Argosy Energy Inc.
TSX : GSY

Argosy Energy Inc.

August 06, 2009 19:47 ET

Argosy Energy Inc. Announces 2009 Second Quarter Results

CALGARY, ALBERTA--(Marketwire - Aug. 6, 2009) - ARGOSY ENERGY INC. ("Argosy") (TSX:GSY), a junior energy company focused on the acquisition, exploration, exploitation and development of oil and natural gas in Western Canada is pleased to announce the results of its second quarter 2009 operations.



Highlights

3 Months 3 Months
Ending Ending
$ Thousands except production/day June 30, June 30,
and common share information 2009 (1) 2008 (1)
----------------------------------------------------------------------------
Cash flow - (Non-GAAP)
Total 86 3,030
Per share basic 0.015 0.745
Net income (loss)
Total (1,726) 356
Per share basic (0.30) 0.09
Per share diluted (0.30) 0.08
Common shares outstanding 5,858,834 4,067,951
Debt, including working capital
deficiency before fair value of
derivatives (26) (44)
Operational :
Sales 2,255 6,019
Royalties 305 1,262
Operating and transportation costs 587 458
Field Net Back (2) 1,363 4,299
Net Back/ bbl (2) 16.03 51.88
General and administrative 1,097 528
Volumes :
Natural gas (mcf/d) 4,921 4,882
Oil (bbl/d) 29 11
NGL's (bbl/d) 86 86
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Total Boe/d 935 911
----------------------------------------------------------------------------
Wells Drilled (Gross) :
Oil - -
Gas - 1
D&A - -
----------------------------------------------------------------------------
Total - 1
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Capital Expenditures 608 8,707

Notes:
(1) Includes figures presented on a continuity of Interests basis.
(2) Argosy's definition of cash flow and/or netbacks may not be comparable
to that reported by other companies. See the caption Non GAAP Measures.


Management Discussion and Analysis

The following discussion and analysis was prepared on August 5, 2009 and is management's assessment of Argosy's historical financial and operating results and should be read in conjunction with the audited financial statements and related notes for the years ended, December 31, 2008 and 2007.

The financial data presented has been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). Comparative figures for periods ending prior to the closing date of the Arrangement September 30, 2008 are presented in accordance with continuity of interest guidelines as if the assets acquired by Argosy had always operated as a stand-alone entity.

The reporting and measurement currency is the Canadian dollar.

Argosy Energy Inc. was formed pursuant to a Plan of Arrangement between Accrete Energy Inc. ("Accrete"), Pengrowth Energy Trust, Pengrowth Company, Pengrowth Energy Partnership and Argosy ("the Arrangement") on September 30, 2008 and is a junior energy company focused on the acquisition, exploration, exploitation and development of oil and natural gas in Alberta in western Canada.

Additional information may be found on the Company's web site at www.argosyenergy.com and on the SEDAR web site at www.sedar.com.

Argosy's shares trade on the Toronto Stock Exchange ("TSX") under the symbol GSY.

The Plan of Arrangement

Argosy was inactive from the time of its incorporation to September 30, 2008 at which time, and pursuant to the Arrangement, Argosy acquired certain assets, including producing and exploratory oil and gas properties and certain tax pools from Accrete. Reference should be made to the Accrete Energy Inc. Management Information Circular dated September 2, 2008 (the "Circular") available at www.sedar.com for further details.

Accrete shareholders, pursuant to the Arrangement, received one quarter of a share of Argosy for each Accrete share held and, provided that the applicable shareholder was not an insider of Accrete as contemplated by applicable securities laws, one eighth of a warrant to acquire an Argosy share at an exercise price of $4.60 per share.

A total of 4,494,667 common shares of the Company were issued to former Accrete shareholders in connection with the exchange of Argosy common shares for Accrete common shares pursuant to the Arrangement.

No Argosy warrants were exercised prior to their expiry date.

At Claresholm, pursuant to the Arrangement, Argosy acquired 16 (13.6 net) natural gas wells, 3 (3 net) oil wells, 3 (2.6 net) potential natural gas wells, 12,682 net undeveloped acres, 47 square kilometers of 3D seismic over such lands, gathering and sales pipelines and a 75% working interest in a natural gas processing facility. Argosy also acquired 1 (.6 net) well that was in the process of being drilled. Argosy targets the Bow Island, Glauconite, Sunburst and Barons formations at depths of 2,000 to 2,300 meters in this area.

At Saxon, pursuant to the Arrangement, Argosy acquired 1 (1 net) producing natural gas well, 15,840 net undeveloped acres together with 36 square miles of 3D seismic and 20 kilometers of 2D seismic over the lands acquired.

At Edson, pursuant to the Arrangement, Argosy acquired 4 (4 net) natural gas wells, 2 of which are producing and 2 of which are still to be ties in together with 6,400 net undeveloped acres of land. Argosy also acquired various interests in the Atlee Buffalo, Peco, Caroline and Saddle Hills areas pursuant to the Arrangement which would be classified as minor miscellaneous interests.

On September 30, 2008 and concurrent with the closing of the Arrangement, Argosy issued 1,208,051 flow through shares at an issue price of $5.20 per share and 156,116 common shares at an issue price of $4.60 per share by way of private placement to certain Argosy directors, officers, employees and consultants for total gross proceeds of $6,999,999.

At June 30, 2009, there are 5,858,834 common shares outstanding.

These financial statements present the historical financial position, results of operations and cash flow of Accrete for periods prior to the closing date of the Arrangement on a carve-out basis following continuity of interest guidelines as if the assets acquired by Argosy had always operated as a stand-alone entity.

The historical financial data for periods prior to the closing date of the Arrangement presented herein was extracted from the books and records of Accrete.

Certain financial statement items were maintained by Accrete at a corporate rather than on a property-by-property basis and accordingly, it was necessary to make allocations of amounts reported.

Going Concern

The unaudited interim financial statements have been prepared by management on a going concern basis in accordance with Canadian generally accepted accounting principles. The going concern basis of presentation assumes that the Company will continue in operation for the foreseeable future and be able to realize its assets and discharge its obligations in the normal course of business. Recent market events, including disruptions in credit markets and other financial systems and the deterioration of global economic conditions have resulted in significant declines in commodity prices. At June 30, 2009, the Company has a working capital deficiency of $25,958,000 million including bank loans outstanding of $25,823,000 million in relation to the available demand operating facility of $26 million. The available borrowing limits of the $28 million in total available credit facilities are based on the Bank's interpretation of the Company's reserves and future commodity prices of which there can be no assurance that such amount will not decrease at the next scheduled review to be completed on or before October 1, 2009.

Management has restricted capital, non-essential expense and administrative spending and continues to pursue alternative financing opportunities to supplement cash flow to fund its future prospects and commitments (See Contractual Obligations). Bank debt has been reviewed and the credit renewed by Argosy's bank but no other arrangements have been made as of yet nor can it be assured that such arrangements can or will be made. However, management believes that the financing initiatives that it has undertaken may mitigate the conditions and events which could raise doubt about the validity of the going concern assumption used in preparing these unaudited interim financial statements. If the going concern assumption were not appropriate, adjustments might be necessary to the carrying values of assets and liabilities, the reported revenues and expenses and the balance sheet classifications used.

Forward-Looking Statements

Certain statements included or incorporated herein constitute forward-looking statements. These statements relate to future events or the future performance of Argosy Energy Inc. ("Argosy"). All statements other than statements of historical fact are forward-looking.

Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "continue", "might", "may", "will", "should", "could", "anticipate", "believe", "expect", "intend", "plan", "estimate" "budget", "forecast", "predict", "project", "potential", or the negative of these terms and similar expressions. In addition, these financial statements and accompanying management discussion may contain forward-looking statements attributed to third party industry sources. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.

Forward-looking statements include, but are not limited to, statements with respect to: The performance characteristics of Argosy's oil and natural gas properties; oil and gas production levels; the quantity of oil and natural gas reserves; the performance characteristics of oil and natural gas properties; projection of market prices; other trends of the capital markets; the size of and future net revenues from Argosy's oil and natural gas reserves; capital expenditure programs; supply and demand for oil and natural gas and commodity prices; financial conditions; industry conditions; capital expenditure programs; drilling plans; expectations regarding the Argosy's ability to raise capital and to continually add to reserves through acquisitions, exploration and development; treatment under governmental regulatory regimes and tax laws; and realization of the anticipated benefits of acquisitions and dispositions.

