian generally accepted accounting
principles ("GAAP") and therefore may not be comparable to similar
measures used by other companies. Cash flow includes all cash flow
from operating activities and is calculated before changes in non-
cash working capital. The most comparable measure calculated in
accordance with GAAP would be net earnings (loss). Cash flow is
reconciled with net earnings (loss) in the 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 March 31, 2010 and 2009, respectively. Long-term debt in the
amount of $27.5 million and $16.4 million as at March 31, 2010 and
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 Q1 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.
Petrolifera continued its program of financial consolidation during the first quarter of 2010 ("Q1 2010"). Production remained relatively stable compared to Q3 2009 and Q4 2009 although it was down from the prior year. This stabilization reflects the impact of the first new drilling for some time in Argentina; this occurred during Q4 2009, which favorably impacted on Q1 2010 results by overcoming normal declines. As a consequence, we had a respectable level of sales and cash flow from operations. A modest loss was recorded.
Most of our activity during the quarter focused on Colombian drilling, financial matters and capital raising activity. With the decline in our reserves in 2009, we continued our dialogue with our reserve-backed lenders and we believe we are nearing completion of a revised facility, which we anticipate on renewal and with final documentation will be characterized by an extended overall term in addition to some regular debt reduction payments. This renewal will enhance working capital, which for the moment has all of our reserve backed debt as a current liability. Further liquidity enhancements occurred subsequent to the end of the reporting period with the closing of the successful bought deal equity financing we initiated in March 2010 and completed in early April 2010.
As the quarter progressed, we recognized the likelihood of having to dedicate a portion of our anticipated cash flow to debt retirement. Also, having been unable to consummate a significant farmout of either our Colombian or Peruvian acreage in as timely a manner as envisaged in our internal planning process, we determined we needed additional funds to pursue and complete certain exploration spending in Colombia, including at Brillante. Simultaneously, we were continuing our dialogue with industry partners about possible joint ventures to recover some of our sunken capital, in one form or another and to receive a carry through certain higher cost drilling.
We were fortunate to secure a bought deal proposal from a strong syndicate of Canadian investment banks and raised over $20 million of new equity (before expenses of the issue). This included proceeds from the exercise of the over-allotment option granted to the dealers who marketed the issue of common shares. This extra capital provided Petrolifera with more flexibility and is anticipated to place us in a stronger bargaining position with prospective farminees, especially as we dialogue about joint ventures on our high potential acreage.
Colombia
During the quarter, we successfully remediated the La Pinta 1X well through the use of a snubbing unit, which we had secured and transported to Colombia as part of our program to attempt to retest the CDO Formation. Readers will recall this Formation had yielded light crude oil with an instantaneous flow rate exceeding 700 bbl/d, before sand plugged the tubing in the well and the flow stopped. Instantaneous flow rates are not stabilized flow rates and may not be indicative of the ability of the well to produce light gravity crude oil at these or comparable rates.
Unfortunately, while the remediation was successful, the tubing again plugged and we have decided to abandon this zone and move uphole to test the Porquero Formation, which encountered crude oil shows while drilling, and based on log analysis, appears to be crude oil bearing and a potentially good reservoir. This can only be confirmed by testing, which should be underway shortly. The outcome of the test will determine a future course of action on this crude oil play and the La Pinta 1X well. We have initiated a 3D seismic program over the La Pinta structure, which is also prospective at shallower depths for both crude oil and natural gas.
We spudded the Brillante SE-1X well on the Sierra Nevada License in mid-February, 2010. The well was drilled on time and under budget without encountering any undue drilling complications and tested significant volumes of natural gas with no water. A 212 foot gross pay interval (105.5 feet of net pay) was tested and yielded flowing natural gas at a rate of 8.4 mmcf per day, through a 48/64" choke, with a surface pressure of 579 psi from a depth of just below 3,000 feet. While not conclusive on a standalone basis, these rates and the shallow depths augur well for possible future commercial exploitation, although further testing and likely more drilling will be required before this can be confirmed. A final absolute open flow ("AOF") rate of 18 mmcf per day was calculated once bottom hole data could be recovered. The well had considerably more indicated pay thickness below the tested zone, which has been recognized by an independent consultant in a petrophysical evaluation, which could add to the reserve and resource backing for the play and the well. A long term production test will be conducted before any decisions on commerciality can be made.
We continue to anticipate farming out the cost of drilling and testing the San Angel well prior to year end on the Magdalena License, which is contiguous with the Sierra Nevada Block. Confirmation of the indicated significant Brillante discovery and possible success at San Angel would likely provide the potential for significant resource backing and infrastructure construction to get the natural gas to available markets, once necessary regulatory approvals are received. Market conditions seem to be developing on a favorable basis with growing demand, limited new finds and the prospect of attractive pricing for natural gas.
Our Turpial Block in the Middle Magdalena Basin of Colombia will be evaluated by an expanded 2D seismic program this year. Petrolifera will retain a 50 percent working interest in this Block, while continuing to hold a 100 percent interest in both the Magdalena and Sierra Nevada Licenses. Our large working interests provides considerable leverage to success through drilling for our shareholders, while also facilitating a basis to farmout a portion of this working interest for work, cash or other form of consideration on the lands. In this manner, Petrolifera gets carried through the expenditures and cash outlays during the high cost, higher risk phases of the evaluation of its acreage.
Other
In Argentina, we have successfully farmed our remaining interest in the Vaca Mahuida Block and will retain operatorship, a 25 percent working interest and are carried for the cost of up to four exploratory wells on the License. Some early encouragement has occurred while drilling. Our Puesto Guevara Block was also farmed out for a carry through two wells while retaining a 44 percent working interest and operatorship.
We anticipate up to four additional infill development wells will be drilled within the Puesto Morales Norte Field during the balance of 2010 and Petrolifera anticipates we may be able to encourage the drilling of numerous farmout wells to evaluate other potential on the Block, including the evaluation of the Loma Montosa Formation, which is productive in the area.
We continue to be excited about our holdings in all of Argentina, Colombia and Peru. Our Peruvian blocks continue to be held in high regard by the industry and we envisage accelerated activity on them as the year progresses, once we secure our Environmental Impact Assessment approvals for drilling, especially on Block 107. Farmout discussions are continuing with new interest from third parties emerging as time passes.
Having secured new capital, increased financial flexibility and a strengthened balance sheet, Petrolifera can now move forward with confidence and the prospect of a much broader and more valuable reserve base, which will enable the company to focus on the future and prospective exploitation of this expanded asset base with attendant cash flow growth, once the overall scale of the opportunity and success is more thoroughly evaluated and converted to productive status.
In our opinion, our land base remains among the best in the industry among companies active in onshore South America at the present time. Our large working interests favor us for the impact of success on underlying valuations. The restoration of exploration success will restore confidence in the outlook for Petrolifera and continued drilling will lead to growth and added value.
Forward-looking Information:
This press release contains forward-looking information including, but not limited to the planned infill drilling at PMN, Argentina and expansion of the associated water handling facilities, anticipated finalization of a revised credit facility which is expected extend the term of the facility and provide for regular debt reduction payments, further testing of the La Pinta 1X well in Colombia, anticipated results from the Brillante SE-1X well in Colombia, drilling of the exploratory well on the San Angel prospect within the Magdalena License onshore Colombia during 2010 and planned farmout and/or joint venture arrangements to reduce the company's financial exposure to high cost exploration and drilling activities in Colombia and Peru.. Additional forward-looking information is contained in the attached Management's Discussion and Analysis and reference should be made to the additional disclosures of the assumptions and risks and uncertainties relating to such forward-looking information in the Management's Discussion and Analysis.
Forward-looking information is not based on historical facts but rather on Management's expectations regarding the company's future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities and expectations with respect to general economic conditions. Such forward-looking information reflects Management's current beliefs and assumptions and is based on information currently available to Management. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information, including but not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production, delays or changes to plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of geological interpretations; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environment risks), the risk of commodity price and foreign exchange rate fluctuations, the uncertainty associated with negotiating with foreign governments and third parties located in foreign jurisdictions and the risk associated with international activity. There can be no assurance that testing of the Porquero Formation in the La Pinta 1X well drilled on the Sierra Nevada License will yield commercial results. 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 is required. 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. In order to secure an extension of the term of its reserve-backed credit facility, Petrolifera may be required to make additional repayments under this facility and/or pay certain renewal fees to its lender. In addition, borrowings under an amended reserve-backed credited facility may be subject to increased interest rates, depending on market conditions at the time of review. There can be no assurance that Petrolifera will be able to renegotiate the terms of its reserve-backed credit facility on terms acceptable to it or at all.
Additional risks and uncertainties associated with Petrolifera's future plans are described in the Management's Discussion and Analysis attached hereto 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
The following is dated as of May 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 months ended March 31, 2010 as contained in this interim report and the audited consolidated financial statements for the years ended December 31, 2009 and 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.
This MD&A includes forward-looking information including but not limited to the company's plan to renegotiate its existing reserve-backed credit facility, anticipated further testing of the La Pinta 1X well in Colombia, 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 required by Canadian GAAP for the three months ended March 31, 2009, because of the subsequent decision made on July 15, 2009 to retain the Argentinean operations, these operations must be presented as though they were "held for use" despite the previous classification in the 2009 first quarter's unaudited consolidated financial statements and MD&A as "discontinued operations".
For the three months ended March 31, 2009 the presentation of the Argentinean operations as "held for use" does not recognize depletion related to the period from March 2 through to March 31, 2009 resulting from the previous classification as "discontinued operations". Because depletion was not recognized for a portion of the period during the three months ended March 31, 2009, depletion, depreciation and accretion expense ("DD&A") and net earnings recognized for the three months ended March 31, 2009 are not comparable to the DD&A and the net loss recognized for the three months ended March 31, 2010, respectively.
