CALGARY, ALBERTA -- (Marketwired) -- 05/01/13 -- Americas Petrogas Inc. ("Americas Petrogas" or the "Company") (TSX VENTURE: BOE) announces that it has filed its 2012 audited consolidated financial statements and Management's Discussion and Analysis ("MD&A") relating to its 2012 year-end results. The Company also filed the disclosure and reports relating to reserves data and other oil and gas information required pursuant to National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. These filings can be accessed electronically on the System for Electronic Document Analysis and Retrieval (SEDAR) website: www.sedar.com. All amounts are in Canadian dollars unless otherwise stated.
Year-end Highlights and Recent Developments
-- During 2012, the Company continued to produce and sell oil from two of
its conventional blocks, Medanito Sur and Rinconada Norte, both operated
by the Company. Production during 2012, including some oil from testing
unconventional wells, averaged 1,991 bopd (net), an increase of
approximately 252% over the average daily production during 2011 of 566
bopd (net).
-- Operating netback of $35,608,189 ($50.11 per barrel) during the year
ended December 31, 2012 compared to $5,830,721 ($30.60 per barrel)
during the same period of 2011. This improvement of $29,777,468
represents an increase of 511% and can be attributed mainly to higher
quantity of oil sold and higher prices in 2012. See note (1) below.
-- This year's net revenue increased by $37,320,362 compared to 2011, which
is an increase of 420%.
-- In 2012, the Company recognized $1,296,224 of Oil Plus benefits related
to 2010. Subsequent to year-end US$857,000 of this recognized amount had
already been collected. Oil Plus is a government incentive offered to
producers.
-- $58.2 million of consolidated cash, cash equivalents and short-term
investments as of December 31, 2012.
-- Completed an expansion of the Company's own production and processing
facilities at Medanito Sur to handle up to 6,300 bopd.
-- Eight conventional wells were drilled during the fourth quarter of 2012.
Of these eight wells, six are in production, one is awaiting completion,
and one is shut-in. During the entire year of 2012, thirty-one (31)
conventional wells were completed and 27 wells found hydrocarbons, for a
success rate of 87%. Recent drilling on Medanito Sur has resulted in new
discoveries in previously untested areas of the block, indicating
potential new fields.
-- The Aguada Los Loros (ALL.x-1) well, on the Los Toldos I block (98,300
gross acres or 398 square kilometers or 154 sections), was drilled and
subsequent to year-end, in early 2013, a four-stage hydraulic
stimulation program was performed in the Vaca Muerta shale formation
(562 meters or 1,843 feet thick). The well discovered gas and natural
gas liquids. The initial production of the Vaca Muerta shale formation
increased from 1.3 million cubic feet (36,738 cubic meters) per day to
3.2 million cubic feet (90,418 cubic meters) per day of natural gas with
9 to 18 barrels of oil per day condensate (54-58 degree API) on managed
choke sizes (4-6mm). Hydrocarbon shows were also encountered and data
acquired in the following formations: lower Agrio, Mulichinco, Quintuco
and Tordillo. For more information, see "Additional Information on
Unconventional" below.
-- On the Los Toldos Este (LTE.x-1) well on the Los Toldos II block (38,400
gross acres or 155 square kilometers or 60 sections), a five-stage
hydraulic stimulation program was performed in the Vaca Muerta shale
formation (343 metres or 1,125 feet thick). The initial flow rate of the
Vaca Muerta shale formation was 797 barrels of oil equivalent per day
(boepd) of which 694 barrels of oil per day (bopd) was high quality
light sweet oil, 39.6 degrees API. The average flow rate for the initial
30 days was 309 boepd, of which there was 254 bopd. Hydrocarbon shows
were also encountered and data acquired in the following formations:
Upper Agrio, Lower Agrio, Mulichinco, Quintuco and Tordillo. For more
information, see "Additional Information on Unconventional" below.
-- Drilling of the Agua de Afuera (ADA.x-1) well, on the Los Toldos II
block, reached total depth ("TD") in late 2012. The well drilled through
340 meters or 1,115 feet of the primary target Vaca Muerta shale
formation with oil and gas shows through most of this shale section.
Hydrocarbon shows were also encountered in secondary targets such as the
Agrio, Quintuco and Tordillo. For more information, see "Additional
Information on Unconventional" below.