Some risks and other factors, which would cause results to differ materially from those expressed in the forward-looking statements contained in these financial statements and accompanying management discussion, but are not limited to: general economic conditions in Canada, the United States and globally; industry conditions, including fluctuations in the price of oil and natural gas; governmental regulation of the oil and gas industry, including environmental regulation; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; volatility of commodity prices; environmental risks; fluctuation in foreign exchange or interest rates; liabilities inherent in oil and gas operations; geological, technical, drilling and processing problems; unanticipated operating events which can reduce production or cause production to be shut in or delayed; failure to obtain industry partner and other third party consents and approvals, when required; stock market volatility and market valuations; competition for, among other things, capital, acquisitions of reserves, undeveloped land, skilled personnel, and equipment and facilities; the need to obtain required consents, permits or approvals from regulatory authorities; competition for, among other things, capital, acquisition of reserves, undeveloped land, skilled personnel and equipment and facilities; the lack of availability of qualified personnel or management; uncertainties associated with estimating oil and natural gas reserves; aboriginal land claims; Stock market volatility, and the other factors considered under "Risks".

Readers are cautioned that the foregoing lists should not be considered to be exhaustive. Readers are also cautioned that these factors and risks are difficult to predict and that the preparation of financial statements in accordance with Canadian GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Forward-looking statements and other information contained herein concerning the oil and gas industry and Argosy's general expectations concerning this industry are based on estimates prepared by management using data from publicly available industry sources as well as from reserve reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which Argosy believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While Argosy is not aware of any misstatements regarding any industry data presented herein, the industry involves risks and uncertainties and is subject to change based on various factors.

Although the assumptions used in the preparation of such information and statements are considered reasonably accurate by the Company at the time of preparation may prove to be incorrect. Accordingly, readers are cautioned that the actual results achieved will vary from the information provided herein and the variations may be material.

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 reserves and resources described can be profitably produced in the future.

Investors should not place undue reliance on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. These forward-looking statements are made as of the date of this or as of the date specified in the documents incorporated by reference into the financial statements and accompanying management discussion., as the case may be.

Non GAAP Measures

This MD&A contains the term "cash flow" and "netbacks" which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") as an indicator of the Company's performance. Argosy's definition of cash flow and/or netbacks may not be comparable to that reported by other companies.

The Company evaluates its performance based on net earnings, net back and cash flow from operations.

The Company considers cash flow a key measure as it illustrates the Company's ability to meet obligations necessary to repay debt and fund future growth through capital investment. Cash flow per share is presented using the weighted average shares outstanding in a manner consistent with that used to calculate earnings per share.

The following reconciles cash flow from operating activities, the most comparable GAAP measure to cash flow used in this MD&A:



$ Thousands 3 Months Ended 6 Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash flow provided by operating
activities (GAAP) (466) 1,134 (526) 5,201
Net changes in non-cash working
capital 552 1,896 1,036 405
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Cash flow (non - GAAP) 86 3,030 510 5,606
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The following table reconciles field and corporate netback to income before
taxes the most comparable GAAP measure:

3 Months Ended Six Months Ended
$ Thousands June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Net income and comprehensive income
(GAAP) (1,726) 356 (3,216) 1,099
Future income taxes (recovery) (535) 125 (956) 385
Depletion, depreciation and
accretion 1,934 1,981 4,137 3,522
Stock based compensation expense 124 18 248 50
Interest expense 258 601 462 1,202
Realized (gain)/loss on derivative
instruments (70) 140 (70) 140
Unrealized loss on derivative
instruments 281 550 281 550
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Corporate netback (non - GAAP) 266 3,771 886 6,948
General and administrative expense 1,097 528 2,109 818
----------------------------------------------------------------------------
Field netback (non - GAAP) 1,363 4,299 2,995 7,766
----------------------------------------------------------------------------


The reader is cautioned that the use of the term boe's ("barrels of oil equivalent") may be misleading particularly when used in isolation. A boe conversion of 6 mcf to 1 boe may not represent a value equivalency at the wellhead.

As the determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these financial statements requires the use of estimates and assumptions which have been made using careful judgment. In the opinion of management, the unaudited interim financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized in the financial statements.

Business Environment

Cold weather in the consuming regions during the first quarter of 2008 resulted in large withdrawals from storage to feed the increased demand for natural gas for heating and power generation. This, together with reduced supply, and rising oil prices resulted in an increase in the price of natural gas in the first half of 2008.

Near the end of the third quarter of 2008, the upward trend in natural gas prices that had occurred in the first half of 2008 reversed abruptly. Natural gas prices steadily declined through the first quarter of 2009. Natural gas prices that had previously decreased in tandem with the decrease in oil prices failed to rebound with the uptick in oil prices in the first half of 2009. A strong growth in natural gas production particularly from shale and tight gas drilling in the U.S., large storage injections, moderate weather and shrinking industrial demand caused by the global financial turmoil contributed to the weakening of natural gas prices.

For the first half of 2008, oil prices remained volatile because of geopolitical tension overseas but strong demand growth in Asia and a weakened US dollar caused them to trend upward to record levels. That trend reversed itself in the last quarter of 2008 as the global credit crisis emerged. Fears of a world wide recession became a reality and demand for oil was diminished resulting in price weakness. Oil prices rebounded somewhat in the first half of 2009 in response to OPEC cutbacks and various geopolitical events.

The hangover from the global credit crisis that erupted in the third quarter of 2008 lingers and has caused capital markets to be virtually inaccessible to junior oil and gas producers while the banks rigorously assess credit risks and tighten lending policies.

These factors have negatively impacted company valuations and have negatively impacted the amount of capital investment in natural gas drilling in particular.



Financial Information

Net
Net Income Net Income Income(Loss)
Total Revenue (Loss) (Loss) Diluted
($ thousands) ($ thousands) Basic $/Share $/Share
----------------------------------------------------------------------------
2009
First Quarter 3,215 (1,490) (0.25) (0.25)
Second Quarter 2,255 (1,726) (0.30) (0.30)
----------------------------------------------------------------------------
2008 (1)
First Quarter 4,728 743 0.18 0.17
Second Quarter 6,019 356 0.09 0.08
Third Quarter 5,282 284 0.07 0.07
Fourth Quarter 4,767 (1,337) (0.23) (0.23)
----------------------------------------------------------------------------
Total 20,796 46 0.01 (0.01)
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2007 (1)
First Quarter 2,116 246 0.06 0.06
Second Quarter 3,029 1,041 0.25 0.24
Third Quarter 4,950 319 0.08 0.07
Fourth Quarter 4,694 (581) (0.14) (0.14)
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Total 14,789 1,025 0.25 0.23
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(1) Figures for the quarters ending prior to September 30, 2008 were carved
out from the financial information of Accrete Energy Inc.


Production
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Oil (bbl/d) 29 11 29 5
NGL (bbl/d) 86 86 97 94
----------------------------------------------------------------------------
Total Oil/NGL (bbl/d) 115 97 126 99
Gas (mcf/d) 4,921 4,882 5,197 4,899
----------------------------------------------------------------------------
Total (boe/d) 935 911 992 916
----------------------------------------------------------------------------


Natural Gas Production (mcf/d)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Atlee-Buffalo 29 46 31 43
Claresholm 4,482 4,291 4,711 4,228
Edson 294 370 325 443
Saxon 116 175 130 185
----------------------------------------------------------------------------
Total 4,921 4,882 5,197 4,899
----------------------------------------------------------------------------


Crude Oil Sales (bbl/d)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------

Claresholm 29 11 29 5
----------------------------------------------------------------------------
Total 29 11 29 5
----------------------------------------------------------------------------


Natural Gas Liquids Sales (bbl/d)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------

Claresholm 75 73 82 74
Edson 10 12 14 19
Saxon 1 1 1 1
----------------------------------------------------------------------------
Total 86 86 97 94
----------------------------------------------------------------------------


Production volumes increased due to drilling and acquisition activity at Claresholm in 2008 and early 2009. In 2008, 7 (5.4 net) natural gas wells were drilled in that area. All but 1were put on stream by year end. 3 (1.2 net) wells were purchased from an industry partner. 1 well (.6 net) was drilled in 2009 and it was not put on stream until the second quarter 2009. The effect of the production increases brought about by drilling was offset in part by natural declines and by curtailments at non operated facilities at Edson and Saxon.

Oil production increased because 3 (3 net) oil wells were drilled in the new Barons oil project that was initiated in the Claresholm area in the third quarter of 2008. Argosy believes that this project is extensive but the project will entail water flooding to realize its full potential. Drilling on this project was initially limited soon after the project was initiated due to the decrease in oil prices and remains limited due to capital constraints.

Natural gas liquids production is up due to drilling activity, offset in part by natural declines.