FINANCIAL AND OPERATING REVIEW
SALES VOLUMES, PRICING AND REVENUE
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Three Months Ended March 31 2010 2009 % change
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Daily sales volumes:
Crude oil and natural gas liquids - bbl/d 3,706 5,245 (29)
Natural gas - mcf/d 3,862 6,500 (41)
Equivalent - boe/d 4,349 6,328 (31)
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Average selling prices:
Crude oil and natural gas liquids - $/bbl $ 50.65 $ 52.17 (3)
Natural gas - $/mcf 2.54 2.98 (15)
Weighted average selling price - $/boe $ 45.41 $ 46.30 (2)
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Petroleum and natural gas sales ($000) $ 17,776 $ 26,371 (33)
Interest and other income ($000) 132 36 267
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Total revenue ($000) $ 17,908 $ 26,407 (32)
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Petroleum and natural gas revenues for the first quarter of 2010 were $17.8 million on average sales volumes of 4,349 boe per day, compared to $26.4 million on average sales volumes of 6,328 boe per day during the same period in 2009, decreases of 33 percent and 31 percent, respectively. For the first quarter of 2010, sales of crude oil and natural gas liquids represented 85 percent of the company's sales volumes, which is comparable to the 83 percent for the same period in 2009. The reduction in sales revenues for the first quarter of 2010 as compared to the same period in 2009 reflects a lower weighted average selling price, combined with lower sales volumes. This was mainly attributable to natural production declines and operational challenges that included unscheduled workovers on a key producing well, PMN x-1082 and to a lesser extent on well PMN 1022. There were also scheduled workovers on several other wells, including PMN 1111, in addition to temporary shut-ins caused by equipment failures, primarily pumps. All of Petrolifera's sales during 2010 were from its Puesto Morales/Rinconada and Puesto Morales Este Concessions in Argentina and all of its crude oil sales were made to the Argentinean operation of a large multinational company.
Relative to the fourth quarter of 2009, when petroleum and natural gas revenues were $17.9 million on sales volumes of 4,509 boe per day, comparable revenues and stabilized sales volumes were experienced during the first quarter of 2010. During the fourth quarter of 2009, the company embarked on a five well infill development program within the Puesto Morales Norte ("PMN") Field in the Neuquen Basin, Argentina and invested capital to increase the water treatment capacity of its facilities, in an attempt to stabilize production. The infill wells indicated a total tested or onstream initial productivity of approximately 1,100 bbl/d of crude oil. The company anticipates further stabilizing production volumes upon completion of the expansion of its water treatment handling facilities, anticipated due to this drilling, during the second quarter of 2010.
The company's realized crude oil and natural gas liquids prices modestly decreased three percent to average $50.65 per barrel for the first quarter of 2010, compared to $52.17 per barrel realized during the same period in 2009. Higher realized US dollar crude oil pricing averaging US$49.50 per barrel during the first quarter of 2010 compared favorably to the average US$42.40 per barrel received during the same period in 2009. This was offset by an average 20 percent strengthening of the Canadian dollar as compared to the US dollar. This resulted in a lower reported price during the first quarter of 2010 relative to the same period in 2009, as presented in Canadian dollars. The company's first quarter realized crude oil and natural gas liquids prices increased five percent relative to the realized price of $48.08 per barrel during the prior quarter in 2009.
Petrolifera negotiated a new crude oil sales agreement with a well-established multinational purchaser during 2010 and secured a higher crude oil price than the first and fourth quarters of 2009. During the first quarter of 2010, the crude oil price realized by Petrolifera averaged approximately 63 percent of the WTI average of US$78.66 per barrel. The complexities of the regulated commodity pricing regime were highlighted in the first quarter of 2009, when the company received approximately 99 percent of the WTI average of US$42.97 per barrel.
The realized natural gas price during the first quarter of 2010 reflected some relaxation of regulated Argentinean natural gas prices in industrial markets relative to the same period in 2009. The company successfully negotiated a price increase for 2010 winter sales volumes to US$2.46 per mcf. This was a three percent improvement relative to the US$2.40 per mcf realized on sales volumes during the winter of 2009. However, during the first quarter of 2010 natural gas prices decreased 15 percent over the level realized during the same period in 2009 to average $2.54 per mcf. The lower realized natural gas pricing during the first quarter of 2010 relative to the same period in 2009, as expressed in Canadian dollars, resulted from a 20 percent strengthening of the Canadian dollar as compared to the US dollar. The realized natural gas price was comparable between the first quarter of 2010 and fourth quarter 2009. Natural gas prices are believed to have the potential of further improvement in the longer term, due to market conditions and new Argentinean policy initiatives aimed at eventual market deregulation for industrial sales, including for power generation.
Interest and other income was minimal during the first quarters of both 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 first quarter of 2010, the company did not receive any interest payments on its investment, formerly known as ABCP, as the specified short term interest rate was below the 50 basis points required to be paid out on this investment. See "Restricted Cash 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 March 31 2010 2009
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($000, except per unit amounts) Total Per boe Total Per boe
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Average daily sales (boe/d) 4,349 6,328
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Petroleum and natural gas revenue $ 17,776 $ 45.41 $ 26,371 $ 46.30
Interest and other income 132 0.34 36 0.06
Royalties (2,544) (6.50) (3,429) (6.02)
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Net revenue 15,364 39.25 22,978 40.34
Operating costs (5,183) (13.24) (5,882) (10.33)
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Corporate netback $ 10,181 $ 26.01 $ 17,096 $ 30.01
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(1) Calculated by dividing related revenue and costs by total boe sold,
resulting in a corporate netback. Netback does not have a
standardized meaning prescribed by GAAP and therefore is unlikely to
be comparable to similar measures used by other companies. The most
comparable measure calculated in accordance with GAAP would be net
earnings (loss). Nevertheless, Petrolifera's management uses netbacks
as a performance measurement of operating efficiency and the
prevailing royalty regime. A high ratio of netback to selling price
is a positive indicator. A reconciliation of corporate netback to net
income (loss) can be found in the Net Earnings (Loss) table.
Compared to amounts recognized in the first quarter of 2009, Petrolifera's corporate netback of $26.01 per boe decreased 13 percent for the same period in 2010, mainly due to higher operating costs per boe and lower realized selling prices. Petrolifera's calculated unit netback of $26.01 per boe remained a respectable 57 percent of the first quarter 2010 selling price per boe, a reduction from the 65 percent achieved during the same period in 2009.
The corporate netback in the first quarter of 2010, however, was 11 percent higher than in the fourth quarter in 2009. Improved average realized selling prices and lower operating costs per boe during the three months ended March 31, 2010, compared to the last quarter in 2009 contributed to the improvement.
OPERATING COSTS
During the first quarter of 2010, total operating costs of $5.2 million decreased by approximately 12 percent compared to $5.9 million recognized during the same period in 2009, largely due to lower total production volumes and proceeds from third party oil treatment, which reduced the company's operating costs, while allowing the company to better utilize its petroleum processing facility. On a per boe basis, however, operating costs increased 28 percent for the first quarter of 2010 to $13.24 per boe, compared to $10.33 per boe for the same period in 2009. Lower petroleum sales volumes, combined with increased costs for contract operator and equipment rentals (with more pumping crude oil wells) during the first quarter of 2010, resulted in the increase. The challenges related to the company's waterflood program, mitigated to a lesser extent by the PMN infill well drilling program near the end of 2009, resulted in an increase in total fluid throughput, although with a lower crude oil cut. Accordingly, the additional fluid handling costs resulted in a further increase in the operating costs per boe for the first quarter of 2010, relative to the same period in 2009.
ROYALTIES
Royalties represent charges levied by governments and landowners against production or revenue. Included in royalties are revenue taxes imposed by provincial jurisdictions. Royalties during the first quarter of 2010 were $2.5 million ($6.50 per boe) or 14 percent of oil and natural gas revenue, compared to $3.4 million ($6.02 per boe), or 13 percent of oil and natural gas revenue, in the same period in 2009. The increase, on a boe basis, is primarily attributable to an increase in the ratio of production from concessions with higher royalty rates.
NET EARNINGS (LOSS) AND SHARES OUTSTANDING
NET EARNINGS (LOSS)
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Three Months Ended March 31 2010 2009
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($000, except per unit amounts) Total Per boe Total Per boe
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Corporate netback $ 10,181 $ 26.01 $ 17,096 $ 30.01
General and administrative (1,775) (4.53) (1,937) (3.40)
Stock-based compensation (677) (1.73) (1,592) (2.80)
Finance charges (1,060) (2.71) (1,577) (2.77)
Foreign exchange loss (319) (0.82) (2,445) (4.29)
Depletion, depreciation and
accretion (8,087) (20.66) (6,904) (12.12)
Income tax provision (542) (1.38) (1,044) (1.83)
Taxes other than income taxes (274) (0.70) (409) (0.72)
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Net earnings (loss) $ (2,553) $ (6.52) $ 1,188 $ 2.09
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In the first quarter of 2010, the company reported a net loss of $2.6 million ($0.02 per weighted average basic and diluted share) compared to net earnings of $1.2 million ($0.02 per weighted average basic and diluted share) for the same period in 2009. The net loss for 2010 was mainly due to a lower weighted average selling price resulting from a significantly stronger Canadian dollar as compared to the US dollar, lower commodities sales volumes and higher non-cash DD&A. Due to the 2009 sales process relating to the company's Argentinean interests, DD&A is not comparable on a quarter over quarter basis. See "Depletion, Depreciation and Accretion Expense"
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). In the first quarter of 2010, the company's comprehensive loss was $5.7 million, compared to the comprehensive income for the same period in 2009 of $5.3 million. The comprehensive loss for the first quarter of 2010 was due to the aforementioned net loss for the first quarter of 2010 and a three percent strengthening of the Canadian dollar as at March 31, 2010, as compared to the Canadian/US dollar relationship at December 31, 2009. This reduced the net assets of the company's Argentinean operations, which are denominated in US dollars and reported in Canadian dollars. The comprehensive income during the first quarter of 2009 was due to the recognized net earnings combined with a four percent strengthening of the US dollar at March 31, 2009, as compared to the Canadian/US dollar relationship as at December 31, 2008. This increased the Canadian dollar value of the reported net assets of the company's Argentinean operations.