-- The La Hoya (LHo.x-1) well, located on the Company's Totoral block in
the southwestern region of the Neuquen Basin, was drilled (approximately
1,900 metres total depth), cased and cemented in mid-2012. It
intersected the Vaca Muerta Shale formation with thickness of 203 metres
or 666 feet with oil and gas shows through the whole shale column.
During drilling, hydrocarbon shows were also encountered and data
acquired in the Mulichinco, Quintuco, and Quebrada del Sapo formations.
Early in 2013, the Company reported the discovery of light oil related
to this well. In January 2013, a three-stage hydraulic stimulation
program was performed in the Vaca Muerta shale formation. After the
initial clean-up flow back, the well produced a total liquid rate of 300
to 600 barrels per day (bpd) which included 30 to 60 barrels of oil per
day (bopd) of high quality light sweet oil, 33 degrees API gravity. For
more information, see "Additional Information on Unconventional" below.
-- In late 2012, the government announced a price of US$7.50 per million
BTU for unconventional gas under its Gas Plus program.
-- The Company recognized accounting impairment losses relating to
Gobernador Ayala IV and Rinconada Norte.
-- The Company completed a brine mineral resource estimate relating to
Potassium Chloride (KCl, potash) in accordance with National Instrument
43-101.
-- The Company continues to advance on its phosphates project in Peru.
Recently, the Company staked an additional approximately 10,000 hectares
(24,700 acres) of concession lands in the Sechura Desert with potential
for phosphates and other minerals.
-- In 2012, after extensive surface sampling involving numerous trenches,
the Company conducted a 19-borehole drilling program on its southeastern
block at Bayovar to identify the presence and extent of evaporites,
phosphates, gypsum and other brines. The drilling program was completed
in December 2012. Analysis and testing of the cores is planned for later
this year.
-- Subsequent to year-end, in April 2013, the Company began the process of
exercising the option to acquire an interest in the Bayovar concession.
The exercising of the option is subject to government approval of
required documents for exercising the option.
Conventional Reserves
A summary of the Company's conventional oil and gas reserves only, prepared by an independent petroleum engineering company as at December 31, 2012 is as follows:
Proved Reserves (gross): 1,717,000 barrels of oil equivalent (boe)
Proved Reserves (net): 1,367,000 boe
Proved plus Probable Reserves (gross): 10,837,000 boe
Proved plus Probable Reserves (net): 9,099,000 boe
The full content of the Company's Statement of Reserves Data and Other Oil and Gas Information for the years ended December 31, 2012 and December 31, 2011, respectively, including the significant assumptions, is filed on SEDAR (www.sedar.com).
Outlook
We are continuing the exploration, appraisal and development drilling of the oil prospects in our conventional operations. Despite an expected dip in the early part of 2013, we believe production, reserves and cash flow will grow in 2013 as a consequence of our active drilling program.
We are continuing with our plans to drill unconventional wells (tight sands and shales), which primarily target the Vaca Muerta along with other conventional zones of interest, on our Loma Ranqueles block and our Totoral-Yerba Buena-Bajada Colorada concession, both of which are 90% owned by Americas Petrogas. Testing will continue on our already-drilled unconventional wells on Los Toldos and Totoral.
"The Company is very pleased with its significant progress in 2012 on the unconventional blocks and looks forward to additional drilling and test results in 2013. On the conventional side, we are making measured but consistent progress in enhancing our production and operational cash flow." said Barclay Hambrook, President and Chief Executive Officer.
Financial and Operating Results
Year ended December 31
2012 2011
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Per barrel Per barrel
Barrels of oil sold 710,649 190,564
Gross oil sales
revenue $ 53,795,419 $ 75.70 $ 11,385,271 $ 59.75
Royalties (7,587,546) (10.67) (2,497,760) (13.11)
Production costs (10,599,684) (14.92) (3,056,790) (16.04)
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Operating netback(1) $ 35,608,189 $ 50.11 $ 5,830,721 $ 30.60
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Funds flow from
operations(2) $ 21,743,731 $ (4,032,282)
Per share - basic $ 0.11 $ (0.02)
Per share - diluted $ 0.10 $ (0.02)
Weighted average number of common shares outstanding(3)
Basic 205,767,533 180,056,950
Diluted 212,642,586 180,056,950
December 31, December 31,
2012 2011
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Cash and cash equivalents $ 12,426,267 $ 27,762,717
Short-term investments(4) $ 45,748,768 $ 28,768,630
Current assets $ 72,106,798 $ 60,771,658
Current liabilities $ 20,132,604 $ 28,829,896
Working capital(5) $ 51,974,194 $ 31,941,762
Long-term debt $ - $ -
Notes:
(1) "Operating netback" is a non-IFRS measure and is calculated as
revenues from oil sales less royalties and production costs.