Product Prices

Natural Gas Prices ($/mcf)



3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------

Atlee-Buffalo 3.49 9.79 4.33 9.07
Claresholm 3.84 11.34 4.68 10.05
Edson 3.94 11.64 4.65 9.84
Saxon 3.93 11.80 4.82 10.36
----------------------------------------------------------------------------
Average Price 3.85 11.36 4.68 10.03
----------------------------------------------------------------------------


In 2009, AECO daily index prices averaged $4.29/mcf for the first quarter, $3.44/mcf for the second quarter and $4.20 for the half. That compares with $7.82, $10.15 and $8.98 for the same periods in 2008. The surge in prices enjoyed in 2008 was quashed by strong growth in natural gas supply particularly from shale and tight gas drilling in the U.S., large storage injections, moderate weather and shrinking industrial demand caused by the global financial turmoil. Liquids are recombined to Company production giving it a higher heating content resulting in a premium price being received. The liquids storage facility at the Claresholm gas processing facility allows the Company to sell some of the natural gas liquids that would otherwise be recombined. Thus, the premium enjoyed at Claresholm is not quite as large as at Saxon and Edson.

Crude Oil Sales Prices ($/bbl)



3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Claresholm 63.75 117.88 55.14 129.67
----------------------------------------------------------------------------
Average Price 63.75 117.88 55.14 129.67
----------------------------------------------------------------------------


The oil stream in 2009 is comprised of more conventional oil production from the Company's new Barons oil project at Claresholm. These wells were put on stream later in the third quarter of 2008 missing the record prices that were enjoyed earlier in the year.

Natural Gas Liquids (NGL) Sales Prices ($/bbl)



3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Claresholm 45.07 105.22 43.17 93.18
Edson 58.45 108.06 49.19 90.80
Saxon 68.37 120.88 64.89 137.36
----------------------------------------------------------------------------
Average Price 46.87 105.80 44.28 93.17
----------------------------------------------------------------------------


Natural gas liquid prices moved in tandem with oil prices. Saxon natural gas
liquids contain more condensate than those in Edson and Claresholm, and
thereby command higher prices.


Revenue
Total Sales
($ thousands)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil 165 118 292 118
NGL 367 828 776 1,594
Gas 1,723 5,050 4,402 8,947
Processing - 23 - 88
----------------------------------------------------------------------------
Total 2,255 6,019 5,470 10,747
----------------------------------------------------------------------------


Natural Gas Sales Revenue ($ thousands)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Atlee-Buffalo 9 41 24 71
Claresholm 1,566 4,429 3,991 7,733
Edson 105 392 274 794
Saxon 43 188 113 349
----------------------------------------------------------------------------
Total 1,723 5,050 4,402 8,947
----------------------------------------------------------------------------

The decrease in natural gas sales revenue is due to decreased prices offset
in part by increased production.


Crude Oil Sales Revenue
($ thousands)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Claresholm 165 118 292 118
----------------------------------------------------------------------------
Total 165 118 292 118
----------------------------------------------------------------------------


Production from the new oil wells that were drilled and put on stream caused
oil revenues to increase. This was partially offset by a decrease in prices.

Natural Gas Liquids (NGL) Sales Revenue
($ thousands)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Claresholm 308 699 640 1,255
Edson 53 118 123 314
Saxon 6 11 13 25
----------------------------------------------------------------------------
367 828 776 1,594
----------------------------------------------------------------------------

The decrease in natural gas liquids sales revenue is due to decreased
prices.

Processing Revenue
($ thousands)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Area
Claresholm - 23 - 88
----------------------------------------------------------------------------
Total - 23 88
----------------------------------------------------------------------------


Processing fees were charged to third parties utilizing Argosy facilities.
Argosy bought out its partner in the Claresholm wells from which it derived
processing revenue.


Royalties ($ thousands)

3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Area Total Rate Total Rate Total Rate Total Rate
$ $ $ $
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Atlee-Buffalo - (4)% 2 5% 1 4% 9 13%
Claresholm 322 16% 1,170 22% 1,095 22% 1,991 22%
Edson (13) (9)% 55 11% 79 20% 116 5%
Saxon (4) (7)% 35 18% 22 18% 53 14%
----------------------------------------------------------------------------
Total 305 14% 1,262 21% 1,197 22% 2,169 20%
----------------------------------------------------------------------------


The figures for the 3 month period ended June 30, 2009 include adjustments to prior period crown royalties that were booked in the current quarter. These adjustments related to gas cost allowance.

For the first half 2009, crown royalties were $1,152,000 ($2,054,000 in 2008). Total gross overriding royalties were $38,000($115,000 in 2008), and freehold royalties totaled $7,000($0 in 2008).



Production and Transportation Expenses ($ thousands except per boe
information)

3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Area Total $/boe Total $/boe Total $/boe Total $/boe
$ $ $ $
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Atlee-Buffalo 5 12.74 12 18.62 8 8.29 17 13.04
Claresholm 483 6.23 303 4.17 1,078 6.64 518 3.63
Edson 87 16.14 115 17.15 164 13.20 224 13.26
Saxon 12 6.34 27 9.83 28 6.90 53 9.15
----------------------------------------------------------------------------
Total 587 6.85 457 5.51 1,278 7.09 812 4.87
----------------------------------------------------------------------------


Field compression and plunger lifts were added in the third quarter 2008 for certain wells at Claresholm. Maintenance and repair costs at Claresholm have increased because the wells and natural gas processing plant require more attention as they age. Oil production at Claresholm is trucked, adding to transportation expenses for that area.

Saxon and Edson natural gas is processed by third party processors. Production expenses at Edson are higher than at Saxon because the rate charged for processing and transportation charges in respect to pipeline tariffs are higher at Edson. Property taxes were booked in the second quarter at Edson causing the per barrel rate to increase.

Atlee-Buffalo is not operated by Argosy. Production and transportation expense for that area includes charges by the operator.

Because production from Atlee-Buffalo, Edson and Saxon is from only a few wells, Argosy can not achieve the economies of scale that it can at Claresholm. It should be noted too, relatively small one time charges can skew the per barrel rate significantly.

Field and Corporate Netbacks



Field Netback
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$/boe
Atlee-Buffalo 8.96 38.68 16.72 34.51
Claresholm 15.96 52.20 16.95 46.87
Edson 16.14 50.72 13.20 45.45
Saxon 21.12 49.93 18.40 46.25
----------------------------------------------------------------------------
Field Netback 16.03 51.88 16.67 46.60
----------------------------------------------------------------------------


Field netbacks for the first quarter 2009 decreased from those enjoyed in the equivalent period last year primarily because of decreased commodity prices. The decrease was exacerbated by an increase in operating costs offset in part by a decrease in royalties.



Corporate Netback
($ thousands)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field Netback 1,363 4,299 2,994 7,766
General and
Administrative 1,097 528 2,109 818
----------------------------------------------------------------------------
Corporate Netback 266 3,771 885 6,948
----------------------------------------------------------------------------


Field netbacks for the first quarter 2009 decreased from those enjoyed in the equivalent period last year because of decreased commodity prices and increased operating costs.

General and administrative expenses for the period ended June 30, 2009, were carved out of the general and administrative costs of Accrete. General and administrative expenses were allocated to the Company based on the ratio of production volumes from the properties that were carved out to Argosy to the total production volumes of Accrete prior to the Arrangement. Effective October 1, 2008, Argosy bore all of the overhead that had formerly been incurred by Accrete because it retained all of the employees and assumed the office space and other normal administrative costs of Accrete. Accordingly, the comparison of corporate net back between periods is not meaningful.



General and Administrative Expense
($ thousands)
3 Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Salary & Benefits 656 302 1,293 516
General Office Expenses 466 267 880 393
----------------------------------------------------------------------------
1,122 569 2,173 909
Recoveries (25) (41) (64) (91)
----------------------------------------------------------------------------
Total 1,097 528 2,109 818
----------------------------------------------------------------------------


General and administrative expenses for the first quarter of 2008 were carved out of the total general and administrative expenses of Accrete. The general and administrative expenses that were incurred by Accrete were allocated between Argosy and Accrete on basis of relative production volumes.

Effective October 1, 2008, Argosy bore all of the overhead that had formerly been incurred by Accrete because it retained all of the employees and assumed the office space and other normal administrative costs of Accrete. Accordingly, the comparison between the 2008 and 2009 figures is not meaningful.

Approximately $154,000 ($208,000 in 2008) of direct salary costs related to geological and geophysical personnel have been capitalized.

Interest Expense

Argosy utilized its operating line of credit and cash flow to fund its 2008 capital program.

Interest expense for periods ending prior October 1, 2008 is similar to general and administrative expense in that it was carved out of that which was incurred by Accrete. The carve out, in this case, was based on the relative cash requirements for the carved out properties relative to the total cash requirements of Accrete. The Arrangement imposed a formula for the calculation of the bank debt assumed by Argosy that had no relation to the historical funding requirements for the properties that were carved out.

As such, a comparison between the 2008 and 2009 figures is not meaningful.

Stock-Based Compensation

Stock-based compensation is accounted for using the fair value method. Under the fair value method of accounting, this compensation expense is recorded in the earnings statement over the vesting period.

The fair value of the options granted to June 30, 2009 was estimated to be $ 1,175,000 ($2.03 per option granted).

