- 1 - AMERICAS PETROGAS INC. MANAGEMENT`S DISCUSSION

Transcription

AMERICAS PETROGAS INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS
March 31, 2015
This MD&A for Americas Petrogas Inc. (TSX-V:BOE) should be read in conjunction with the Company’s condensed interim
consolidated financial statements as of and for the period ended March 31, 2015 and the Company’s annual MD&A and
audited consolidated financial statements as of and for the year ended December 31, 2014. Except as otherwise indicated
or where the context so requires, references to “Americas Petrogas” or the “Company” in the description of the Company’s
business, assets, properties and operations include the business, assets, properties and operations of Americas Petrogas
Inc. and its subsidiaries. The Company prepares its financial statements in accordance with IFRS as issued by the IASB.
All dollar figures stated herein are expressed in Canadian dollars ($ or Cdn$), unless otherwise specified.
This MD&A contains forward-looking information. Please see section “1.15 Other MD&A Information not disclosed
elsewhere and Advisories” for a discussion of the risks, uncertainties and assumptions relating to forward looking
information.
This MD&A contains Additional GAAP Measures (net revenue, gross profit (loss), operating profit (loss) and funds flow from
operations) and Non-GAAP Financial Measures (operating netback and working capital). Please see section “1.15 Other
MD&A Information not disclosed elsewhere and Advisories” for further information and definitions of these measures.
Please see section “1.4 Results of Operations” for further information on the calculation of “operating netback” and section
“1.6 Liquidity” for further information on the calculation of “working capital”.
Please see section “1.15 Other MD&A Information not disclosed elsewhere and Advisories” for a listing of defined terms
used in this MD&A.
This MD&A is based on information available up to May 29, 2015, the date on which it was approved by the Board of
Directors.
Introduction and Overview
Americas Petrogas Inc. is an international oil and gas exploration and production company headquartered in Calgary,
Canada. The Company’s oil and gas operations are focused in Argentina’s prolific Neuquén Basin, where the Company
holds interests in 1.5 million gross acres (1.0 million net acres) of land. The Company’s exploration and development
activities in the Neuquén Basin, along with positive announcements of large international oil companies in the Neuquén
Basin, continues to indicate the potential for unconventional shale oil, shale gas, tight oil, and tight gas in Argentina.
Houston-based petroleum engineering firm, Ryder Scott, has completed various independent analyses (in accordance with
the standards contained in the COGE Handbook and NI 51-101), which included net 7.56 billion barrels of oil equivalent
P50 Best Case Unrisked Prospective (Recoverable) Resources (73% gas and 27% oil/condensate) on nine (9) of Americas
Petrogas’ Neuquén Basin unconventional shale blocks as at March 31, 2014. See section “1.15 Other MD&A Information
not disclosed elsewhere and Advisories” for additional information, including oil and gas advisories. The Company also has
a conventional reservoir exploration and development program across three (3) of its blocks in the eastern Neuquén Basin,
with positive production and development economics. Americas Petrogas partners include ExxonMobil and YPF across
several of its Neuquén Basin blocks. For further information, see section “1.7 Capital Resources and Update of Blocks”
below.
Highlights and Recent Activities
•
In November 2014, the Neuquén province in Argentina issued a decree granting Americas Petrogas and its joint venture
partners (ExxonMobil and Gas y Petróleo del Neuquén) an evaluation period on the four Los Toldos Blocks (LT-1 Block,
LT-2 Block, LT-3 Block and LT-4 Block), which measure approximately 163,800 acres or 663 square kilometers gross.
The evaluation period spans four (4) years beginning May 2014 and ending May 2018.
•
As at March 31, 2015, the Company had $8.8 million of consolidated cash and cash equivalents. As well, at March 31,
2015, the Company had a positive consolidated working capital position of $4.8 million (working capital is calculated as
current assets ($20.0 million) less current liabilities ($15.2 million)). See section “1.6 Liquidity” for additional information.
•
During 2014, $7.3 million of Oil Plus benefits were collected from Oil Plus receivables recognized in 2013. In 2013, a
total of $19.5 million of Oil Plus benefits were collected from Oil Plus receivables recognized in 2012 and 2013. An
additional $21.4 million of Oil Plus benefits, which have not been recognized in the financial statements to date, have
been applied for and remain to be collected.
•
With respect to the Company’s unconventional Vaca Muerta shale exploration wells on the Los Toldos blocks, the
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Company, in conjunction with its partner, ExxonMobil, continued to conduct long-term production testing on the LTE.x1 well and the ADA.x-1 well.
•
In February 2015, the Hydrocarbons Commission of Argentina issued Resolution 14/2015 that created the Crude Oil
Production Stimulus Program, which will be valid during 2015 and may be extended for up to an additional 12 months.
The program provides for a payment of US$3.00 per barrel when quarterly production is equal or greater than a base
production level. The base production level is 95% of production for the fourth quarter of 2014.
•
Management is continuing to work diligently on a review of strategic alternatives aimed at enhancing shareholder value.
The opportunities being considered by the review include joint ventures, farm-outs, sale of selected assets and
corporate transactions.
•
During the three months ended March 31, 2015, an average of 1,261 barrels of oil were sold per day (net) at an average
selling price of $94.98 generating gross oil sales of $10.8 million. This compares to the three months ended March 31,
2014 when an average of 1,238 barrels of oil were sold per day (net) at an average selling price of $81.72 generating
gross oil sales of $9.1 million.
•
Net revenue (an additional GAAP measure) for the three months ended March 31, 2015 was $9.0 million compared to
$7.8 million for the first quarter of 2014.
•
For the three months ended March 31, 2015, operating netback (a non-GAAP measure) was $3.6 million ($31.29 per
barrel). For the three months ended March 31, 2014, operating netback was $4.1 million ($36.73 per barrel). No oil
plus benefits were credited to production costs during the three months ended March 31, 2015 and 2014.
•
With respect to funds flow from operations (an additional GAAP measure), the Company had an inflow of $0.4 million
during the first quarter of 2015, compared to an inflow of $2.0 million during the first quarter of 2014. The decrease can
be largely attributed to higher production costs.
•
For the first quarter of 2015, net loss attributable to owners of the Company was $1.6 million, which included $3.0 million
of non-cash, foreign exchange gains on intercompany loans. This compares to net loss attributable to owners of the
Company for the first quarter of 2014 of $24.6 million, which included $18.0 million of non-cash, foreign exchange losses
on intercompany loans.
•
In August 2014, the Company announced discovery of near-surface Sechura phosphate rock on its Bayovar Property.
The Company’s Peruvian subsidiary completed a trenching program on Bayovar concession 6, one of four concessions
on Americas Petrogas’ Bayovar Property. A total of five (5) trenches were sampled over a distance of 350 meters. The
lab results were favourable.
•
In 2015, the Company filed on SEDAR the NI 43-101 Mineral Resource technical report on the Company's drill holes
on the Bayovar 6, 7 and 8 concessions on its Bayovar Property located in the Sechura Desert, Peru.
•
In late 2014 and early 2015, the Company drilled numerous new holes on the Bayovar Property, drill cores from which
are waiting to be assayed.
For further information, see section “1.7 Capital Resources and Update of Blocks” below.
Financial Highlights
Financial highlights for the three months ended March 31, 2015 and 2014 are shown below. For additional information,
please see sections “1.2 Overall Performance” and “1.4 Results of Operations”.
Three months ended March 31
2015
2014
($ in thousands, except share, per share, and per barrel amounts)
Crude oil sales
$
10,779
$
9,108
Net revenue(1)
$
9,012
$
7,763
Operating netback(2)
$
3,551
$
4,094
$
31.29
$
36.73
$
(1,556)
$
(24,557)
Operating netback per barrel(2)
Net income (loss) attributable to owners of the
Company(3)
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Earnings (loss) per share– basic and diluted
$
(0.01)
$
(0.12)
Funds flow from operations(4)
Per share – basic
Per share – diluted
$
$
$
417
0.00
0.00
$
$
$
2,047
0.01
0.01
Weighted average number of common shares outstanding(5)
Basic
Diluted
231,739,106
231,739,106
212,572,440
214,139,198
Cash flow from operating activities
$
732
$
8,860
Capital expenditures
$
6,654
$
10,948
1,261
Average barrels sold per day
$
Average selling price per barrel
94.98
1,238
$
81.72
Notes:
(1)
“Net revenue” is an additional GAAP measure because it is presented in the consolidated statement of income (loss). Net revenue is gross revenue less royalties. The Company
uses “net revenue” as an indicator of operating performance.
(2)
“Operating Netback” is a non-GAAP measure. The Company uses “operating netback” as an indicator of operating performance, profitability and liquidity. Operating netback is
(3)
For the three months ended March 31, 2015, net loss attributable to owners of the Company included $3.0 million non-cash, foreign exchange gain (three months ended March
(4)
“Funds flow from operations” is an additional GAAP measure because it is presented in the consolidated statement of cash flows (‘Cash provided by (used by) operating activities,
calculated as revenues from oil sales less royalties and production costs. See section “1.4 Results of Operations” for further information on the calculation of “operating netback”.
31, 2014 -- $18.0 foreign exchange loss) on intercompany loans.
before changes in non-cash working capital’). The Company uses “funds flow from operations” and “funds flow from operations per share” to analyze operating performance and
liquidity. Funds flow from operations is calculated as net cash generated from (used by) operating activities (as determined in accordance with IFRS) before changes in noncash balance sheet operating items. Funds flow from operations per share is calculated by dividing funds flow from operations by the weighted average number of shares
outstanding. Funds flow from operations should not be considered an alternative to, or more meaningful than net cash generated from (used by) operating activities as determined
in accordance with IFRS. Funds flow from operations per share should not be considered an alternative to, or more meaningful than earnings (loss) per share as determined in
accordance with IFRS. See section “1.4 Results of Operations” for further information on the calculation of “funds flow from operations” and “funds flow from operations per
share”.