Operating netback is used as an indicator of operating performance,
profitability and liquidity. Operating netback does not have a
standardized meaning prescribed by IFRS. It is unlikely for non-IFRS
measures to be comparable to similar measures presented by other
companies. See reconciliation above.
(2) "Funds flow from operations" is an additional IFRS measure because it
is presented in the consolidated statement of cash flows. Funds flow
from operations and funds flow from operations per share are used 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 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.
(3) 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 year ended December 31, 2012, 6,875,053 common shares
were deemed to be issued for no consideration in respect of options.
(4) Short-term investments are bank-sponsored investments and other high
credit rating instruments which are current in nature, with an
initial maturity greater than three months when purchased and which
are not redeemable at face value on demand.
(5) Working capital is a non-IFRS measure and is calculated as current
assets less current liabilities. Working capital is used to assess
liquidity and general financial strength. Working capital does not
have a standardized meaning prescribed by IFRS. It is unlikely for
non-IFRS measures to be comparable to similar measures presented by
other companies. Working capital should not be considered an
alternative to, or more meaningful than current assets or current
liabilities as determined in accordance with IFRS.
Revenue
For the year ended December 31, 2012, the Company reported gross oil sales revenue of $53,795,419 and net oil sales revenue, after deducting royalties, of $46,207,873 compared to net oil sales revenues, after deducting royalties, of $8,887,511 for the year ended December 31, 2011 - this represents an increase in net oil sales revenues of 420%. The increase in oil sales revenue in 2012 is a result of increased oil production and higher average sales prices.
Net Loss
The Company reported net loss attributable to owners of the Company of $12,500,031 or $0.06 per share for 2012 compared to $16,740,226 or $0.09 per share for 2011.
Operating Netback and Cash Flow
Operating netback for 2012 was $35,608,189 ($50.11 per barrel) compared to $5,830,721 ($30.60 per barrel) during 2011. This improvement of $29,777,468 represents an increase of 511%.
With respect to funds flow from operations, the Company generated an inflow of $21,743,731 during the year ended December 31, 2012 compared to an outflow of $4,032,282 during the same period of 2011. 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.
During the year ended December 31, 2012, the Company generated $9.8 million of cash from operating activities (which includes changes in non-cash balance sheet operating items), compared to 2011 when the Company used $1.0 million in operating activities (which includes changes in non-cash balance sheet operating items). The cash inflow in 2012 is attributable primarily to increased gross profit from oil sales (excluding non-cash depletion and depreciation). With respect to investing activities, the Company spent $75.9 million on capital expenditures in the year ended December 31, 2012, compared to $29.3 million spent in 2011. The increase in capital spending focused on increasing production at the Company's conventional operations, particularly Medanito Sur, as well as acquisition and exploration activities pertaining to the Company's unconventional blocks.
Financial Position
As of December 31, 2012, the Company has a cash position (including cash, cash equivalents and short-term investments) of $58.2 million. The December 31, 2012 statement of financial position shows higher current assets. Accounts receivable has increased as a result of increased oil sales and accrual of Oil Plus benefits. The Company's reported exploration and evaluation assets have increased in 2012, net of impairment loss, as a result of continuing activities in Argentina and Peru. The Company's reported property, plant and equipment has increased, net of depletion and impairment loss, primarily as a result of continuing activities on the Medanito Sur block. During 2012, the Company recognized deferred tax assets related to its operations in Argentina. During 2012, the Company settled US$18.95 million of promissory notes.
For further information regarding the Company's financial results, financial position and related changes, please see the consolidated financial statements and the related MD&A.