This value is charged to stock based compensation cost over the vesting period. A total of $132,000 of stock based compensation was incurred in the six months ended June 30, 2009. Of this, $124,000 was charged to expense and $8,000 was capitalized. A total of $50,000 was incurred in the six months ended June 30, 2008 but, that figure was based on an allocation similar to that for general and administrative expenses and, as such, the comparison between the 2008 and 2009 figures is not meaningful.

Depletion Depreciation & Accretion

Depletion, depreciation and accretion of the asset retirement obligation for the three month period ended June 30, 2009 totaled $1,934,000 or $22.70/Boe. The figure for the previous year was calculated on a carve out basis and is not directly comparable. The rate for the quarter ended June 30, 2009, compares with the 3 month period ended March 31, 2009 which was $23.29/Boe and the 3 months ended December 31, 2008 which was $23.34/Boe.

Costs of $8,865,000 ($8,726,000 in 2008) relating to unproved properties have been excluded from costs subject to depletion for the 6 month period ended June 30, 2009. This included the costs of undeveloped land such as that at Ansell and Saxon that has been purchased at land sales for future exploitation.
A total of $1,713,000 ($1,480,000 in 2008) related to future development costs were included in the depletion calculation.

Income Taxes

The Company recorded an income tax recovery of $941,000 for the period ended June 30, 2009.

Argosy has approximately $36,300,000 million of income tax pools and $577,000 of operating loss carry forwards at June 30, 2009 and does not anticipate being cash taxable in 2009.

Cash Flow

Cash flow from operations for the 6 months ended June 30, 2009 was $564,000 ($0.10 per share) versus $ 5,606 ($0.96 per share) for the equivalent period last year. The decrease in cash flow occurred partly because of reduced production volumes but primarily because of reduced commodity prices.



Capital Expenditures

($ thousands) 3 Months 3 Months 6 Months
Ended Ended Ended
March 31, June 30, June 30,
2009 2009 2009
$
----------------------------------------------------------------------------
Drilling and Completions (218) (38) (256)
Geology and Geophysical 108 670 778
Equipping and Tie-Ins 346 (87) 259
Land 184 62 246
Office Equipment 10 1 11
----------------------------------------------------------------------------
Total Cash Expenditures 430 608 1,038
----------------------------------------------------------------------------


The credit balance in drilling and completions arises because of the reversal of an over accrual for expenditures in the previous quarter. The Company has resolved to exercise restraint in connection with capital expenditures. During the first quarter 2009 the Company drilled 1 gas well (0.6 net). A success rate of 100% was achieved.



Liquidity and Capital Resources

$
(thousands)
--------------
2009 Exploration and development program funding

Cash, Beginning of period -
Cash flow 572
Change in non-cash working capital (2,594)
Increase in Bank Debt 3,060
Cash, end of period -
----------------------------------------------------------------------------
Net capital expenditures 1,038
----------------------------------------------------------------------------


Commodity prices and production volumes have a large impact on the ability of the Company to generate adequate cash flow. The current period of economic slowdown and low commodity prices have limited the Company's ability to make investments in drilling and exploration activities. A prolonged period of low commodity prices would negatively affect cash flow from operations that would likely result in a reduction in the amount of cash flow available for investment in drilling programs which would in turn negatively impact future production volumes. A prolonged period of low commodity prices may also affect the availability of funds that might be available by way of bank financing because the bank financing is dependent on the value of the Company's reserves. The value of the Company's reserves would be negatively impacted by commodity pricing and lower production volumes.

The Company has limited its drilling activities to a level that would potentially maintain current production levels, meet its flow through commitment and preserve capital. It will continue its geological and geophysical activities with a view to capitalizing on them when the economy turns.

The Company will continue to strive for higher operating efficiencies and take advantage of lowered costs that may be available to it due to the economic downturn.

Argosy intends to fund its capital expenditure program from internally generated cash flow, debt, and new equity or other funding if available on favorable terms.

At December 31, 2008 the Company's credit facility comprised a Revolving Operating Demand Loan facility with a credit limit of $22,000,000 and an Acquisition/Development Demand Loan with a credit limit of $9,000,000.

In January 2009, the Company's credit facility was reviewed by the Bank and the facility that was in place at year end was replaced with a Revolving Operating Demand Loan with a credit limit of $29 million and an Acquisition / Development Demand Loan with a credit limit of $2 million.

In July 2009, the Company's credit facility was reviewed by the Bank and the facility that was put in place in January 2009 was replaced with a Revolving Operating Demand Loan with a credit limit of $26 million and an Acquisition / Development Demand Loan with a credit limit of $2 million.

The Revolving Operating Demand Loan is subject to the Bank's right of demand and periodic review and bears interest at Bank prime plus a percentage determined in accordance with the bank's pricing grid. The Bank's pricing grid is dependent on the Company's debt to cash flow ratio. The application of the Bank's pricing grid will result in a rate which is 2.5% greater than the Bank's prime rate.

The Acquisition/Development Demand Loan is also subject to the Bank's right of demand and periodic review, requires unspecified monthly principal repayments over the engineering half life of the reserves being financed as determined by the Bank, bears interest at a rate which is 0.5% higher than the Revolving Operating Demand Loan and has a standby fee of one quarter of between .25% and .5% of the undrawn portion of the credit facility.

The next Bank review is scheduled for October 1, 2009.

Risk Management

The Company's business, exploration for and development of crude oil and natural gas is inherently risky. There can be no guarantee that crude oil and natural gas can be found and produced on an economic basis. In order to mitigate that risk, the Company operates in areas in which it has technical and operating expertise. The Company uses the latest technology to further reduce risk and increase the probability of success.

The Company operates all of its production and this allows it to a great extent to control the timing and costs in the areas in which it operates. Programs can thus be expanded or contracted on a timely basis in response to changing parameters. In this time of extreme market volatility, Argosy intends to limit its drilling activities to a level that would potentially maintain current production levels, preserve capital and manage its borrowings. See also "Liquidity and Capital Resources".

The Company carries insurance to protect itself from catastrophic events and it reviews its coverage at least annually to ensure that the insurance policies that are in place are adequate. The company follows all environmental and industry regulations and has instituted formal procedures to ensure that this occurs. Such procedures are communicated to all personnel and contractors.

The Company's operations are funded through internally generated cash flow, debt and new equity if available on favorable terms.

Cash flow can be materially affected by fluctuations in commodity prices and foreign currency which are out of the Company's control. While substantially all of the Company's petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollar. Argosy had no forward exchange rate contracts in place as at or during the period ended June 30, 2009.

Commodity prices for petroleum and natural gas are impacted by not only the relationship between the Canadian and United States dollar but also by world economic events that dictate the levels of supply and demand.

The Company has attempted to mitigate commodity price risk through the use of various financial derivative contracts classified as "held for trading" to manage volatility of commodity gas prices. These contracts can only be undertaken upon approval by the Board of Directors. The Company's banking documents limit such activities to 50% of actual production.

Such contracts are marked to market at the reporting date and an unrealized gain or loss is booked to the accounts. During the period ended June 30, 2009, the Company recorded an unrealized loss of $460,000 on the call and an unrealized gain of $63,000 on the swap as a result of marking the contracts to market. During the same period, a total $70,000 was actually received in respect to the swap and that was recorded as a realized gain.



As at June 30, 2009, the following derivative contracts were outstanding:

Commodity
Type of Hedge Hedged Volume Price Period
----------------------------------------------------------------------------
Financial fixed 2,000 Cdn July 1, 2009 to
price swap Natural Gas GJ/day $4.27/Gj December 31, 2009 (1)
Financial fixed 2,000 Cdn January 1, 2010 to
price call Natural Gas GJ/day $7.70/Gj March 31, 2011 (1)

(1) A giga joule (GJ) converts to a mcf at the rate of 1.055056 Gj per mcf.


Outlook

The global financial crisis caused a deterioration of the condition of credit markets and extreme volatility in commodity markets has introduced a great deal of uncertainty. In these times, the Company has chosen to limit its drilling activities to a level that would potentially maintain current production levels satisfy its flow through commitment and preserve capital.

Sensitivities

The Company's performance is affected by factors such as changes in production volumes, commodity prices and interest rates.

The following table illustrates the impact on cash flow and net earnings as a result of changes in commodity prices and interest rates based on forecast cash flows and capital expenditures of between $2 and $4 Million for 2009:



Cash Flow and
$ Thousand Pretax Earnings

----------------------------------------------------------------------------
Impact on the year ended December 31, 2008
Change in Canadian crude oil by $1/ bbl 5
Change in field gate price of Natural Gas by $1/ mcf 1,144
Change in Natural Gas Liquids price by $1/ bbl 24
Change of 1% in prime interest rates 260


Critical Accounting Estimates

There are no changes from those described in Management's Discussion and analysis for the year ended December 31, 2008.

Risks

There are no changes from those described in Management's Discussion and analysis for the year ended December 31, 2008.