(5)
Diluted weighted average number of common shares outstanding is computed by adjusting basic weighted average number of common shares outstanding for dilutive
instruments. The number of shares included with respect to options, warrants and similar instruments is computed using the treasury stock method, which assumes any proceeds
received by the Company upon exercise of the in-the-money instruments would be used to repurchase common shares at the average market price for the period. For the three
months ended March 31, 2015, nil (three months ended March 31, 2014 - 1,566,758) common shares were deemed to be issued for no consideration in respect of options.
As of March 31, 2015, Americas Petrogas had $8.8 million of consolidated cash and cash equivalents. As well, at March
31, 2015, the Company had a positive consolidated working capital position of $4.8 million (working capital is calculated as
current assets ($20.0 million) less current liabilities ($15.2 million)). These funds will allow the Company to pursue its
exploration and development plans for part of 2015, though new funding (including joint ventures, debt, equity and/or
operating cash flows) will ultimately be required later in 2015. For additional information, see section “1.6 Liquidity”.
1.1 Background Information and Date
Americas Petrogas is in the business of: (1) exploration of conventional and unconventional (shale oil, shale gas and liquids,
and tight sands) oil and gas properties in Argentina, (2) development and production of conventional oil and gas properties
in Argentina; and (3) exploration of near-surface phosphates, potash, and other minerals, and potential development of a
fertilizer project in Peru. Americas Petrogas is a publicly traded company that was formed on August 22, 2008 by an
amalgamation of two predecessor entities.
The following organization chart summarizes the Company’s subsidiaries, their jurisdictions of incorporation and the
percentage of voting securities held by the Company:
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Additional information relating to the Company, including a summary of its oil and natural gas reserves prepared by an
independent engineering company as at December 31, 2014, is available on SEDAR at www.sedar.com.
1.2 Overall Performance
Oil production has continued on Medanito Sur and Rinconada Norte during 2015.
For the three months ended March 31, 2015, the Company reported gross oil sales of $10.8 million and net oil sales revenue,
after deducting royalties, of $9.0 million compared to net oil sales revenue, after deducting royalties, of $7.8 million for three
months ended March 31, 2014. The increase in oil sales revenue in 2015 is primarily the result of higher oil sales prices.
For further details on the Company’s financial results, please see section “1.4 Results of Operations” below.
Operating netback (a non-GAAP measure) for the first quarter of 2015 was $3.6 million compared to $4.1 million during the
same period of 2014. This decrease can be attributed to higher production costs and royalties in 2015. For additional
information regarding Oil Plus, see section “1.6 Liquidity”.
Net loss attributable to owners of the Company was $1.6 million or $0.01 per share for the first quarter of 2015 compared
to net loss attributable to owners of the Company of $24.6 million or $0.12 per share for the first quarter of 2014.
With respect to funds flow from operations (an additional GAAP measure), the Company had an inflow of $0.4 million during
the first quarter of 2015, compared to an inflow of $2.0 million for the first quarter of 2014. Funds flow from operations
reflects cash flow from operating activities (as determined in accordance with IFRS) before changes in non-cash balance
sheet operating items. Alternatively, it reflects net income (loss) on the statement of income (loss), adjusted for non-cash
items of income (loss) including, but not limited to, depletion and depreciation, stock-based compensation and unrealized
foreign exchange items. For further information, see section “1.4 Results of Operations” below.
During the first quarter of 2015, the Company generated $0.7 million of cash from operating activities (which includes
changes in non-cash balance sheet operating items), compared to the first quarter of 2014 when the Company generated
$8.9 million from operating activities. The decrease in cash inflow in 2015 is primarily attributable to higher production costs
and changes in non-cash balance sheet operating items. With respect to investing activities, the Company spent $6.7
million on capital expenditures in the first quarter of 2015 (most of which related to costs for drilling four wells at Medanito
Sur in late 2014), compared to $10.9 million spent during the first quarter of 2014. During 2015, the Company has continued
investing some of its excess cash in bonds issued by Argentina (available-for-sale financial assets) – this resulted in a net
cash inflow of $1.0 million during the first quarter of 2015.
The March 31, 2015 statement of financial position shows lower current assets, primarily as a result of cash spent on the
Company’s activities in Argentina and Peru. The Company’s exploration and evaluation assets have increased in 2015 as
a result of continuing activities in Argentina and Peru as well as changes in foreign exchange rates (functional currencies
compared to presentation currency). The Company’s reported property, plant and equipment have decreased in 2015 as
a result of depletion expense, which was partially offset by changes in foreign exchange rates (functional currencies
compared to presentation currency). Accounts payable and accrued liabilities decreased as a result of payments made to
vendors. During the first quarter of 2015, the Company made principal payments of approximately $0.8 million (AR$5.6
million) towards loans payable. The increase in contributed surplus is primarily attributable to the continued vesting of stock
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options. Another change in 2015 compared to 2014 was in accumulated other comprehensive income/loss, which reflects
foreign currency adjustments (net of related income tax) which result from translating and consolidating the financial
statements of the Company’s foreign operations into the Canadian dollar presentation currency.
For further details about and analysis of the Company’s financial condition, results of operations and cash flows, see section
“1.4 Results of Operations” below.
1.3 Selected Annual Information
See section 1.3 of the annual MD&A for the year ended December 31, 2014.
1.4 Results of Operations
Operating Netback and Funds Flow from Operations
During the three months ended March 31, 2015, the Company sold 113,490 barrels of oil compared to 111,457 barrels of
oil during the same period of 2014, an increase of 2%. Information on operating netback is shown below.
2015
2014
($ in thousands, except per barrel amounts)
Per
barrel
$ 10,779
(1,767)
(5,461)
$ 3,551
Crude oil sales
Royalties(1)
Production costs
Operating netback(2)
Per
barrel
$ 94.98
(15.57)
(48.12)
$ 31.29
$ 9,108
(1,345)
(3,669)
$ 4,094
$ 81.72
(12.07)
(32.92)
$ 36.73
Notes:
(1)
The royalty rate on production from Rinconada Norte is 12%. The royalty rate on production from Medanito Sur is 15% for the year ending March 2015 and was 13.5% for
the year ended March 2014.
(2)
“Operating Netback” is a non-GAAP measure. The Company uses “operating netback” as an indicator of operating performance, profitability and liquidity. Operating
netback is calculated as revenues from oil sales less royalties and production costs.
Funds flow from operations is shown as ‘Cash provided by (used by) operating activities, before changes in non-cash
working capital’ on the statement of cash flows. An alternative computation is shown below.
($ in thousands, except share and per
share amounts)
Net cash generated from (used by)
operating activities
Net change in non-cash balance sheet
operating items
Funds flow from operations(1)
2015
$
2014
732
$
(315)
$
417
(6,813)
$
Weighted average number of common shares outstanding
231,739,106
Basic
(2)
231,739,106
Diluted
Funds flow from operations per share(1)
Basic
Diluted
$
$
0.00
0.00
8,860
2,047
212,572,440
214,139,198
$
$
0.01
0.01
Note:
(1)
The term “funds flow from operations” is an additional GAAP measure because it is presented in the consolidated statement of cash flows (‘Cash provided by (used by) operating
activities, before changes in non-cash working capital’). The Company uses “funds flow from operations” and “funds flow from operations per share” to analyze operating performance
and liquidity. Funds flow from operations is calculated as net cash generated from (used by) operating activities (as determined in accordance with IFRS) before changes in non-cash
balance sheet operating items. Funds flow from operations per share is calculated by dividing funds flow from operations by the weighted average number of shares outstanding.
Funds flow from operations should not be considered an alternative to, or more meaningful than net cash generated from (used by) operating activities as determined in accordance
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with IFRS. Funds flow from operations per share should not be considered an alternative to, or more meaningful than earnings (loss) per share as determined in accordance with
IFRS.
(2)
Diluted weighted average number of common shares outstanding is computed by adjusting basic weighted average number of common shares outstanding for dilutive instruments.
The number of shares included with respect to options, warrants and similar instruments is computed using the treasury stock method, which assumes any proceeds received by the
Company upon exercise of the in-the-money instruments would be used to repurchase common shares at the average market price for the period. For the three months ended March
31, 2015, nil (three months ended March 31, 2014 - 1,566,758) common shares were deemed to be issued for no consideration in respect of options.
Revenue and Cost of Operations
During the three months ended March 31, 2015, the Company sold 113,490 barrels of oil compared to 111,457 barrels of
oil during the same period of 2014, an increase of 2%. Information on revenue and costs of operations is shown below.
2015
2014
($ in thousands, except per barrel amounts)
Per barrel
Barrels of oil sold
Crude oil sales
Net oil sales revenue(1)
Production costs
Depletion and depreciation
Gross profit (loss)
113,490
$ 10,779
$ 9,012
$ 5,461
$ 4,926
$ (1,375)
$ 94.98
$ 79.41
$ 48.12
$ 43.40
$ (12.12)
Per barrel
111,457
$ 9,108
$ 7,763
$ 3,669
$ 7,568
$ (3,474)
$ 81.72
$ 69.65
$ 32.92
$ 67.90
$ (31.17)
Notes:
(1)
Gross revenue net of royalties. The royalty rate on production from Rinconada Norte is 12%. The royalty rate on production from Medanito Sur is 15% for the year ending March 2015
and was 13.5% for the year ended March 2014.
Of the 113,490 barrels of oil sold in the first quarter of 2015, approximately 62,000 barrels relate to the recovery of capital
expenditures. Of the 111,457 barrels of oil sold in the first quarter of 2014, approximately 50,900 barrels relate to the
recovery of capital expenditures. For additional information, see section “1.7 Capital Resources and Update of Blocks”
below and note 4(p) of the annual consolidated financial statements.
The oil sold during 2015 and 2014 was primarily obtained from wells drilled on Medanito Sur, with additional oil from
Rinconada Norte and from testing of unconventional blocks.
The royalty rate on production from Rinconada Norte is 12%. The royalty rate on production from Medanito Sur is 15% for
the year ending March 2015 and was 13.5% for the year ended March 2014.
The product pricing policy in Argentina is impacted by an export tax regime, domestic supply-demand, and government
policy. For further information see section “1.6 Liquidity” below.