Additional Information on Unconventional
-- Aguada Los Loros: In 2012, the Aguada Los Loros (ALL.x-1) well, on the
Los Toldos I block (98,300 gross acres or 398 square kilometers or 154
sections), was drilled and subsequent to year-end, in early 2013, a
four-stage hydraulic stimulation program was performed in the Vaca
Muerta shale formation (562 meters or 1,843 feet thick). The well
discovered gas and natural gas liquids. The initial production of the
Vaca Muerta shale formation, after the clean-up flow back, at depths
between 2,570 to 2,929 metres (8,432 to 9,609 feet), increased from 1.3
million cubic feet (36,738 cubic meters) per day to 3.2 million cubic
feet (90,418 cubic meters) per day of natural gas with 9 to 18 barrels
of oil per day condensate (54-58 degree API) on managed choke sizes (4-
6mm). Testing was conducted over a period of approximately 20 days with
high well-head pressure throughout. The well-head pressure declined
normally during flow testing. This, in addition to core and other
studies, will help the broad evaluation of the future productivity and
the potential of the well and the reservoir. Currently the well is shut-
in for a Pressure Build-up test but an option is available to connect
the well to a nearby regional gas pipeline for long-term testing and
possible future production. Hydrocarbon shows were also encountered and
data acquired in the following formations: lower Agrio, Mulichinco,
Quintuco and Tordillo.
-- Los Toldos Este: A five-stage hydraulic stimulation program was
performed in the Vaca Muerta shale formation (343 metres or 1,125 feet
thick) on the Los Toldos Este (LTE.x-1) well, on the Los Toldos II block
(38,400 gross acres or 155 square kilometers or 60 sections). The
initial flow rate of the Vaca Muerta shale formation, after the clean-up
flow back, at depths between 2,795 to 3,065 metres was 797 barrels of
oil equivalent per day (boepd) of which 694 barrels of oil per day
(bopd) was high quality light sweet oil, 39.6 degrees API. The average
flow rate for the initial 30 days was 309 boepd, of which there was 254
bopd. Two production flow tests were also conducted to determine the
productivity of the perforated intervals. This, in addition to core and
other studies, will help the broad evaluation of the future productivity
and the potential of the well and the reservoir. The well is currently
on a long-term production test. Hydrocarbon shows were also encountered
and data acquired in the following formations: Upper Agrio, Lower Agrio,
Mulichinco, Quintuco and Tordillo.
-- Agua de Afuera: Drilling of the Agua de Afuera (ADA.x-1) well, on the
Los Toldos II block, reached total depth ("TD") in late 2012. The well
drilled through 340 meters or 1,115 feet of the primary target Vaca
Muerta shale formation with oil and gas shows through most of this shale
section. Hydrocarbon shows were also encountered in secondary targets
such as the Agrio, Quintuco and Tordillo. The ADA.x-1 well was drilled
to a TD of 3,448 meters or 11,311 feet. A complete suite of logs has
been run and conventional and side wall cores were cut and recovered.
Casing has been successfully set and cemented to a TD of approximately
3,442 meters or 11,290 feet in preparation for a planned well test.
Detailed analysis of the cores and cuttings at international service
company laboratories in Argentina and in the USA is ongoing. The ADA.x-1
well is located approximately 9 kilometers west of the LTE.x-1
unconventional, shale well.
-- La Hoya: The La Hoya (LHo.x-1) well, located on the Company's Totoral
block in the southwestern region of the Neuquen Basin, was drilled
(approximately 1,900 metres total depth), cased and cemented in mid-
2012. It intersected the Vaca Muerta Shale formation with thickness of
203 metres or 666 feet with oil and gas shows through the whole shale
column. During drilling, hydrocarbon shows were also encountered and
data acquired in the Mulichinco, Quintuco, and Quebrada del Sapo
formations. Early in 2013, the Company reported the discovery of light
oil related to this well. The LHo.x-1 well drilled and established oil
production from the Vaca Muerta Shale in a new and large region, the
Picun Leufu Sub-Basin, which extends over much of the Company's three
southernmost blocks -- Totoral, Yerba Buena and Bajada Colorada
(1,126,600 acres or 4,559 square kilometres or 1,760 sections). In
January 2013, a three-stage hydraulic stimulation program was performed
in the Vaca Muerta shale formation. After the initial clean-up flow
back, the well produced through an electrical submersible pump during a
20-day test period at a total liquid rate of 300 to 600 barrels per day
(bpd) which included 30 to 60 barrels of oil per day (bopd) of high
quality light sweet oil, 33 degrees API gravity. During this test
period, the well did not show any rate decline. The LHo.x-1 well is
currently being tested to determine the fluid contribution of each
interval that was hydraulically stimulated. As well, core analysis and
studies are still in progress.