SHARES OUTSTANDING
In the first quarter of 2010, the weighted average number of common shares outstanding was 121.8 million, compared to 54.9 million for the same period in 2009. The increase in the weighted average number of common shares for the first quarter of 2010 reflected the August 2009 issuance of 65.3 million common shares from treasury, for gross proceeds of $57.5 million; the September 2009 private placement issuance of 1.1 million common shares from treasury, for proceeds of $1.0 million; and 0.4 million options that were exercised during the third quarter of 2009 and first quarter of 2010, resulting in the issuance of a like number of common shares. As the company had a net loss for the first quarter of 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 calculation, whereas for the same period in 2009, 0.2 million additional common shares were included in the calculation of diluted net earnings per share.
As at the close of business on May 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.
GENERAL & ADMINISTRATIVE AND STOCK-BASED COMPENSATION
General and administrative ("G&A") expenses were $1.8 million and $1.9 million for the first quarters of 2010 and 2009, respectively. These costs primarily consist of management and administrative salaries, legal and professional fees, insurance, travel and other administrative expenses. G&A expenses primarily related to further exploration and evaluation of the prospects in Colombia, Peru and Argentina of $1.4 million and $1.2 million were also capitalized during the first quarters of 2010 and 2009, respectively.
On a per boe basis, expensed G&A was $4.53 per boe of sales in the first quarter of 2010 compared to $3.40 per boe in the same period in 2009. The increase in G&A per boe in the first quarter of 2010, relative to the same period in 2009, was primarily due to lower sales volumes.
In the first quarter of 2010, a non-cash expense of $0.7 million ($0.5 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 first quarter of 2010, as compared to the same quarter of 2009, primarily reflects an increase in the number of options granted.
During the first quarter of 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 $1.1 million and $1.6 million for the first quarter of 2010 and 2009, respectively, was interest paid and accrued on the company's outstanding current and long-term bank debt and deferred financing charges that are allocated over the life of the reserve-backed credit facility. The decrease in finance charges during the first quarter of 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 5.5 percent for the respective quarters.
FOREIGN EXCHANGE
In the first quarter of 2010, the weakening of the US dollar relative to the Canadian dollar, resulted in a foreign exchange gain on lower reported US dollar denominated debt, as expressed in Canadian dollars. This foreign exchange gain was offset by foreign exchange losses on Argentinean and corporate working capital, as partially denominated in Argentinean pesos and US dollars, respectively. As the Canadian dollar strengthened relative to both aforementioned foreign currencies, the company reported a corresponding reduction in working capital, as expressed in Canadian dollars. Combined, this resulted in a net foreign exchange loss of $0.3 million in the first quarter of 2010, compared to a loss of $2.4 million during the same quarter in 2009.
DEPLETION, DEPRECIATION & ACCRETION
DD&A is calculated using the unit-of-production method relative to total estimated proved reserves. DD&A in the first quarter of 2010 totaled $8.1 million or $20.66 per boe, an increase compared to $6.9 million or $12.12 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 during the period from March 2 to March 31, 2009, when these interests were for sale, in the March 31, 2009 unaudited Consolidated Financial Statements. As a result of management's decision to no longer pursue a sale, 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 for all reported periods ended on or subsequent to September 30, 2009. As a result of not recognizing depletion and depreciation expense in the financial results for a portion of the three months ended March 31, 2009, total DD&A and DD&A per boe for the first quarter of 2009 is not comparable to the same measures in the first quarter of 2010.
Capital costs of $13.3 million (Dec. 31, 2009 - $14.0 million) incurred for unevaluated properties and other assets in Argentina and $56.6 million (Dec. 31, 2009 - $56.1 million) and $61.0 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.
Accretion expense, which is included in DD&A, was $0.1 million for the first quarter of 2010, compared to $0.2 million for the same period in 2009. Accretion expense will continue to be recorded at appropriate levels in the future to accrete the discounted liability of $9.4 million (Dec. 31, 2009 - $9.6 million) over the estimated timing of reclamation expenditures on the company's oil and gas properties.
TAXES
The current income tax provision of $0.6 million and $1.0 million in the first quarters of 2010 and 2009, respectively, related primarily to income taxes payable in Argentina. Additionally, a future income tax expense of $0.1 million for the first quarter of 2009 was recorded at the statutory rate to recognize the differences between the remaining tax pools and accounting carrying values. The implied effective tax rate of the income tax provision is not indicative of the company's jurisdictional tax rates for the first quarters in 2010 and 2009. Taxes other than income taxes of $0.3 million and $0.4 million for the first quarters of 2010 and 2009, respectively, represent taxes charged on all banking transactions in Argentina.
CAPITAL RESOURCES, CAPITAL EXPENDITURES AND LIQUIDITY
In April 2010, the company further improved its liquidity and balance sheet with a successful bought deal public equity offering of $20.1 million. The equity was raised primarily to fund future Colombian capital programs, including exploration activity on the company's Sierra Nevada and Magdalena acreages, located onshore Colombia, and to pay down a portion of the company's reserve-backed debt facility. This equity raise, in combination with the company's cash balances and cash flows from its Argentinean interest, are expected to provide the company the required liquidity to meet existing work commitments and pay down outstanding reserve-backed debt, while the company continues to negotiate farmout arrangements aimed at maximizing shareholder-value from its strong ownership positions and early stage geological and geophysical activity in Peru and Colombia.
During the first quarter of 2010, the company entered into two farmout agreements on its Puesto Guevara and Vaca Mahuida Concessions, both located in Rio Negro Province, Argentina. Under each new farmout agreement, the farmee agreed to incur all of the remaining capital spending requirements to fulfill the concession's work program. In addition, the company was reimbursed $1.0 million for a previously drilled well on its Vaca Mahuida Concession. With the signing of the 2010 Argentinean farmout agreements, the company now has no remaining work commitments in Argentina, allowing it to direct existing cash reserves and cash flows to debt reduction and then to evaluating its more prospective land holdings in Peru and Colombia.
The company continues to negotiate farmout arrangements on exploratory lands in Peru and Colombia. Recent strong crude oil prices have renewed the interests of third parties in new exploration and development opportunities. For the remainder of 2010, the company's only remaining significant work program is the drilling of an exploratory well on the Magdalena License, located in the lower Magdalena Basin onshore Colombia and to a lesser extent the seismic programs currently underway on Sierra Nevada and Turpial Licenses, respectively located in the Lower and Middle Magdalena Basins, onshore Colombia. The company anticipates completing an exploratory well on its Magdalena License, within the San Angel prospect during the fourth quarter of 2010. Farmout discussions are well advanced for this project. See "Commitments, Contractual Obligations, Guarantees & Off-Balance Sheet Financing" for a detailed discussion of the status of the company's various work commitments.
The company continues to negotiate the final terms of a revised credit facility agreement with an extended term beyond the current expiry of September 5, 2010. In the interim, the company has classified its reserve-backed credit facility as a current liability on its balance sheet. The company anticipates repayment of its reserve-backed debt from cash flows from its Argentinean interests, cash balances, proceeds from farmout arrangements and proceeds from the April 2010 equity offering once the extended facility agreement is finalized. Should farmout arrangements not proceed as planned, the company has the ability to defer budgeted capital expenditures on certain licenses. The company anticipates reducing its reserve-backed credit facility by up to a total of $20 million during 2010.
CASH FLOW
Cash flow and cash flow per share do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital. The most comparable measure calculated in accordance with GAAP would be net earnings (loss). Cash flow is reconciled with net earnings (loss) below. Cash flow per share is calculated by dividing cash flow by the weighted average shares outstanding. Management uses these non-GAAP measurements for its own performance measures and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund a portion of its future growth expenditures.
Reconciliation of net earnings (loss) to cash flow:
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Three Months Ended March 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net earnings (loss) $ (2,553) $ 1,188
Add (deduct) non-cash charges:
Depletion, depreciation and accretion 8,087 6,904
Stock-based compensation 677 1,592
Unrealized foreign exchange loss 618 815
Amortization of deferred finance charges 373 225
Future income tax provision (recovery) (25) 80
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Cash flow $ 7,177 $ 10,804
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Per share, basic 0.06 0.20
Per share, diluted 0.06 0.20
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Cash flow in the first quarter of 2010 was $7.2 million or $0.06 per weighted average basic and diluted share, compared to $10.8 million or $0.20 per weighted average basic and diluted in the same period of 2009. The 34 percent decrease in total cash flow during the first quarter of 2010, relative to the first quarter of 2009, primarily resulted from the impact of a 20 percent strengthening of the Canadian dollar, as compared to the US dollar, and lower sales volumes that were mainly attributable to natural reservoir pressure declines. The company had implemented a waterflood program at PMN in order to mitigate the observed natural reservoir pressure declines, but the program has been less effective than anticipated. Cash flow per share for the first quarter of 2010 decreased relative to the same period in 2009 for the aforementioned reasons and from the impact of an increase in the number of shares outstanding.
Cash flow in the first quarter of 2010 improved 22 percent relative to cash flow in the fourth quarter of 2009 of $5.9 million or $0.05 per weighted average basic and diluted share. The increase in cash flow during the first quarter of 2010, compared to the fourth quarter of 2009, primarily resulted from an increase in the average realized selling price and a realized foreign exchange gain, combined with decreases in operating costs and finance charges. Sales volumes stabilized during the first quarter of 2010 compared to the fourth quarter in 2009. During the fourth quarter of 2009, the company embarked on a five well infill development program within the PMN Field in the Neuquen Basin, Argentina and invested capital to increase the water treatment capacity of its facilities, in an attempt to stabilize production. The infill wells indicated a total tested or onstream initial productivity of approximately 1,100 bbl/d of crude oil. The company anticipates further stabilizing production volumes upon completion of the expansion of its water treatment handling facilities, anticipated due to this drilling, during the second quarter of 2010.
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 (each, a "Common Share") 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 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 received during April 2010 will be used by the company to fund a $10.5 million capital expenditure program in respect of its Sierra Nevada and Turpial Licenses in Colombia, to reduce reserve-backed indebtedness by US$5.0 million and to augment working capital.
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"), 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").