Cost of Operations
Production costs for the three months ended March 31, 2015 was $5.5 million ($48.12 per barrel) compared to $3.7 million
($32.92 per barrel) for the same period of 2014. Production costs increased as a result of: (i) expenses related to workovers
of previously drilled wells, (ii) higher costs in Argentina related to equipment rentals, salaries and contractors, and (iii) the
strengthening of the Argentine Peso relative to the Canadian dollar.
Production costs per barrel for the three months ended March 31, 2015 ($48.12) decreased modestly relative to production
costs per barrel for the three months ended December 31, 2014 ($52.46).
Because of relatively small production volumes, fixed production costs are a relatively high proportion of the total production
costs on a per-barrel basis. The Company's facilities are capable of handling a much higher level of production.
Depletion and depreciation for the three months ended March 31, 2015 was $4.9 million ($43.40 per barrel) compared to
$7.6 million ($67.90 per barrel) for the same period of 2014. An updated depletion rate was calculated upon the completion
of the December 31, 2014 conventional reserves report.
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General and Administrative Expenses
Stock-based compensation expense arises from the vesting of stock options. The Company issued new stock options in
May 2013. For further information regarding stock options, see note 11 of the Company’s condensed interim consolidated
financial statements for the period ended March 31, 2015.
Other general and administrative expenses have increased modestly in the first quarter of 2015 compared to the same
period of 2014. A breakdown of other general and administrative expenses follows:
2015
2014
($ in thousands)
Employee benefits expense (1)
Taxes other than income taxes
Professional and consulting fees
Rent
Travel
Listing, transfer agent and related expenses
Other expenses
$
$
2,106
497
342
177
58
25
205
3,410
$
$
1,800
573
226
135
45
55
297
3,131
Note:
(1)
Employee benefits expense includes directors’ fees, salaries, bonuses, medical benefits, and post-employment benefits. For the three months ended March 31, 2015,
employee benefits expense excludes $586 (March 31, 2014 - $1,450) of stock–based compensation expense recognized in respect of employees, directors and other
management personnel.
Gain on Sale of Available-for-Sale Financial Assets
During the three months ended March 31, 2015, the Company purchased and sold bonds with combined face values of
US$3.2 million. As a result of selling bonds for proceeds above cost, the Company recognized gains of Cdn$1.0 million in
the statement of income (loss) during the three months ended March 31, 2015.
Income Tax Expense
For the three months ended March 31, 2015 the Company recognized $0.2 million of income tax expense (three months
ended March 31, 2014 - $0.2 million), all of which relates to minimum taxes in Argentina. For the year ended December
31, 2015, the Company anticipates having a taxable loss.
Foreign Exchange Gain/Loss and Other Comprehensive Income/Loss
Foreign exchange gain/loss on the statement of income (loss) reflects the impact of changes in exchange rates on foreign
denominated financial instruments. For the three months ended March 31, 2015, the Company recorded net $3.2 million
of foreign exchange gains (March 31, 2014 - $16.5 million foreign exchange losses) on the consolidated statement of income
(loss). The foreign exchange gain on the consolidated statements of income (loss) for the three months ended March 31,
2015 includes $3.0 million of foreign exchange gains (March 31, 2014 - $18.0 million foreign exchange losses) related to
intercompany monetary items.
At January 1, 2013, the Company reassessed the designation of intercompany monetary items and determined that
repayment of certain intercompany monetary items due from Petrogas Argentina is planned or likely to occur. Accordingly,
all exchange differences on translating these intercompany monetary items after January 1, 2013 are recognized in the
consolidated statement of income (loss) as foreign exchange gain (loss), and not as other comprehensive income (loss).
The Company’s head office frequently holds U.S. dollar financial instruments in the form of cash, cash equivalents, shortterm investments and available-for-sale financial assets. As at March 31, 2015, the Company’s head office held US$0.2
million (Cdn$0.3 million) of U.S. dollar cash and cash equivalents. Changes in the Canadian dollar – U.S. dollar exchange
rate results in the Company’s head office recognizing foreign exchange gains/losses on its U.S. dollar financial instruments.
The Company reported net $3.7 million of other comprehensive income for the first quarter of 2015. The reported other
comprehensive income/loss results from translating and consolidating the financial statements of the Company’s foreign
operations into the Canadian dollar presentation currency. For the three months ended March 31, 2015: (i) $0.1 million of
other comprehensive income was recorded as a result of consolidating the financial statements of the Company’s head
office operations (all of which relates to foreign denominated intercompany loans), (ii) $2.5 million of other comprehensive
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income was recorded as a result of translating and consolidating the financial statements of GrowMax and APPSA, and (iii)
$1.1 million of other comprehensive income was recorded as a result of translating and consolidating the financial
statements of Petrogas Argentina and Energicon.
The volatility of foreign exchange markets has created a significant amount of foreign exchange risk for the Company, given
the various transactions in Argentine Pesos, Peruvian Soles, Canadian dollars and U.S. dollars. This affects both the foreign
exchange gain/loss reported on the statement of income (loss) as well as the other comprehensive income/loss reported
on the statement of comprehensive income (loss). The Company has not hedged its foreign exchange risks.
The following table summarizes the spot exchange rates obtained from the Bank of Canada:
Date
March 31, 2015
December 31, 2014
September 30, 2014
June 30, 2014
March 31, 2014
December 31, 2013
September 30, 2013
June 30, 2013
March 31, 2013
December 31, 2012
Exchange rate
US$1.00=Cdn$1.2666 AR$1.00=Cdn$0.1438
US$1.00=Cdn$1.1601 AR$1.00=Cdn$0.1371
US$1.00=Cdn$1.1200 AR$1.00=Cdn$0.1322
US$1.00=Cdn$1.0670 AR$1.00=Cdn$0.1313
US$1.00=Cdn$1.1055 AR$1.00=Cdn$0.1380
US$1.00=Cdn$1.0636 AR$1.00=Cdn$0.1632
US$1.00=Cdn$1.0303 AR$1.00=Cdn$0.1775
US$1.00=Cdn$1.0518 AR$1.00=Cdn$0.1951
US$1.00=Cdn$1.0160 AR$1.00=Cdn$0.1983
US$1.00=Cdn$0.9949 AR$1.00=Cdn$0.2024
Status of Significant Blocks
For information on the status of the Company’s significant blocks, see section “1.7 Capital Resources and Update of
Blocks” below.
1.5 Summary of Quarterly Results
Mar 31-15
Dec 31-14
Sep 30-14
Jun 30-14
Mar 31-14
Dec 31-13
Sep 30-13
Jun 30-13
$9,012
$5,918
$5,591
$6,761
$7,763
$12,055
$13,243
$14,856
Net income (loss) attributable
to owners of the Company(3)
(in thousands)
$(1,556)
$(8,101)
$(5,130)
$(15,063)
$(24,557)
$(15,621)
$(5,593)
$5,121
Basic and diluted earnings
(loss) per share
$(0.01)
$(0.03)
$(0.02)
$(0.07)
$(0.12)
$(0.07)
$(0.03)
$0.02
Barrels of oil sold
113,490
74,325
75,891
91,741
111,457
160,552
189,966
218,252
Average number of barrels
sold per day
1,261
808
825
997
1,238
1,745
2,065
2,398
Crude oil sales average per
barrel(1)
$94.98
$95.00
$89.27
$87.79
$81.72
$86.97
$80.96
$78.92
Production costs (recovery)
average per barrel(2)
$48.12
$52.46
$47.53
$39.11
$32.92
$(10.58)
$9.60
$(21.44)
Depletion and depreciation
average per barrel
$43.40
$12.16
$73.53
$67.13
$67.90
$87.14
$38.79
$30.43
Net revenue(1) (in thousands)
Notes:
(1)
The royalty rate on production from Rinconada Norte is 12%. The royalty rate on production from Medanito Sur is 15% for the year ending March 2015 and was 13.5% for the year ended March
2014.
(2)
The Company did not recognize any Oil Plus benefits during the first quarter of 2015 or during the year ended December 31, 2014. For the fourth quarter of 2013, production costs are net of
approximately $6.6 million ($41.20 per barrel) of Oil Plus benefits related to increasing production. For the third quarter of 2013, production costs are net of approximately $4.34 million ($22.83 per
barrel) of Oil Plus benefits related to increasing production. For the second quarter of 2013, production costs are net of approximately $9.78 million ($44.79 per barrel) of Oil Plus benefits related to
increasing production. For further information regarding Oil Plus, see section “1.6 Liquidity”. To date, all recognized Oil Plus benefits have been collected.
(3)
The Company had no discontinued operations in any of these fiscal periods.
(4)
The financial statements have been prepared in accordance with IFRS and are presented in Canadian dollars. The Company’s functional currencies are: Canadian dollar for Americas Petrogas’
head office, Argentine Peso for Petrogas Argentina and Energicon, and U.S. dollar for GrowMax and APPSA.
-8-
The increase in barrels of oil sold in the first quarter of 2015 is the result of four new wells drilled on Medanito Sur late in
2014. The lower barrels of oil sold in each of the four quarters of 2014, compared to the fourth quarter of 2013, can be
attributed to no new conventional wells having been drilled until the fourth quarter of 2014, coupled with natural decline. An
updated depletion rate was calculated upon the completion of the December 31, 2014 conventional reserves report.
Though international oil prices tend to fluctuate, the product pricing regime in Argentina for light crude oil of the type
produced from Medanito Sur and Rinconada Norte has ranged from a low in 2012 of approximately US$74.00 per barrel to
a high in 2014 of approximately US$83.70 per barrel. Oil sales prices decreased modestly in the first quarter of 2014;
however, the selling price rose back to US$83.00 by May 2014. The current gross selling price is approximately US$76.00
per barrel for the Medanito light crude marker blend. For further information, see section “1.6 Liquidity”.
The Company derecognized deferred tax assets during the fourth quarter of 2014.