The Company will post an updated investor presentation to its website later this week.
About Americas Petrogas Inc.
Americas Petrogas Inc. is a Canadian company whose shares trade on the TSX Venture Exchange under the symbol "BOE". Americas Petrogas has conventional and unconventional shale oil and gas and tight sands oil and gas interests in numerous blocks in the Neuquen Basin of Argentina. Americas Petrogas has joint venture partners, including ExxonMobil and Apache, on various blocks in the shale oil and gas corridor in the Neuquen Basin, Argentina. Americas Petrogas also owns an 80% interest in GrowMax Agri Corp., a private company involved in the exploration for near-surface potash, phosphates and other minerals, and potential development of a fertilizer project in Peru. Indian Farmers Fertiliser Co-operative Limited (IFFCO) owns a 20% interest in GrowMax Agri Corp. For more information about Americas Petrogas Inc., please visit www.americaspetrogas.com.
This Press Release contains forward-looking information including, but not limited to, the Company's goals and growth, estimates of reserves, production and cash flows, new fields in the Medanito Sur block, testing and production of the ALL.x-1 well on the Los Toldos I block, connecting of the ALL.x-1 well to a regional gas pipeline, testing and production of the LTE.x-1 well on the Los Toldos II block, testing of the ADA.x-1 well on the Los Toldos II block, testing of the LHO.x-1 well on the Totoral block, advancement of the Company's phosphates project in Peru, the potential for phosphates and other minerals on the recently staked concession land in the Sechura Desert, exercising and pending approval of the option to acquire an interest in the Bayovar concession, analysis and testing of the cores in respect of the 19-borehole drilling program on the southeastern block at Bayovar, exploration, appraisal and development activities related to conventional oil and gas, drilling of unconventional wells on the Loma Ranqueles block and the Totoral-Yerba Buena-Bajada Colorada concession, additional drilling and testing in 2013, and other exploration, development and production activities in respect of the projects in Argentina and Peru. There can be no assurance that the Company will successfully exercise the option to acquire an interest in the Bayovar concession. Additional forward-looking information is contained in the Company's Annual MD&A for December 31, 2012, and reference should be made to the additional disclosures of the assumptions, risks and uncertainties relating to such forward-looking information in that MD&A document.
Forward-looking information 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 (including the timing, location, depth and the number of wells), environmental matters, business prospects and opportunities and expectations with respect to general economic conditions. Such forward-looking information reflects management's current beliefs and assumptions and is based on information, including reserves information, currently available to management. Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by the forward-looking information, including but not limited to, risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production, delays or changes to plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of geological interpretations; the uncertainty of estimates and projections in relation to production, costs and expenses and health, safety and environment risks), the risk of commodity price and foreign exchange rate fluctuations, the uncertainty associated with negotiating with foreign governments and third parties located in foreign jurisdictions and the risk associated with international activity.
Although the forward-looking information contained herein is based upon assumptions which management believes to be reasonable, the Company cannot assure investors that actual results will be consistent with this forward-looking information. This forward-looking information is made as of the date hereof and the Company assumes no obligation to update or revise this information to reflect new events or circumstances, except as required by law. Because of the risks, uncertainties and assumptions inherent in forward-looking information, prospective investors in the Company's securities should not place undue reliance on this forward-looking information.
Any references in this Press Release 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.
Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading.
The Company's reserve estimates have been prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Accordingly, the Company classifies its reserves as proved, probable or possible. Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable - it is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves - it is equally likely that the actual remaining quantities recovered will be greater or less than the sum of estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves - it is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered.
NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THE RELEASE.
Contacts:
Americas Petrogas Inc.
Barclay Hambrook P. Eng., MBA
President and CEO
(403) 685-1888
inquiries@americaspetrogas.com
www.americaspetrogas.com