The net proceeds of the 2009 Public Offering and Private Placement were added to working capital to augment cash balances, to be used to fund a portion of the company's exploration capital expenditure program, primarily in Colombia and to reduce indebtedness relating to the company's reserve-backed credit facility. As at March 31, 2010, the net proceeds of the 2009 Public Offering and Private Placement had been used to repay US$15.0 million of the company's reserve-backed credit facility, to fund approximately $24.2 million of capital expenditures in Colombia and to fund a US$4.1 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.
The proposed use of net proceeds per the 2009 Public Offering and Private Placement relative to actual use of net proceeds as at March 31, 2010, are as follows:
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Use of Net
Proceeds Per Use of Net
2009 Public Proceeds
Offering and as at
Private Mar. 31,
($000) Placement 2010
-------------------------------------------------------------------------
Capital expenditure program, primarily in
Colombia $ 32,743 $ 24,227
Reduction of reserve-backed credit facility Up to 16,000 15,953
Working capital 6,700 4,152
Cash to be deployed in 2010 to capital
expenditure program - 11,111
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$ 55,443 $ 55,443
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CAPITAL EXPENDITURES
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Three Months Ended March 31 2010 2009
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($000)
-------------------------------------------------------------------------
Colombia $ 14,000 $ 15,005
Argentina 2,315 4,638
Peru 446 5,960
Corporate 5 9
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Capital expenditures 16,766 25,612
Proceeds from farmout arrangement (1,024) -
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Net capital expenditures $ 15,742 $ 25,612
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Net capital expenditures in the first quarter of 2010 were $15.7 million, compared to $25.6 million for the same period in 2009. Net capital spending throughout the first quarter of 2010 was financed from available cash, cash flow and proceeds from 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 3,350 feet subsurface that flowed 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 579 psi. The company calculates the absolute open flow ("AOF") rate of the well to be 18.0 mmcf per day of 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. Current plans are to suspend the well until a permit to conduct a long-term test is received. Evaluations of deeper pay intervals drilled in the Brillante SE-1X well will be conducted in subsequent appraisal wells.
Readers are cautioned that measured flow rates and calculated AOF rates may not be indicative of stabilized production rates for the Brillante SE-1X well. Further long term testing of the Brillante SE-1X well is 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.
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 snubbing unit reentered the La Pinta 1X well bore to clean out the tubing string blockage and attempted to test the well. Unfortunately, the test again resulted in plugged tubing and a decision was made to move uphole to attempt to test a zone in the Upper Porquero Formation. The test results from the Upper Porquero Formation are anticipated during the second quarter of 2010.
The company commenced a 144 km(2) 2D seismic work program in the first quarter of 2010 over its Turpial License in the Middle Magdalena Basin, onshore Colombia, where the company was carried through the first US$1.9 million of costs related to this work program by its joint venture partner. After completion of this work program, the joint venture partner will earn a 50 percent working interest in the Turpial License from the company, which will retain an equal working interest and operatorship.
Argentina
In the first quarter of 2010, expenditures to increase the fluid capacity of the company's water treatment and handling facilities were incurred. The capacity expansion was required as a result of the 2009 fourth quarter's five infill well drilling program within the PMN Field in the Neuquen Basin, Argentina. The infill wells indicated a total tested or onstream initial productivity of approximately 1,100 bbl/d of crude oil. The company anticipates further stabilizing production volumes upon completion of the expansion of its water treatment handling facilities, anticipated due to this drilling, during the second quarter of 2010. The company also capitalized 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, during the first quarter of 2010.
During January, 2010, the company announced that it had entered into an additional farmout agreement on the Vaca Mahuida ("VM") Concession, situated southeast of Puesto Morales, Argentina. After completion of the committed work program and related expenditures, ownership of the Concession would be reduced to a 25 percent working interest with Petrolifera continuing as the operator. During April 2010, the company and its partners commenced the VM drilling campaign, that contemplates four exploratory wells, ranging in depths from 1,000 to 1,500 meters, with the costs of the exploratory wells financed by farmees. In addition, during the first quarter of 2010 the company was reimbursed $1.0 million for back-costs of the VM X-2014 exploratory well, completed as a shut-in natural gas well. The company estimated that the AOF rate of the well was 1.4 mmcf per day of natural gas. A long-term test of the perforated interval is scheduled during the second quarter of 2010. Under the terms of the latest VM farmout agreement, Petrolifera will be reimbursed, if required, for payments to the Rio Negro Provincial Government for the value of any outstanding amount of work units that have not been incurred by the end of the first period of the exploration license, which expires on May 31, 2010.
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 Rio Negro, Argentina. The company's ownership in this Concession will be reduced to 44 percent with Petrolifera continuing as the operator upon completion by the farmee of the committed work program, which requires the drilling of one exploratory well. The farmee has also agreed to the drilling of a second exploratory well. The exploratory wells are anticipated to range in depths from 1,000 meters to 1,700 meters.
Peru
Minimal capital expenditures were incurred for pre-drilling activities for the first quarter of 2010 on the company's three Peruvian blocks. The company has met, or surpassed, all of it 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, comprised of approximately one million acres contiguous with Block 107, is minimal.
The company continues the process of discussing the terms of proposed 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 sunken costs incurred on these Blocks and to secure work commitments for new drilling and/or seismic activity. On Block 106, further discussions are anticipated with a number of qualified, interested third parties with a view to farming out an interest in this License.
CREDIT FACILITIES
During April 2009, the company negotiated with a Canadian chartered bank an expansion of a line-of-credit ("ABCP line-of-credit"), primarily secured by the longer term notes exchanged for the ABCP, to a maximum of $28.2 million. Any borrowings from the expanded ABCP line-of-credit are categorized as long-term, as the facility's initial maturity is April, 2011 and the company can make up to five extension requests, with each extension for an additional one-year period. The line-of-credit bears interest at a floating rate.
As at March 31, 2010, the company had a US$100.0 million reserve-backed revolving credit facility with a syndicate of banks with an established availability of US$50.0 million. Borrowings from the reserve-backed credit facility are categorized as current, as the facility is scheduled to expire on September 5, 2010. The company is currently negotiating the terms to extend the reserve-backed credit facility. Management anticipates new terms will require scheduled repayments of the outstanding draws over a period extending approximately 18 months beyond the existing agreement's September 5, 2010 expiry date. The company anticipates up to $20.0 million in reserve-backed debt repayments during 2010, which the company intends to finance from existing cash balances, cash flows and proceeds, if any, from farmout agreements mainly on the company's Sierra Nevada License located in the lower Magdalena Basin, onshore Colombia and Block 107, located in the Ucayali Basin, onshore Peru. It is anticipated a significant portion of the outstanding reserve-backed debt will be reclassified as a long-term liability upon completion of the amended facility agreement which will result in an immediate improvement in working capital.
The reserve-backed revolving 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 December 31, 2009. From time-to-time changes in the availability of the reserve-backed credit facility are anticipated to occur through significant reserve additions, disposals or revisions. Reductions in current availability under the reserve-backed credit facility would require additional repayments based on amounts currently drawn.
As at March 31, 2010 and December 31, 2009, the outstanding reserve-backed facility was US$50.0 million and the long-term ABCP line-of-credit facility was $27.5 million.
The company is subject to external restrictions on its reserve-backed revolving credit facility. Under this facility's agreement, the outstanding draws cannot exceed two times the 12 month trailing EBITDA. EBITDA is a non-GAAP measure and is defined by the credit facility agreement as net earnings (loss) prior to deduction of finance charges, income taxes, depletion, depreciation and accretion expense, stock-based compensation and unrealized foreign exchange losses. As at March 31, 2010, outstanding draws on the reserve-backed credit facility and a portion of long-term bank debt were $59.4 million and the maximum amount allowed as calculated by the credit facility (two times EBITDA) was $70.6 million, so Petrolifera was in compliance with this covenant. With existing realized commodity pricing, the company's cost structure and a planned debt reduction program for the ensuring year, Petrolifera anticipates that it will continue to be in compliance with the financial debt to EBITDA ratio covenant.
Reconciliation of net earnings (loss) to EBITDA is as follows:
12 Months
Three Months Ended Ended
-------------------------------------------------------------------------
June 30, Sept. 30, Dec. 31, Mar. 31, Mar. 31,
($000) 2009 2009 2009 2010 2010
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Net earnings (loss) $ 3,427 $(11,359) $ (4,081) $ (2,553) $(14,566)
Add (deduct) interest,
income taxes,
depletion,
depreciation and
accretion expense and
other non-cash expenses:
Depletion, depreciation,
and accretion 138 17,568 8,936 8,087 34,729
Finance charges 1,348 1,132 1,040 1,060 4,580
Fair value impairment - 2,104 - - 2,104
Stock-based compensation 846 1,561 675 677 3,759
Income tax provision
(recovery) 5,634 (3,428) 724 542 3,472
Unrealized foreign
exchange loss (gain) 1,396 (640) (143) 618 1,231
EBITDA $ 12,789 $ 6,938 $ 7,151 $ 8,431 $ 35,309
RESTRICTED CASH AND LONG-TERM INVESTMENTS
As at March 31, 2010 and December 31, 2009, long-term investments included notes received in exchange for ABCP with a face value of $34.6 million and a carrying value of $18.7 million and collateral to support issued letters of credit of $0.5 million and $0.7 million, respectively. Restricted cash, as at March 31, 2010, included collateral to support issued letters of credit of $0.9 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 notes received in exchange for ABCP is explained herein.
In the first quarter of 2010, the company did not receive any cash interest receipts on each class of notes 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 quarter of 2010.
Although we understand there have been some isolated third party transactions during the first quarter of 2010, as no active market quotations have developed for the longer term notes, management has estimated the fair value of the company's investment in the longer term notes at March 31, 2010 based on a probabilistic recovery of principal and interest, after taking into account all available information. Under this valuation method, several different outcomes of the recovery of the principal and interest are estimated, considering the information available as at March 31, 2010. A weighted average recovery is then calculated. This weighted average recovery is used to determine the discounted cash flows that are expected from these investments. The discount rate used to discount the expected cash flows from the 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 Risk-
Class of Capital Interest Weighted Weighted 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%
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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 March 31, 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 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.
Management has commenced its IFRS conversion project which consists of the following three phases:
1. Preliminary phase - this phase commenced with a review of the
company's significant accounting policies relative to current and
proposed IFRS. The results of this analysis were priority ranked
according to the complexity and the extent of the impact in adoption
of IFRS accounting policies.