Changes in Legislation

Alberta Royalties

On October 25, 2007, the Government of Alberta released its New Royalty Framework ("NRF") which is to be the basis of royalty regulations that became effective on January 1, 2009. The NRF imposes a regime whereby Alberta Crown Royalty rates are based on production rates, well depths and commodity prices.

The NRF includes a shallow rights reversion policy whereby mineral rights to shallow gas formations that are not being developed would revert back to the Government of Alberta and would be available for lease.

On April 10, 2008 the Government of Alberta introduced new 5 year programs that offered incentives to continue to explore for deeper targets. Under these programs, exploration oil wells over 2,000 meters and similar program for gas wells drilled to depths of 2,500 meters or greater may qualify for 12 months royalty credits to a maximum of $1 million.

On November 19, 2008, the Government of Alberta announced a five year program of transitional royalty rates. Under this program, new natural gas or conventional oil wells that are drilled between November 19, 2008 and December 13, 2013 and that are drilled to depths between 1,000 and 3,500 meters will be given a one time option, on a well by well basis, to elect to pay royalties under the NRF or the transitional rates.

On March 3, 2009, the Government of Alberta announced an incentive program that would provide a $200 per meter drilled royalty credit to companies on a sliding scale based on their production levels for the previous year. In addition, a new well incentive program was announced that would offer a maximum five-per-cent royalty rate for the first year of production from new oil or gas wells.

On June 25, 2009, the Government of Alberta announced that the incentive programs announced on March 3, 2009 would be extended to March 2011.

The application of the NRF resulted in the lowering of royalties on the Company's existing production because it is sensitive to lower prices. The incentive programs announced on April 10, 2008 and March 3, 2009 the transitional program announced on November 19, 2008 may reduce royalty costs for 2009 to the extent that qualifying wells are drilled in 2009. Such reductions will be based on drilling activity. The current economic slowdown and low commodity price regime may limit the Company's ability to take full advantage of the incentive programs. See "Liquidity and Capital Resources".

Greenhouse Gas and Air Emissions Legislation

The Federal Government released on April 26, 2007, its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as ecoACTION and which includes the Regulatory Framework for Air Emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Regarding large industry and industry related projects, the Government's Action Plan intends to achieve the following: (i) an absolute reduction of 150 megatonnes in greenhouse gas emissions by 2020 by imposing mandatory targets; and (ii) air pollution from industry is to be cut in half by 2015 by setting certain targets. New facilities using cleaner fuels and technologies will have a grace period of three years. In order to facilitate companies' compliance with the Action Plan's requirements, while at the same time allowing them to be cost-effective, innovative and adopt cleaner technologies, certain options are provided. These are: (i) in-house reductions; (ii) contributions to technology funds; (iii) trading of emissions with below-target emission companies; (iv) offsets; and (v) access to Kyoto's Clean Development Mechanism.

On March 8, 2007, the Alberta Government introduced Bill 3, the Climate Change and Emissions Management Amendment Act, which intends to reduce greenhouse gas emission intensity from large industries. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12% starting July 1, 2007; if such reduction is not initially possible the companies owning the large emitting facilities will be required to pay $15 per tonne for every tonne above the 12% target. These payments will be deposited into an Alberta-based technology fund that will be used to develop infrastructure to reduce emissions or to support research into innovative climate change solutions. As an alternate option, large emitters can invest in projects outside of their operations that reduce or offset emissions on their behalf, provided that these projects are based in Alberta. Prior to investing, the offset reductions offered by a prospective operation must be verified by a third party to ensure that the emission reductions are real. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact of those requirements on the Company and its operations and financial condition. Bill 3 does not currently have an impact on the Company as it does not own any facilities emitting in excess of 100,000 tonnes per year.

Disclosure Controls and Internal Controls Over Financial Reporting

Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be disclosed by the Company is recorded, processed, summarized and reported within the time periods specified under the Canadian securities law. Argosy's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation, that the Company's disclosure controls and procedures as of the end of June, 2009 are effective and provide reasonable assurance that material information related to the Company is made known to them by others within the Company.

Argosy's Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining internal controls over financial reporting ("ICFR"). They have, as at the quarter ended June 30, 2009, designed ICFR or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The control framework Argosy's officers used to design the ICFR is the Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations.

Argosy's Chief Executive Officer and Chief Financial Officer are required to cause the Company to disclose herein any change in the Company's internal controls over financial reporting that occurred during the Company's most recent interim period that has materially affected, or is reasonably likely to affect, the Company's internal controls over financial reporting. No material changes in the Company's internal controls were identified during the period ended June 30, 2009 that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting.

It should be noted that a control system, including the Argosy's disclosure and internal controls and procedures, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met and it should be not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

Contractual Obligations

The Company issued 1,208,051 common flow through shares at an issuance price of $5.20 per share. The tax deductions related to the flow through shares issued in 2008 were renounced to flow through shareholders and booked to the accounts in February 2009. The Company will be required to spend approximately $5,816,000 in 2009 on qualifying CEE expenditures to fulfill its flow through obligation. At June 30, 2009, $3,115,000 of such expenditures remains to be made.

As consequence of the Plan of Arrangement, Argosy has agreed to indemnify Accrete or its successors from any claims arising from liabilities not retained by Accrete, for breaches of representations and warranties of Accrete and Argosy for breaches of covenants by Accrete, which survives the effective date of the arrangement for one year.

Accrete entered into an agreement with a major drilling contractor. Accrete was obligated to utilize the contractor's rig for a period of 200 days during the one year term of the agreement that commenced August 15, 2007. Argosy has assumed this obligation pursuant to the Arrangement. The Company has estimated that a liability of up to $500,000 could be incurred. The Company is currently negotiating the settlement of this obligation. In 2009, $252,000 was paid to the drilling contractor as a good faith gesture; however, a further $248,000 could be incurred should negotiations fail.

The Company has entered into various commitments related to the leasing of office premises and office equipment. The payments due under such leases are as follows:



($ thousands)
2009 2010 2011 2012 2013 Thereafter
----------------------------------------------------------------------------

Office Premises 354 708 741 808 879 -
Office equipment 2 1 - - - -
----------------------------------------------------------------------------
356 709 741 808 879 -
----------------------------------------------------------------------------


At June 30, 2009 the Company's credit facility comprised a Revolving Operating Demand Loan facility with a credit limit of $29,000,000 and an Acquisition/Development Demand Loan with a credit limit of $2,000,000.

In July 2009, the Company's credit facility was reviewed by the Bank and the facility that was in place at June 30, 2009 was replaced with a Revolving Operating Demand Loan with a credit limit of $26 million and an Acquisition / Development Demand Loan with a credit limit of $2 million.

The Revolving Operating Demand Loan has no specific terms of repayment aside from the bank's right of demand and periodic review.

The Revolving Operating Demand Loan bore interest in accordance with the Bank's pricing grid that ranges from Bank prime rate plus .25% to Bank prime rate plus 2.5% dependant on the debt to cash flow ratio. Currently, the applicable rate is Bank prime rate plus 2.5%.

The Acquisition/Development Demand Loan bore interest at bank prime rate plus .5 percent higher than that charged for the Revolving Operating Demand Loan, is subject to a standby charge of between .25% and .5% on the undrawn portion of this loan and is subject to the Bank's right of demand and periodic review.

Security for these facilities include a general assignment of book debts, a $75,000,000 debenture with a first floating charge over all assets with a negative pledge and an undertaking to provide fixed charges on the Company's major producing reserves at the request of the bank.

A covenant to the Revolving Operating Demand Loan facility requires that the Company maintain a working capital ratio, exclusive of bank indebtedness, of at least 1 to 1. For purposes of this calculation, the undrawn availability under the facility is added to current assets. The Company is in compliance with this debt covenant at June 30, 2009.

The next review of the Company's credit facility is scheduled for October 1, 2009.

Change in Accounting Policies and Recent Accounting Pronouncements

Goodwill

As of January 1, 2009, the Company adopted CICA Handbook Section 3064 "Goodwill and Intangible Assets", which defines the criteria for the recognition of intangible assets. The adoption of this policy had no impact on the Company's financial statements.

Business Combinations

In January 2009, the CICA issued Section 1582, "Business Combinations", which replaces former guidance on business combinations. The new Section expands the definition of a business subject to an acquisition and establishes significant new guidance on the measurement of consideration given, and the recognition and measurement of assets acquired and liabilities assumed in a business combination. The implementation of this section had no impact on the Company's financial statements.

Consolidated Financial Statements

In January 2009, the CICA issued Handbook Section 1601, "Consolidated Financial Statements", and 1602, "Non-controlling Interests", which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The implementation of this section had no impact on the Company's financial statements.

International Financial Reporting Standards ("IFRS")

On February 13, 2008, Canada's Accounting Standards Board ("AcSB") confirmed January 1, 2011 as the effective date for the mandatory convergence of Canadian GAAP to IFRS.