Gains as a result of selling available-for-sale financial assets were: $1.0 million for the first quarter of 2015, $0.3 million in
the fourth quarter of 2014, $0.5 million in the second quarter of 2014, $1.5 million in the fourth quarter of 2013, $0.8 million
in the third quarter of 2013 and $4.5 million in the second quarter of 2013.
The third quarter of 2013 includes a net impairment recovery of $1.1 million related to exploration and evaluation assets.
The second quarter of 2013 includes impairment losses of $6.8 million related to exploration and evaluation assets.
An additional factor to consider is the amount of foreign exchange gain/loss that may arise due to fluctuations in exchange
rates. Foreign exchange gain/loss reflects the impact of changes in exchange rates on foreign denominated financial
instruments. The following table summarizes the foreign exchange gain/loss recorded by the Company during its most
recent eight quarters:
Foreign exchange gain (loss)
(in thousands)
Mar 31-15
Dec 31-14
Sep 30-14
Jun 30-14
Mar 31-14
Dec 31-13
Sep 30-13
Jun 30-13
$3,195
$4,068
$2,778
$(7,016)
$(16,467)
$(8,609)
$(9,907)
$(990)
For further information, see section “1.4 Results of Operations” above.
1.6 Liquidity
Overall
As of March 31, 2015, Americas Petrogas has $8.8 million of consolidated cash and cash equivalents. As well, at March
current assets ($20.0 million) less current liabilities ($15.2 million)). Net loss attributable to owners of the Company was
$1.6 million during the three months ended March 31, 2015. Accumulated deficit as at March 31, 2015 amounted to $114.1
million (December 31, 2014 - $112.6 million).
To date, the Company has relied on cash flows from operations, equity and debt financing, and farm-outs to fund its
operations and capital expenditures. Cash flows from operations are dependent on a number of factors including production
levels, oil prices and operating costs. There is no assurance that production levels and/or oil prices will not decrease in the
future. The Company’s existing cash, and expected cash flows from operations may not be sufficient to fulfill the Company’s
work commitments relating to its Argentina and Peru properties. Failure to meet work commitments could result in the
Company being required to relinquish a portion of the related land that it holds an interest in, and performance bonds,
posted by the Company, could be affected. See section “1.7 Capital Resources and Update of Blocks – Aggregate
Commitments on Oil and Gas Concessions” and section “1.7 Capital Resources and Update of Blocks – Aggregate
Commitments on Mining Concessions”.
The Company has loans outstanding that are subject to various covenants. In January 2015, the bank waived a breach of
the covenant at December 31, 2014. Any future breach of the covenants, if not waived by the bank, could potentially result
in the loans ($4.0 million – principal outstanding at March 31, 2015) being required to be repaid early.
As a result of the foregoing matters, there are material uncertainties that raise significant doubt about the ability of the
Company to continue as a going concern and, accordingly, the appropriateness of using the going concern accounting
principles. However, management is currently evaluating and pursuing funding alternatives, including reviewing strategic
alternatives to maximize value for the shareholders. The Company’s management is fully engaged in its top priority to
alleviate funding needs through seeking farm-outs, joint ventures, potential sale of assets or merger. However, there can
be no assurance that the steps management is taking will be successful.
-9-
The Company’s access to sufficient capital will impact its ability to complete exploration and development activities. The
Company’s consolidated financial statements for the three months ended March 31, 2015 do not reflect the adjustments to
the carrying values of assets and liabilities and the reported revenues and expenses and balance sheet classifications that
would be necessary if the Company is unable to realize its assets and settle its liabilities as a going concern in the normal
course of operations. Such adjustments could be material.
For further information, see section “1.15 Other MD&A Information not disclosed elsewhere and Advisories – Businsss Risk
Factors”.
Oil and Gas Selling Price
The current gross selling price is approximately US$76.00 per barrel for the Medanito light crude marker blend.
In February 2015, the Hydrocarbons Commission of Argentina issued Resolution 14/2015 that created the Crude Oil
Production Stimulus Program, which will be valid during 2015 and may be extended for up to an additional 12 months. The
program provides for a payment of US$3.00 per barrel when quarterly production is equal or greater than a base production
level. The base production level is 95% of production for the fourth quarter of 2014. The Company believes it will be eligible
for this stimulus benefit for the first and second quarters of 2015.
In regards to product pricing, oil exports in Argentina are subject to an export tax regime. Domestic oil prices are determined
through the application of an export parity factor that is intended to equalize the realized prices between export and domestic
markets. In conjunction with the export parity factor, during 2013, the Argentine government agreed to permit higher
domestic oil prices in order to stimulate oil exploration and production activity. This regime, coupled with domestic oil
demand, allowed the oil price for the Company’s Medanito light crude to increase to approximately US$83.00 by December
2013. In early 2014, as a result of a significant devaluation in the Argentine Peso, the Argentina government required a
temporary reduction in oil prices; however, this temporary reduction was gradually eliminated by May 2014.
In addition to the aforementioned product-pricing regime, the Argentine government introduced an “Oil Plus” program in
2008 whereby producers were offered incentives for certain oil production increases and reserve replacements. The
Company’s policy is to recognize benefits from the Oil Plus program, as a deduction of either production costs or capital
expenditures, when it is probable that the related economic benefits will flow to the Company.
During 2014, $7.3 million of Oil Plus benefits were collected from Oil Plus receivables recognized in 2013. In 2013, a total
of $19.5 million of Oil Plus benefits were collected from Oil Plus receivables recognized in 2012 and 2013. An additional
$21.4 million of Oil Plus benefits, which have not been recognized in the financial statements to date, have been applied for
and remain to be collected.
Another encouraging aspect is the current gas price in Argentina for additional and new production of US$7.50 per million
BTU.
Operating Environment
Two of the Company’s subsidiaries are located in Argentina. The government of Argentina has regulations in place which
require approval by the Central Bank for any payments of foreign currency, such as U.S. dollars, to entities outside of
Argentina. These regulations can cause delays in repayment of intercompany loans, payment of dividends and repatriation
of capital.
Other
The Company’s financial instruments as of March 31, 2015 consist of cash and cash equivalents, restricted investments,
accounts receivable, miscellaneous receivables included in other current and non-current assets, accounts payable and
accrued liabilities, loans payable, acquisition costs payable, and miscellaneous payables included in other current liabilities.
For additional information on financial instruments, see section “1.14 Financial Instruments and Other Instruments” below.
Petrogas Argentina has a lease commitment on office space in Argentina. The future minimum lease payments payable
under this operating lease are as follows:
Not later than one year
Later than one year and not later than five years
- 10 -
$0.4 million
$0.1 million
Petrogas Argentina has a lease commitment on equipment in Argentina. The future minimum lease payments payable
under this operating lease are as follows:
Later than one year and not later than five years
$2.4 million
$2.1 million
The Company has additional commitments related to its oil and gas activities and its mining activities – for further
information, see section “1.7 Capital Resources and Update of Blocks” below.
1.7 Capital Resources and Update of Blocks
During the first quarter of 2015, the Company continued to produce and sell oil from two of its conventional blocks, Medanito
Sur and Rinconada Norte, both operated by the Company. Sales volumes during the first quarter of 2015, including oil from
testing unconventional wells, averaged 1,261 bopd (net), compared to the average daily sales during the first quarter of
2014 of 1,238 bopd (net).
During the fourth quarter of 2014, the Company drilled four conventional wells. All of these wells are currently in production.
Americas Petrogas Unconventional Oil and Gas Properties
Los Toldos Blocks
Americas Petrogas is the operator of the LT-1 block (398 square kilometers), the LT-2 (155 square kilometers), the LT-3
block (26 square kilometers) and the LT-4 block (84 square kilometers). The four Los Toldos blocks are not adjacent but
are in the same general vicinity of the Neuquén Basin. The Company currently holds a 45% participating interest in the four
Los Toldos blocks, with ExxonMobil holding a 45% participating interest and Gas y Petróleo del Neuquén maintaining a
10% participating interest.
partners an evaluation period on the LT-1 block, the LT-2 block, the LT-3 block and the LT-4 block. The evaluation period
spans four (4) years beginning May 2014 and ending May 2018.
The main investments, which the Company and its joint venture partners have committed to for the initial two and one-half
years of the evaluation period, are:
-
Connect the ALL.x-1 well on Los Toldos I to a nearby gas pipeline;
Install artificial lift systems in the LTE-x-1 well and the ADA-x-1 wells on Los Toldos II to study the effects of artificial
lift on production rates and to continue with the long-term production testing;
Drill two (2) wells in block I or II (1 horizontal, and 1 vertical or horizontal); and
Acquire 200 square kilometers of 3D seismic in blocks III or IV and drill one (1) vertical well.
Totoral, Yerba Buena and Bajada Colorada Blocks
Americas Petrogas is the operator on the Totoral (813 square kilometers), Yerba Buena (1,174 square kilometers) and
Bajada Colorada (1,061 square kilometers) blocks.
The Company’s original commitments for the Totoral, Yerba Buena and Bajada Colorada blocks were due in September
2013. However, an extension was negotiated to September 2015 and the Company returned to the government
approximately 1,510 square kilometres of the three blocks, leaving the Company with 3,048 square kilometres or 753,200
acres gross (2,743 square kilometres or 677,880 acres net). Ryder Scott estimated (updated as of March 31, 2014) that
there are net 1.72 billion BOE of P50 Best Case Unrisked Prospective (Recoverable) Resources on the retained lands of
the TYB blocks (69% oil/condensate and 31% gas). Furthermore, Ryder Scott Company estimated that the Company has
net 7.56 billion boe P50 Best Case Unrisked Prospective (Recoverable) Resources (27% oil/condensate and 73% gas) in
the Company’s nine unconventional shale oil and shale gas properties. The Ryder Scott estimates only considered the
Vaca Muerta, Lower Agrio and Los Molles shales. The report did not consider additional zones of interest such as the
Mulichinco, Quintuco, Tordillo, and other prospective formations. The Ryder Scott estimates were prepared in accordance
with the standards contained in the COGE Handbook and NI 51-101. There is no certainty that it will be commercially viable
to produce any portion of the resources.