2. Impact and evaluation phase - the company is now in the process of
preparing draft analysis for the impact and evaluation phase, where
items identified in the preliminary phase are addressed according to
the priority levels assigned to them. This phase involves analysis of
policy choices allowed under IFRS and the impact on the financial
statements.
3. Implementation phase - this final phase involves implementing all
changes approved in the impact and evaluation phase.
Upon completion of the preliminary phase, management determined that the differences most likely to have the greatest degree of complexity and impact on the company's consolidated financial statements were as follows:
- First-time adoptions exemption - the International Accounting
Standards Board has approved additional exemptions from the
retrospective application of IFRS for first time adopters. Of most
relevance to the company, is an exemption that allows full cost oil
and gas companies to elect, at the date of transition to IFRS, to
measure exploration and evaluation assets at the amount determined
under Canadian GAAP and to measure oil and gas assets in the
development or production phases by allocating the amount determined
under Canadian GAAP to the underlying assets pro-rata using reserve
volumes or reserve values as of that date. Management will consider
if this exemption should be applied as it continues to monitor the
IFRS adoption efforts of the company's peers.
- Re-classification of exploration and evaluation ("E&E") expenditures
from property, plant and equipment ("PP&E") on the consolidated
balance sheet - this will consist of the book value of the company's
undeveloped land that relates primarily to its Colombian and Peruvian
properties. E&E assets will not be depleted and must be assessed for
impairment when indicators suggest the possibility of impairment.
- Calculation of depletion expense for PP&E - upon transitioning to
IFRS, the company has the option to calculate depletion using a
reserve base of proved reserves or both proved and probable reserves,
as compared to the Canadian GAAP method of calculating depletion
using only proved reserves.
- Impairment of PP&E - under IFRS, impairment of PP&E must be
calculated at a more detailed level than what is currently required
under Canadian GAAP. Impairment calculations will be performed at the
cash generating unit level using either total proved or proved plus
probable reserves.
- Foreign currency translation methods and the functional currencies of
each of the company's foreign operations - under IFRS, the functional
currency emphasizes the currency that determines the pricing of the
transactions that are undertaken, rather than focusing on the
currency in which those transactions are denominated.
- With the recent withdrawal of the IAS 12 Income Taxes exposure draft
and the issuance of IAS 37 Provisions, Contingent Liabilities and
Contingent Assets, management is still determining the impact of
these revised standards mainly on its IFRS transition of income taxes
and asset retirement obligations.
During the impact and evaluation phase, certain potential policy differences between IFRS and Canadian GAAP are currently being investigated to assess whether there may be a broader impact on the company's:
- Disclosure controls - throughout the transition process, the company
will be assessing stakeholders' information requirements and will
ensure that adequate and timely information is provided so that all
stakeholders are kept apprised.
- Internal controls over financial reporting ("ICFR") - as the adoption
of IFRS policies is completed, an assessment will be made to
determine changes required for ICFR. The company anticipates changes
to its IT systems and the training of impacted staff and implementing
appropriate additional controls related to the grouping of
development assets into cash generating units and separately
identifying E&E assets.
- Contracts and lending agreements - management has been cognizant of
the upcoming transition to IFRS and will ensure that agreements that
reference Canadian GAAP statements or financial covenants are
modified to allow for IFRS statements and calculations made in
accordance with IFRS statements, respectively. Based on the expected
changes to the company's accounting policies at this time, there are
no foreseen issues with the existing wording of debt covenants and
other agreements as a result of the conversion to IFRS.
The conclusion of the impact and evaluation phase, anticipated during the second quarter of 2010, will require the audit committee of the Board of Directors to review and approve all accounting policy choices as proposed and recommended by management. The final implementation phase involves implementing all changes approved in the impact and evaluation phase.
Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on the financial statements. In addition, due to anticipated changes to IFRS and International Accounting Standards prior to the company's adoption of IFRS, management's plan is subject to change based on new facts and circumstances that arise after the date of this MD&A. The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect the company. Management's timeframe to complete the third and final implementation phase of its IFRS adoption efforts is scheduled during the second half of 2010 which will allow the company to adopt IFRS in place of Canadian GAAP effective January 1, 2011.
COMMITMENTS, CONTRACTUAL OBLIGATIONS, GUARANTEES & OFF-BALANCE SHEET ARRANGEMENTS
WORK COMMITMENTS
In 2005, Petrolifera acquired two significant oil and gas exploration licenses onshore Peru for Blocks 106 and 107, respectively located in the Maranon and Ucayali Basins. During April 2009, Petrolifera was awarded a license over Block 133, offsetting and contiguous with Block 107 and 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 has converted the Turpial and Sierra Nevada II TEAs into exploration licenses with the latter renamed Magdalena. The company is in the second phase of its Sierra Nevada License work program, which requires the drilling of one exploratory well and acquiring additional seismic prior to June, 2010. 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 March 2010, the company commenced a 3D seismic program over the La Pinta structure which, when completed and combined with the Brillante SE-1X exploratory well, is anticipated to complete the Sierra Nevada's second phase work program. The company commenced the second phase 2D seismic work program on its Turpial exploration contract, disproportionally financed by the company's joint venturer. Completion of further seismic acquisition and 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 drilling an exploratory well on its San Angel prospect during the fourth quarter of 2010.
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 Puesto Guevara and Vaca Mahuida Concessions work commitments of US$0.6 million and US$2.9 million, respectively, through agreements reached in the first quarter of 2010. Once the company's joint venturers have funded the work commitments for the Puesto Guevara and Vaca Mahuida Concessions, the company's working interests will be 44 percent and 25 percent, respectively, in these concessions. The company has no remaining work commitments in Argentina.
CONTRACTUAL OBLIGATIONS
The company's contractual obligations for drilling, leases for office premises and other equipment and an administrative services agreement for the nine months ended December 31, 2010 and annually thereafter are as follows:
-------------------------------------------------------------------------
Subsequent
2010 2011 to 2011 Total
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Drilling contracts and
other leases $ 12,240 $ 492 $ - $ 12,732
-------------------------------------------------------------------------
GUARANTEES
The company has issued letters of credit in the total amount of US$1.3 million to secure the capital expenditure requirements associated with the Colombian work commitments and US$0.1 million to secure the capital expenditure requirements associated with one exploration license in Peru. Deposits of US$4.1 million and US$1.2 million were placed in trust accounts in Colombia to meet certain work obligations on the respective Magdalena and Turpial Licenses as they occur.
OFF-BALANCE SHEET ARRANGEMENTS
The company does not have any off-balance sheet arrangements.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the company is accumulated, recorded, processed, summarized and reported to the company's management as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation as of the end of the three months covered by this MD&A, the company's Executive Chairman, President and Chief Operating Officer and Chief Financial Officer have concluded that the company's disclosure controls and procedures as of the three months ended March 31, 2010 are effective to provide reasonable assurance that material information related to the company, including its consolidated subsidiaries, is communicated to them as appropriate to allow timely decisions regarding required disclosure.
Management of the company is also responsible for designing 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 months ended March 31, 2010 that would materially affect, or are reasonably likely to materially affect, the company's internal controls over financial reporting.
BUSINESS RISKS
Petrolifera is exposed to certain risks and uncertainties inherent in the oil and gas business. Furthermore, being a smaller independent company, it is exposed to financing and other risks which may impair its ability to realize on its assets or to capitalize on opportunities which might become available to it. Additionally, Petrolifera operates in various foreign jurisdictions and is exposed to other risks including currency fluctuations, political and economic risk, price controls and varying forms of fiscal regimes and government policies or changes thereto which may impair Petrolifera's ability to conduct profitable operations.
The risks arising in the oil and gas industry include price fluctuations for both crude oil and natural gas over which the company has limited control; risks arising from exploration and development activities; production risks associated with the depletion of reservoirs and the ability to market production. Additional risks include environmental and health and safety concerns.
Virtually all of the company's total revenue in its three months ended March 31, 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's outlook has improved with increased liquidity and the Brillante SE-1X discovery and as it awaits the outcome of testing of the Porquero Formation in the La Pinta 1X well.
Completion of negotiations to extend the Company's reserve-backed loan facility is anticipated to further enhance working capital and provide increased financial flexibility.
A modest company financed capital expenditure program is anticipated to be supplemented by third party expenditures under existing and anticipated farmout agreements, especially in Colombia and Peru.
There can be no assurance that farmouts will be completed on acceptable terms although much of the company's capital expenditure is discretionary in nature.