Argosy intends to adopt the requirements set out by AcSB and other regulatory bodies. The impact of adopting IFRS is not reasonable to estimate at this time. Argosy has engaged independent consultants to assist in implementation of IFRS. The independent consultants are currently in the initial scoping stages of the project.

The first financial statements that the Company will have to prepare under IFRS will be the unaudited statements for the quarter ended March 31, 2011 that will include unaudited comparative financial information for the quarter ended March 31, 2010. The first audited financial statements that the Company will have to prepare will be those for the year ended December 31, 2011 with comparative financial information for the year ended December 31, 2010. As a result, all of the opening balance sheet figures as at January 1, 2010 must be computed prior to the issuance of the unaudited financial statements for the quarter ended March 31, 2011 so as comparative figures may be shown.

As of January 1, 2009, the Company adopted the requirements of CICA Handbook Section 3064 "Goodwill and Intangible Assets", which defines the criteria for the recognition of intangible assets. This had no impact on the Company's financial results.

Transactions With Related Parties

The Company has not entered into any transactions with related parties, nor did it have any balances outstanding with related parties at year end.

Off Balance Sheet Arrangements

The Company has not entered into any off-balance sheet transactions.



Argosy Energy Inc.
Balance Sheets
(Unaudited)

June 30, December 31,
($ Thousands) 2009 2008
----------------------------------------------------------------------------

ASSETS
Current assets
Accounts receivable 1,268 3,296
Prepaid expenses 479 606
Future income tax (note 8) 71 -
----------------------------------------------------------------------------
1,818 3,902
Property and equipment (note 4) 65,151 68,192
----------------------------------------------------------------------------
66,969 72,094
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES

Current liabilities
Accounts payable and accrued liabilities 1,672 6,357
Fair value of derivative financial instruments
(notes 2 and 10) 281 -
Bank indebtedness (note 5) 25,823 22,763
----------------------------------------------------------------------------
27,776 29,120

Asset retirement obligation (note 7) 829 771
Future income tax (note 8) 6,855 6,171
----------------------------------------------------------------------------
35,460 36,062
----------------------------------------------------------------------------

SHAREHOLDERS' EQUITY
Share capital (note 6) 35,416 36,986
Contributed surplus (note 6) 646 383
Deficit (4,553) (1,337)
----------------------------------------------------------------------------
31,509 36,032
----------------------------------------------------------------------------
66,969 72,094
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Basis of Presentation and Going Concern (note 2)
Commitments (note 11)

See accompanying notes to financial statements


Argosy Energy Inc.
Statements of Income (Loss) and Comprehensive Income (Loss)
(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
($ Thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue (note 2) (note 2)
Petroleum and natural gas revenue 2,255 6,019 5,470 10,747
Royalties (305) (1,262) (1,197) (2,169)
Realized (loss) on derivative
instruments 70 (140) 70 (140)
Unrealized loss on derivative
instruments (281) (550) (281) (550)
----------------------------------------------------------------------------
1,739 4,067 4,062 7,888
----------------------------------------------------------------------------
Expenses
Production 463 345 1,069 643
Transportation 124 113 209 169
General and administrative, net of
recoveries
1,097 528 2,109 818
Interest 258 601 462 1,202
Stock based compensation (note 6) 124 18 248 50
Depletion, depreciation and accretion 1,934 1,981 4,137 3,522
----------------------------------------------------------------------------
4,000 3,586 8,234 6,404
----------------------------------------------------------------------------
Income before income taxes (2,261) 481 (4,172) 1,484
Future income taxes (note 8) 535 (125) 956 (385)
----------------------------------------------------------------------------
Net income (loss) and comprehensive
income (loss) (1,726) 356 (3,216) 1,099
----------------------------------------------------------------------------

Net income (loss) per share (Note 6):
Basic (0.30) 0.09 (0.55) 0.27
Diluted (0.30) 0.08 (0.55) 0.25


See accompanying notes to financial statements.

Argosy Energy Inc.
Statements of Deficit
(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
($ Thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
(note 2) (note 2)
Deficit, beginning of period (2,827) - (1,337) -
Net income (loss) for the period (1,726) 356 (3,216) 1,099
Retained earnings allocated to Accrete (356) (1,099)
----------------------------------------------------------------------------
Deficit, end of period (4,553) - (4,553) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to financial statements.


Argosy Energy Inc.
Statements of Cash Flows
(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
($ Thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by (used in): (note 2) (note 2)
Operating Activities
Net income (1,726) 356 (3,216) 1,099
Items not affecting cash:
Stock based compensation expense 132 18 263 50
Future income taxes (535) 125 (957) 385
Unrealized loss on derivative
instruments 281 550 281 550
Depletion, depreciation and
accretion 1,934 1,981 4,137 3,522
----------------------------------------------------------------------------
86 3,030 508 5,606
Change in non-cash working
capital (note 9) (552) (1,896) (1,034) (405)
----------------------------------------------------------------------------
(466) 1,134 (526) 5,201
----------------------------------------------------------------------------
Investing Activities
Property and equipment additions (608) (8,707) (1,038) (13,411)
Change in non-cash working
capital (note 9) (483) 233 (1,496) 1,171
----------------------------------------------------------------------------
(1,091) (8,474) (2,534) (12,240)
----------------------------------------------------------------------------
Financing Activities
Bank debt 1,557 4,646 3,060 6,563
Accrete Energy Inc. - 2,694 - 476
----------------------------------------------------------------------------
1,557 7,340 3,060 7,039
----------------------------------------------------------------------------
Increase (decrease) in cash - - - -
Cash - beginning of period - - - -
----------------------------------------------------------------------------
Cash - end of period - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental Information :
Interest Paid 258 601 462 1,202
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to financial statements.


Argosy Energy Inc.
Notes to the Financial Statements
For the period ended June 30, 2009
(Unaudited)


1. Description of Business

Argosy Energy Inc. ("Argosy") is an independent public Company engaged in the acquisition, exploration, exploitation, development and production of crude oil and natural gas in Alberta, Canada.

Argosy was inactive from the time of its incorporation under the Business Corporations Act (Alberta) on June 6, 2008 to September 30, 2008 at which time, and pursuant to a Plan of Arrangement between Accrete Energy Inc. ("Accrete"), Pengrowth Energy Trust, Pengrowth Company, Pengrowth Energy Partnership and Argosy ("the Arrangement"), Argosy acquired certain assets including producing and exploratory oil and gas properties and certain tax pools from Accrete effective on the closing date of September 30, 2008.

2. Basis of Presentation and Going Concern

The unaudited interim financial statements have been prepared by management on a going concern basis in accordance with Canadian generally accepted accounting principles, following the same accounting policies and methods of computation as the audited financial statements of Argosy Energy Inc. for the year ended December 31, 2008, except as outlined in note 3.

The going concern basis of presentation assumes that the Company will continue in operation for the foreseeable future and be able to realize its assets and discharge its obligations in the normal course of business. Market events, including disruptions in credit markets and other financial systems and the deterioration of global economic conditions have resulted in significant declines in commodity prices. At June 30, 2009, the Company has a working capital deficiency of $25.7 million, including bank loans outstanding of $25.8 million. The available borrowing limits are based on the bank's assessment of the Company's reserves and future commodity prices of which there can be no assurance that such amount will not decrease at the next scheduled review to be completed on or before October 1, 2009.

The Company has outlined its operating commitments in Note 11. Management has restricted capital, non- essential expense and administrative spending and continues to pursue financing opportunities to fund its future prospects and commitments. No financing agreements have been signed nor can it be assured that such agreements will be reached however management believes the courses of action being taken will mitigate the conditions and events which could raise doubt about the validity of the going concern assumption used in preparing these unaudited interim financial statements. If the going concern assumption were not appropriate, adjustments might be necessary to the carrying values of assets and liabilities, the reported revenues and expenses and the balance sheet classifications used.

For the period up to September 30, 2008, these financial statements present the historical financial position, results of operations and cash flow of Accrete on a carve-out basis following continuity of interest guidelines as if the assets acquired by Argosy had always operated as a stand-alone entity. Certain financial statement items were maintained by Accrete at a corporate rather than on a property-by-property basis and accordingly, it was necessary to make allocations of amounts reported in the financial statements of Accrete in order to prepare these financial statements for the carved-out assets. The historical financial statements may not necessarily be indicative of the results that would have been attained if Argosy had operated as a stand-alone entity for the periods prior to September 30, 2008.

Certain information and disclosure normally required to be included in notes to annual financial statements have been condensed or omitted. These unaudited interim financial statements should be read in conjunction with the audited financial statements of Argosy Energy Inc. for the year ended December 31, 2008.