For additional details regarding the Ryder Scott estimates, including applicable definitions, disclosures, advisories and
disclaimers, please refer to the news releases of Americas Petrogas dated August 22, 2013 and April 30, 2014 which are
filed on SEDAR at www.sedar.com.
- 11 -
Under the extension, the Company has committed to drilling two additional exploration wells on the Totoral, Yerba Buena,
and Bajada Colorada Blocks. These wells are expected to cost approximately Cdn$6.7 million (US$5.3 million) each. The
Company has a Cdn$8.9 million (US$7.0 million) performance bond for work commitments on these three blocks.
Huacalera Block
Americas Petrogas currently holds a 39% participating interest in the Huacalera block and YPF, pursuant to its acquisition
of Apache, holds a 51% participating interest. Prior to being acquired by YPF, Apache was the operator of the Huacalera
block and carried both Energicon and Petrogas Argentina in the drilling of the Hua.x-1, a deep exploration well on the
Huacalera block. Subject to the successful testing of the well from various formations, Apache agreed, at its own cost, to
perform a 3D seismic program over a 100 square kilometer area of the Huacalera block. In July 2011, the Hua.x-1 well
reached TD of 4,100 metres (13,450 feet).
Apache had previously applied to the government for a modification of the 2013 commitments on this block. However, the
modification was not granted and discussions are ongoing regarding the commitments. The Company believes that any
amendments to the commitments will likely involve relinquishment of some acreage. Based on the existing commitments
in place, the Company has committed to funding its share (based on working interest) of the costs related to the drilling of
a second deep well on the Huacalera block. The Company’s costs are estimated to be approximately Cdn$5.4 million
(US$4.3 million).
Loma Ranqueles Block
Americas Petrogas has a 90% participating interest in and is the operator of the Loma Ranqueles Block. The Company has
completed seismic work over the entire Loma Ranqueles Block. The Company originally committed to drilling one deep
exploration well on Loma Ranqueles Block prior to August 2014; however, the Company received an extension on this
commitment until June 2015. The estimated cost of drilling this well is approximately Cdn$13.9 million (US$11.0 million).
The Company has posted a Cdn$7.6 million (US$6.0 million) performance bond for ongoing work commitments on the
Loma Ranqueles Block.
Americas Petrogas Conventional Oil and Gas Properties and Operations
Up to the current date, substantially all of the revenue earned by the Company has been generated from its conventional
oil and gas operations conducted on the Medanito Sur and Rinconada Norte blocks.
Medanito Sur Block
The Company holds a 40% participating interest in and is the operator of the Medanito Sur Block (106 square kilometers).
At Medanito Sur, average daily sales have increased in 2015 (approximately 1,221 bopd for the three months ended March
31, 2015) compared to 2014 (approximately 906 bopd for the year ended December 31, 2014) due to four new wells drilled
on the block during the fourth quarter of 2014.
Americas Petrogas is responsible for funding all of the capital expenditures on the Medanito Sur block, including the 60%
share of its carried co-venturers. For “exploration wells” on the Medanito Sur block, the Company is entitled to 100% of
production until the recovery of 60% of exploration capital expenditures, after which “exploration wells” are treated in the
same manner as “development wells”. For “development wells”, the Company is entitled to receive 70% of production
remaining after recovering royalties and operating costs, until the recovery of 60% of development capital expenditures.
After the recovery of 60% of capital expenditures, the Company is entitled to receive 40% of production remaining after
recovering operating costs and royalties. The Company estimates that during 2015, it will be entitled to an average net
75% of production from the Medanito Sur block.
For the years ended March 2014 and 2015, the royalty rate at Medanito Sur was 13.5% and 15.0%, respectively. For the
year ending March 2016, the royalty rate is 16.5%. For the year ending March 2017, the royalty rate will be 18.0%. The
royalty rate will be 41.5% beginning in March 2017.
Rinconada Norte Block
The Company holds a 65% participating interest in and is the operator of the Rinconada Norte block (95 square kilometers).
Oil production at the Rinconada Norte block began in late 2011. Production from the Rinconada Norte block is transported
to the nearby processing facilities of Gran Tierra (recently acquired by Madalena Energy Inc.), the Company’s 35% joint
venture partner. The royalty rate under the exploitation concession for Rinconada Norte is 12% until 2016, at which time
the exploitation concession must be renewed and may be subject to a new royalty regime.
- 12 -
Vaca Mahuida block
On the Vaca Mahuida Block (942 square kilometers), Madalena Energy Inc., which acquired the assets of Gran Tierra in
Argentina, is the operator and Americas Petrogas is the technical operator.
In 2010, the Company, in conjunction with Gran Tierra, drilled five exploration wells and applied to the Rio Negro provincial
government for an exploitation concession on the entire Vaca Mahuida block. The application remains pending. The
Company is entitled to 25% of gross production from all wells on the Vaca Mahuida block.
Aggregate Commitments on Oil and Gas Concessions
Americas Petrogas enters into agreements, commitments, and incurs obligations in the normal course of its business that
impact on the Company’s liquidity and capital resources. These obligations and commitments relate primarily to exploration
activities. In some cases, the Company has the ability to vary the timing for fulfillment of its obligations and commitments
so long as they are fulfilled by the deadlines specified in the respective agreements.
The Company estimates that, in order to fulfill its contractual oil and gas obligations and commitments, it would be required,
at a minimum, to expend (before Value-added tax) the following amounts:
Year
2015
2016
Amount
$27.2 million (US$21.5 million)
$43.1 million (US$34.0 million)
As of March 31, 2015, the Company has fulfilled Cdn$1.7 million (US$1.3 million) of its 2015 commitments.
partners an evaluation period on the Los Toldos Blocks, which resulted in additional work commitments. For further
information, see section “1.7 Capital Resources and Update of Blocks – Los Toldos Blocks” above.
The Company has additional commitments related to the Huacalera Block which are estimated to be approximately Cdn$5.4
million (US$4.3 million). These commitments were originally due in 2013 but YPF, the Company’s joint venture partner and
operator on the block, is in discussions to have those commitments extended on behalf of itself and the Company, though
there is no assurance that any extensions will be obtained.
Failure to meet work commitments could result in the Company being required to relinquish a portion of the related land. It
could also result in the enforcement of performance bonds posted related to the work commitments. As of the current date,
the Company has posted Cdn$16.5 million (US$13.0 million) of performance bonds for its ongoing work commitments in
Argentina.
For additional information, see section “1.6 Liquidity” above.
Bayovar Property
Americas Petrogas’ Bayovar Property is located in the Bayovar district within the Sechura Desert, Peru. The Bayovar
Property includes blocks 5, 6, 7 and 8.
In September 2008, APPSA entered into the Bayovar Agreement with Activos Mineros S.A.C. of the government of Peru
which provided APPSA with the option to acquire a 70% participating interest in the Bayovar Property located in the Sechura
area, Piura province, Peru. The remaining 30% participating interest in the Bayovar Property is held by the Peruvian Coventurers who were fully carried by the Company until completion of an acceptable feasibility study (see section “1.9
Transactions with Related Parties” for further information). In May 2009, following the signing of the Bayovar Agreement,
APPSA signed a surface rights access agreement with the Community Foundation of San Martin de Sechura that provides
APPSA the unconditional right of surface access to the Bayovar Property area for 30 years. APPSA has the right to extend
the surface rights access agreement to a total of 99 years. In May 2014, the Peruvian state-owned company Activos Mineros
S.A.C. and the Executive Director of ProInversion executed the transfer agreement granting the Bayovar Property to
APPSA, Americas Petrogas’ Peruvian subsidiary. The execution of the transfer agreement resulted in additional
commitments, which are described further below.
In 2014, the Company officially recorded, with the public registry in Peru, 8,800 additional hectares (approximately 21,700
acres or 88 square kilometers) of concessions in the Bayovar district within the Sechura Desert, Peru. These 8,800 hectares
of registered new concessions are located to the northeast of lands currently held by Vale S.A., which operates a producing
- 13 -
phosphate mine in the Bayovar district in conjunction with Mosaic Company and Mitsui & Co., Ltd.
When added to the Company’s original Bayovar Property (concessions 5, 6, 7 and 8), which measures in excess of 82,000
hectares (202,600 acres or 820 square kilometres), the Company now holds registered concessions totaling in excess of
90,800 hectares (224,300 acres or 908 square kilometers) in the Bayovar district within the Sechura Desert, Peru. The new
concessions are immediately to the east of the Company’s Bayovar 6 and Bayovar 8 concessions. The Company has staked
an additional 1,200 hectares of lands in the same area for which registration is still pending.
Phosphates and Other Minerals
In addition to potash brines, the Company believes that the Bayovar Property area also has considerable phosphate
resources located in the southern and western portions of the concession. These resources could extend over an area as
large as 33,547 hectares. The southern portion of the Bayovar Property is located nearby an existing open-pit surface
phosphate mine that was put into production in August 2010 by Vale S.A., a large Brazilian mining company. A phosphates
project, operated by Fosfatos del Pacifico, a subsidiary of Cementos Pacasmayo (Hochschild Group) of Peru and partially
owned by Mitsubishi Corp. of Japan and Zuari Industries Ltd., is also located in the vicinity of the southern portion of the
Bayovar Property. As well, Focus Ventures Ltd (a TSX Venture listed company) is pursuing phosphates in the Bayovar
area.
In 2015, the Company received its NI 43-101 compliant Mineral Resource estimate for its Bayovar phosphate project. The
independent estimate was prepared by Golder, supervised by Jerry DeWolfe, MSc. P.Geo, an Independent Qualified Person
defined under NI 43-101. The independent estimate was based on the Company’s historic drill holes on the Bayovar 6, 7
and 8 concessions on its Bayovar Property located in the Sechura Desert, Peru. For additional information, please see the
technical report, with an effective date of March 15, 2015, filed on SEDAR on May 13, 2015.
In late 2014 and early 2015, the Company drilled numerous new holes, the cores from which are waiting to be assayed.