FORWARD-LOOKING INFORMATION
This interim report, contains forward-looking information including, but not limited to the anticipated finalization of a revised credit facility which is expected extend the term of the facility and provide for regular debt reduction payments, further testing of the La Pinta 1X well in Colombia, drilling of the exploratory well, on the San Angel prospect within the Magdalena License onshore Colombia during 2010, additional exploration and development activities in Colombia, Peru and Argentina, anticipated results from the La Pinta 1X well and Brillante SE-1X well in Colombia, planned infill drilling at PMN, Argentina and expansion of the associated water handling facilities, 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, anticipated improvements in natural gas prices in Argentina, planned capital expenditures (including sources of funding and timing thereof) and anticipated debt repayments to be made against the company's reserve-backed credit facility and 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 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 testing of the Porquero Formation in the La Pinta 1X well drilled on the Sierra Nevada License will yield commercial results. 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 is required. 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. In order to secure an extension of the term of its reserve-backed credit facility, Petrolifera may be required to make additional repayments under this facility and/or pay certain renewal fees to its lender. In addition, borrowings under an amended reserve-backed credited facility may be subject to increased interest rates, depending on market conditions at the time of review. There can be no assurance that Petrolifera will be able to renegotiate the terms of its reserve-backed credit facility on terms acceptable to it or at all. 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
-----------------------------------------------------
For the Three Months
Ended or As At June 30 Sept 30 Dec 31
-----------------------------------------------------
FINANCIAL RESULTS ($000,
EXCEPT PER SHARE
AMOUNTS) - UNAUDITED
-----------------------------------------------------
Total revenue 33,622 32,126 37,411
Cash flow(1) 13,485 15,726 21,689
Basic, per share(1) 0.27 0.29 0.39
Diluted, per share(1) 0.26 0.28 0.39
Net earnings (loss) 3,590 3,564 2,662
Basic, per share 0.07 0.06 0.05
Diluted, per share(5) 0.07 0.06 0.05
Net capital expenditures 29,110 21,046 35,539
Cash 41,039 14,865 30,701
Working capital (deficit) 13,295 8,148 19,956
Long-term investments(6) 29,947 28,488 25,428
Long-term bank debt(6) 43,800 45,576 77,150
Shareholders' equity 168,735 178,069 202,347
Total assets 292,882 279,174 355,658
-----------------------------------------------------
OPERATING RESULTS
-----------------------------------------------------
Sales volumes:
Crude oil and natural
gas liquids - bbl/d 7,111 6,850 6,877
Natural gas - mcf/d 5,922 5,363 5,451
Equivalent - boe/d(2) 8,098 7,744 7,786
Pricing:
Crude oil and natural
gas liquids - $/bbl 49.90 48.93 56.76
Natural gas - $/mcf 2.38 2.58 2.88
Selected highlights -
$/boe (2):
Weighted average
selling price 45.56 45.07 52.15
Interest and other
income 0.07 0.02 0.08
Royalties 6.33 6.80 7.66
Operating costs 8.60 9.00 10.28
Corporate netback(3) 30.69 29.29 34.29
-----------------------------------------------------
COMMON SHARE INFORMATION
(000, EXCEPT SHARE PRICE)
-----------------------------------------------------
Shares outstanding at
end of period 54,798 54,948 54,948
Weighted average shares
outstanding for the
period:
Basic 50,500 54,884 54,948
Diluted(5) 51,735 55,897 55,043
Volume traded during
quarter 4,590 7,884 8,826
Common share price ($):
High 11.25 8.72 3.99
Low 8.25 3.16 0.75
Close (end of period) 8.69 3.37 1.05
-----------------------------------------------------
-------------------------------------------------------------------------
2009 2010
-------------------------------------------------------------------------
For the Three Months
Ended or As At Mar 31 June 30 Sept 30 Dec 31 Mar 31
-------------------------------------------------------------------------
FINANCIAL RESULTS ($000,
EXCEPT PER SHARE
AMOUNTS) - UNAUDITED
-------------------------------------------------------------------------
Total revenue 26,407 22,255 17,229 17,900 17,908
Cash flow(1) 10,804 10,233 5,503 5,867 7,177
Basic, per share(1) 0.20 0.19 0.07 0.05 0.06
Diluted, per share(1) 0.20 0.18 0.07 0.05 0.06
Net earnings (loss) 1,188 3,427 (11,359) (4,081) (2,553)
Basic, per share 0.02 0.06 (0.14) (0.03) (0.02)
Diluted, per share(5) 0.02 0.06 (0.14) (0.03) (0.02)
Net capital expenditures 25,612 20,477 13,389 9,378 15,742
Cash 30,994 14,803 55,953 35,732 32,207
Working capital (deficit) 33,768 22,895 724 (2,508) (10,659)
Long-term investments(6) 21,501 21,172 19,873 19,395 19,202
Long-term bank debt(6) 104,649 102,104 27,464 27,464 27,456
Shareholders' equity 209,240 201,749 238,475 232,126 227,097
Total assets 371,054 353,424 368,288 349,065 345,509
-------------------------------------------------------------------------
OPERATING RESULTS
-------------------------------------------------------------------------
Sales volumes:
Crude oil and natural
gas liquids - bbl/d 5,245 4,652 3,653 3,833 3,706
Natural gas - mcf/d 6,500 6,232 4,252 4,056 3,862
Equivalent - boe/d(2) 6,328 5,691 4,362 4,509 4,349
Pricing:
Crude oil and natural
gas liquids - $/bbl 52.17 48.72 48.07 48.08 50.65
Natural gas - $/mcf 2.98 2.87 2.74 2.53 2.54
Selected highlights -
$/boe (2):
Weighted average
selling price 46.30 42.97 42.93 43.15 45.41
Interest and other
income 0.06 - - - 0.34
Royalties 6.02 6.74 6.09 6.40 6.50
Operating costs 10.33 11.04 14.36 13.42 13.24
Corporate netback(3) 30.01 25.20 22.48 23.33 26.01
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
(000, EXCEPT SHARE PRICE)
-------------------------------------------------------------------------
Shares outstanding at
end of period 54,948 54,948 121,759 121,759 121,789
Weighted average shares
outstanding for the
period:
Basic 54,948 54,948 82,418 121,759 121,789
Diluted(5) 55,195 55,600 82,539 121,777 121,812
Volume traded during
quarter 10,053 13,268 55,032 35,921 47,157
Common share price ($):
High 1.60 3.47 2.85 1.09 1.31
Low 0.80 1.49 0.76 0.79 0.84
Close (end of period) 1.60 2.85 1.08 0.97 0.96
-------------------------------------------------------------------------
(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 after March 2, 2009 due to the decision, at
that time, to sell the company's Argentinean interests. Attributing
to fluctuations in working capital is the classification of debt as
either current or long-term.
(5) As the company has net losses during the three months ended
September 30 and December 31, 2009 and March 31, 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 March 31, 2010 and December 31, 2009. Long-
term debt in the amount of $27.5 million as at March 31, 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 March 31, December 31,
2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
ASSETS
Current
Cash $ 32,207 $ 35,732
Accounts receivable 20,957 20,871
Restricted cash 863 3,247
Inventory (Note 3) 634 958
Income taxes receivable 4,537 4,636
Prepaid expenses 943 464
Deferred financing costs (Note 5) 330 706
-------------------------------------------------------------------------
60,471 66,614
Long-term investments (Note 4) 19,202 19,395
Property and equipment 265,836 263,056
-------------------------------------------------------------------------
$ 345,509 $ 349,065
-------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities $ 19,359 $ 15,850
Income taxes payable 973 913
Bank debt (Note 5) 50,780 52,330
Due to a related company 18 29
-------------------------------------------------------------------------
71,130 69,122
Long-term bank debt (Note 5) 27,456 27,464
Asset retirement obligations (Note 6) 9,380 9,552
Future income taxes 10,446 10,801
-------------------------------------------------------------------------
118,412 116,939
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital and warrants (Note 7(a)) 148,286 148,264
Contributed surplus (Note 7(b)) 21,128 20,453
Accumulated other comprehensive loss (6,926) (3,753)
Retained earnings 64,609 67,162
-------------------------------------------------------------------------
227,097 232,126
-------------------------------------------------------------------------
$ 345,509 $ 349,065
-------------------------------------------------------------------------
Commitments and guarantees (Note 10)
Subsequent event (Note 11)
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
(UNAUDITED)
-------------------------------------------------------------------------
Three Months Ended March 31 2010 2009
-------------------------------------------------------------------------
$000 (except per share amounts)
-------------------------------------------------------------------------
REVENUE
Petroleum and natural gas sales $ 17,776 $ 26,371
Interest and other income 132 36
-------------------------------------------------------------------------
17,908 26,407
Royalties (2,544) (3,429)
-------------------------------------------------------------------------
15,364 22,978
-------------------------------------------------------------------------
EXPENSES
Operating 5,183 5,882
General and administrative 1,775 1,937
Finance charges (Note 5) 1,060 1,577
Taxes other than income taxes 274 409
Foreign exchange loss 319 2,445
Depletion, depreciation and accretion 8,087 6,904
Stock-based compensation (Note 7(c)) 677 1,592
-------------------------------------------------------------------------
17,375 20,746
-------------------------------------------------------------------------
Earnings (loss) before income taxes (2,011) 2,232
Current income tax provision 567 964
Future income tax provision (recovery) (25) 80
-------------------------------------------------------------------------
542 1,044
-------------------------------------------------------------------------
NET EARNINGS (LOSS) (2,553) 1,188
RETAINED EARNINGS, BEGINNING OF PERIOD 67,162 77,987
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 64,609 $ 79,175
-------------------------------------------------------------------------
NET EARNINGS (LOSS) PER SHARE (Note 9(a))
Basic $ (0.02) $ 0.02
Diluted $ (0.02) $ 0.02
-------------------------------------------------------------------------
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
-------------------------------------------------------------------------
Three Months Ended March 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net earnings (loss) $ (2,553) $ 1,188
Foreign currency translation adjustment (3,173) 4,113
-------------------------------------------------------------------------
Comprehensive income (loss) $ (5,726) $ 5,301
-------------------------------------------------------------------------
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
-------------------------------------------------------------------------
Three Months Ended March 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Accumulated other comprehensive income (loss),
beginning of period $ (3,753) $ 16,106
Foreign currency translation adjustment (3,173) 4,113
-------------------------------------------------------------------------
Accumulated other comprehensive income (loss),
end of period $ (6,926) $ 20,219
-------------------------------------------------------------------------
PETROLIFERA PETROLEUM LIMITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
-------------------------------------------------------------------------
Three Months Ended March 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Cash provided by (used in) the following
activities:
OPERATING
Net earnings (loss) $ (2,553) $ 1,188
Items not involving cash:
Depletion, depreciation and accretion 8,087 6,904
Stock-based compensation (Note 7(c)) 677 1,592
Unrealized foreign exchange loss 618 815
Amortization of deferred charges (Note 5) 373 225
Future income tax provision (recovery) (25) 80
-------------------------------------------------------------------------
Cash flow from operations before non-cash
working capital changes 7,177 10,804
Changes in non-cash working capital (Note 9(b)) (2,551) 9,654
-------------------------------------------------------------------------
4,626 20,458
-------------------------------------------------------------------------
FINANCING
Proceeds from bank debt - 8,716
Repayment of long-term bank debt (8) (202)
Issue of common shares (Note 7(a)) 20 -
-------------------------------------------------------------------------
12 8,514
-------------------------------------------------------------------------
INVESTING
Exploration and development of oil and
gas properties (16,766) (25,612)
Proceeds from farmout agreement (Note 10) 1,024 -
Receipt of interest on long-term investment - 1,081
Proceeds from restricted cash 2,475 -
Changes in non-cash working capital (Note 9(b)) 5,463 (4,456)
-------------------------------------------------------------------------
(7,804) (28,987)
-------------------------------------------------------------------------
DECREASE IN CASH (3,166) (15)
Impact of foreign exchange on foreign currency
denominated cash balances (359) 308
CASH, BEGINNING OF PERIOD 35,732 30,701
-------------------------------------------------------------------------
CASH, END OF PERIOD $ 32,207 $ 30,994
-------------------------------------------------------------------------
Supplementary cash flow information (Note 9(c))
PETROLIFERA PETROLEUM LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED MARCH 31, 2010
(UNAUDITED)
1. FINANCIAL STATEMENT PRESENTATION
The interim unaudited Consolidated Financial Statements as at and for the
three months ended March 31, 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 March 31, December 31,
2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Crude oil $ 634 $ 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 March 31, 2010 and December 31, 2009
using a weighted average cost basis and is carried at the lower of cost
and net realizable value.