3. Change In Accounting Policies

Goodwill

As of January 1, 2009, the Company adopted CICA Handbook Section 3064 "Goodwill and Intangible Assets", which defines the criteria for the recognition of intangible assets. The adoption of this policy had no impact on the Company's financial statements.

Business Combinations

In January 2009, the CICA issued Section 1582, "Business Combinations", which replaces former guidance on business combinations. The new Section expands the definition of a business subject to an acquisition and establishes significant new guidance on the measurement of consideration given, and the recognition and measurement of assets acquired and liabilities assumed in a business combination. The adoption of this policy had no impact on the Company's financial statements.

Consolidated Financial Statements

In January 2009, the CICA issued Handbook Section 1601, "Consolidated Financial Statements", and 1602, "Non-controlling Interests", which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The implementation of this section had no impact on the Company's financial statements.

International Financial Reporting Standards ("IFRS")

On February 13, 2008, Canada's Accounting Standards Board ("AcSB") confirmed January 1, 2011 as the effective date for the mandatory convergence of Canadian GAAP to IFRS for Canadian public companies.

Argosy is required to adopt the requirements set out by AcSB and other regulatory bodies. Argosy has engaged independent consultants to assist in implementation of IFRS. The independent consultants are currently in the initial scoping stages of the project. The impact of adopting IFRS is not reasonable to estimate at this time.

The first financial statements that the Company will have to prepare under IFRS will be the unaudited statements for the quarter ended March 31, 2011 that will include unaudited comparative financial information for the quarter ended March 31, 2010. The first audited financial statements that the Company will have to prepare will be those for the year ended December 31, 2011 with comparative financial information for the year ended December 31, 2010. As a result, all of the opening balance sheet figures as at January 1, 2010 must be computed prior to the issuance of the unaudited financial statements for the quarter ended March 31, 2011 so as comparative figures may be shown.



4. Property and Equipment

As at As at
June 30, December 31,
2009 2008
($ thousands) $ $
----------------------------------------------------------------------------
Petroleum and natural gas properties and equipment 91,619 90,562
Furniture, fixtures and other 187 176
----------------------------------------------------------------------------
91,806 90,738
Less: Accumulated depletion and depreciation 26,655 22,546
----------------------------------------------------------------------------
65,151 68,192
----------------------------------------------------------------------------


At June 30, 2009 costs of $8,865,000 ($8,728,000 at December 31, 2008) with respect to unproved properties have been excluded from costs subject to depletion. At June 30, 2009 a total of $1,713,000 ($1,713,000 at December 31, 2008) of future development costs were included in the depletion calculation. Direct salary costs related to geological and geophysical personnel in the amount of $154,000 for the six months ended June 30, 2009 ($208,000 in 2008) have been capitalized. The net amount at which petroleum and natural gas properties are carried is subject to a cost recovery test (the "ceiling test"). The ceiling test at December 31, 2008 indicated that the net undiscounted recoverable amount from proved oil and natural gas reserves and the lower of cost or market of unproved properties exceeded the net carrying value of the petroleum and natural gas properties and equipment. The prices used in the ceiling test evaluation of the Company's petroleum and natural gas properties and equipment were as follows:



Crude Oil Natural Gas
West Texas Edmonton AECO Gas
Intermediate Par Price Price
(Cdn$/bbl) (1) (Cdn$/bbl) (Cdn$/ mmbtu)
----------------------------------------------------------------------------
2009 69.70 68.61 7.58
2010 77.71 78.94 7.94
2011 84.57 83.54 8.34
2012 91.89 90.92 8.70
2013 96.85 95.91 8.95
2014-2018 (2) 97.68 101.87 9.54
----------------------------------------------------------------------------
Thereafter (3) + 2% +2% +2%
----------------------------------------------------------------------------

(1) US / Canadaian Exchange rates 2009 - 0.825, 2010 -0..875, 2011 - 0.875,
2012 - 0.925, 2013 and thereafter - 0.95
(2) Average prices for the period
(3) Represents the change in future prices from 2018 to the end of the
reserve life


5. Bank Indebtedness

At June 30, 2009 the Company's credit facility comprised a Revolving Operating Demand Loan facility with a credit limit of $29,000,000 and an Acquisition/Development Demand Loan with a credit limit of $2,000,000.

The Revolving Operating Demand Loan bore interest at bank prime plus 2.5 percent in accordance with the Bank's pricing grid and had no specific terms of repayment aside from the bank's right of demand and periodic review.

The Acquisition/Development Demand Loan bore interest at bank prime rate plus .25 percent over that of the Revolving Operating Demand Loan and required monthly principal repayments commencing the month following drawdown and was also subject to the Bank's right of demand and periodic review.

The Company's credit facility was reviewed by the Bank in July 2009 and the $29 million Revolving Operating Demand Loan and the $2 million Acquisition / Development Demand Loan were replaced with a Revolving Operating Demand Loan with a credit limit of $26 million and an Acquisition / Development Demand Loan with a credit limit of $2 million.

The Revolving Operating Demand Loan will bear interest at Bank prime plus a percentage determined quarterly ranging from .25% to 2.5% greater than the Bank's prime rate in accordance with the Bank's pricing grid. The Bank's pricing grid is dependent on the Company's debt to cash flow ratio where debt is defined by the Bank as working capital deficit, consolidated long term debt including capital leases and retractable preferred shares which are retractable at the option of the holder and cash flow is defined by the Bank as net earnings, depletion, depletion and accretion, future income taxes and other charges to income not requiring a cash payment calculated for the most recently completed quarter and annualized.

The application of the Bank's pricing grid results in a rate which is 2.5% greater than the Bank's prime rate.

The Revolving Operating Demand Loan has no specific terms of repayment aside from the Bank's right of demand and periodic review. The Acquisition/Development Demand Loan requires unspecified monthly principal repayments over the engineering half life of the reserves being financed as determined by the Bank

The Acquisition/Development Demand Loan will bear interest at a rate which is 0.5% higher than the Revolving Operating Demand Loan and bears a standby fee of between .25% and .5% on the undrawn portion of the loan facility.

Security for the facilities includes a general assignment of book debts, a $75,000,000 debenture with a first floating charge over all assets with a negative pledge and an undertaking to provide fixed charges on the Company's major producing reserves at the request of the bank.

A covenant to the Revolving Operating Demand Loan facility requires that the Company maintain a working capital ratio, exclusive of bank indebtedness, of at least 1 to 1. For purposes of this calculation, the undrawn availability under the facility is added to current assets. The Company was in compliance with this debt covenant at June 30, 2009.

The next review of the facilities is scheduled for October 1, 2009.

6. Share Capital

Authorized:

An unlimited number of common voting shares and an unlimited number of preferred shares issuable in series for which the directors may fix, among other things, the rights, privileges, restrictions, conditions, voting rights, rates, method of calculation and dates of payment of dividends and terms of redemption, purchase and conversion if any, and any other provisions.



Issued and outstanding:

Number of
Common Voting Shares Shares $ Thousands
----------------------------------------------------------------------------

Issued on incorporation, June 6, 2008 1 .1
Cancelled on closing of the Arrangement (1) (.1)
Issued pursuant to the Arrangement 4,494,667 29,986
Issued on private placement to officers ,
directors and employees - flow through shares 1,208,051 6,282
Issued on private placement to officers,
directors and employees - common shares 156,116 718
----------------------------------------------------------------------------
Balance, December 31, 2008 5,858,834 36,986
----------------------------------------------------------------------------
Tax effect flow through shares - 1,570
----------------------------------------------------------------------------
Balance, June 30, 2009 5,858,834 35,416
----------------------------------------------------------------------------


The tax deductions related to the flow through shares issued in 2008 were renounced to flow through shareholders and booked in February 2009.

The following reconciles the common shares used in calculating net earnings (loss) per common share ("EPS"):



June 30
2009
----------------------------------------------------------------------------
Weighted average common voting shares outstanding - basic 5,858,834
Effect of dilutive stock options n/a
----------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 5,858,834
----------------------------------------------------------------------------


Basic EPS is computed by dividing the net income (loss) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS gives effect to all dilutive instruments outstanding during the period including stock options using the treasury stock method. In computing diluted EPS, the average stock price for the period is used in determining the number of shares assumed to be purchased from the exercise of "in the money stock options". Diluted EPS excludes the effect of stock options in 2009 because their inclusion would be anti-dilutive.

Stock Options

Under the terms of the Argosy Energy Inc. 2008 Incentive Stock Option Plan, (the "plan"), directors, officers, employees and consultants (the "Participant(s)") are eligible to be granted options to purchase common shares. The plan provides that the Company can reserve up to 10% of the common shares that are issued and outstanding for the granting of options.

The maximum number of option shares that may be reserved for issuance to any one Participant under the plan cannot exceed 5% of the issued and outstanding common shares.