Potash Brine
Mineral salt containing brines occur in a coastal sabkha at the Bayovar Property. Besides phosphates, magnesium chloride,
sulfates, bromine and other valuable mineralization, these brines contain potassium chloride.
In 2011, GrowMax and APPSA signed an agreement with Kisan, a shareholder of GrowMax, to supply up to one-half of the
total future production of potash from the Bayovar project to IFFCO at a modest discount to the market price for potash in
India (see section “1.9 Transactions with Related Parties” in the Company’s annual MD&A for further information). .
Aggregate Commitments on Mining Concessions
In May 2014, APPSA, which holds a net 70% interest in the Bayovar Property, and the Peruvian Co-venturers officially
exercised the option to acquire the Bayovar Property, and the transfer agreement for the Bayovar Property was executed.
The Peruvian group holding a 30% interest in the Bayovar Property is a related party – see section “1.9 Transactions with
Related Parties” below for further information.
The execution of the transfer agreement resulted in the following project commitments for the Company and its Peruvian
joint venture partner on the Bayovar Property:
• Commence commercial production within three years following the transfer agreement being executed;
• Produce a minimum of 70% of the annual sales volume set forth in the study, within three years following execution
of the transfer agreement;
• Invest a minimum of: Year 1 – US$0.5 million; Year 2 – US$1.1 million; and Year 3 – US$10.6 million;
• Complete a complementary feasibility study; and
• Post a performance bond of US$5.0 million.
The transfer agreement requires the following future payments to each of (i) the Peruvian state-owned company and (ii) the
local community:
• US$250,000 plus applicable taxes, paid over three years from the execution date of the transfer agreement; and,
• Production bonus of US$33.00 to be paid for each metric tonne of potassium chloride mineral sold from the Bayovar
Property, payable every six months, beginning in the second half of the fourth year following execution of the
transfer agreement. With respect to each tonne of any other non-metallic minerals produced from the Bayovar
Property, the price to be paid will be determined as follows: US$33.00 multiplied by the relative market price of the
other non-metallic mineral to the market price of potassium chloride.
(i) Future payments to the Peruvian state-owned company
- 14 -
The future payments to the Peruvian state-owned company are considered acquisition costs. Accordingly, the fair value
of the estimated future payments upon execution of the transfer agreement in May 2014 of Cdn$3.2 million (US$2.9
million) was capitalized to mining exploration and evaluation assets and a related financial liability (designated as a fair
value through profit or loss financial liability) was recognized on the statement of financial position as acquisition costs
payable. As a result of the change in the fair value of the liability from December 31, 2014 to March 31, 2015, the
Company recognized fair value losses of $118,000 (all of which was unrealized) through the statement of income (loss)
as ‘Gain (loss) on fair value through profit or loss financial instruments’.
With respect to these payments to the Peruvian state-owned company, 30% is expected to be recoverable from the
Company’s joint venture partner on the Bayovar Property.
For further information, see note 9 of the Company’s interim consolidated financial statements for the three months
ended March 31, 2015.
(ii) Future payments to the local community
Future payments to the community have not been recognized in the financial statements. Future payments to the
community will be recognized as incurred. The future expected payments payable to the community under the transfer
agreement are as follows:
Later than one year and not later than five
Beyond five years up to 28 years
US$0.1 million
US$0.7 million
US$20.4 million
With respect to these payments to the community, 30% is expected to be recoverable from the Company’s joint venture
partner on the Bayovar Property.
Summary
In order for the Company to fulfill its commitments for 2015, the Company will need to obtain additional financing. As well,
if the Company’s exploration activities are successful or should the Company wish to accelerate its exploration and
development plans, in Argentina and/or Peru, the Company will need additional funding for more drilling (beyond the
minimum commitments) and for development activities. The Company believes that such additional funding should be
accessible, if successful progress is demonstrated; however, there is no assurance that additional funding will be available,
or if available, that it will be on terms acceptable to the Company. For further information, see section “1.6 Liquidity” above.
Besides operational cash flows and equity financing, possible opportunities for funding include farm-outs of the Company’s
various exploration blocks, project financing on projects such as Medanito Sur, Rinconada Norte and Bayovar, a spinout of
GrowMax and/or an equity financing by GrowMax. Americas Petrogas does not have any general credit facilities. As
exploration work progresses, the Company’s financing plans could change and the change could be material.
There are several key factors that can impact the plans and expectations regarding fulfilling the capital commitments and
availability of capital resources, including, but not limited to, the need for government approvals, availability of drilling rigs,
oil and gas prices, phosphates prices, potash/carnallite prices, costs of production, the degree of success, if any, in finding
hydrocarbons, the financial capabilities of joint venture partners, and the availability of new funding on terms acceptable to
the Company.
1.8 Off-Balance Sheet Arrangements
The Company has operating leases as noted in section “1.6 Liquidity” above.
1.9 Transactions with Related Parties
Details of transactions between the Company and related parties are disclosed below.
During the three months ended March 31, 2015 and 2014, the Company incurred rent charges of $17,000 and $17,000
respectively, from a company owned by a member of key management.
The Company incurred the following fees and expenses in connection with other related parties:
- 15 -
2015
($ in thousands)
Legal fees
Consulting fees
Short-term employee benefits
Pension costs – defined contribution plans
Stock-based compensation expense
2014
$
46
93
38
2
30
$
62
33
50
2
55
$
209
$
202
Substantially all of the legal fees were paid or payable to a law firm of the Company’s corporate secretary for typical
corporate legal services and financings.
The legal fees incurred during the three months ended March 31, 2015 and 2014 were expensed.
Other related parties consisted of (i) close family members of a senior executive of Americas Petrogas, (ii) a private Peruvian
company controlled by a close family member of a senior executive of Americas Petrogas, and (iii) the corporate secretary
of Americas Petrogas.
Compensation of key management personnel
During the three months ended March 31, 2015 and 2014, the Company’s key management personnel consisted of seven
individuals. The remuneration of these individuals was as follows:
($ in thousands)
Short-term employee benefits(1)
Pension costs – defined contribution plans
Stock-based compensation expense(2)
2015
2014
$
520 $
447
9
9
308
613
$
837
$
1,069
Notes:
(1)
(2)
Includes directors’ fees, salaries, bonuses, and medical benefits.
Reflects the amount recorded as an expense in the consolidated statement of income (loss). The fair value of stock-based compensation is measured at grant date
using an option pricing model, and is recognized as an expense over the vesting period.
Bayovar concession
As a result of the execution of the transfer agreement for the Bayovar Property, APPSA has a net 70% interest in the
Bayovar Property. A close family member of a senior executive of Americas Petrogas holds, on behalf of a Peruvian group
(“the Peruvian Co-venturers”), the remaining 30% interest in the Bayovar Property. Americas Petrogas was responsible for
funding 100% of costs on the Bayovar Property until the date of completion of a feasibility study. Capital costs incurred in
respect of the Bayovar Property are disclosed under Mining in note 6 of the interim consolidated financial statements. A
receivable from the Peruvian Co-ventures in the amount of $1.0 million is included in Other Non-Current Assets at March
31, 2015. See note 9 of the interim consolidated financial statements for information on commitments in respect of the
Bayovar Property.
Subsidiaries
See note 17(c) of the Company’s interim consolidated financial statements for the three months ended March 31, 2015 for
information about foreign exchange gain (loss) on intercompany monetary items.
1.10 Fourth Quarter
Not applicable.
- 16 -
1.11 Proposed Transactions
None.
1.12 Critical Accounting Estimates
The preparation of financial statements requires management to make judgments, estimates, and assumptions that affect
the application of policies and reported amounts of assets, liabilities, and revenues and expenses. The estimates and
associated assumptions are based on historical experience and various other factors that are believed to be reasonable
under the circumstances. Actual results may differ from these estimates.
For further information, see the disclosures and accounting policies included in the annual consolidated financial statements.
1.13 Change in Accounting Policies including Initial Adoption
Effective January 1, 2015, the Company adopted the following new and revised IFRSs that were issued by the IASB. Unless
otherwise stated, the application of these IFRSs did not have any material impact on disclosure or the amounts reported for
the current or prior years but may affect the disclosure and accounting for future transactions or arrangements.
•
•
•
•
•
•
•
Amendment to IFRS 3, Business combinations
Amendment to IFRS 13, Fair value measurement
Amendment to IAS 40, Investment property
Amendment to IFRS 8, Operating segments
Amendment to IAS 16, Property, plant and equipment and IAS 38, Intangible assets
Amendment to IAS 24, Related party disclosures
Amendment to IAS 19, Employee benefits
1.14 Financial Instruments and Other Instruments
The following table summarizes the Company’s types of financial instruments and their carrying amounts:
($ in thousands)
Financial assets
Loans and receivables
Cash and cash equivalents
Accounts receivable
Other current assets
Restricted investments
Other non-current assets
March 31, 2015
$
$
Financial liabilities
Other financial liabilities
Accounts payable and accrued liabilities
Other current liabilities
FVTPL financial liabilities
Loans payable(1)
Acquisition costs payable
$
December 31, 2014
8,790
4,519
225
6,358
958
20,850
$
6,365
718
$
$
3,903
3,554
$
14,540
14,718
4,036
357
5,824
570
25,505
11,106
507
4,458
3,145
$
19,216
Note:
(1)
Includes current and non-current portion.
The fair value of cash and cash equivalents, accounts receivable, other current assets, restricted investments, other noncurrent assets, accounts payable and accrued liabilities and other current liabilities approximate their carrying values.
At the statement of financial position date, the fair value of the loans payable and acquisition costs payable is their carrying
- 17 -
values. The fair value of these instruments was determined using a discounted cash flow method.
Income, expenses, gains and losses associated with financial instruments are generally reported under other income
(expense) in the consolidated statement of income (loss).
The Company’s financial instruments are exposed to certain risks, including currency risk, interest rate risk, commodity
price risk, credit risk and liquidity risk. The Company’s exposure to these risks and its methods of managing the risks have
been discussed by the Company’s directors.
Currency Risk
The Company is exposed to financial risk related to fluctuations in foreign exchange rates.