4. FINANCIAL INSTRUMENTS
Capital management
The company is subject to external restrictions on its reserve-backed
revolving credit facility. As at March 31, 2010, the facility had an
overall limit of US$100.0 million, with an availability of
US$50.0 million (2009 - US$50.0 million), based on producing crude oil
and natural gas reserves as at June 30, 2009. This facility has a
provision for a borrowing base adjustment every six months, with the next
adjustment to be calculated based on information as at December 31, 2009.
Outstanding bank debt and a portion of long-term debt cannot exceed two
times the 12 month trailing EBITDA. EBITDA is defined by the credit
facility agreement as net earnings (loss) prior to deduction of interest,
income taxes, depletion, depreciation and accretion expense and other
non-cash expenses and is reconciled to net earnings (loss) as follows:
12 Months
Three Months Ended Ended
-------------------------------------------------------------------------
($000) June 30, Sept. 30, Dec. 31, Mar. 31, Mar. 31,
2009 2009 2009 2010 2010
-------------------------------------------------------------------------
Net earnings (loss) $ 3,427 $(11,359) $ (4,081) $ (2,553) $(14,566)
Add interest, income
taxes, depletion,
depreciation and
accretion expense and
other non-cash expenses:
Depletion, depreciation,
and accretion 138 17,568 8,936 8,087 34,729
Finance charges 1,348 1,132 1,040 1,060 4,580
Fair value impairment - 2,104 - - 2,104
Stock-based compensation 846 1,561 675 677 3,759
Income tax provision
(recovery) 5,634 (3,428) 724 542 3,472
Unrealized foreign
exchange loss (gain) 1,396 (640) (143) 618 1,231
-------------------------------------------------------------------------
EBITDA $ 12,789 $ 6,938 $ 7,151 $ 8,431 $ 35,309
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at March 31, 2010, outstanding draws on bank debt and a portion of
long-term bank debt were $59.4 million and two times EBITDA was
$70.6 million, for a ratio of 0.84:1.00, which is in compliance with the
imposed limit.
Fair values of financial instruments
Financial instruments are recognized initially at fair value on the
balance sheet, and include cash, accounts receivable, restricted cash,
long-term investments, accounts payable and accrued liabilities, bank
debt, due to a related company and long-term bank debt. The company has
classified all of its financial instruments as held for trading, with the
exception of the bank debt and long-term bank debt, which are classified
as other liabilities. Held for trading instruments 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
instruments:
Cash $ 32,207 $ 32,207 $ - $ -
Accounts receivable 20,957 - 20,957 -
Restricted cash 863 - 863 -
Long-term investments 19,202 - 513 18,689
-------------------------------------------------------------------------
Total held for trading
financial assets $ 73,229 $ 32,207 $ 22,333 $ 18,689
-------------------------------------------------------------------------
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. Long-term investments includes notes
received in exchange for Asset Backed Commercial Paper ("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. The
fair and face values for the Level 3 financial asset notes formerly known
as ABCP is explained below.
In January, 2009, the Pan-Canadian Investors Committee for Third-Party
Structured ABCP announced that the Superior Court of Ontario granted the
Plan Implementation Order and that, accordingly, the plan for
restructuring ABCP had been fully implemented. In exchange for the
shorter-term ABCP, the company has now received the longer term notes
with maturities that generally approximate those of the assets previously
contained in the underlying conduits.
Although there have been some isolated third party transactions during
the three months ended March 31, 2010, as no active market quotations
have developed for the longer term notes, management has estimated the
fair value of the company's investment in the longer term notes at
March 31, 2010, based on a probabilistic recovery of principal and
interest, after taking into account all available information. Under this
valuation method, several different outcomes of the recovery of the
principal and interest are estimated, considering the information
available as at March 31, 2010. A weighted average recovery is then
calculated. This weighted average recovery is used to determine the
discounted cash flows that are expected from these investments. The
discount rate used to discount the expected cash flows from the 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 Risk-
Class of Capital Interest Weighted Weighted 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 March 31, 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 earnings.
Credit risk
The company is exposed to credit risk in relation to its cash, accounts
receivable, restricted cash and long-term investments.
Cash, restricted cash and the collateral to support issued letters-of-
credit as 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 venture partners 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$15.2 million of crude oil
production to one multinational purchaser and US$0.8 million in natural
gas production to a reputable local gas marketing company during the
three months ended March 31, 2010. Receivables with local government
agencies mainly pertain to excise taxes paid on certain expenditures. The
company has not experienced any collection problems with its
counterparties and does not currently have any overdue amounts.
Refer to the fair values of financial instruments contained herein for
further discussion regarding the credit risk of the longer term notes
formerly known as ABCP as recognized as a portion of long-term
investments.
The carrying amounts of cash, accounts receivable, restricted cash and
long-term investments represent the company's maximum credit exposure.
The company does not have an allowance for doubtful accounts and did not
write off any receivables during the three months ended March 31, 2010.
Liquidity risk
The company manages the risk of not meeting its financial obligations
through management of its capital structure, annual budgeting of its
revenues, expenditures and cash flows, cash flow forecasting and
maintaining an unused credit facility where practicable.
Accounts payable, as disclosed on the Consolidated Balance Sheet, fall
due within the next year and are anticipated to be funded through the
company's cash and collections of accounts receivable. The revolving
reserve-backed credit facility has a current available limit of
US$50.0 million, of which all is drawn at March 31, 2010. From time-to-
time, changes in the availability of the reserve-backed credit facility
are anticipated to occur through significant reserve additions, disposals
or revisions. The company continues negotiations to extend the term on
this facility which expires on September 5, 2010. The company holds a
$28.2 million line-of-credit (of which $27.5 million is drawn at
March 31, 2010) that is primarily secured by the longer term notes
received in exchange for the ABCP ("ABCP line-of-credit").
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 $ 32,207 $ 8,022 $ 10,668 $ 7,755 $ 14 $ 5,748
Accounts
receivable 20,957 97 6,239 6,436 1,204 6,981
Restricted
cash 863 - 863 - - -
Long-term
investments 19,202 18,689 513 - - -
Accounts
payable and
accrued
liabilities (19,359) (424) (4,972) (5,065) (12) (8,886)
Bank debt (50,780) - (50,780) - - -
Long-term
bank debt (27,456) (27,456) - - - -
-------------------------------------------------------------------------
Net financial
assets
(liabi-
lities) $(24,366) $ (1,072) $(37,469) $ 9,126 $ 1,206 $ 3,843
-------------------------------------------------------------------------
The company estimates a 20 percent change in the Canadian Dollar
against the above listed foreign currencies could be reasonably
possible over a twelve month period. A 20 percent strengthening in
the CAD would result in a change to earnings (loss) before taxes and
other comprehensive income (loss) as follows (an equal but opposite
impact to earnings (loss) before taxes and other comprehensive income
(loss) would result if the CAD weakened by 20 percent):
---------------------------------------------------------------------
USD ARS PEN COP
---------------------------------------
($000) CAD $ equivalent amounts
---------------------------------------------------------------------
Decrease in earnings before
taxes $ (218) $ - $ (201) $ (641)
Increase in other
comprehensive income $ 4,942 $ - $ - $ -
---------------------------------------------------------------------
5. BANK DEBT AND LONG-TERM BANK DEBT
In 2007, the company entered into a US$100.0 million reserve-backed
revolving credit facility with availability as at March 31, 2010 of US
$50.0 million. The company continues negotiations to extend the term on
this facility which expires on September 5, 2010, 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 December 31, 2009.
As at March 31, 2010 the outstanding reserve-backed facility was
$50.8 million (US$50.0 million), classified as bank debt (2009 - US$50.0
million). Deferred financing costs of $0.3 million related to this
facility are being amortized up to September 5, 2010, the expiration of
the facility, and, accordingly, is classified as a current asset (2009 -
$0.7 million). For the three months ended March 31, 2010, the company
recognized amortization of deferred charges of $0.4 million (2009 -
$0.2 million).
During 2009, the company negotiated with a Canadian chartered bank an
expansion of its ABCP line-of-credit to a maximum of $28.2 million. The
ABCP line-of-credit was primarily secured by the longer term notes
exchanged for the ABCP. Any borrowings from the expanded ABCP line-of-
credit are categorized as long-term, as the facility's initial maturity
is April, 2011 and the company can make up to five extension requests
with each extension representing an additional one-year period. The ABCP
line-of-credit bears interest at a floating rate. As at March 31, 2010
and December 31, 2009 the outstanding ABCP line-of-credit facility was
$27.5 million.
Interest expense on the facilities for the three months ended March 31,
2010 was $0.7 million (2009 - $1.4 million), as disclosed on the
Consolidated Statement of Operations and Retained Earnings as finance
charges which also includes the amortization of deferred finance charges.
The effective interest rate on the company's facilities was 3.1 percent
for the three months ended March 31, 2010 (2009 - 5.5 percent). The
unused credit on the ABCP line-of-credit facility was $0.7 million as at
March 31, 2010 and December 31, 2009.