The grant price under the plan is defined by the plan to be the closing price on the principal stock exchange on which the common shares are traded on the last business date preceding the date of grant or if the common shares did not trade on that date, the weighted average price for the five trading days preceding the date of grant if the common shares are listed and posted for trading on a stock exchange or the value conclusively determined by the Board of Directors if it is not.

The vesting of stock options is determined by the board of directors and the term, as also determined by the board of directors cannot exceed five years from the date of grant of such options.

A participant's entitlement under the plan ceases upon ceasing to be a Participant. If such cessation is involuntary, then the vested and unvested options can be exercised for a period of ninety days after such date. Where a Participant is terminated for cause, the Participant may only exercise those options that have become vested. Where a Participant is terminated by the company without cause, the Participant is entitled to exercise stock options that have vested during the notice period or in the event of compensation being paid in lieu of notice, for 21 days after ceasing to be a Participant.

Options granted under the plan are not assignable and no financial assistance is extended to optionees.

The board of directors is empowered to amend the plan. Any amendment to the plan is subject to the receipt of necessary regulatory approvals and any amendment required by applicable law or regulatory policy to be approved by shareholders does not become effective until so approved.



The following table summarizes information about stock options outstanding
at June 30, 2009:

Options outstanding:

Balance September 30, 2008 -
Granted 580,000
----------------------------------------------------------------------------
Balance, December 31, 2008 580,000
Forfeited (3,000)
----------------------------------------------------------------------------
Balance, June 30, 2009 577,000
----------------------------------------------------------------------------


The Company has accounted for its employee stock options granted using the fair value method at the date of grant in 2008 using the Black-Scholes model.

The fair value of the options granted to June 30, 2009 was estimated to be $ 1,169,000 ($2.03 per option granted).

This value is expensed as stock based compensation cost over the vesting period. A total of $248,000 was charged to expense and a total of $15,000 was capitalized for a total stock based compensation charge of $263,000 for the period ended June 30, 2009.

The assumptions used in calculating the fair value include a volatility factor ranging of 46%, a weighted average risk free interest rate of 3% and a weighted average expected life of the options of 5 years.



Weighted
Average
Options Remaining Number Exercise
Outstanding Contractual Exercisable Price
Grant Price Life (Vested) ($/Share)
----------------------------------------------------------------------------
$4.60 (1) 376,000 376,000 4.60
$4.60 (2) 201,000 - 4.60
----------------------------------------------------------------------------
577,000 376,000
----------------------------------------------------------------------------

(1) Five year term, vest equally over a three year period commencing on the
date of grant.
(2) Five year term, vest equally over a three year period commencing on the
first anniversary of the date of grant.


Contributed Surplus

Six Months Year
Ended Ended
June 30, December 31,
($ thousands) 2009 2008
----------------------------------------------------------------------------
Balance, beginning of period 383 -
Stock Based Compensation 263 383
----------------------------------------------------------------------------
Balance, end of period 646 383
----------------------------------------------------------------------------


7. Asset Retirement Obligation

Asset retirement obligation comprises:

($ thousands) Six Months Year
Ended Ended
June 30, December31,
2009 2008
----------------------------------------------------------------------------
Balance, beginning of period 771 614
Liabilities incurred 31 144
Accretion expense 27 13
----------------------------------------------------------------------------
Balance, end of period 829 771
----------------------------------------------------------------------------


The total future asset retirement obligation was estimated based on the Company's net ownership interest in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows to settle the asset retirement obligation is approximately $2,175,000 (2008 $2,169,000) which will be incurred over the next twenty five years. A credit adjusted risk-free rate of 7%-8% (2008 7%-8%) and an inflation rate of 2% (2008 2%) was used to calculate the fair value of the obligations.

8. Income Taxes

The Company's exploration and development expenditures and undepreciated capital costs total $36,300,000. These costs may be carried forward indefinitely to reduce future taxable income. The Company also has $577,000 of non-capital losses that may be applied to reduce taxable income in the next 20 years.

The following reconciles the difference between income tax recorded and the expected income tax expense obtained by applying the expected income tax rate to earnings before taxes:



Three Months Six Months
Ended Ended
June 30, June 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Income/(Loss) before income taxes (2,260) 482 (4,172) 1,484
Statutory Rate 29% 29.5% 29% 29.5%
Expected income tax expense at the
combined federal and provincial
statutory rate (656) 142 (1,210) 438
Stock based compensation cost 36 6 72 15
Tax-rate changes 85 (27) 181 (68)
Other - 4 - -
--------------------------------------
Future income tax expense (535) 125 (957) 385
--------------------------------------


The following table summarizes the tax effect of temporary differences:

June 30, December 31,
($ thousands) 2009 2008
----------------------------------------------------------------------------
Future income tax assets (liabilities):
Carrying value of capital assets in excess of tax
basis (7,206) (6,363)
Asset retirement obligation 207 192
Fair value of financial instruments 71 -
Loss carry forward 144 -
----------------------------------------------------------------------------
(6,784) (6,171)
Current future income tax asset:
Fair value of financial instruments (71) -
----------------------------------------------------------------------------
(6,855) (6,171)
----------------------------------------------------------------------------


9. Supplemental Cash Flow Information

Change in non-cash working capital comprises:

Six Months
Ended
June 30
($ thousands) 2009 2008
----------------------------------------------------------------------------
Accounts receivable 2,028 (387)
Prepaid expenses 127 (89)
Accounts payable and accrued liabilities (4,685) 1,242
Change in non-cash working capital
(2,530) 766
----------------------------------------------------------------------------
Relating to:
Investing activities (1,496) 1,171
Operating activities (1,034) (405)
----------------------------------------------------------------------------
(2,530) 766
----------------------------------------------------------------------------


10. Fair Value of Financial Instruments

The Company's financial instruments as at June 30, 2008 and December 31, 2008 include accounts receivable, fair value of derivative contracts, accounts payable and accrued liabilities and bank indebtedness. The fair value of accounts receivable, accounts payable and accrued liabilities approximate their carrying amounts due to their short-terms to maturity.

The fair value of derivative contracts is determined by reference to market information provided by the Company's bank. During the period ended June 30, 2009, the Company recorded an unrealized loss of $410,000 on the call and an unrealized gain of $129,000 on the swap as a result of marking the contracts to market. During the same period, a total $70,000 was actually received in respect to the swap and that was recorded as a realized gain.



As at June 30, 2009, the following derivative contracts were outstanding:

Unrealized
Commodity Gain(Loss)
Type of Hedge Hedged Volume Price Period $
----------------------------------------------------------------------------
July 1, 2009 to
Financial fixed 2,000 Cdn December 31, 129,000
price swap Natural Gas GJ/day $ 4.27/Gj 2009 (1)
January 1,
Financial fixed 2,000 Cdn 2010 to March (410,000)
price call Natural Gas GJ/day $ 7.70/Gj 31, 2011 (1)
------------
(281,000)
------------

(1) A giga joule (GJ) converts to a mcf at the rate of 1.055056 GJs per mcf.


Bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.

11. Commitments

As a consequence of the Plan of Arrangement, Argosy has agreed to indemnify Accrete or its successors from any claims arising from liabilities not retained by Accrete, for breaches of representations and warranties of Accrete and Argosy for breaches of covenants by Accrete until September 30, 2009.

The Company issued 1,208,051 common flow through shares at an issuance price of $5.20 per share. The tax deductions related to the flow through shares issued in 2008 were renounced to flow through shareholders and booked to the accounts in February 2009. The Company will be required to spend approximately $5,816,000 in 2009 on CEE expenditures to fulfill its flow through obligation. At June 30, 2009, $3,115,000 of such expenditures remains to be made.

Accrete entered into an agreement with a major drilling contractor. Accrete was obligated to utilize the contractor's rig for a period of 200 days during the one year term of the agreement that commenced August 15, 2007. Argosy has assumed this obligation pursuant to the Arrangement. The Company has estimated that a liability of up to $500,000 could be incurred. The Company is currently negotiating the settlement of this obligation. In 2009, $252,000 was paid to the drilling contractor as a good faith gesture however, a further $248,000 could be incurred should negotiations fail.

The Company has entered into various commitments related to the leasing of office premises and office equipment. The payments due under such leases are as follows:


Contractual obligations
($ thousands) 2009 2010 2011 2012 2013 Thereafter

----------------------------------------------------------------------------

Office Premises 354 708 741 808 879 -
Office equipment 2 1 - - - -
----------------------------------------------------------------------------
356 709 741 808 879 -
----------------------------------------------------------------------------


Contact Information

  • Argosy Energy Inc.
    Mr. Peter Salamon
    President and CEO
    (403) 269-8846
    or
    Argosy Energy Inc.
    Mr. Tom Dalton
    Vice President Finance and CFO
    (403) 269-8846
    or
    Argosy Energy Inc.
    2100, 500 - 4th Avenue SW
    Calgary, Alberta T2P 2V6
    Email: investor@argosyenergy.com
    Website: www.argosyenergy.com