The Company’s financial statements are presented in Canadian dollars. The functional currency of Americas Petrogas’
head office operations is the Canadian dollar. The functional currency of GrowMax and APPSA is the U.S. dollar. The
functional currency of Petrogas Argentina and Energicon is the Argentine Peso. Because the Company is publicly listed on
a Canadian stock exchange, it has chosen to present its financial statements in Canadian dollars.
Although the Company’s head office operation has a Canadian dollar functional currency, the operation incurs some
expenditures in U.S. dollars and makes investments in U.S. dollars. Conversely, GrowMax has a U.S. dollar functional
currency but incurs some expenditures in Canadian dollars. Accordingly, the Company is exposed to foreign exchange risks
pertaining to the Canadian dollar - U.S. dollar exchange rate.
Additionally, Petrogas Argentina obtains some of its funding in U.S. dollars from head office but substantially all of its
expenditures and sales collections are in Argentine Pesos. Accordingly, Petrogas Argentina is exposed to foreign exchange
risk pertaining to the Argentine Peso - U.S. dollar exchange rate. APPSA incurs expenditures in U.S. dollars and Peruvian
Soles. Americas Petrogas has not entered into any foreign currency hedges.
Interest Rate Risk
Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes
in market interest rates. The Company aims to stagger the maturity dates of its investments (including cash equivalents and
short-term investments) over different time periods and dates to minimize exposure to interest rate changes.
In June 2013, Petrogas Argentina obtained two loans, one with a face value of AR$10.0 million (Cdn$1.9 million) and the
other with a face value of AR$40.0 million (Cdn$7.6 million). The AR$10.0 million loan bears interest at a fixed rate of
15.25% per annum. The AR$40.0 million loan bore interest at a fixed rate of 26% per annum for the initial twelve months
of the term, the rate is currently variable. These loans increased the Company’s exposure to interest rate risk.
Also contributing to the Company’s exposure to interest rate risk was the recognition of acquisition costs payable – for
further information, see note 9 of the Company’s interim and annual consolidated financial statements.
The Company monitors its exposure to interest rates and has not entered into any derivative financial instruments to manage
this risk.
Commodity Price Risk
The Company is exposed to price risk with respect to fluctuations in the price of crude oil. These fluctuations directly affect
revenues. For further information see section “1.6 Liquidity” above.
Credit Risk
Credit risk is the risk of an unexpected loss if a customer or third party to a financial instrument fails to meet its contractual
obligation. Credit risk arises from the Company’s cash, cash equivalents, accounts receivable, other current assets,
restricted investments and other non-current assets. The carrying value of these financial assets represents the maximum
exposure to credit risk. The Company’s exposure to credit risk is considered to be low-moderate, given the size and nature
of the various counterparties involved and their history of performance.
The Company’s restricted investments at March 31, 2015 and December 31, 2014 are held with a financial institution that
was assigned a long-term issuer default rating of BBB- (Fitch Ratings).
All of the Company’s oil sales during 2015 and 2014 were made in Argentina to one large international oil and gas company.
- 18 -
Amounts due from this customer are included in accounts receivable at March 31, 2015 and December 31, 2014.
Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company
has a planning and budgeting process in place to help determine the funds required to support the Company’s normal
operating requirements on an ongoing basis. The Company attempts to ensure that there are sufficient funds to meet its
short-term business requirements, taking into account its holdings of cash.
As of March 31, 2015, Americas Petrogas had $8.8 million of consolidated cash and cash equivalents. As well, at March
current assets ($20.0 million) less current liabilities ($15.2 million)).
For additional information, see section “1.6 Liquidity”.
Covenants
On June 14, 2013, Petrogas Argentina obtained two loans; one with a face value of AR$40.0 million or Cdn$7.6 million and
the other with a face value of AR$10.0 million or Cdn$1.9 million.
The financial covenants of the loans require Petrogas Argentina to:
(a) Not allow, at any time during the term of the loans,
the ratio of total financial debt (excluding
intercompany loans) as numerator to earnings before
interest, taxes, depreciation, and amortization
(EBITDA) as denominator to be greater than 1, as
shown in the most recent annual financial statements
of Petrogas Argentina.
As at December 31, 2014, the ratio of total financial debt
(excluding intercompany loans) as numerator to earnings
before interest, taxes, depreciation, and amortization
(EBITDA) was calculated to be 2.90. In January 2015,
the bank waived the breach of this covenant.
(b) Not allow, at any time during the term of the loans, (i)
Petrogas Argentina’s net worth to be less than
AR$100,000,000 as shown in the most recent annual
financial statements of Petrogas Argentina, and (ii)
the financial debt (including the amount owed by
Petrogas Argentina under the loans and excluding
the amount owed under the intercompany loans) to
be greater than AR$100,000,000.
As at December 31, 2014, Petrogas Argentina’s net
worth was calculated to be AR$205,592,979.
As at March 31, 2015, Petrogas Argentina’s financial
debt (including the amount owed by Petrogas Argentina
under the loans and excluding the amount owed under
the intercompany loans) was calculated to be
AR$28,161,746.
1.15 Other MD&A Information not disclosed elsewhere and Advisories
Disclosure of Outstanding Share Data
As of May 29, 2015, the Company has the following securities outstanding:
Description of Security
Number of
Securities
Outstanding
Additional Comments
Common Shares
231,739,106
Stock Options
14,925,343
Exercisable at prices ranging from $1.35 to US$2.93 and
which expire between December 2015 and May 2018.
575,000
Exercisable at a price of $0.90 and expire on June 10,
2015. If exercised, each unit option would result in the
issuance of one common share and one-half of one
common share purchase warrant.
Unit Options
- 19 -
Warrants
9,583,333
Exercisable at a price of $1.125 and expire on June 10,
2017.
Business Risk Factors
For information on risk factors associated with Americas Petrogas’ business, see “Business Risk Factors” in the Company’s
annual MD&A for the year ended December 31, 2014
Internal Controls and Disclosure Controls over Financial Reporting
Since the Company is a Venture Issuer, it is required to file basic certificates, which it has done for the quarter ended March
31, 2015. The Company makes no assessment relating to establishment and maintenance of disclosure controls and
procedures as at March 31, 2015.
Additional Information
Additional information relating to the Company is available on SEDAR at www.sedar.com.
ABBREVIATIONS
In this MD&A, the abbreviations set forth below have the following meanings: ‘
Oil and Natural Gas Liquids
bbl
barrel of oil
bbls
barrels of oil
bopd
barrels of oil per day
boe
barrels of oil equivalent
boepd
barrels of oil equivalent per day
mbbls
thousands of barrels of oil
mstb
thousands of stock tank barrels of oil
NGLs
natural gas liquids
Other
API
American Petroleum Institute
the measure of the density or gravity
of liquid petroleum products derived
from a specific gravity
Natural Gas
mcf
thousand cubic feet
mmcf
Million cubic feet
mcfd
thousand cubic feet per day
mmcfd
million cubic feet per day
m
m3
km
km2
metres
cubic metres
kilometres
square kilometres with one square
kilometre being equivalent to
approximately 247 acres
Glossary of Terms
In this Management’s Discussion and Analysis, the following terms have the meanings ascribed to them, unless the context
otherwise requires:
“Americas Petrogas” or “Company” means Americas Petrogas Inc., a corporation existing under the laws of Alberta and,
unless the context otherwise requires, includes the wholly owned or controlled subsidiaries of the Company;
“Apache” means Apache Corporation, an American multi-national oil company, with its head office in Houston, Texas, and
when used herein, includes its subsidiaries;
“APPSA” means Americas Potash Peru S.A., a body corporate under the laws of Peru and a wholly owned subsidiary of
GrowMax;
“Argentina” means the Argentine Republic;
“Bayovar Agreement” means a transfer option agreement dated September 30, 2008 between APPSA and Activos Mineros
S.A.C. of the government of Peru granting a four year option to acquire mining leases in the Bayovar Property and which
was extended to early 2014;
- 20 -
“Bayovar Property” means Bayovar mineral concessions Ramon (Licence Bayovar #5 and #6) and Zapayal (Licence
Bayovar #7 and #8) in the Sechura area, Piura province, Peru in which APPSA holds a 70% participating interest pursuant
to the exercise of the Bayovar Agreement;
“Board of Directors” or “Board” means the duly elected board of directors of the Company;
“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook;
“Common Shares” means the common shares in the share capital of the Company;
“Energicon” means Energicon S.A., a body corporate under the laws of Argentina and a wholly owned subsidiary of
Americas Petrogas;
“ExxonMobil” means Exxon Mobil Corp., an American multi-national oil company, with its head office in Houston, Texas,
and when used herein, includes its subsidiaries;
“Geominex” means Geominex Consultants Inc.;
“Golder” means Golder Associates Ltd.;
“Gran Tierra” means Gran Tierra Energy Inc., an international oil and gas exploration and production company with offices
in Calgary, Alberta, and when used herein, includes its subsidiaries and successors;
“GrowMax” means GrowMax Agri Corp., a corporation existing under the laws of Alberta and an 89% owned subsidiary of
Americas Petrogas;
“ISAB” means the International Accounting Standards Board;
“IFFCO” means Indian Farmers Fertiliser Co-operative, a co-operative under the laws of India and a shareholder of
GrowMax;
“Kisan” means Kisan International Trading FZE, a body corporate registered under the Jebel Ali Free Zone Authority,
United Arab Emirates, and a shareholder of GrowMax;
“LT-1 block” means the Los Toldos 1 concession block;
“Los Toldos blocks” means collectively, the LT-1 block, the LT-2 block, the LT-3 block and the LT-4 block;
“Management’s Discussion & Analysis” or “MD&A” means this management’s discussion;
“NI 43-101” means National Instrument 43-101 – Standards of Disclosure for Mineral Projects;
“NI 51-101” means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities;
“Petrogas Argentina” means Americas Petrogas Argentina S.A. a body corporate under the laws of Argentina and a whollyowned subsidiary of Americas Petrogas;
“Peru” means the Republic of Peru;
“Peruvian Co-venturers” means the party that owns the remaining 30% participating interest in the Bayovar Property;
“ProInversion” means the Agency for Promotion of Private Investment of the government of Peru;
- 21 -
“Ryder Scott” means Ryder Scott Company LP, an independent petroleum engineering consulting firm with its head office
in Houston, Texas;
“SEDAR” means the System for Electronic Document Analysis and Retrieval of the Canadian Securities Administrators;
“TD” means total depth;
“tonne” means a metric ton, being 1,000 kilograms or 2,204.6 pounds;
“TSX-V” means the TSX Venture Exchange; and
Advisories
Forward Looking Information
This MD&A and certain documents incorporated by reference into this MD&A contain forward-looking information including,
but not limited to, the Company’s goals and growth strategy, testing of the LTE.x-1 well, testing of the ADA.x-1 well, strategic
opportunities available to the Company and the ongoing strategic review, outstanding Oil Plus benefits, plans to extend the
commitments on the Huacalera Block and possible relinquishments in connection therewith, estimates of reserves and
resources potential for unconventional shale oil, shale gas, tight oil and tight gas in Argentina, estimates of future production
costs and other costs, expected future production, exploration and development activities in respect of the projects in
Argentina and Peru, drilling and production activities on the Medanito Sur Block and the Rinconada Norte Block, the
performance of a 3D seismic program on the Huacalera Block, the pending application for an exploitation concession for
the Vaca Mahuida block, drilling and commitments on the Totoral, Yerba Buena, Bajada Colorada Blocks, the Huacalera
Block, the Loma Ranqueles Block and the Los Toldos Blocks, oil pricing in Argentina, the potential impact of the “Oil Plus”
and Crude Oil Production Stimulus programs, the expectation to generate positive operating cash flow, government and
other regulatory approvals, fulfillment of farmout commitments by Apache and ExxonMobil, advancement and potential of
the Company’s phosphate project in Peru, commitments related to the Company’s activities in Peru, the potential for
phosphates and other minerals in respect of the land in the Sechura Desert, the assaying of drill cores in Peru, drilling
programs in Peru, lab results of the recent trenching program on Bayovar concession 6, future exploration and development
plans and opportunities in Argentina and Peru, future drilling plans in Argentina and Peru, oil and gas concession extensions
in Argentina, the costs, timing and success of the Company’s potash and phosphate exploration and development activities,
costs and revenues in respect of the Company’s Bayovar Property located in Peru, future potash and phosphate pricing,
expectations regarding the Company’s ability to fund all of its commitments/contractual agreements and other discretionary
future capital costs; and the availability of additional funding (including equity financing, farmout agreements, project
financing, a spinout of GrowMax and equity financing by GrowMax). There can be no assurance that the Company will
obtain financing or fulfill its work commitments. Furthermore, there can be no assurance that the strategic review will result
in a sale or merger of the Company, joint venture(s), or a sale of specific assets.