6. ASSET RETIREMENT OBLIGATIONS
At March 31, 2010, the estimated total undiscounted amount required to
settle the asset retirement obligations was $16.7 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:
-------------------------------------------------------------------------
Three Months Ended March 31 2010
($000)
-------------------------------------------------------------------------
Asset retirement obligations, beginning of period $ 9,552
Change in estimate (22)
Cumulative translation adjustment (284)
Accretion expense 134
-------------------------------------------------------------------------
Asset retirement obligations, end of period $ 9,380
-------------------------------------------------------------------------
7. SHARE CAPITAL, WARRANTS AND CONTRIBUTED SURPLUS
(a) Authorized:
The authorized capital is comprised of an unlimited number of common
shares and 33,240,250 warrants, respectively.
Issued common shares:
-------------------------------------------------------------------------
Number of Amount
Three Months Ended March 31, 2010 Common Shares ($000)
-------------------------------------------------------------------------
Common shares, beginning of period 121,758,510 $ 143,610
Issued common shares upon exercise of
options (c) 40,000 20
Assigned value of options exercised (b) - 2
-------------------------------------------------------------------------
Common shares, end of period 121,798,510 $ 143,632
-------------------------------------------------------------------------
Issued warrants:
-------------------------------------------------------------------------
Number Amount
Three Months Ended March 31, 2010 of Warrants ($000)
-------------------------------------------------------------------------
Warrants, beginning and end of period 33,240,250 $ 4,654
Share capital and warrants:
-------------------------------------------------------------------------
March 31, December 31,
As at 2010 2009
-------------------------------------------------------------------------
Share capital and warrants $ 148,286 $ 148,264
-------------------------------------------------------------------------
(b) Contributed Surplus:
-------------------------------------------------------------------------
Three Months Ended March 31 2010
-------------------------------------------------------------------------
Contributed surplus, beginning of period $ 20,453
Stock-based compensation (c) 677
Assigned value of options exercised (a) (2)
-------------------------------------------------------------------------
Contributed surplus, end of period $ 21,128
-------------------------------------------------------------------------
(c) Stock Options:
As at March 31, 2010 and 2009, the company had outstanding stock options
to acquire common shares, as follows:
-------------------------------------------------------------------------
Three Months Ended March 31 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 255,000 1.03 - -
Exercised (40,000) (0.50) - -
Forfeited or cancelled - - (1,841,160) (13.45)
-------------------------------------------------------------------------
Outstanding, end of
period 7,898,067 1.59 2,735,167 2.41
-------------------------------------------------------------------------
Exercisable, end of
period 3,309,135 $ 1.71 1,394,667 $ 2.41
-------------------------------------------------------------------------
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
March 31, 2010 and 2009:
-------------------------------------------------------------------------
As at March 31 2010 2009
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Remaining Remaining
Number Contractual Number Contractual
Outstanding Life (yrs) Outstanding Life (yrs)
-------------------------------------------------------------------------
$0.50 - - 240,000 0.8
$0.86 - $1.09 5,189,567 4.2 547,667 1.3
$1.70 - $1.75 313,000 0.6 418,000 1.6
$2.00 1,007,000 3.6 1,057,000 4.6
$2.64 - $3.37 1,209,000 4.0 225,000 4.5
$5.40 - $19.20 179,500 1.7 247,500 2.5
-------------------------------------------------------------------------
Total 7,898,067 3.9 2,735,167 3.0
-------------------------------------------------------------------------
During the three months ended March 31, 2010, a non-cash expense of
$0.7 million (2009 - $0.5 million) was recorded as stock-based
compensation, reflecting the amortization of the fair value of stock
options over the vesting period. Additionally, during the three months
ended March 31, 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 three months ended March 31, 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
yield interest rate Expected life volatility
-------------------------------------------------------------------------
2010 -% 2.0% - 2.3% 4 years 81.1% - 81.8%
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of all options
granted for the three months ended March 31, 2010 was $0.62 per option.
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 March 31, 2010
-------------------------------------------------------------------------
Revenue, gross $ - $ 17,908 $ - $ - $ 17,908
Net loss (1,966) (559) (13) (15) (2,553)
Property and equipment 316 147,607 56,654 61,259 265,836
Capital expenditures 5 2,315 446 14,000 16,766
Total assets $ 36,971 $174,255 $ 60,272 $ 74,011 $345,509
-------------------------------------------------------------------------
Three Months Ended or
As At March 31, 2009
-------------------------------------------------------------------------
Revenue, gross $ 9 $ 26,376 $ 22 $ - $ 26,407
Net earnings (loss) (3,049) 4,309 (49) (23) 1,188
Property and equipment 276 195,230 54,681 29,269 279,456
Capital expenditures 9 4,638 5,960 15,005 25,612
Total assets $ 53,009 $224,050 $ 62,643 $ 31,352 $371,054
-------------------------------------------------------------------------
Crude oil sales totaling US$15.2 million (2009 - US$22.7 million) were
made to a large international oil company and natural gas sales totaling
US$0.8 million (2009 - US$1.4 million) were made to a local gas marketing
company during the three months ended March 31, 2010.
9. SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the calculation of basic and diluted
common shares:
-------------------------------------------------------------------------
Three Months Ended March 31 2010 2009
-------------------------------------------------------------------------
Weighted average common shares outstanding 121,788,732 54,948,010
Dilutive effect of stock options and share
purchase warrants 23,596 247,234
-------------------------------------------------------------------------
Weighted average common shares outstanding -
diluted 121,812,328 55,195,244
-------------------------------------------------------------------------
As the company has net losses for the three months ended March 31, 2010,
the dilutive effect of stock options and share purchase warrants became
anti-dilutive, causing 121,788,732 weighted average dilutive common
shares outstanding to be used as the denominator in the diluted per share
net loss calculation for three months ended March 31, 2010.
(b) Net change in non-cash working capital
-------------------------------------------------------------------------
Three Months Ended March 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Accounts receivable $ (542) $ 9,358
Inventory 194 (77)
Income taxes receivable (54) (256)
Prepaid expenses (489) (398)
Accounts payable and accrued liabilities 3,736 (3,134)
Income taxes payable 78 (330)
Due to a related company (11) 35
-------------------------------------------------------------------------
$ 2,912 $ 5,198
-------------------------------------------------------------------------
Operating $ (2,551) $ 9,654
Investing 5,463 (4,456)
-------------------------------------------------------------------------
$ 2,912 $ 5,198
-------------------------------------------------------------------------
(c) Supplementary cash flow information
-------------------------------------------------------------------------
Three Months Ended March 31 2010 2009
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Interest paid $ 618 $ 1,322
Income taxes paid $ 508 $ -
-------------------------------------------------------------------------
10. COMMITMENTS AND GUARANTEES
Work commitments
Each of the Peruvian licenses have negotiated work programs for a period
of seven years and the company has the right to withdraw from the
licenses at the end of each work program. In 2005 Petrolifera acquired
Blocks 106 and 107, two significant oil and gas exploration licenses in
Peru. In April, 2009 the company was awarded a third license with Block
133, a block that is contiguous with Block 107.
On Block 106, the company has completed the fourth phase work program.
The company is currently determining the proposed drilling site locations
on Block 106, and subsequently will compile and submit an Environmental
Impact Assessment ("EIA") to the Peruvian authority. On Block 107, the
company has completed the third phase of the work programs and has
submitted to the Peruvian authority an EIA identifying proposed drilling
sites. Upon the Peruvian authority's approval of the Block 107 EIA, the
company will have the right to provide notice prior to May 2012 that it
intends to enter into the fourth phase of the work programs with a
commitment to invest a minimum of US$10.0 million through the drilling of
one well prior to May, 2013. The company is in the first phase of its
work programs on Block 133 license which requires a minimum investment of
US$0.3 million through the acquisition of 20 km of seismic, field geology
and satellite mapping prior to February, 2011.
In 2007, the company was granted three concessions comprised of one
license and two technical evaluation agreements ("TEA") in Colombia.
Petrolifera has converted the Turpial and Sierra Nevada II TEAs into
exploration licenses with the latter renamed Magdalena. Each of the
Colombian licenses have annual negotiated work programs for a period of
six years and the company has the right to withdraw from the licenses at
the end of each work program. The second phase of the work programs on
the Sierra Nevada License requires the drilling of one exploratory well
and 70 km(2) of 3D seismic acquisition and processing prior to June,
2010. The company has completed the drilling of the Brillante SE-1X
exploratory well and has commenced a 3D seismic program over its La Pinta
structure. On the company's Turpial License, the second phase of the work
programs will be mostly financed by the company's equal working interest
joint venturer and is currently underway through the minimum acquisition
and interpretation of 114 km(2) of 2D seismic prior to September, 2010.
The company is in the first phase of its Magdalena License which requires
an exploration well be completed prior to December, 2010.
In Argentina, the company has farmed out its Puesto Guevara and Vaca
Mahuida Concessions work commitments of US$0.6 million and
US$2.9 million, respectively, through agreements reached during the three
months ended March 31, 2010. The Vaca Mahuida farmout agreement also
reimbursed the company $1.0 million for the costs of a previously drilled
exploratory well. Once the company's partners have met the work
commitments for the Puesto Guevara and Vaca Mahuida Concessions, the
company's working interest will be 44 percent and 25 percent,
respectively.
Contractual commitments
The company's contractual commitments under service contracts for
drilling, leases for office premises and other equipment and an
administrative services agreement for the nine months ended December 31,
2010 and annually thereafter are as follows:
-------------------------------------------------------------------------
Subsequent
2010 2011 to 2011 Total
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Drilling service contracts
and other leases $ 12,240 $ 492 $ - $ 12,732
-------------------------------------------------------------------------
Guarantees
The company has issued letters of credit in the total amount of
US$1.3 million to secure the capital expenditure requirements associated
with the Colombian work commitments and US$0.1 million to secure the
capital expenditure requirements associated with one exploration license
in Peru. Deposits of US$4.1 million and US$1.2 million were placed in
trust accounts in Colombia to meet certain work obligations on the
respective Magdalena and Turpial Licenses as they occur.
11. SUBSEQUENT EVENT
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 (each, a "Common Share") 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.
12. 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 months ended
March 31, 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 March 31, 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
months ended March 31, 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
March 31, 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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