Forward-looking information is not based on historical facts but rather is based on management’s expectations regarding
the Company’s future growth, results of operations, production, future capital and other expenditures (including the amount,
nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental
matters, business prospects and opportunities and expectations with respect to general economic and capital market
conditions. Such forward-looking information reflects management’s current beliefs and assumptions and is based on
information currently available to Americas Petrogas’ 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 natural resources 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 and dealing with foreign governments and third parties located in foreign jurisdictions; general market risks; title
risks; expropriation risks; risks arising from dependence on key personnel; uninsurable risks; risks arising from the inability
to obtain necessary equipment and services; risks arising from reliance on third party contractors and partners; third party
credit risk; risks arising from managing the growth of the Company; inflation risks; dilution risks; risks associated with
obtaining and retaining qualified personnel and the risk associated with international activity.
There can be no assurance that the Company will obtain licenses, concessions, extensions or other approvals when
needed, or at all, and that further exploration of the Company’s Peruvian or Argentine properties will lead to commercial
discoveries or, if there are commercial discoveries, that the Company will be able to secure the necessary regulatory
approvals to commercially exploit such resources as intended. Few oil and gas or mineral properties that are explored are
ultimately developed into new oil and gas reserves or mineral resources. Readers are cautioned that measured oil and gas
- 22 -
flow rates may not be indicative of sustainable production rates. Readers are cautioned that the presence of phosphates
in samples is not necessarily indicative that phosphates are capable of being successfully produced in commercial
quantities. There is no assurance reserves will be assigned to such phosphate-bearing formations. There is no assurance
that future trenches will be dug or that future wells will be drilled on the Bayovar Property or that if dug/drilled, will be
successful. Cash flow from operations is dependent on future production levels, commodity prices, foreign exchange rates,
and government restrictions. Additional risks and uncertainties associated with the Company’s future plans are described
elsewhere in this MD&A. 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.
Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably
produced in the future.
The forward-looking statements contained in this MD&A and in the documents incorporated by reference herein
are expressly qualified by this cautionary statement. 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.
Oil and Gas Advisories
The following definitions are based from those given in the Canadian Oil and Gas Evaluation Handbook
Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring
accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already
produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following
categories:
Total Petroleum Initially-In-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally
occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in
known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.
Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to
be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in
place includes production, reserves, and contingent resources; the remainder is unrecoverable.
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from
known accumulations using established technology or technology under development but which are not currently
considered to be commercially recoverable due to one or more contingencies. Contingences may include such factors as
economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as
Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation
stage.
Undiscovered Petroleum Initially-In-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to
be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is
referred to as "prospective resources" and the remainder as "unrecoverable."
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable
from undiscovered accumulations by application of future development projects. Prospective resources have both an
associated chance of discovery and a chance of development.
Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable
by future development projects. A portion of these quantities may become recoverable in the future as commercial
circumstances change or technological developments occur; the remaining portion may never be recovered due to the
physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates
for reserves and resources. The Best Estimate is considered to be the best estimate of the quantity that will actually be
recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If
probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered
will equal or exceed the best estimate.
- 23 -
In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of
the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion
of the resources. For undiscovered hydrocarbons, the term ‘unrisked’ means that no geologic or chance of discovery (“play
risk”) has been incorporated into the hydrocarbon volume estimates.
In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that
it will be commercially viable to produce any portion of the resources. For discovered hydrocarbons, the term ‘unrisked’
means that no chance of development risk (“commercial risk”) has been incorporated in the hydrocarbon volume estimates.
The estimates of resources for individual properties may not reflect the same confidence level as estimates of resources for
all properties, due to the effects of aggregation.
Any references in this MD&A to test rates, flow rates, initial test or production rates, and/or early production rates are useful
in confirming the presence of hydrocarbons; however, such rates are not necessarily indicative of long-term performance
or of ultimate recovery. Such rates may also include recovered "frac" fluids used in well completion stimulation. Readers
are cautioned not to place reliance on such rates in calculating the aggregate production for the Company.
The term BOE (barrels of oil equivalent) is used throughout this MD&A. All calculations converting natural gas to BOE have
been made using a conversion ratio of six thousand cubic feet (six "Mcf") of natural gas to one barrel of oil, unless otherwise
stated. The use of BOE may be misleading, particularly if used in isolation, as the conversion ratio of six Mcf of natural gas
to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as
compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis
may be misleading as an indication of value.
Additional GAAP Measures
Net revenue
The term “net revenue” is an additional GAAP measure because it is presented in the consolidated statement of income
(loss). Net revenue is gross revenue less royalties. The Company uses “net revenue” as an indicator of operating
performance.
Gross profit (loss)
The term “gross profit (loss)” is an additional GAAP measure because it is presented in the consolidated statement of
income (loss). Gross profit (loss) is net revenue less cost of operations. The Company uses “gross profit” as an indicator
of operating performance.
Operating profit (loss)
The term “operating profit (loss)” is an additional GAAP measure because it is presented in the consolidated statement of
income (loss). Operating profit (loss) is net revenue less cost of operations and general and administrative expenses. The
Company uses “operating profit” as an indicator of operating performance.
Funds flow from operations
The term “funds flow from operations” is an additional GAAP measure because it is presented in the consolidated statement
of cash flows (‘Cash provided by (used by) operating activities, before changes in non-cash working capital’). The Company
uses “funds flow from operations” and “funds flow from operations per share” to analyze operating performance and liquidity.
Funds flow from operations is calculated as cash flow from operating activities (as determined in accordance with IFRS)
before changes in non-cash balance sheet operating items. Funds flow from operations per share is calculated by dividing
funds flow from operations by the weighted average number of shares outstanding. Funds flow from operations should not
be considered an alternative to, or more meaningful than net cash generated from (used by) operating activities as
determined in accordance with IFRS. Funds flow from operations per share should not be considered an alternative to, or
more meaningful than earnings (loss) per share as determined in accordance with IFRS. In addition to being presented on
the statement of cash flows, an additional reconciliation of net cash generated from (used by) operating activities and funds
flow from operations can be found below in “Section 1.4 Results of Operations”. The Company believes that funds flow from
operations, which is not impacted by fluctuations in non-cash working capital balances, is more indicative of operational
performance than net cash generated by operating activities.
- 24 -
Non-GAAP Measures
The Company uses and reports certain measurements in the evaluation of its operating performance, financial performance,
and financial position that do not have any standardized meaning prescribed by IFRS, referred to as “non-GAAP measures.”
It is unlikely for non-GAAP measures to be comparable to similar measures presented by other companies.
Operating Netback
The Company uses “operating netback” as an indicator of operating performance, profitability and liquidity. Operating
netback is calculated as revenues from oil sales less royalties and production costs. See section “1.4 Results of Operations”
for further information on the calculation of this measure.
Working Capital
The Company uses “working capital” to assess liquidity and general financial strength. Working capital is calculated as
current assets less current liabilities. Working capital should not be considered an alternative to, or more meaningful than
current assets or current liabilities as determined in accordance with IFRS. See section “Highlights and Recent Activities”
or “1.6 Liquidity” for further information on the calculation of this measure.
- 25 -

- 1 - AMERICAS PETROGAS INC. MANAGEMENT`S DISCUSSION

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